EX-99.01 2 d497269dex9901.htm EX-99.01
Exhibit 99.01

Bank of America Merrill Lynch Refining Conference March 7, 2013

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," "intend," 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 187,000 BPD Approximately 6,800 branded marketing sites Nearly 1,900 sites in U.S. and Canada Retail segment Intend to spin-off Retail segment to shareholders 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

Refinery Capacities (000 bpd) Capacities (000 bpd) Nelson Index Refinery Total Through-put Crude Oil Nelson Index Corpus Christi 325 205 20.6 Houston 160 90 15.1 Meraux 135 135 10.2 Port Arthur 310 290 12.7 St. Charles 270 190 15.2 Texas City 245 225 11.1 Three Rivers 100 95 12.4 Gulf Coast 1,545 1,230 14.0 Ardmore 90 86 12.0 McKee 170 168 9.5 Memphis 195 180 7.5 Mid-Con 455 434 9.2 Pembroke 270 220 11.8 Quebec City 235 230 7.7 North Atlantic 505 450 9.7 Benicia 170 145 15.0 Wilmington 135 85 15.8 West Coast 305 230 15.3 Total or Avg. 2,810 2,344 12.4 Valero's Geographically Diverse Operations 4 Shutdown in March 2012 235,000 bpd capacity Nelson Index of 8

(CHART) Update on Potential Retail Separation Making progress on our plan to separate our retail business as new company called CST Brands, Inc. and unlock potential value for shareholders CST Brands, Inc. (formerly Corner Store Holdings, Inc.) has filed a draft registration statement with the SEC Intend to distribute to VLO shareholders 80% of CST Brands outstanding shares to trade on the NYSE under the ticker symbol "CST" Valero expects to receive approximately $1.1 billion in cash via new debt on CST Brands and incur a tax liability of approximately $260 million, mainly due to Canadian assets Expect separation to occur in 2Q13, subject to timing of IRS, SEC, and other regulatory agencies Investors and analysts have treated Valero mainly as a refiner, ignoring higher potential value of retail segment as shown in chart below 5 4.2x 5.2x Source: Factset as of 7/19/12, NTM = Next 12-months consensus estimate EV / NTM EBITDA Differential of Retailers versus Valero Energy

Overview of CST Brands, Inc. Expect to be one of the largest independent retailers of transportation fuels and convenience merchandise in North America Nearly 1,900 sites in two geographic segments: U.S. and Canada Retail-U.S. 1,032 company-operated retail sites, of which 81% are owned Sites located in the central and southwest U.S. Retail-Canada Consists of Motorist, Cardlock, and Home Heat businesses in eastern Canada 848 retail fuel sites 768 sites in the Motorist business 80 unattended sites in the Cardlock business 38% of sites are owned and 62% are leased Note: Store count data as of December 31, 2012. 6

CST Brands - Highlights Large scale with nearly 1,900 sites will make it the second-largest publicly traded independent retailer of fuel and convenience merchandise in North America Sites located in geographically diverse regions: the southwestern United States and eastern Canada 61% of U.S. sites are in Texas, which has a relatively favorable economy and attractive demographics for convenience stores Significant ownership of real estate - one of highest in peer group Solid performance track record Competitively positioned with good brand recognition Significant growth opportunities New-To-Industry (NTI) retail site program (estimate 20 or more in 2013) Growing food service and increasing emphasis on in-store merchandise Excellent logistics, private label program, and existing strong core merchandise sales 7

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 Low-cost U.S. natural gas provides competitive advantage Increasing Valero's yield of distillates, which have higher margins and global growth 8

(CHART) 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 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 9 (CHART) Sources: Industry and Consultant reports and Valero estimates

Valero in the Atlantic Basin 10 10 Aruba Terminal

Gulf Coast Crude Discounts and Product Margins: 4Q12 to 1Q13 Margins: 4Q12 to 1Q13 Margins: 4Q12 to 1Q13 11 Source: Argus, 1Q13 quarter-to-date pricing is through 3-1-13; Gas crack uses USGC CBOB Valero Gulf Coast Product and Feedstocks vs. ICE Brent In 1Q13, LLS has been pricing at a premium to ICE Brent due to limited trading volumes combined with market impacts such as the recent proration of Seaway pipeline Gasoline cracks have increased, but heavy sour and medium sour discounts have decreased from 4Q12 levels

(CHART) Continued Global Demand Growth Important to Refining Margins 12 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 because products are generally very storable, transportable, and fungible commodities MMBPD

(CHART) World Refinery Capacity Growth Expect significant new global refining additions in the next several years Mainly new plants in Asia and the Middle East Some investment in Latin America New capacity announcements from Brazil, Mexico, and Colombia will likely be much smaller and much later than originally announced Others very unlikely to happen because of costs: Ecuador, Peru, Algeria, Egypt Asian demand growth has been consuming Asian refining growth Net Global Refinery Additions 13 MMBPD Source: Consultant and Valero estimates; Net Global Refinery Additions = New Capacity + Restarts- Closures

Rapid Growth in U.S. Crude Supply 14 (CHART) 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; 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 2012 avg. - 449 MBPD (155 MBPD in Dec.)

Rapid Growth in Logistics to U.S. Gulf Coast 15 (CHART) Logistics capacity to move inland crude from the Mid-Continent and Texas to the U.S. Gulf Coast is expanding quickly to debottleneck inland markets Seeing significant rail capacity coming online, particularly in Bakken and Canada Most popular for East and West Coasts destinations, where pipeline access in unlikely, but tends to be higher cost delivery than to Gulf Coast Source: Consultants, company announcements and Valero estimates 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 2012 - 449 MBPD U.S. Total Shale Crude Supply in 2016 (estimated)

Valero's Estimate of Marginal Light Crude Oil Costs per Barrel in 12 to 24 Months 16 to USEC Rail $14 to $17/bbl to St. James Rail $12/bbl to Cushing Rail $9/bbl Cushing ICE Brent -$7 to $10 to Houston Pipe $4/bbl Midland ICE Brent -$7 to $10 to Houston Pipe $4/bbl CC to Houston $1/bbl Houston to St. James $1/bbl Bakken ICE Brent -$14 to $17 to West Coast Rail $13/bbl USGC to USEC US Ship $5 to $6/bbl USGC to Canada Foreign Ship $2/bbl From Alberta add $1 to $2/bbl to Bakken Prices USEC ICE Brent + ICE Brent -$2 to $5 ICE Brent -$2 to $3 ICE Brent -$3 to $6 Alberta ICE Brent -$15 to $16 Expect Gulf Coast will have cost advantage versus East Coast, West Coast, and foreign markets

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 U.S. Decision postponed until early 2013 Nebraska Governor recommended approval of the route in January 2013 Favorable environmental assessment from State Department in March 2013 Cushing to Gulf Coast leg has been separated from the project, and has started construction. Expected to complete late 2013 Expect to use rail and other pipeline options if not approved 17 Source: TransCanada Corporation Western Gateway to Kitimat Trans Mountain to Vancouver Enbridge working to expand capacity to U.S. as well

Valero has increased the amount of domestic light crudes processed as additional volumes have become available In 4Q12, Valero did not process foreign light crudes at its Gulf Coast and Memphis refineries Valero is evaluating potential projects to further increase its domestic light crude processing capacity Valero's Ability to Run Discounted Light Crude at Gulf Coast and Memphis Refineries 18 (CHART) Actual Volumes Processed

Lower-Cost Natural Gas Provides Structural Advantage to U.S. Refiners 19 Note: Per barrel cost of 700,000 mmBtus/day of natural gas consumption at 90% utilization (2,529 MBPD) of Valero's capacity $1.5 billion higher pre-tax annual costs $3.1 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 700,000 mmBtus/day of natural gas at full utilization, split roughly in half between operating expense and gross margin Increased from 600,000 with the addition of hydrocrackers at Port Arthur and St. Charles

Distillates Have Higher Margins and Faster Growth 20 Distillate (diesel, kero, jet fuel) margins are significantly higher than gasoline Distillate demand growth rate is much higher than gasoline Europe continues to be short diesel, but long marginal refining capacity and processing expensive crude oils and natural gas (CHART) Source: Argus, 2013 YTD through March 1, 2013 /bbl (CHART) World Product Demand Growth /year

57,000 BPD Port Arthur hydrocracker completed and operating at or above expectations With recent price environment and current unit performance, project is meeting or exceeding economic expectations Diesel quality is higher than expected Provides blending opportunity to upgrade margin on lower-quality distillate production Total distillate yield higher than expected Estimate 60,000 BPD St. Charles HCU mechanical completion and operating in 2Q13 Both hydrocrackers were designed to benefit from the price outlook of high crude and low natural gas Pursuing projects to expand capacity of each unit to 75,000 BPD in 2015 Successfully Completed Port Arthur Hydrocracker 21 St. Charles Port Arthur

Valero Increasing Distillate Yields 22 (CHART) 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 Recent acquisitions have also increased distillate yields (CHART)

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 2012 2011 was first full-year with 1st quartile portfolio performance in mechanical availability 2012 is best-ever energy efficiency for refining portfolio Excluding Meraux downtime in 3Q12, mechanical availability would have remained 1st quartile in 2012 Working diligently on weaker performers to improve entire portfolio Improving Refinery Operations 23 1st Quartile 2nd Quartile 1st Quartile 2nd Quartile 3rd Quartile 3rd Quartile Source: Solomon Associates and Valero Energy; excludes Aruba

Expect Large Decline in Capital Spending in 2013 24 "Stay- in- business" spending 2012 capital high due to spending on growth projects, mainly on two new hydrocrackers For 2013, largest category of strategic/growth spending is for logistics projects (pipelines, tanks, docks and rail), domestic crude processing expansions and completion of the St. Charles hydrocracker ($150 million moved from 2012 to 2013) 2013 Retail (U.S. and Canada) capital estimated at approximately $200 million with about 75% in the strategic/economic growth category $1,540 $1,645 $1,625 Decline

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 from $0.05 per share in 2Q11 to $0.20 per share in 1Q13 Bought 10.6 million shares for $281 million 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 $1.7 billion of cash and $5.7 billion of additional liquidity on December 31, 2012 Maintaining investment grade credit rating is a priority Reduced debt by $558 million in 2012 Paid off $180 million of debt in January 2013 and plan to pay off an additional $300 million in 2Q13 Net debt-to-cap ratio at 12/31/12 was 22.7% Far below credit facility covenant of 60% No other coverage-type ratios or borrowings on bank revolver Retail spin-off to shareholders planned for 2Q13 Returning more value to shareholders 25 (CHART) Cash Returned to Shareholders (CHART) Source: 2013 EPS estimates from First Call as of 3-4-13

Valero's Strategic Priorities 26 Constant focus on safety, environmental, and regulatory compliance Maintain investment grade credit rating Continue improvement in refining portfolio performance to 1st quartile levels Complete major, value-added capital projects Improve portfolio performance Evaluate options for poor performing assets Evaluate attractively priced, strategic, and accretive acquisitions with strong synergies Continue to upgrade product streams Continue to return available cash to shareholders, with high yield 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/strong competitive position of U.S. refining Expect abundant U.S. shale and Canadian crude oil production to provide a cost advantage to U.S. Gulf Coast refiners versus foreign and U.S. East and West Coast refiners Investing in projects to improve access and capability to process local, cost- advantaged crude oils Valero's hydrocracker projects take advantage of low-cost natural gas and high distillate demand and margins Improving performance of refining portfolio Key growth projects and falling capital expenditures should contribute significant free cash flow in 2013 Expect to return more cash to shareholders Goal to have one of the highest cash yields among peers (buybacks and dividends) Retail spin, basically dividend to shareholders 27

Appendix 28

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 29 Expect margins to improve Low margins should rationalize less competitive capacity High crude oil prices support ethanol prices International demand supporting margins 2013 corn ethanol mandate grows 4.7% over 2012 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 Retail Segment Performance 30 Retail achieved record EBITDA in 2011 and second highest year in 2012 Going forward, CST Brands, Inc. will incur incremental costs not reflected in the numbers above, such as corporate G&A, cost adjustments, etc. (see draft registration statement for CST Brands for additional information) (CHART) Valero Retail Segment EBITDA (CHART) Number of Valero Retail Segment Sites Note: includes all Canadian motorist and cardlock sites reported in Canadian results Note: EBITDA = Pretax operating income + depreciation and amortization + special items, excludes interest expense; see reconciliation in appendix

159 83 63 37 2 625 29 30 4 Geographically Diverse Operations 31 U.S. U.S. Canada Canada Total Total Owned 833 81% 284 33% 1,117 60% Leased land, and/or improvements 199 19% 484 57% 683 36% Cardlock 0 0% 80 10% 80 4% Total 1,032 100% 848 100% 1,880 100% As of December 31, 2012 Corner Store Headquarters - San Antonio, Texas 122 542 184

Attractive Acquisition Prices for Meraux and Pembroke 32 (CHART) @ $48.50 per share

Refinery Project Estimated Total Investment (millions) Estimated 2013 Spend (millions) Estimated Completion Date Estimated Key Economic Benefit Key Drivers/Additional Comments McKee 25 MBPD Crude Unit Project $130 $50 2Q14 $9 mm per year of EBITDA for every $1/bbl of Brent - WTI Brent - WTI differential; permitting in progress Quebec Crude Logistics $110-$200 $25 Early 2015 $2-$5/bbl improvement in feedstock cost Enables substitution of cheaper North American crude oil versus more expensive imports Houston/ Corpus Christi Crude Topping Facilities $220-$280 per site $60 Early 2015 Enables substitution of cheaper North American crude oil versus more expensive imports Port Arthur 15 MBPD HCU Expansion $160 $5 2015 Similar margins to base HCU project Natural gas to diesel spread, volume expansion with high crude price St. Charles 15 MBPD HCU Expansion $160 $5 2015 Similar margins to base HCU project Natural gas to diesel spread, volume expansion with high crude price Port Arthur/St. Charles HCUs and Crude Projects $295 $270 2013 for HCUs 2014 for crude projects Spending to complete HCUs and associated projects Natural gas to diesel spread, volume expansion with high crude price Meraux 20 MBPD HCU Expansion $160 $65 2014 $75 - $100 mm per year EBITDA Natural gas to diesel spread, volume expansion with high crude price 2013 Strategic/Economic Growth Spending Details 33 Note: EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense

Refinery Project Category Estimated Total Investment (millions) Estimated 2013 Spend (millions) Key Driver/Additional Comments Various locations Logistics Improvements $590 $160 Additional logistics facilities focused on lowering feedstock costs, increasing product marketing flexibility. Projects include dock facilities, rail unloading, pipeline, and terminal projects Various locations Rail Car Purchase $750 $250 Purchase 5,320 rail cars to expand fleet of rail cars to approximately 12,320 cars. Increases feedstock flexibility and access to discounted inland crudes Various Locations Alternative Fuels Delivery $35 $30 Add additional facilities for ethanol and biodiesel blending facilities Various Locations Refinery Optimization $725 $175 Many smaller projects to improve the efficiency and profitability of our refineries. Examples: new reactor for previous Port Arthur hydrocracker to extend runtime, energy efficiency projects, and advanced process controls Various Locations Alternative Energy $165 $70 Completion of Diamond Green Diesel, Quick hit ethanol investments which reduce feedstock cost, increase product yield and netback Retail Strategic Capital N/A $145 New stores, remodels, and various other strategic spending 2013 Strategic/Economic Growth Spending Details 34 Estimated total investment can take up to 5 years depending on the project category

Port Arthur Hydrocracker Project Investment Highlights Favorable economics driven by margin and volume gains Main unit is 57,000 barrels/day hydrocracker (rolling 12-month average per permit) 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 Also adding facilities to process over 150,000 barrels/day of high-acid, heavy sour crudes (e.g. Canadian and Latin American). This benefit is delayed until late-2014. 35 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 Complete Complete Complete Complete Estimated total investment (mil.) $1,620 $1,620 Cumulative spend thru 4Q 2012 (mil.) $1,550 $1,550 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 36 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 2Q13 2Q13 2Q13 2Q13 Estimated total investment (mil.) $1,650 $1,650 Cumulative spend thru 4Q 2012 (mil.) $1,400 $1,400 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 110,000 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 Economic benefit builds to base case from 2013 to 2016 37 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Summary of Project Status and Economics1 Estimated completion date Complete Complete Estimated total investment (mil.) $370 $370 Cumulative spend thru 4Q 2012 (mil.) $370 $370 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 Base case economics assume $1.25/gal RIN value, when current market is $0.65/gal to $0.90/gal 38 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 2Q13 2Q13 2Q13 2Q13 Estimated Partner Equity (mil.) $106 $106 Cumulative Valero project spend thru 4Q 2012 (mil.) $314 $314 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 39 Commodity Base Case ($/barrel) 2008 ($/barrel) 2009 ($/barrel) 2010 ($/barrel) 2011 ($/barrel) 2012 ($/barrel) LLS Crude oil1 85.00 102.07 62.75 81.64 111.09 112.20 LLS - USGC HS Gas Oil -3.45 2.03 -2.86 -2.72 -5.75 -7.59 USGC Gas Crack 6.00 2.47 6.91 5.32 5.11 4.66 USGC ULSD Crack 11.00 20.5 7.26 8.94 13.24 15.99 Natural Gas, $/MMBTU (NYMEX) 5.00 8.90 4.16 4.38 4.03 2.71 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 40 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 41 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)

Valero's Hydrocracker Projects Show Profits Under Various Price Sets Under Various Price Sets Under Various Price Sets 42 Note: EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense; see details in appendix; millions

60,000 BPD Hydrocracker Model Estimates Under Various Price Sets 43 Key Drivers and Prices 2008 Prices 2008 Prices 2009 Prices 2009 Prices 2010 Prices 2010 Prices 2011 Prices 2011 Prices 2012 Prices 2012 Prices LLS /bbl $102.07 $62.75 $81.64 $111.09 $112.20 LLS - HSVGO /bbl $2.03 -$2.86 -$2.72 -$5.75 -$7.59 GC Gasoline - LLS /bbl $2.47 $6.91 $5.32 $5.11 $4.66 GC Diesel - LLS /bbl $20.50 $7.26 $8.94 $13.24 $15.99 Natural Gas (NYMEX) /mmBtu $8.90 $4.16 $4.38 $4.03 $2.71 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 $3.14 GC LPGs - LLS /bbl -$40.02 -$20.11 -$23.97 -$38.30 -$49.70 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 $146.33 $8.8 Less: Feedstock cost -$109.07 -$6.5 -$69.83 -$4.2 -$88.80 -$5.3 -$120.93 -$7.3 -$122.54 -$7.4 = Gross Margin $27.80 $1.7 $12.88 $0.8 $17.05 $1.0 $22.79 $1.4 $23.79 $1.4 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 $23.24 $1.4 Estimated Annual EBITDA ($MM/year) $613 $261 $341 $487 $509 Note: 2012 YTD prices as December 31, 2012

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% to 25% over the past few years U.S. Shifted to Net Exporter 44 (CHART) 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; Source: EIA, Consultant and Valero estimates Implied Production of U.S. Refined Products for Domestic Use

U.S. Refining Capacity Is Globally Competitive 45 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 Industry capacity expansions will continue to put pressure on marginal refineries in less- competitive regions, including recent restarts of previously closed capacity Source: EIA and IEA, data as of December 2012 (CHART) Refinery Utilization by PADD, Trailing 12-months These regions have less- competitive capacity "Mid-con" "Gulf Coast" "West Coast" "Rockies" "East Coast"

(CHART) Expect U.S. and Canadian Crude Supply to Provide Feedstock Cost Advantage 46 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 in 2013 Expect cost of Gulf Coast light crudes will go from structural ~$2/bbl premium to structural discount under Brent Expect Brent priced light sweet crudes to set global prices for waterborne crude and feedstocks LLS may not be a good marker for Gulf Coast light crudes with abundant supply into Texas Note: Import volumes include light and medium crudes between 28 and 50 API with less than 0.7% sulfur

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 and oil production results so far have been weak 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 47

Growth of Crude Logistics to U.S. Gulf Coast 48 Throughput Capacities, '000 bpd 2010 2011 2012 2013E 2014E 2015E Cushing Seaway 150 400 850 850 Keystone 550 830 830 Rail - 60 230 271 271 411 Total - 60 380 1,221 1,951 2,091 Permian Longhorn 225 225 225 BridgeTex 300 300 SXL Permian Express 150 350 350 SXL WTG 80 80 80 Rail - 12 159 189 254 319 Total - 12 159 644 1,209 1,274 Eagleford Harvest 150 150 150 150 Enterprise 350 350 350 350 KinderMorgan 300 300 300 300 Plains 185 185 185 185 NuStar 130 200 200 200 200 Rail - 40 63 63 63 63 Total - 170 1,248 1,248 1,248 1,248 Bakken/Patoka ETP/Enbridge Trunkline 660 Inergy Rail Expansion 80 80 80 Savage Rail 60 60 60 60 Global Partners Rail 140 140 140 North Dakota Govt. Rail Survey 115 275 730 880 880 880 Total 115 275 790 1,160 1,160 1,820 Source: Consultants, company announcements and Valero estimates

*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 shut completely when processing deal with Shell ended in December 2012 2Alon announced the closure of these refineries for economic reasons, may restart Global Refining Capacity Rationalization 49 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 Funshun, China PetroChina 70 2011 Location Owner CDU Capacity Closed (MBPD) Year Closed Keihin Ohgimachi, Japan Showa Shell 120 2011 Clyde, Australia Shell 75 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 160 2012 St. Croix, U.S.V.I Hovensa 350 2012 Aruba Valero 235 2012 Rome, Italy TotalErg 82 2012 Fawley, U.K.* ExxonMobil 80 2012 Trecate, Italy* ExxonMobil 70 2012 Paramo, Czech Republic Unipetrol 20 2012 Lisichansk, Ukraine TNK-BP 175 2012 Bakersfield/Paramount, CA Alon 90 2012 Ewa Beach, Hawaii Tesoro 94 2013 Port Reading, NJ Hess N/A 2013 Venice, Italy ENI 80 2013 Sakaide, Japan Cosmo Oil 140 2013 Japan Indemitsu Kosan 100 2014 Japan Nippon 200 2014 Kurnell, Australia Caltex 135 2014

Global Refining Capacity For Sale or Under Strategic Review 50 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 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 Falconara, Italy API 80 Sources: Industry and Consultant reports and Valero estimates

Gulf Coast Light Crude Discount to Brent Improves Gulf Coast Competitiveness 51 (CHART) Source: Argus, 2013 data through 3-1-13 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 In 2012, LLS flipped from a historical premium to a discount to Brent (but we expect continued 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 (or U.S. Gulf Coast light crude) 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 52 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 700,000 mmBtus/day of natural gas at full utilization, split roughly in half between operating expense and gross margin (CHART) Source: Argus, 2013 = YTD through March 1, 2013; natural gas price converted to barrels using factor of 6.05x Brent $114/bbl ($18.88/ mmBtu) U.S. NG $20/bbl ($3.34/ mmBtu) Asian LNG $98/bbl ($16.25/ mmBtu) Euro. NG $63/bbl ($10.48/ mmBtu) /bbl

(CHART) Gasoline Fundamentals 53 (CHART) USGC LLS Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) (CHART) Source: Argus; 2013 data through March 1 Source: DOE weekly data; 2012 data through week ending February 22 Source: DOE weekly data; 2012 data through week ending February 22 U.S. Gasoline Days of Supply U.S. Net Imports of Gasoline and Blendstocks (mbpd) Source: DOE monthly data; 2012 data through December 2012

Distillate Fundamentals 54 54 (CHART) USGC LLS On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) (CHART) (CHART) Source: Argus; 2013 data through March 1 Source: DOE weekly data; 2012 data through week ending February 22 Source: DOE weekly data; 2012 data through week ending February 22 Source: DOE monthly data; 2012 data through December 2012 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd)

U.S. Transport Indicators 55 (CHART) (CHART) (CHART) (CHART) Latest data Week 8, 2013

U.S. Transport Indicators: Trucking Indicators 56 (CHART) (CHART) ATA data through Nov-12, TSI data through Dec-12 (CHART) (CHART)

(CHART) (CHART) Mexico Statistics Diesel Gross Imports (MBPD) Source: PEMEX, latest data January 2013 Gasoline Gross Imports (MBPD) Source: PEMEX, latest data January 2013 (CHART) Crude Unit Throughput (MBPD) Crude Unit Utilization (CHART) 57 Source: Mexico Secretary of Energy, latest data January 2013 Source: Mexico Secretary of Energy, latest data January 2013

Venezuelan Exports to the U.S. 58 (CHART) Source: EIA, December 2012

(CHART) Competitively Exporting into Growing Markets Source: DOE Petroleum Supply Monthly with data as of December 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 the largest source of exported products. Latin America continues to be the largest U.S. export market, followed by Western Europe. (CHART) U. S. Product Exports By Destination U. S. Product Exports By Source MMBPD 12 Month Moving Average 59

(CHART) 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 December 2012 MBPD Diesel net exports continue to rise significantly, with U.S. refiners sending a net of 883 MBPD to other countries in 2012. Gasoline net imports have fallen from almost 1 MMBPD in 2006 to only 168 MBPD in 2012. 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 1,623 MBPD in 2012. 60

(CHART) U.S. Gasoline Exports by Destination Gasoline exports remain at elevated levels due to the strong 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 December 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report and VLO estimates MBPD 61 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 December 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 Although the shutdown of U.S. East coast refineries will require more gasoline to balance 62 (CHART) 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 December 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 63 (CHART) MBPD 12 Month Moving Average

U.S. Diesel Imports by Source Diesel imports fell sharply in 2012 due to less volume from Latin America Source: DOE Petroleum Supply Monthly with data as of December 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report 64 (CHART) MBPD 12 Month Moving Average

Ethanol and Retail Reconciliation of Operating Income to EBITDA 65 Retail (millions) 2005 2006 2007 2008 2009 2010 2011 2012 U.S. Operating Income $81 $113 $154 $260 $170 $200 $213 $240 + U.S. depreciation and amortization expense $60 $60 $59 $70 $70 $73 $77 $77 Non-cash Asset Impairment - - - - - - - $12 = U.S. EBITDA $141 $173 $214 $330 $240 $273 $290 $329 Canada Operating Income $73 $69 $95 $109 $123 $146 $168 $108 + Canada depreciation and amortization expense $23 $27 $31 $35 $31 $35 $38 $42 Non-cash Asset Impairment - - - - - - - $9 = Canada EBITDA $96 $96 $126 $144 $154 $181 $206 $159

(CHART) Most Crude Oil Discounts Improving 66 $/barrel Source: Argus; 2013 year-to-date through March 1; LLS prices are roll adjusted

Regional Refinery Indicator Margins 67 Source: Argus; 2013 year-to-date through March 1; 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% + 10% (ANS - West Coast High Sulfur Vacuum Gasoil cargo prompt) 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 68

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 69