EX-99.01 2 d95714dex9901.htm EX-99.01

Investor Presentation September 2015 Exhibit 99.01

2 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.

3 Who We Are World’s Largest Independent Refiner • 15 refineries, 2.9 million barrels per day (BPD) of high- complexity throughput capacity • Greater than 70% of refining capacity located in U.S. Gulf Coast and Mid- Continent • Approximately 10,000 employees Operator of Liquids-Focused Logistics Assets • General partner and majority owner of Valero Energy Partners LP (NYSE: VLP), a fee-based master limited partnership (MLP) • Significant inventory of logistics assets within Valero Wholesale Fuels Marketer • Approximately 7,400 marketing sites in U.S., Canada, United Kingdom and Ireland • Brands include Valero, Ultramar, Texaco, Shamrock, Diamond Shamrock and Beacon One of North America’s Largest Renewable Fuels Producers • 11 corn ethanol plants, 1.3 billion gallons per year (85,000 BPD) production capacity • Operator and 50% owner of Diamond Green Diesel joint venture – 10,800 BPD renewable diesel production capacity

4 Strong Gulf Coast and Mid-Continent Presence Refineries and ethanol plants are in advantaged locations

5 Current Macro Environment Abundant supply of crude oil and natural gas 1 Expected petroleum demand increase, with highest growth in China, India and Middle East countries 5 Forecasted world GDP growth 3 Structural product shortage in Latin America, Europe, Africa and Eastern Canada 6 Demand response to lower product prices 4 COST STRUCTURE SUPPLY DEMAND North American logistics infrastructure additions 2 See appendix for footnotes

6 Production Growth Provides Resource Advantage to North American Refiners 58 74 U.S. Natural Gas Production (Bcf/day) Source: DOE, 2015 data through May 9,212 7,257 5,475 9,527 U.S. Crude Oil Production and Imports (MBPD) Imports Production

7 Safety and Reliability are Imperative for Profitability Mechanical Availability Personnel Index Maintenance Index Non-Energy Cash Opex Energy Intensity Index VLO’s Performance Versus Industry Benchmarks 2008 2010 2012 2014 4 th Quartile 1 st Quartile 3 rd Quartile 2 nd Quartile See appendix for footnotes Operate Safely and Reliably

8 Leader in Refinery Complexity and Clean Product Yields 12.4 12.3 11.5 11.1 10.9 VLO HFC TSO MPC PSX Nelson Complexity Index 91% 86% 84% 83% 78% HFC VLO PSX TSO MPC 1H15 Clean Product Yields (As Percentage of Total Products) See appendix for footnotes Expand Commercial and Operational Flexibility

9 Leader in Location-Advantaged CDU Capacity and Our Gulf Coast Assets Have Flexible Feed Slates 26% 17% 12% 12% 4% 37% 34% 30% 23% 10% Feedstock Ranges in Gulf Coast (2010 – 2015) See appendix for footnotes 1,948 1,731 1,230 443 129 VLO MPC PSX HFC TSO Location-Advantaged CDU Capacity (MBPD) Eastern Canada U.S. Gulf Coast U.S. Mid-Continent Expand Commercial and Operational Flexibility

10 Our System Enables Optimization of Product Exports and Netbacks 69 86 255 308 164 221 412 472 2011 2012 2013 2014 1H15 Current Capacity Potential Future Capacity VLO’s U.S. Product Exports (MBPD) Diesel Gasoline Expand Commercial and Operational Flexibility Actual export volumes for 2011 – 1H15. See appendix for additional footnotes.

11 Location Advantage, Feedstock Flexibility and Low Opex Deliver Strong Operating Income $5.50 $6.20 $7.20 $7.90 $8.90 VLO MPC HFC PSX TSO 1H15 Refining Operating Expenses Per Barrel Throughput (Includes Cash Costs and D&A) $10.40 $7.50 $7.20 $6.60 $5.00 HFC VLO MPC TSO PSX 1H15 Refining Operating Income Per Barrel of Product Yield Rounded figures presented. See appendix for additional footnotes. Expand Commercial and Operational Flexibility

12 Current Capital Allocation Framework Sustaining Capex • Estimate $1.5 billion or lower annual spend • Key to safe and reliable operations Dividend Growth • Should be sustainable • Compete for cash flow versus reinvestments Debt and Cash • Maintain investment grade credit rating and strong balance sheet • Target 20% to 30% debt- to-cap ratio (1) (1) Debt-to-cap ratio based on total debt reduced by $2 billion of cash. Growth Capex • Prioritize higher-value, higher-growth, quicker payback opportunities Stock Buybacks • Flexibility to return cash and manage capital employed Acquisitions • Evaluate versus alternative uses of cash Disciplined Capital Management to Unlock Value

13 Investing in Logistics and Higher Margin Businesses $765 $730 $695 $655 $790 $300 $400 $715 $2,650 $2,400 2015E 2016E Capital Expenditures (millions) Logistics Light Crude Processing, Natural Gas and NGLs Upgrading Turnarounds & Catalyst Sustaining (1) Excludes estimated placeholder for potential methanol project of $150 million in 2015 and $300 million in 2016, as evaluation remains in progress (1) Disciplined Capital Management to Unlock Value

14 Investing in Feedstock Flexibility Light Crude • 160 MBPD total new topping capacity at Corpus Christi and Houston refineries to process up to 50 API sweet crude • Replaces approximately 55 MBPD of purchased low sulfur resid for FCCs with indigenous production • Net throughput capacity increase of approximately 105 MBPD expected • Expect startup in 1H16 and annual EBITDA contribution of approximately $500 MM See appendix for project details Disciplined Capital Management to Unlock Value

15 Investing to Increase High Value Product Yields Distillate • Meraux’s hydrocracker expansion (1) in 4Q14 increased distillate yields by approximately 19 MBPD • 30 MBPD total hydrocracker capacity addition at Port Arthur (4Q15) and St. Charles (1Q16) expected to increase distillate yields by approximately 23 MBPD Alkylate • New 13 MBPD alkylation unit at Houston refinery • Upgrades low-cost NGLs to premium-priced alkylate • In phase 3 of development with investment decision expected in 1Q16 and startup in 2018 if approved Methanol • 1.6 – 1.7 million TPY (36 – 38 MBPD) production capacity at St. Charles refinery • Leverages existing assets to reduce capital requirement compared to grassroots facility • In phase 3 of development with investment decision expected in 4Q15 and startup in 2018 if approved (1) See appendix for project details Disciplined Capital Management to Unlock Value

16 Delivering High Cash Returns to Stockholders is One of Our Priorities 75% total payout target for 2015 2015 YTD through September 2. Payout ratio as percent of 2015 net income. 169 360 462 554 409 409 349 281 928 1,296 992 1,807 25% 31% 51% 51% 61% YTD 75% Target 2011 2012 2013 2014 1H15 2015 YTD Buybacks ($MM) Dividends ($MM) Payout Ratio Disciplined Capital Management to Unlock Value

17 Our Sponsored MLP Valero Energy Partners (NYSE:VLP) Disciplined Capital Management to Unlock Value Logistics MLP • VLO owns entire 2% general partner interest, all incentive distribution rights and 69.6% LP interest • High-quality assets integrated with Valero’s refining system • Fee-based, liquids-focused revenue generation with no direct commodity price exposure

18 $95 $200 4Q14 Annualized 4Q15E Annualized Adjusted EBITDA Attributable to VLP (millions) Expect $1 Billion of Drop-Down Transactions to VLP in 2015 See appendix for reconciliation of estimated 2015 EBITDA to net income Sold Houston and St. Charles Terminals to VLP for $671 MM in March 2015 Disciplined Capital Management to Unlock Value

19 More Than $1 Billion of Estimated MLP Eligible EBITDA Inventory Racks, Terminals, and Storage (1) • Over 100 million barrels of active shell capacity for crude and products • 139 truck rack bays Rail • Three crude unloading facilities with estimated total capacity of 150 MBPD • 5,320 purchased railcars, expected to serve long-term needs in ethanol and asphalt Pipelines (1) • Over 1,200 miles of active pipelines • 440 mile Diamond Pipeline (2) from Cushing to Memphis refinery expected to be commissioned in 1H17 Marine (1) • 51 docks • Two Panamax class vessels (1) Includes assets that have other joint venture or minority interests. (2) VLO holds option until January 2016 to acquire 50 percent interest in Diamond Pipeline. Disciplined Capital Management to Unlock Value Fuels Distribution • Approximately 800 MBPD fuels distribution volume

20 Renewables Business Has Performed Well Ethanol • 11 plants with 1.3 billion gallons total annual production • Low capital investment with scale and location in corn belt • Operational best practices transferred from refining Disciplined Capital Management to Unlock Value Diamond Green Diesel • 50-50 joint venture with Darling Ingredients • Approximately 11 MBPD production capacity • Renewable diesel prices at a premium versus biodiesel due to higher quality

21 VLO 14.2% Median 10.4% 2016E Return on Average Market Capital Employed VLO 5.9x Median 8.1x 2016E Price to Earnings Ratio We Believe Valero is an Excellent Investment • Majority of capacity located in U.S. Gulf Coast and Mid-Continent with access to cost-advantaged crude, natural gas, NGLs and corn • Proven operations excellence • Excellent investment and operations in renewable fuels • Focus on expansion of valuation multiple – Disciplined capital investment to drive earnings growth – Unlocking value through growth in MLP-able assets and drop-downs to VLP – Capital allocation to stockholders We believe VLO is undervalued. We have a disciplined management team, a strong financial position and a favorable macro environment. See appendix for footnotes Peer range Peer range

22 Appendix Contents Topic Pages Footnotes 23 2015 Goals 24 Refining Operating Statistics 25 – 28 Capital Investment Details 29 – 34 Valero Energy Partners LP 35 Natural Gas Cost Sensitivity 36 Crude Oil Transportation 37 – 38 Global Fundamentals 39 – 43 Non-GAAP Reconciliations 44 IR Contacts 45

23 Footnotes Slide 5 Macro environment themes represent industry consult views, of which points 1, 2, 5, and 6 are supported by additional slides in the presentation. Slide 7 Contractor recordable incident rate from U.S. Bureau of Labor Statistics. Tier 1 process safety event defined within API Recommended Practice 754. Industry benchmarking and VLO performance statistics from Solomon Associates and Valero. Slide 8 Nelson Complexity Index for HFC, TSO, and MPC from company presentations. PSX’s Nelson Complexity calculated per Oil and Gas Journal NCI formula based on crude capacities in company 10-K report and process unit capacities in Oil and Gas Journal as of January 1, 2015. Total company NCI is weighted average for refineries. Product yields from company 10-Q reports and presentations for six months ended June 30, 2015. Clean products defined as gasoline, jet fuel/kerosene, and distillates. Slide 9 Crude distillation capacities from company 10-K reports and presentations, grouped by geographic location. Valero’s Gulf Coast feedstock ranges are based upon quarterly processing rates between 1Q10 and 2Q15. Slide 10 Valero’s potential future gasoline and distillate export capacities are based upon potential expansion opportunities at the St. Charles and Port Arthur refineries. Slide 11 Refining operating expenses include cash costs and depreciation and amortization from company 10-Q reports for six months ended June 30, 2015. PSX’s refining operating expense per barrel of throughput from analyst reports. Refining operating income and total product yields from company 10-Q reports for six months ended June 30, 2015. PSX’s refining operating income approximated as segment net income from company 10-Q with a 50% allocation of interest and debt expense and an assumed income tax of 35%. Slide 21 Source for price to earnings ratios and returns on average market capital employed (ROMC) is Barclays. 2016 estimated ROMC defined as (tax effected operating and other income) / (average of 2016 and 2015 market capital employed), where market capital employed is calculated as (year-end share price * shares outstanding) + total debt. Prices as of August 28, 2015 market close.

24 Key Goals Expected in 2015 Operations Excellence Start up Montreal crude terminal with the Enbridge Line 9B reversal and lower Quebec City refinery’s crude costs versus Brent compared to 2014 Grow product export market share and increase branded wholesale fuels volume Capital Returns to Stockholders Increase total payout ratio of earnings over 2014’s 50% payout level Disciplined Capital Investments Complete construction of Houston and Corpus Christi crude topping units Make final investment decisions on methanol plant at St. Charles refinery and alkylation unit at Houston refinery Complete 25 MBPD McKee refinery CDU capacity expansion Complete 30 MBPD total hydrocracker capacity expansions at Port Arthur and St. Charles refineries Gain permit approval to construct Benicia crude rail unloading facility Unlocking Asset Value Increase the identified MLP-able EBITDA available for drop-downs to VLP Execute $1 billion of drop-down transactions to VLP

25 Our Refining Capacity and Nelson Complexity Refinery Capacities (MBPD) Nelson Complexity Index Throughput Crude Corpus Christi (1) 325 205 19.9 Houston 175 90 15.4 Meraux 135 125 9.7 Port Arthur 375 335 12.4 St. Charles 290 215 16.0 Texas City 260 225 11.1 Three Rivers 100 89 13.2 Gulf Coast 1,660 1,284 14.0 Ardmore 90 86 12.1 McKee 180 168 9.5 Memphis 195 180 7.9 Mid-Con 465 434 9.3 Pembroke 270 210 10.1 Quebec City 235 230 7.7 North Atlantic 505 440 8.9 Benicia 170 145 16.1 Wilmington 135 85 15.9 West Coast 305 230 16.0 Total or Average 2,935 2,388 12.4 (1) Represents the combined capacities of two refineries—Corpus Christi East and Corpus Christi West.

26 Reliability Initiatives Have Improved Refinery Availability and Enabled Higher Utilization

27 Valero Is Currently Utilizing 84 Percent of Its Available Light Crude Capacity in North America McKee Refinery Crude Unit Expansion • 25 MBPD additional capacity expected in 2H15 • Distillate recovery improvements Houston Refinery Crude Topping Unit • 90 MBPD capacity expected 1H16 • Displaces 30 MBPD intermediate feedstock purchases Corpus Christi Refinery Crude Topping Unit • 70 MBPD capacity expected 1H16 • Displaces 25 MBPD intermediate feedstock purchases Actual light crude consumption less than capacity due to turnaround maintenance and economics. Includes imported foreign sweet crudes. 1,030 1,220 1,410 2Q15 Actual Utilization Current Capacity Estimate Future Capacity (with Projects) MBPD

28 0% 50% 100% 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 Quebec City Refinery Crude Slate Foreign Imports North American Expect Quebec City Refinery to Have Access to 100% North American Crude in 2015 Processing advantaged crudes delivered by rail and foreign flagged ships from U.S. Gulf Coast, with additional transportation cost savings expected after reversal of Enbridge Line 9B in 4Q15

29 Meraux Hydrocracker Conversion Completed December 2014 Investment Highlights • Converted hydrotreater into high-pressure hydrocracker and repurposed old FCC gas plant for additional LPG recovery • Expect to upgrade 23 MBPD gasoil and low-cost hydrogen (via natural gas) mainly into high quality diesel • Expect to increase refinery distillate yield versus gasoline (Gas/Diesel ratio drops from 0.72 to 0.59) • Expect to increase refinery liquid volume yield by 1.8% • Avoided compliance capex on FCC Status • Project started up in Dec 2014 and is operating well Incremental Volume (MBPD) Feeds Purchased hydrogen (MMSCFD) 13 Products (MBPD) Gasoline 5 Jet - Diesel 19 HSVGO 2 Unconverted gasoil (23) Fuel oil - Project Estimates Total investment $260 MM Annual EBITDA contribution (1) $90 MM Unlevered IRR on total spend (1) 25% (1) Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense

30 McKee Refinery Diesel Recovery Improvement and CDU Expansion Startup Expected in 2H15 Investment Highlights • Adding 25 MBPD crude unit capacity and parallel light ends processing train • Expect to improve yields and volume gain by recovering diesel from FCC and HCU feeds • Expect to increase diesel and gasoline production on price-advantaged crude • Expect to reduce energy consumption via heat integration Status • Diesel recovery and benefits started in mid-2014; expect crude expansion start- up in 2H15 Incremental Volume (MBPD) Feeds WTI 25 Products (MBPD) LPG 0.4 Benzene concentrate 0.3 Gasoline 12 Jet - Diesel 12 Resid 0.6 Project Estimates Total investment $140 MM Annual EBITDA contribution (1) $100 MM Unlevered IRR on total spend (1) 45% (1) Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense

31 Light Crude Processing Investments • 160 MBPD new topping capacity designed to process up to 50 API domestic sweet crude – Estimated 55 MBPD low sulfur resid yield should lower feedstock costs – Net throughput capacity increase of approximately 105 MBPD, with startup expected in 1H16 • Expect 50% IRR on 2014 prices, >25% IRR with Brent and LLS even • Corpus Christi Refinery: Estimated $350 MM capex for 70 MBPD capacity • Houston Refinery: Estimated $400 MM capex for 90 MBPD capacity Estimate $500 million annual EBITDA for combined projects in 2014 price environment Incremental Volume (MBPD) Feeds Eagle Ford crude 160 Low sulfur atmos resid (55) Products LPG 3.3 Propylene 1.3 BTX 0.4 Naphtha (at export prices) 40 Gasoline 12 Jet 39 Diesel 13 Resid (3) Combined Project Estimates Total investment (1) $750 MM Annual EBITDA contribution (2) $500 MM Unlevered IRR on total spend (2) 50% (1) Excluding interest and overhead allocation (2) Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense

32 Houston and Corpus Christi Crude Topping Project Economics Corpus Christi Refinery Houston Refinery (1) Estimates based on 2014 full year average prices; EBITDA = operating income before deduction for depreciation and amortization expense Project Estimates Total investment $400 MM Annual EBITDA contribution (1) $240 MM Unlevered IRR on total spend (1) 45% Project Estimates Total investment $350 MM Annual EBITDA contribution (1) $260 MM Unlevered IRR on total spend (1) 55% Estimates Incremental Volume (MBPD) Feeds Eagle Ford crude 90 Low sulfur atmos resid (29) Distillate (2) Butane (2) Hydrogen (MMSCFD) 3 Products LPG 0.8 Propylene 0.4 Naphtha 24 Gasoline 5 Jet 23 Diesel 4 Slurry 0.2 LPG 0.8 Estimates Incremental Volume (MBPD) Feeds Eagle Ford crude 70 Low sulfur atmos resid (24) Products LPG 2.5 Propylene 0.9 BTX 0.4 Naphtha 16 Gasoline 7 Jet 16 Diesel 9 Resid (3)

33 Project Price Set Assumptions Driver ($/bbl) 2014 Average ICE Brent 99.49 ICE Brent – WTI 6.35 ICE Brent – LLS 2.75 USGC CBOB – ICE Brent 3.52 G3 CBOB – WTI 12.27 USGC ULSD – ICE Brent 14.25 G3 ULSD – WTI 23.88 Natural gas (Houston Ship Channel, $/mmBtu) 4.34 Naphtha – ICE Brent -0.67 LSVGO – ICE Brent 8.86

34 Estimated Key Price Sensitivities on Project Economics Change in Estimated EBITDA (1) Relative to 2014 (2) Prices ($millions/year) McKee Diesel Recovery & CDU Expansion Meraux HCU Expansion Corpus Christi Topper Houston Topper ICE Brent, +$1/bbl none $0.8 $0.4 none ICE Brent – WTI, +$1/bbl $5.5 none None none ICE Brent – LLS, +$1/bbl N/A none $25.6 $32.9 Group 3 CBOB – ICE Brent, +$1/bbl $2.0 N/A N/A N/A Group 3 ULSD – ICE Brent, +$1/bbl $5.5 N/A N/A N/A USGC CBOB – ICE Brent, +$1/bbl N/A $1.7 $2.4 $2.4 USGC ULSD – ICE Brent, +$1/bbl N/A $6.8 $9.0 $9.9 Natural gas (Houston Ship Channel), +$1/mmBtu -$0.7 -$1.9 -$4.3 -$3.2 Naphtha – ICE Brent, +$1/bbl N/A none $5.8 $8.8 LSVGO – ICE Brent, + $1/bbl N/A -$7.3 $3.1 $5.2 Total investment IRR, +10% cost -6% N/A -5% -4% (1) Operating income before deduction for depreciation and amortization expense (2) 2014 full year average Margin drivers shown are not inclusive of all feedstocks and products in economic models. Estimated economic sensitivities can not be accurately interpolated or extrapolated solely from the estimated key price sensitivities shown above.

35 Valero’s GP Interest in VLP Nearing the “High Splits” Target Quarterly Distribution per Unit Marginal Percentage Interest in Distributions Unitholders GP Minimum quarterly $0.2125 98% 2% First target above $0.2125 up to $0.244375 98% 2% Second target above $0.244375 up to $0.265625 85% 15% Third target above $0.265625 up to $0.31875 75% 25% Thereafter above $0.31875 50% 50% • 2Q15 distribution at $0.2925 per unit • Valero’s GP interest in VLP expected to reach 50% split in 4Q15, payable in 2016, based on accelerated drop-down strategy

36 $3/mmBtu U.S. $0.90/bbl $7/mmBtu Europe $2.20/bbl $11/mmBtu Asian LNG $3.65/bbl Natural Gas Cost Sensitivity for Valero’s Refineries U.S. Natural Gas Provides Opex and Feedstock Cost Advantages Estimated per barrel cost of 864,000 mmBtu/day of natural gas consumption at 92% refinery throughput capacity utilization, or 2.7 MMBPD. $1.3 billion higher pre-tax annual costs $1.5 billion higher pre-tax annual costs • Our refining operations consume approximately 864,000 mmBtu/day of natural gas, split almost equally between operating expense and cost of goods sold • Significant annual pre-tax cost savings compared to refiners in Europe or Asia • Prices expected to remain low and disconnected from global oil and gas markets

37 Estimated Crude Oil Transportation Costs to Houston Pipe $2 to $4/bbl USGC to USEC U.S. Ship $3 to $5/bbl USGC to Canada Foreign Ship $2/bbl U.S. Ship $4 to $5/bbl Brent to USEC $2/bbl to USEC Rail $11 to $13/bbl to St. James Rail $11/bbl Cushing Midland to Houston Pipe $3/bbl CC to Houston $1 to $2/bbl Houston to St. James $1 to $2 /bbl to West Coast Rail $13 to $15/bbl Alberta to Bakken $1 to $2/bbl Rail $9/bbl Alberta to Eastern Canada Rail $11 to $12/bbl Bakken to Cushing Rail $9/bbl to Cushing Pipe $5 to $6/bbl

38 KEY New Crude Oil Pipeline Capacities Niobrara Eagle Ford Cushing Bakken Recently Completed 2015 Startup > 2015 Est. Startup Capacities in MBPD. Permian Alberta

39 Net 0.8 Net 1.5 Net 1.4 -2.5 -1.5 -0.5 0.5 1.5 2.5 3.5 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E 2016E MMBPD World Petroleum Demand Growth U.S. OECD (excl. U.S.) Non-OECD Global Petroleum Demand Projected to Grow Source: Consultant (EIA and IEA) and Valero estimates. Consultant annual estimates generally updated 6 to 12 months after year end. Emerging markets in Latin America, Middle East, Africa, and Asia lead demand growth

40 0.85 0.70 0.98 0.91 0.96 -0.4 0.0 0.4 0.8 1.2 2015 2016 2017 2018 2019 MMBPD Estimated Net Global Refinery Crude Distillation Changes Europe China Middle East Other (incl. U.S. and Latin America) Total World Refinery Capacity Growth • New capacity additions expected in Asia and the Middle East • Announced new capacity in Latin America likely to be smaller and start later than planned • Capacity rationalization expected to continue in Europe Source: Consultant and Valero estimates; Net Global Refinery Additions = New Capacity + Restarts – Announced Closures

41 0 100 200 300 400 500 600 700 800 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Other Europe Other Latin America Mexico Canada Latest 4 Wk avg estimate (Finished only) 12 Month Moving Average (MBPD) Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) Source: DOE Petroleum Supply Monthly data through May 2015. 4 Week Average estimate from Weekly Petroleum Statistics Report and Valero estimates. U.S. Gasoline Exports

42 Source: DOE Petroleum Supply Monthly with data through May 2015. 4 Week Average estimate from Weekly Petroleum Statistics Report U.S. Diesel Exports 0 200 400 600 800 1000 1200 1400 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Other Europe Other Latin America Mexico Canada Latest 4 Wk avg estimate 12 Month Moving Average (MBPD)

43 -3,000 -2,500 -2,000 -1,500 -1,000 -500 0 500 1,000 1,500 2,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Other Diesel Gasoline Total MBPD Net Exports of Products from the U.S. Source: DOE Petroleum Supply Monthly data through May 2015. Gasoline represents all finished gasoline plus all blendstocks (including ethanol, MTBE, and other oxygenates) • Net refined products exports increased from 335 MBPD in 2010 to 3 MMBPD in 2015 • Diesel net exports averaged 919 MBPD in 2014; 817 MBPD in 2015 (Jan-May) • Gasoline net exports averaged 66 MBPD in 2014; 67 MBPD in 2015 (Jan – May)

44 Non-GAAP Reconciliations Forecasted (thousands) Full Year Beginning March 1, 2015 Valero Partners Houston and Louisiana Net income $37,300 + Interest expenses 18,100 + Income tax expense 400 + Depreciation expense $20,000 = EBITDA $75,800 Reconciliation of VLP Forecasted Net Income to EBITDA Three Months Ended December 31, 2014 Three Months Ended December 31, 2015 (millions) As Reported Annualized (x4) Forecasted Annualized (x4) Net income $19 $76 $32 $128 Plus: Depreciation expense 5 18 11 44 Interest expense (1) - 1 7 28 Income tax expense - - - - EBITDA $24 $95 $50 $200 Reconciliation of VLP Net Income Under GAAP to EBITDA (1) Interest expense and cash interest paid both include commitment fees to be paid on VLP’s revolving credit facility. Interest expense also includes the amortization of estimated deferred issuance costs to be incurred in connection with establishing VLP’s revolving credit facility.

45 Investor Relations Contacts For more information, please contact: John Locke Vice President, Investor Relations 210.345.3077 john.locke@valero.com Karen Ngo Manager, Investor Relations 210.345.4574 karen.ngo@valero.com