EX-99.01 2 d451265dex9901.htm SLIDES FROM MANAGEMENT PRESENTATION Slides from management presentation
Exhibit 99.1
Investor Presentation December 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 refiner16 refineries3 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 sitesNearly 1,300 company operated in U.S. and CanadaAnnounced intention to separate Retail segmentOne of the largest renewable fuels companies10 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 beltDiamond Green Diesel JV under construction (renewable diesel from waste cooking oil and animal fat)10,000 BPD capacity, 50% to ValeroApproximately 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 2012235,000 bpd capacity Nelson Index of 8
Valero in the Atlantic Basin 5 5
(CHART) Update on Potential Retail Separation Making progress on our plan to pursue a separation of our Corner Store retail business and unlock value for shareholdersSubmitted a request for a private letter ruling to the IRS in OctoberCorner Stores Holdings, Inc. filed a draft Form 10 registration statement with the SEC in NovemberIntent is to distribute to VLO shareholders 80% of Corner Store equity to trade on the NYSE under the ticker symbol "CST"Expect separation to complete late 1Q13 or early 2Q13 subject to timing of filing and regulatory agenciesInvestors 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 of Retailers versus Valero Energy
Valero's Retail Segment Network 7 U.S. U.S. Canada Canada Total Total Owned 828 81% 296 35% 1,124 60% Leased land, and/or improvements 199 19% 474 56% 673 36% Cardlock 0 0% 79 9% 79 4% Total 1,027 100% 849 100% 1,876 100% As of September 30, 2012
Valero's Retail Segment Performance 8 Retail achieved record operating income in 2011, and highest quarter on record in 2Q12. Margins started off well in 4Q12 (CHART) Valero Retail Segment EBITDA (CHART) 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 capacityU.S. competitively exporting into growing and undersupplied marketsExpect abundant and growing U.S. shale oil and Canadian production to provide feedstock cost advantageLow-cost U.S. natural gas provides competitive advantageIncreasing Valero's yield of distillates, which have higher margins and global growth 9
(CHART) Continued Global Demand Growth Important to Refining Margins 10 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 Significant new global refining additions seen in the next several yearsMainly new plants in Asia and the Middle East Some investment in Latin AmericaNew capacity announcements from Brazil, Mexico, and Columbia will likely be much smaller and much later than originally announced. Others very unlikely to happen because of costs: Ecuador, Peru, Algeria, EgyptAsian demand growth has been consuming Asian refining growth Net Global Refinery Additions 11 MMBPD Source: Consultant and Valero estimatesNet Global Refinery Additions = New Capacity + Restarts- Closures
(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 occurCombined 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 12 (CHART) Sources: Industry and Consultant reports and Valero estimates
(CHART) (CHART) Product Margins Responding to Atlantic Basin Closures 13 With recent closures, Atlantic Basin product margins have increased from prior year levelsMarket focused on gasoline margin improvements earlier in 2012, but more significant impact may be strong diesel support due to tightness in diesel balancesU.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, 4Q11 and 4Q12 quarter-to-date pricing is through 11-30-12 /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 demandLarge quantities of U.S. diesel and gasoline exports to Latin America and diesel exports to EuropeStrong international demand has been "pulling" products and paying higher values than in the U.SValero's share of U.S. exports has averaged 20% to 25% U.S. Shifted to Net Exporter 14 (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 NetExports 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 15 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 gasPADD 1 and Europe have lower utilization due to structural disadvantages of higher crude oil and operating costsPlanned capacity expansions in PADD 3 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 September 30, 2012 (CHART) Refinery Utilization by PADD, Trailing 12-months These regions have less- competitive capacity "Mid-con" "Gulf Coast" "West Coast" "Rockies" "East Coast"
Rapid Growth in U.S. Crude Supply 16 (CHART) Shale oil production growth and Mid-Continent heavy-up projects are rapidly increasing domestic light, sweet crude suppliesThis 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-ContinentNGLs 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 ImportsFirst 9-months 2012 - 509 MBPD
Rapid Growth in Logistics to U.S. Gulf Coast 17 (CHART) Logistics capacity to move inland crude from the Mid-Continent and Texas to the U.S. Gulf Coast is expanding quickly to debottleneck the inland marketsBakken logistics capacity is primarily unit-trains that can go to any site with unloading capacity, including both coastsExcess logistics capacity will be available, but crude oil and NGL supplies could be higher Source: 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 ImportsFirst 9-months 2012 - 509 MBPD U.S. Total Shale Crude Supply in 2016
(CHART) Expect U.S. and Canadian Crude Supply to Provide Feedstock Cost Advantage 18 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 2010Expect all Gulf Coast light/medium crude imports could be pushed out of PADD III in 2013Expect LLS 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 feedstocksAlso, expect growing volumes of Canadian heavy sours to eventually reach U.S. Gulf Coast Note: Import volumes include light and medium crudes between 28 and 50 API with less than 0.7% sulfur
LLS Discount to Brent Improves Gulf Coast Competitiveness 19 (CHART) Source: Argus, 2012 data through 11-30-12 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 discount to Brent will become a structural cost advantage, increasing margins versus other Atlantic Basin refiners that process higher priced Brent-type crude
Valero's Ability to Run Discounted Light Crude Valero has increased its exposure to domestic light crude processing as additional volumes have become availableGulf Coast system including Memphis has the ability to add an additional 125 MBPD of domestic crude throughput by year-endIn addition, evaluating potential projects to further increase our domestic light crude processing capacity 20 (CHART)
Lower-Cost Natural Gas Provides Structural Advantage to U.S. Refiners 21 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 futureVLO 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 Faster Growth Faster Growth World Product Demand Growth Source: Consultant, IEA, and Valero estimates 22 Distillate (diesel, kero, jet fuel) margins are significantly higher than gasolineDistillate demand growth rate is much higher than gasolineEurope continues to be short diesel, but long marginal refining capacity and processing expensive crude oils and natural gas (CHART) Source: Argus, 2012 YTD through November 30, 2012 /bbl /year
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 $1,521 $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 outlookEstimate Port Arthur HCU mechanical completion and operating at capacity in 4Q12 Estimate St. Charles HCU mechanical completion 1Q13 and operating at capacity in early 2Q13 23 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 Under Various Price Sets Under Various Price Sets 24 Note: EBITDA = Pretax operating income + depreciation and amortization, excludes interest expense; see details in appendix millions
Valero Increasing Distillate Yields 25 (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 2013Primary driver for increase is the completion of hydrocracker projectsRecent acquisitions have also increased distillate yields (CHART)
Better Better Our goal is to be a 1st-quartile refinerRefining industry benchmark studies show our portfolio continues to improveSeven refineries currently operating in 1st quartile for mechanical availability, the most important Solomon metricSaw results from improvement initiatives in 2011 and YTD 2012First full-year with 1st quartile portfolio performance in mechanical availabilityLowest-ever unplanned downtimeBest-ever energy efficiency for refining portfolioWorking diligently on weaker performers to improve entire portfolio Improving Refinery Operations 26 1st Quartile 2nd Quartile 1st Quartile 2nd Quartile 3rd Quartile 3rd Quartile Source: Solomon Associates and Valero Energy; excludes Aruba; 2012 YTD through October
Expect Large Decline in Capital Spending After Completion of Key Economic Growth Projects 27 "Stay-in-business" spending 2012 capital high due to spending on economic growth projects, mainly the hydrocrackersExpect a significant decline in capital spending after 2012 $1,610 $1,735 $1,645 $1,510 Total$2,470 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 2013Returning cash to shareholdersTripled quarterly dividend to $0.15 per share in 3Q11 and increased it again in 3Q12 to $0.175 per shareBought 9.4 million shares for $242 million so far in 2012 and 16.7 million shares for $347 million in 2011Goal is to have one of the highest cash yields among peers via dividends and buybacks$2.5 billion of cash and $5.7 billion of additional liquidity on September 30Maintaining investment grade credit rating is a priorityPaid off $778 million of long-term debt in 2011Paid off $858 million of high-interest debt in 2012, but reissued $300 million of tax-exempt bonds in May, net reduction of $558 million Net debt-to-cap ratio at 9/30/12 was 20.6%Far below credit facility covenant of 60%No other coverage-type ratios or borrowings on bank revolver 28 (CHART) Cash Returned to Shareholders (CHART) Source: EPS estimates from First Call as of 12-4-12
Valero's Strategic Priorities 29 Constant focus on safety, environmental, and regulatory complianceMaintain investment grade credit ratingContinue improvement in refining portfolio performance to 1st quartile levelsComplete major, value-added capital projectsOptimize portfolio - continue "high-grading" strategyEvaluate dispositions of poor performing assetsConverting Aruba refinery to storage and terminal operation with large reduction in operating expensesEvaluate attractively priced, strategic, and accretive acquisitionsContinue to upgrade product streamsContinue 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 separationWell-positioned to benefit from changing market trendsAtlantic Basin capacity closures have improved refining fundamentalsBenefiting from strong export marketExpect 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 refinersValero's hydrocracker projects take advantage of low-cost natural gas and high distillate demand and marginsImproving performance and competitiveness of refining portfolioKey growth projects and falling capital expenditures should contribute significant free cash flow in 2013Returning more cash to shareholdersGoal to have one of the highest cash yields among peers (buybacks and dividends) 30 Our shareholders should benefit from changing oil and natural gas supply and product export trends
Appendix 31
Made Excellent Ethanol Acquisitions Built position for average of only 35% of estimated replacement cost2Q09: Acquired 7 plants with 780 million gallons per year of world-scale capacity in advantaged locations1Q10: Added 3 plants with 330 million gallons per year of capacity 32 Expect margins to improveRecently narrow margins should rationalize less competitive capacityHigh crude oil prices support ethanol pricesInternational demand supporting margins 2013 corn ethanol mandate grows 4.7% over 2012Valero's low-cost acquisitions of high-quality plants imply a competitive advantage in any margin environmentProvides platform for future production of advanced biofuels
Attractive Acquisition Prices for Meraux and Pembroke 33 (CHART) @ $32 per share
Port Arthur Hydrocracker Project Investment HighlightsFavorable economics driven by margin and volume gainsMain 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 gasUnit has volume expansion up to 30%, but plan to optimize at 20%: 1 barrel of feedstocks yields up to 1.2 barrels of productsMain products are high-quality diesel and jet fuel for growing global demand for middle distillatesLocated at large, Gulf Coast refinery to leverage existing operations and export logisticsAlso 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. 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 4Q12 4Q12 4Q12 4Q12 Estimated total investment (mil.) (Reduced by $94 mil. from prior estimate) $1,521 $1,521 Cumulative spend thru 3Q 2012 (mil.) $1,406 $1,406 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 HighlightsFavorable economics driven by margin and volume gainsMain unit is 60,000 barrels/day hydrocrackerCreates high-value products from low- value feedstocks plus hydrogen sourced from relatively inexpensive natural gasUnit has volume expansion up to 30%, but plan to optimize at 20%: 1 barrel of feedstocks yields up to 1.2 barrels of productsMain products are high-quality diesel and jet fuel for growing global demand for middle distillatesLocated at large, Gulf Coast refinery to leverage existing operations 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 1Q13 Early 2Q13 1Q13 Early 2Q13 Estimated total investment (mil.) (Increased by $165 mil. from prior estimate) $1,525 $1,525 Cumulative spend thru 3Q 2012 (mil.) $1,215 $1,215 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 HighlightsFavorable economics driven by reducing transportation costs and growing volumesNew pipeline with 100,000 barrels/day of throughput capacityPlanned closure of Shell Montreal refinery allows Valero to place additional products into Montreal and Ontario marketsQuebec refinery is largest refinery in the region with 1st-quartile performance and has a cost advantageEconomic benefit builds to base case from 2013 to 2016 36 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 3Q 2012 (mil.) $337 $337 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 HighlightsBuilding a 9,300 BPD renewable diesel plant adjacent to Valero's St. Charles refinery50/50 JV project with Darling Int'l, a leading gatherer of used cooking oils and animal fatUses refinery technology to produce high- quality diesel from low-quality, low-cost cooking oils and fatsDiesel production qualifies as biomass- based diesel, a difficult specification under the Renewable Fuels StandardTotal estimated project cost of $368 millionValero to provide 14-year term loan for up to $221 million to JV at attractive ratesBase case economics assume $1.25/gal RIN value, when current market is $0.45/gal to $0.65/gal 37 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 1Q13 Early 2Q13 Late 1Q13 Early 2Q13 Estimated Partner Equity (mil.) $106 $106 Cumulative Valero project spend thru 3Q 2012 (mil.) $133 $133 Estimated Valero EBITDA (Operating Income before D&A2) (mil.), Base Case Estimated Valero EBITDA (Operating Income before D&A2) (mil.), Base Case $55 Estimated Unlevered IRR on Partner Equity and Loan, Base Case Estimated Unlevered IRR on Partner Equity and Loan, Base Case 21% 1See Appendix for key price assumptions; 2D&A = depreciation and amortization expense
Project Price Set Assumptions 38 Commodity Base Case ($/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 projectsPrice assumptions are based on a blend of recent market prices and Valero's price forecast 1LLS prices are roll adjusted
Project Price Sensitivities 39 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 projectsPrice 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 40 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 designDesigned 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 41 Key Drivers and Prices 2008 Prices 2008 Prices 2009 Prices 2009 Prices 2010 Prices 2010 Prices 2011 Prices 2011 Prices 2012 YTD Prices 2012 YTD Prices LLS /bbl $102.07 $62.75 $81.64 $111.09 $112.33 LLS - HSVGO /bbl $2.03 -$2.86 -$2.72 -$5.75 -$8.87 GC Gasoline - LLS /bbl $2.47 $6.91 $5.32 $5.11 $6.28 GC Diesel - LLS /bbl $20.50 $7.26 $8.94 $13.24 $16.55 Natural Gas (NYMEX) /mmBtu $8.90 $4.16 $4.38 $4.03 $2.77 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 $3.15 GC LPGs - LLS /bbl -$40.02 -$20.11 -$23.97 -$38.30 -$50.82 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 $147.52 $8.9 Less: Feedstock cost -$109.07 -$6.5 -$69.83 -$4.2 -$88.80 -$5.3 -$120.93 -$7.3 -$124.01 -$7.4 = Gross Margin $27.80 $1.7 $12.88 $0.8 $17.05 $1.0 $22.79 $1.4 $23.51 $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 $22.96 $1.4 Estimated Annual EBITDA ($MM/year) $613 $261 $341 $487 $503 Note: 2012 YTD prices as November 16, 2012
Keystone XL Pipeline Keystone XL Pipeline Presidential Permit DelayTransCanada 1,661 mile pipeline that will bring 700,000 bpd of Canadian oil into U.S. marketsExpected to create 20,000 U.S. manufacturing and construction jobs; $5.2 billion tax revenue in Keystone corridor states over 20 yearsCanadian approval granted; waiting on U.S. regulatory approvalU.S. 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. 42 Source: TransCanada Corporation Western Gateway to Kitimat Trans Mountain to Vancouver Enbridge working to expand capacity to U.S. as well
*Partial closure of refinery captured in capacity Note: This data represents refineries currently closed, ownership may choose to restart or sell listed refinerySources: Industry and Consultant reports and Valero estimates1The Petit Couronne refinery has reduced capacity by 60 MBPD with Shell to supplying crude via a processing agreement at 100 MBPD starting in mid-June2The Trainer refinery remains closed, but Delta Airlines has announced its intent to purchase the refinery, which would likely result in a restart of this facility3The Ingolstadt refinery remians closed, but Gunvor has agreed to purchase the plant and has indicated that it may restart Global Refining Capacity Rationalization 43 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 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 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 44 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 Kapolei, HI Tesoro 94 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
Low-Cost U.S. Natural Gas Provides Competitive Advantage 45 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 futureVLO 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 (CHART) Source: Argus, 2012 = YTD through November 30, 2012; natural gas price converted to barrels using factor of 6.05x Brent$112/bbl($18.49/mmBtu) U.S. NG$17/bbl($2.78/mmBtu) Asian LNG$93/bbl($15.42/mmBtu) Euro. NG$56/bbl($9.28/mmBtu) /bbl
(CHART) Gasoline Fundamentals 46 (CHART) USGC LLS Gasoline Crack (per bbl) U.S. Gasoline Demand (mmbpd) (CHART) Source: Argus; 2012 data through November 30 Source: DOE weekly data; 2012 data through week ending November 30 Source: DOE weekly data; 2012 data through week ending November 30 U.S. Gasoline Days of Supply U.S. Net Imports of Gasoline and Blendstocks (mbpd) Source: DOE monthly data; 2011 data through September 2012
Distillate Fundamentals 47 47 (CHART) USGC LLS On-road Diesel Crack (per bbl) U.S. Distillate Demand (mmbpd) (CHART) (CHART) Source: Argus; 2012 data through November 30 Source: DOE weekly data; 2012 data through week ending November 30 Source: DOE weekly data; 2012 data through week ending November 30 Source: DOE monthly data; 2011 data through September 2012 U.S. Distillate Days of Supply U.S. Distillate Net Imports (mbpd)
U.S. Transport Indicators: Trucking Indicators 48
U.S. Transport Indicators 49 Latest data Week 47, 2012 Latest data Week 47, 2012
(CHART) (CHART) Mexico Statistics Diesel Gross Imports (MBPD) Source: PEMEX, latest data October 2012 Gasoline Gross Imports (MBPD) Source: PEMEX, latest data October 2012 (CHART) Crude Unit Throughput (MBPD) Crude Unit Utilization (CHART) 50 Source: Mexico Secretary of Energy, latest data October 2012 Source: Mexico Secretary of Energy, latest data October 2012
Venezuelan Exports to the U.S. 51 (CHART) Source: EIA, September 2012
(CHART) Competitively Exporting into Growing Markets Source: DOE Petroleum Supply Monthly with data as of September 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 issuesU.S. Gulf Coast (PADD III) is largest source of exported productsLatin America continues to be the largest U.S. export market, followed by Western EuropeLatin American petroleum demand has been increasing 2.3% per year over the past 5 years versus U.S. decreasing 1.7% per year (CHART) U. S. Product Exports By Destination U. S. Product Exports By Source MMBPD 12 Month Moving Average 52
(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 September 2012 MBPD Diesel net exports continue to rise significantly, with U.S. refiners sending a net of 881 MBPD to other countries in 2012Gasoline net imports have fallen from almost 1 MMBPD in 2006 to only 170 MBPD in 2012 YTDStill, 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 1,493 MBPD in 2012 YTD 53
(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 September 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report and VLO estimates MBPD 54 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 September 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 2012Although the shutdown of U.S. East coast refineries will require more gasoline to balance 55 (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 September 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 56 (CHART) MBPD 12 Month Moving Average
U.S. Diesel Imports by Source Diesel imports continue to fall in 2012 due to less volume from Latin America Source: DOE Petroleum Supply Monthly with data as of September 2012. 4 Week Average estimate from Weekly Petroleum Statistics Report 57 (CHART) 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 thereafterUtica (Ohio) is potentially a large play, but is not as far along in development and oil production results so far have been weakPermian 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 58
Ethanol and Retail Reconciliation of Operating Income to EBITDA Income to EBITDA Income to EBITDA 59 Retail (millions) 2005 2006 2007 2008 2009 2010 2011 3Q12 LTM U.S. Operating Income $81 $113 $154 $260 $170 $200 $213 $210 + U.S. depreciation and amortization expense $60 $60 $59 $70 $70 $73 $77 $77 = U.S. EBITDA $141 $173 $214 $330 $240 $273 $290 $287 Canada Operating Income $73 $69 $95 $109 $123 $146 $168 $126 + Canada depreciation and amortization expense $23 $27 $31 $35 $31 $35 $38 $41 = Canada EBITDA $96 $96 $126 $144 $154 $181 $206 $167
(CHART) Most Crude Oil Discounts Improving 60 $/barrel Source: Argus; 2012 year-to-date through November 30; LLS prices are roll adjusted
Regional Refinery Indicator Margins 61 Source: Argus; 2012 year-to-date through November 30; 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 rollPrior to 2010, GC Colonial 85 CBOB is substituted for GC 87 Conventional 62
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