The Changing North American Crude Market: Impacts to/from the U.S. Refining Complex Presented to: North American Refining Conference June 9, 2015 Houston, TX John R. Auers, P.E. Executive Vice President
TM&C Overview International consulting practice since 1971 Downstream focus; refinery/chemical engineers Industry and financial clients Strategic Studies FMV Assessments & Venture Analyses National Policy Studies Publish various outlook and multi-client subscription reports Crude and Refined Products Outlook Refinery Construction Outlook North American Crude and Condensate Outlook 2014 Edition issued in October World Crude Outlook Collaborating with Schlumberger Business Consulting; Early Fall 2015 Release 2
Presentation Outline Profile of the U.S. Refining Industry The LTO Revolution Future Refining Limits and Reactions 3
Crude Quality/Product Demand Determines Refinery Design Refineries are Unique as are Individual Crudes Differences greater than in Gas Processing and Petrochemical Industries Refineries Evolve with Changes in Crude Supply and Product Demand Regulations Impact Refinery Design as Well 4
Pre-Crude Boom: Growing Dependence on Imports as U.S. Production Declines 12 10 U.S. Production peaks in 1970. Alaska North Slope begins production. Alaska North Slope peaks in 1988, begins to decline. Demand peaks around 2005, falls in 2008-2009 due to recession. Crude Oil Volume (MMBBL/D) 8 6 4 U.S. oil consumption begins to fall. In coming decades, US oil production continues to fall, while demand increases. Imports grow. 2 Decline in production, Saudis flood market with inexpensive oil coupled with increasing beginning in 1985. Oil prices fall over U.S. Crude Oil Production demand is made up 50% in 1986. U.S. Crude Oil Imports with imports. 0 1970 1975 1980 1985 1990 1995 2000 2005 2009 5
The Evolving U.S. Refining Industry U.S. refiners ANS production running prompts West Coast increasing Middle refineries to adapt Eastern Imports to new crude type U.S. refiners begin to shift crude slate to heavier crude, investment including several JVs in PADD II & III to secure market for heavy crudes Increasing Canadian bitumen production prompts additional infrastructure investments U.S. refiners shift investment to run increasing amounts of advantaged LTO U.S. Crude Production Peaks at ~10 MMBPD 1970 ANS Production begins, U.S. crude demand declines 1978 Shift to Latin American crudes, Mexico and Venezuela 1990 Canada becomes top exporter of crude to U.S. 2004 Canadian exports to U.S. exceed 3 MMBPD, light crude imports continue to decline 2014 1970 1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2015 1973 Oil embargo sparks change in demand 1983 Saudis flood market with inexpensive oil 1995 Imports from Mexico and Venezuela on par with Saudi Arabia 2008 U.S. LTO boom begins 6
U.S. Refiners Are the Most Complex Region Cat Cracking Capacity Hydrocracking Capacity Coking Capacity Total Upgrade Capacity U.S. - 1981 28% 5% 8% 41% U.S. 2015 31% 10% 15% 56% Asia 12% 5% 2% 19% Europe 15% 9% 3% 27% World 16% 6% 5% 27% Upgrading ability is total conversion capacity as percentage of distillation capacity As of Jan 1, 2014, O&G Journal 7
Changing U.S. Refinery Crude Slates 1985-2014 Design Basis -> 32.5 Middle Eastern Latin American & Canadian Heavies Domestic Lights 1.6 32.0 1.4 Gravity, API 31.5 31.0 30.5 1.2 1 0.8 Sulfur, wt. % 30.0 0.6 1985 1990 1995 2000 2005 2010 2015 2015 YTD, API 31.8, Sulfur 1.41 8
Sulfur/API Gravity by PADD 2014 Sulfur (wt. %) 1.80 1.60 1.40 1.20 1.00 0.80 0.60 0.40 0.20 40 35 30 25 20 15 10 5 API Gravity Sulfur API 0.00 PADD I PADD II PADD III PADD IV PADD V 0 9
Regional Refinery Configurations PADD IV 12 Refineries* 0.6 MMBPD 14% Avg. Coking PADD II 25 Refineries* 3.8 MMBPD 14% Avg. Coking U.S. Total 111 Refineries* 17.5 MMBPD 19% Avg. Coking Refinery Breakdown 29 Light 35 Med/Hvy 24 Medium 23 Heavy PADD V 23 Refineries* 2.8 MMBPD 19% Avg. Coking 26% 5 4 11% 51% 4% 6 3 2 1 40% 19% 29% 8 6 21% 6% 37% 7 8 15% 7% 21% 1 8 2 14% 1 35% 4 1 65% PADD I 7 Refineries* 1.3 MMBPD 6% Avg. Coking Data from EIA *Refineries 20 MBPD or greater 24% 5 11% 11 16 25% 12 40% PADD III 44 Refineries* 9.1 MMBPD 16% Avg. Coking 10
Presentation Outline Profile of the U.S. Refining Industry The LTO Revolution Future Refining Limits and Reactions 11
Shale Crude Boom Has Changed the Picture 10 9 8 Total Imports down by almost 3 MMBPD in the last 4 yrs 100 95 Crude Oil Imports (MMBBL/D) 7 6 5 4 3 Refinery utilization has risen as crude costs have declined U.S. production reverses course; increases by over 90% since 2008 Waterborne (non-canadian) imports drop off by 4 MMBPD 90 85 80 Refinery Utilization (%) 2 1 Canadian production grows strongly, imports increase 75 0 2009 2010 2011 2012 2013 2014 2015 U.S. Crude Oil Production U.S. Total Crude Oil Imports U.S. Canadian Imports U.S. Waterborne Imports U.S. Refinery Utilization 70 12
Light/Medium Waterborne Imports 2007 Q1 2015 Waterborne Imports, MMBBL/D 6 5 4 3 2 1 0 5.6 2.2 2007 Q1 2015 3.5 1.2 2007 Q1 2015 1.0 0.2 2007 Q1 2015 0.8 0.8 2007 Q1 2015 Displaced Crude MMBBL/D PADD 3 Light Sweet 1.3 PADD 1 Light Sweet 0.7 PADD 2 Total 0.3 Total Light Sour 0.6 Total Medium 0.6 Total Displacement 3.4 0.4 0.0 2007 Q1 2015 Light Sweet Light Sour Medium Total U.S. PADD 3 PADD 1 PADD 5 PADD 2 13
Canadian Developments are Important Canadian production also growing rapidly Primarily heavy production from Western oil sands Increasing access to tidewater is critical XL stalled 2016 election will be key Other P/L s being developed; significant opposition Rail proceeding; approached 200 MBPD before recent declines Canada important in U.S. export debate Eastern refineries important sink for U.S. light crude P/L s allow export outside N/A; decrease light/medium imports into U.S. 14
Canadian Crude Exports to U.S. 2007 March 2015 3.5 Canadian Imports (MMBPD) 3.0 2.5 2.0 1.5 1.0 0.5 Heavy (<24 API) Lt + Med 0.0 2007 2008 2009 2010 2011 2012 2013 2014 2015 3-Month Rolling Average 15
U.S. Crude Exports to Canada 2007 March 2015 Crude Oil Exports (MBPD) 500 450 400 350 300 250 200 150 100 50 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 16
Eastern Canadian Imports (Quebec/Ontario/Atlantic) 1000 900 Three-month Rolling Average Imports (MBPD) 800 700 600 500 400 300 200 100 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 Heavy Light (Non U.S.) Light (U.S.) 17
Presentation Outline Profile of the U.S. Refining Industry The LTO Revolution Future Refining Limits and Reactions 18
U.S. Growth to Continue How Much? Total Production MMBPD 14.5 13.5 12.5 11.5 10.5 9.5 8.5 7.0 6.0 5.0 4.0 3.0 2.0 1.0 Production Increase MMBPD 7.5 0.0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 EIA AEO 2015 EIA AEO HR 2015 TM&C 2014 NACCO TM&C Revised 19 EIA Data: Annual Energy Outlook 2015
Change in Crude Production by Grade 2014-2022 3500 3000 2500 Vast majority of U.S. production growth is 38 API or greater MBPD 2000 1500 1000 500 0 Light (>31 API) Medium (24-31 API) Heavy (<24 API) Canada U.S. TM&C NACCO 2014 20
Factors Influencing Day of Reckoning When Production Exceeds Domestic Capacity Actual Level of Production Growth Ability to Expand Exports/Back out Imports to/from Canada Access West Coast Markets Ability of U.S. Refining System to Displace Lt. Sour/Medium Crudes Level of U.S. Processing Additions How Current Export Regulations are Applied 21
Industry Already Making Investments Made to provide industry the ability to run very light crudes and condensates delays Day of Reckoning Most being done within refinery gates Focused on Eagle Ford; also some Utica Refinery specific/new atmospheric units, pre-flash towers, etc. Upstream and midstream also making processing investments Field condensate stabilizers to facilitate safe storage and transportation EF Condensate splitters located on the coast (Corpus Christi and Houston) Additional opportunistic investments to take advantage of regional proximity to advantaged crudes PADD IV/North Dakota/Permian Size limited by regional demand 22
LTO s Have More Light Components Percent Naphtha and Lighter in Crude 100% 80% 60% 40% 20% Heavy Crude 16% Medium Crude 23% 24% Conventional Light Crude 28% 32% 38% 39% Light Tight Oils 44% 60-80%+ 0% Assumed Naphtha Cut Point is 350 F 23
Refinery LTO Processing Constraints Crude Tower Modifications or replacement of atmospheric tower to increase vapor load capacity 24
Refinery LTO Processing Constraints Pre-Flash Tower Addition The addition of a pre-flash tower can effectively increase light crude capacity of the atmospheric tower. 25
Refinery LTO Processing Constraints Overhead Cooling/Lights Ends Processing Expansion of overhead cooling and light ends processing systems. 26
Refinery LTO Processing Constraints Naphtha Treating Naphtha treating/processing throughput limited 27
Multiple Constraints Likely Expansion of more than one (depending on specific refinery configurations) likely required to alleviate constraints. 28
Examples of Light Crude Expansions Under Construction In Operation Operator Location Cost $MM Startup Marathon Canton, OH 100 Dec 2014 Delek Tyler, TX 70 Mar 2015 Marathon Catlettsburg, KY 150 May 2015 Valero McKee, TX 130 2H 2015 Valero Houston 290 1H 2016 Valero Corpus Christi 240 1H 2016 Marathon Robinson, IL 160 2016 Flint Hills Corpus Christi 600 2018 29
Condensate Splitters Under Construction Operator Location MBPD Startup Kinder Morgan, Phase 1 50 1Q 2015 Houston, TX Kinder Morgan, Phase 2 50 3Q 2015 Trafigura/Buckeye Corpus Christi, TX 50 3Q 2015 Proposed Operator Location MBPD Startup Magellan Corpus Christi, TX 50 4Q 2016 Martin Midstream Corpus Christi, TX Up to 100 1H 2016 Castleton Commodities Corpus Christi, TX 100 4Q 2016 Targa Resources Houston, TX 35 1Q 2017 Phillips 66 Sweeny, TX TBD TBD 30
Light Crude Investment - 2012 to 2018 *Millions of $ U.S. Total 3600 6800 Spent To Date Total Drop in Oil Price Could Delay $500 to $1000+ MM of Investments 31
Light Crude Investment - 2012 to 2018 *Millions of $ PADD IV 1500 900 Spent To Date Total PADD II 800 1100 PADD V Spent To Date Total PADD I 100 200 50 100 Spent To Date Total PADD III Spent To Date Total 1800 Spent To Date 32 3900 Total Drop in Oil Price Could Delay $500 to $1000+ MM of Investments
Key Existing and Planned Pipelines 33
Investments in Reaction to Saturation Made to convert crude to exportable products Market/regulatory uncertainty will incentivize low cost/complexity projects Similar to forces driving crude-by-rail vs. pipeline No incentive to add to global gasoline surplus Various types will depend on BIS guidelines Current rulings might favor simple crude stabilizer Large USGC located facilities to process growing WTI crude might meet current criteria Other facilities would also be built/wti diesel hydroskimmers could become price-setter if BIS imposes stricter criteria on definition of distillation Midstream segment likely to sponsor many of the projects Conversion of existing heavy crude refineries to light crude is least attractive option 34
Processing Options Distillation Field Condensate Stabilizer USGC Crude Stabilizer Condensate Splitter Increasing Level of Separation and Complexity 35
Processing Options Refining Distillate Hydroskimmer Light Crude Refinery Heavy Crude Refinery A A V V Increasing Level of Separation and Complexity 36
Economic Ranking of Processing Options Based on Capital and Operating Costs and TM&C Product Price Forecast Heavy Crude Refinery Revamp Increasing Level of Required Discount Increased USGC Utilization USGC Refinery "Add-On" Hydroskimmer (USGC product $) USGC Greenfield WTI Simple Stabilizer USGC Refinery "Add- On" Hydroskimmer (Export product $) USGC Greenfield WTI Hydroskimmer (Export product $) 37
Heavy-to-Light Conversions Unlikely Western Hemisphere not short of heavy crude Production will continue to grow Limited heavy crude capacity in the rest of the world Producers will price crude to keep heavy oil refineries full Proactive to lock in refining capacity via JV s and LT contracts Heavy-to-light conversion investment not competitive with other alternatives Extensive modification require very high capital investment Heavy crude refiners have/will invest for optionality Run light crude opportunistically 38
Final Thoughts Production Boom is a Generational Event for NA Oil Industry Provides both opportunities and challenges for all industry segments Moving from energy importer to exporter Significant Implications economy-wide and internationally Implications for Refining Sector Lower crude and natural gas costs add to existing advantages Makes U.S. refineries perhaps the most competitive in the world Regions with best access to growing crude will be most advantaged Investment will be needed/is being made to handle quality issues Incentivizing new capacity; 300 to 500 MBPD in next three years When/If Day of Reckoning arrives is dependent on many factors Crude-to-Product facilities will be built based on domestic discount Finding homes for growing levels of product exports is a key challenge 39
Presenter John R. Auers, P.E. Executive Vice President Univ. of Nebraska Chem. Engr. Univ. of Houston MBA Formerly with Exxon Industry studies/analysis, forecasting, modeling Leads Outlook team Contact Info jauers@turnermason.com Office 214-223-8887 40