PLG 2013 State of Freight Summit Presentation

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PLG Consulting presented an overview of the current flows of materials needed to support shale oil development. This is the fifth presentation that PLG has done on the subject in the last 8 months. The company has worked with some of the largest players in the oil & gas industry to help them gain an advantage through logistics. Contact us at www.plgconsulting.com for more information.

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PLG 2013 State of Freight Summit Presentation

  1. 1. Professional Logistics GroupOil & Natural Gas:The Evolving FreightTransportation ImpactsPrepared forMay 22, 2013 Chicago, ILState of FreightSummit 2013
  2. 2. »  Boutique consulting firm specializing in logistics, engineering, andsupply chain§  Established in 2001§  Over 100 clients and 250 engagements»  Headquarters in Chicago USA, with team members throughoutthe US and with “on the ground” experience in:§  North America / Europe / South America / Asia / Middle East»  Consulting services§  Strategy & optimization§  Assessments & benchmarking§  Transportation assets & infrastructure§  Logistics operations§  M&A/investments/private equity»  Key industry verticals:§  Oil & gas§  Chemicals & plastics§  Wind energy & project cargo§  Bulk commodities (minerals, mining, agricultural)§  Industrial manufactured goods§  Private equityAbout PLG Consulting2  
  3. 3. 3  The Shale DevelopmentRevolution – Big PictureDisruptiveTechnologies•  Hydraulic Fracturing•  Horizontal DrillingContinuousEvolution•  Constant Change•  Rapid ChangeMarket Dynamics•  Supply & Demand•  Customers•  Price•  Logistics
  4. 4. Hydraulic Fracturing andHorizontal Drilling4
  5. 5. Hydraulic FracturingEquipment Staging AreaSource: JPTOnline.orgFrac Tanks/Fluid StorageChemical TrucksBlenderSand StorageUnitPump TrucksData Van5
  6. 6. US Shale Plays6
  7. 7. Shale Driving Growth in NaturalGas and Crude Oil Production»  1,769 onshore rigs in operation as of May 10, 2013»  700% increase in shale gas production since 2007»  Domestic oil production at 21-year high (7.2 MM bbl/d)7Source: Baker Hughes 2013Feb. 20137.18MM bpdU.S. Crude Oil ProductionSource: EIAGAS OIL THERMALSource: Baker HughesGAS OIL THERMAL
  8. 8. 8Shale Development Supply Chainand Downstream ImpactsFeedstock (Ethane)Byproduct (Condensate)Home Heating (Propane)Other FuelsOther FuelsGasolineInputs >> Wellhead >> Direct Output >> Thermal >> Fuels >> Raw Materials >> Downstream ProductsGasNGLsCrudeProppantsOCTGChemicalsWaterCementGenerationProcess FeedstocksAll ManufacturingSteelFertilizer (Ammonia)MethanolChemicalsPetroleum ProductsPetrochemicals»  Shale development impact on the railcar industry is long-term, wide-ranging, and positive with only one exception
  9. 9. Hydraulic Fracturing Materials Inputsand Logistics – Per Well9MaterialsChemicalsClean Water/CementProppantsOCTG (Pipe)Source toTransloading2Local source405Transloading toWellhead Site8~1,0001602047 TotalRailcars~1,200 TotalTruckloadsOil/Gas/NGLsTruck, Rail,PipelineWaste Water~500 TotalTruckloads
  10. 10. 10Correlation of Operating Rig Countwith Sand and Crude ShipmentsSTCC 14413 (sand) and 13111 (petroleum) Source: US Rail Desktop, Baker Hughes
  11. 11. All Sand Handled by Railroad11  STCC 14413 Source: US Rail Desktop
  12. 12. Sand Mining Overcapacity:New Reality12»  Growth in Wisconsin sand miningindustry has slowed§  60 mine/processing operations proposedJune 2011 – June 2012§  Four (4) proposed June 2012 – January2013»  Transportation costs continue toconcern WI and MN sandshippers»  Established Illinois companiesseeing significant upturns involumes and financial returns»  Industry consolidation continues
  13. 13. Processed Sand TotalDelivered CostSource: PLG analysis 13»  Benchmark cost with well-executedperformance§  Example unit train movement from Wisconsin toTexas with total delivered cost of approx. $180/ton§  Logistics drives ~60% of total delivered sand cost»  Potential for significant cost add-ons caused by strategic andtactical issues§  Sub-optimal logistics network design orinfrastructure-  Manifest service (rail)-  Multi-carrier vs. single line haul (rail)-  Equipment/driver shortages§  Poor planning and/or execution-  Rail and/or truck demurrage costs–  Performance penalties§  Uncompetitive sand price§  Poor sand quality
  14. 14. Changes in Sand LogisticsModel and Costs»  Rail rate advantage for volume and unit train vs. manifest service§  On a per-ton basis between Wisconsin and Texas, spreads are 17-29%»  Western carriers are driving single line hauls and encouraginglonger trains to Eagle Ford via pricing differentials»  Canadian and Eastern carriers are aggressively working to growtheir markets by providing very competitive pricing and securingsand originations§  CN/Superior Silica Sands – Poskin (Barron), WI»  Major sand providers establishing “in the play” transloadingfacilities to provide ready access to product§  U.S. Silica - East Liverpool, OH§  U.S. Silica – San Antonio, TX§  Potential 2nd facility under consideration in San Antonio, TX»  Post-boom market maturation14Source: PLG analysis
  15. 15. Sand Railcar Market Conditions»  Conditions are normalizing§  Builder backlog has been resolved–  Wait time is now attributable to other car types in the pipeline§  Many surplus cars have found homes§  2013 total production of sand cars will be closer to thehistorical average of 2,000 – 3,000 units»  Lease market settling into familiar patterns§  Traditional pricing behavior: Newer/286k cars moreexpensive than older/263k cars§  Cars with sub-optimal design (i.e. older grain cars)being flushed out and replaced where possible§  Lessors placing modest “spec” orders§  Credit-worthiness of lessee is still a critical criteria»  Looking forward§  Positive developments in housing/construction shouldequate to additional demand for small cube hoppers§  General optimism that demand from sand shippers mayalso strengthen15
  16. 16. Shale Play Product Flows Outbound»  Natural Gas§  Majority via pipelines, some trucks»  Natural Gas Liquids (NGLs)§  Requires processing (fractionation)§  3-9 gallons/MCF (thousand cubic feet)–  Ethane ~42%–  Propane ~28%–  Normal Butane ~8%–  Iso-Butane ~9%–  Condensate ~13%»  Crude Oil§  Bakken play as a model§  Surging Permian and Eagle Ford development16
  17. 17. Shale Development NaturalGas Impacts»  Industry a “victim of its own success”§  Fracking results in oversupply; gas prices down 33%since 2010§  Rigs leave Marcellus, other gas plays for oil plays§  Helped to deflate frac sand boom»  Low gas prices fueling industrial renaissance§  Overall manufacturing (cost of electricity; “re-shoring”)§  Specific sectors that use natural gas as a feedstock–  Methanol (16MM m/t new capacity under consideration)–  Steel–  Fertilizer17Source: EIASource: EIA
  18. 18. Natural Gas Displacement of Coalfor Thermal Generation»  Natural gas now supplying approx. 30% of thermal fueldemand (~13% share capture from coal)»  Despite recent increases in prices, natural gas sharecapture expected to maintain or grow§  Environmental regulations of coal burning§  Scheduled coal unit retirements»  Adversely affecting coal industry, railroad coal loadings18Source: CME and Morningstar
  19. 19. Shale Related Rail Traffic Still SmallRelative to Coal VolumesSand  Crude  Coal  0500,0001,000,0001,500,0002,000,0002,500,00020082009201020112012SandCrudeCoalCarloadsQuarterly DataRailcars Handled: Sand , Crude & CoalSandCrudeCoal19  STCC 14413 (sand), 13111 (petroleum), 11212 (coal)Source: US Rail Desktop
  20. 20. Coal, Crude & Sand Trends:Carloads and RevenueTotal Coal Cars Handled$0$2$4$6$8$10$12$14$16$18-12345678910BillionsCarloadsMillionsCarloads RevenueTotal Crude & Sand Cars Handled20  $0.0$0.5$1.0$1.5$2.0$2.5$3.0-100200300400500600700800900BillionsThousandsSand Crude RevenueSTCC 14413 (sand), 13111 (petroleum), 11212 (coal) Source: US Rail Desktop
  21. 21. Shale Gas Driving SteelManufacturing Comeback in US21  »  Shale gas boom makes direct-reduced iron steel economical§  DRI plants viable with growth in shale gas§  Not new technology, but preferable with lower cost natural gas§  DRI process uses natural gas in place of coal to produce iron§  Cost of production 20% lower per ton vs. traditional blast furnace»  U.S. jobs and international investment§  Steel production in the U.S has shrunk 3.4% since 2008–  Compare to 14% growth in steel production internationally–  Domestic steel industry capacity running at 74%§  At least five new DRI steel plants being considered in the U.S. – now economical forthe first time in 30 years due to low cost of natural gas§  Both domestic and international firms investing in the technology§  Initial investments create up to 500 jobs and 150 permanent employees»  Reciprocal growth§  Increased demand for U.S. steel creates greater demand for U.S. gas§  Joint venture between Nucor Corp. and Encana Corp. commits $3 billion todevelopment of new gas wells to support DRI plants§  Voestalpine $700MM investment in Texas§  DRI-derived steel of higher quality than that created from recycled scrap, furtherdriving demand
  22. 22. Shale Gas Development Impacton Fertilizer Market»  Natural gas is a feedstock for ammonia production»  Lower gas prices directly benefit American farmers§  Increased demand for corn, soybeans has driven fertilizer costs higher§  Excess natural gas supply can be utilized to produce greater volumes ofnitrogen-based fertilizer more economically»  Cheap U.S. natural gas means billions in investment fornew domestic fertilizer plants, displacing ~11 MM m/t ofimports§  Orascom/Iowa Fertilizer Company - Wever, IA§  CHS - Spiritwood, ND§  Ohio Valley Resources - Spencer County, IN§  Yara - Belle Plaine, SK Canada§  North Dakota Grain Growers Association - Williston Basin, ND§  CF Industries – expansions at Donaldsonville, LA and Port Neal, IA§  PotashCorp - resumption of ammonia production at Geismar, LA§  Agrium – KY or MO (anticipated)»  If new plant construction/expansions are completed,imports of nitrogen-based fertilizers could be reduced from~50% to “near zero” by 2018 22  
  23. 23. Looking Ahead: Natural Gas»  Oversupply conditions expected to persist through 2015§  Over 1,000 wells currently capped in the Marcellus»  Factors that could revive demand, production, andprices (>$5/MMbtu)§  Industrial use expansions come online over next 5 years§  Continued toughening of EPA regulations of coal§  Historic import/export reversal of US/Canada natural gas flows by 2014(Marcellus gas exports to Canada)§  Technology advancements for increased use of CNG as atransportation fuel23  
  24. 24. LNG Export Opportunity»  Political/policy battle between domesticindustrial users and producers»  Sabine Pass, LA and Freeport, TX nowpermitted for exports; more terminals inapplication phase§  3.4 Bcf/day export capacity to come online by2015§  Represents ~5% of projected US dry gasproduction»  20 additional terminal applicationstotaling 29 Bcf/day of export capacitypending before FERC»  Expect only moderate volumes of LNGexports to be approved§  Avoids exposure of natural gas to similar marketforces that have affected oil§  Useful foreign policy instrument for ExecutiveBranch24  Source: Waterborne Energy Inc. Data in $US/MMBtuPhoto: Wall Street Journal
  25. 25. Shale Development NGL Impacts»  Leading NGL and “wet gas” plays are EagleFord, Utica, Permian§  Significant investment and expansion of gathering,fractionation, and takeaway capacity underway in the UticaPlay§  Takeaway capacity in Eagle Ford well exceeds currentproduction (4x)»  Requires fractionation facilities proximal toproduction§  “Y-grade” must be separated into purified products§  75% of fractionation capacity in US Gulf Coast§  Mt. Belvieu, TX major trading & storage hub§  500 Mb/d of new fractionation capacity planned for Utica§  Utica NGL production growth expected to exceed 600%between 2013-2015»  Similar to dry gas, strong production due tofracking has resulted in oversupply anddepressed prices§  Chemical industry benefits25
  26. 26. Shale Development Impact:Chemical Industry»  Abundant ethane supplies have sparked chemical industryrenaissance§  Ethane is “cracked” to make ethylene, the most basic building block in thechemicals supply chain§  Over $95B in new announced petrochemical expansions will come on-lineover the next five years, increasing ethylene capacity by 33% (11 MMmt)§  USA is now the low-cost producer of ethylene-based chemicals due toabundant supplies of ethane from shale plays (up to 60% raw materials costadvantage)§  Domestic end-use of materials, i.e. plastics, will expand significantly§  Up to 40% of new petrochemical output will be for export§  New demand for plastic resin hoppers, specialty and pressure tank cars2605001000150020002500Asia USHistoricalSaudi USRecent$/TonHDPE Calculated CostSources: CMAI, TopLine Analytics, andAlembic analysis, 2012Source: EIA
  27. 27. Natural Gas & PetrochemicalDownstream ProductsFeedstock/IntermediaryFinishedProductsNatural Gas,OIlEthane,Naphtha, etc.EthyleneMiscellaneousVinyl AcetateLinearAlcoholsEthylBenzeneEthyleneOxideEthyleneDichlorideHigh DensityPolyethyleneLow-DensityPolyethyleneAdhesives, coatings, textile/paper. finishing, flooringDetergentsStyreneEthyleneGlycolVinyl ChlorideHouse wares, crates,drums, food containers,bottles.Food packaging, film,trash bags, diapers, toysPVCAntifreezeFibersPETMiscellaneousPolystyreneSANSBRLatexMiscellaneousMedical gloves,carpeting,coatingsTire, hoseInstrument lenses,house waresInsulation, cupsSiding, windows,frames, pipe, medicaltubingPantyhose,carpets, clothingBottles, film27  
  28. 28. Looking Ahead: NGLs28Source: Canadian Energy Research InstituteSource: Sunoco Logistics»  The (somewhat) hidden Condensate story§  Used as diluent for heavy Canadian tar sands oil – critical fortransportation as “Dilbit”§  Trades at ~$104/bbl at Edmonton§  Significant investment in infrastructure being made to deliverEagle Ford, Utica condensate to Western Canada§  Primary delivery via pipeline, but major rail volumes ex. Uticaare required to get to Midwest pipeline injection points§  Additional stressor on tight tank car supplies§  Demand expected to grow from 200 Mb/d to 500 Mb/d by 2020»  Expect export market for NGLs to expand§  Pipeline reversals undertaken to meet demand, particularly ex.Utica to Sarnia, ON petrochemical complex and export storageand dock facilities in Philadelphia
  29. 29. Shale DevelopmentCrude Oil Impacts»  Dramatic increases in US production due to fracking§  7.2 MM bbl/day§  Projected to grow by ~30% over next four years§  Strong play in Bakken; surging Permian and Eagle Ford development§  “Tight” oil sources driving overall North American growth§  Production forecasts frequently revised upward29Source: Morgan Stanley, February 2013Source: Morgan Stanley, February 2013
  30. 30. Driving Toward “Oil Independence?”»  Decreasing dependency on foreign crude§  Combination of US shale plus Canadian oil sands estimated to reduceimports to <15% by 2020§  West African imports already down ~70% from 2010 levels»  However, supply isn’t enough – “independence” alsorelies on lower domestic fuels consumption§  CAFE standards the primary driver»  Reducing imports means reducing waterborne crudes§  Mid-continent sources displacing imports at coasts, making rail critical tothe total crude market§  Bakken as case study for large crude by rail operations30Source: BENTEK Energy
  31. 31. Bakken Oil Production and Logistics31North Dakota Crude Oil ProductionFirst outbound unittrain shipmentDecember, 2009~779,000 BPD February 2013Source: EIA, PLG»  2010-2011 discount of ~$8-12/bbl for Bakkencrude vs. peer WTI§  Undervalued due to logistics constraints “stranding” the oil»  Early objective of crude-by-rail was to bridgegap until pipelines built, but has now becomethe primary transport mode for Bakken crude§  ~70% rail market share§  Pipelines operating below capacity; some projectcancelations»  Significant development of crude by railloading terminals in 2011-2012§  Takeaway capacity now exceeds production§  Bakken vs. WTI differential near even (within ~$5)Source: North Dakota Pipeline Authority, PLG Analysis
  32. 32. Crude Oil by Rail – NorthDakota TerminalsSource: North Dakota Pipeline Authority (April 2013), PLG AnalysisNorth Dakota Crude Oil Rail Loading Capacity (Barrels Per Day)Rail Terminals 2013 2014* 2015* Rail CarrierEOG Rail, Stanley, ND (Up to 90,000 BOPD) 65,000 65,000 65,000 BNSFInergy COLT Hub, Epping, ND (Q2 2012) 120,000 120,000 120,000 BNSFHess Rail, Tioga, ND (Up to 120,000 BOPD) 60,000 60,000 60,000 BNSFBakken Oil Express, Dickinson, ND 100,000 100,000 100,000 BNSFSavage Services, Trenton, ND (Q2 2012 Unit Trains) 90,000 90,000 90,000 BNSFEnbridge, Berthold, ND (Q4 2012) 80,000 80,000 80,000 BNSFGreat Northern Midstream, Fryburg, ND (Q1 2013) 60,000 60,000 60,000 BNSFMusket, Dore, ND (Q2 2012) 60,000 60,000 60,000 BNSFPlains, Ross, ND 65,000 65,000 65,000 BNSFGlobal/Basin Transload, Zap, ND (Estimate Not Confirmed) 40,000 40,000 40,000 BNSFPlains All American, Manitou, ND 65,000 65,000 65,000 BNSFBNSF Total Capacity 805,000 805,000 805,000Plains - Van Hook, New Town, ND 65,000 65,000 65,000 CPDakota Plains, New Town, ND 30,000 80,000 80,000 CPGlobal Partners, Stampede, ND 60,000 60,000 60,000 CPCP Total 155,000 205,000 205,000Various Sites in Minot, Dore, Donnybrook, Gascoyne, and Stampede 30,000 30,000 30,000Total Crude Oil Rail Loading Capacity 990,000 1,040,000 1,040,000*Project still in the review or proposed phase Year End System Capacity32  
  33. 33. North Dakota Class I Railroadsand Crude Oil Terminals33  Map by PLG Consulting
  34. 34. 34  All Crude Handled by RailroadVolume GrowthSTCC 13111 Source: US Rail Desktop
  35. 35. 35  Bakken AreaOutbound Pipelines35  35North Dakota Crude Oil Pipeline Capacity (Barrels Per Day)Pipelines 2013 2014* 2015*Butte Pipeline 160,000 160,000 160,000Butte Loop* (Late 2014) - 110,000 110,000Enbridge Mainline North Dakota 210,000 210,000 210,000Enbridge Bakken Expansion Program (Q1-11/Q1-13) 145,000 145,000 145,000Plains Bakken North (Q2 2013, Up to 75,000 BOPD) 50,000 50,000 50,000High Prairie Pipeline* - 150,000 150,000Enbridge Sandpiper* (Q1 2016) - - -TransCanada Keystone XL* (2015) - - 100,000TransCanada Bakken Marketlink * (4Q 2015) - - 100,000Hiland Partners Double H Pipeline (Q3 2014, Up to 100,000 BOPD) 50,000 50,000Pipeline Total 565,000 875,000 1,075,000*Project Still in the Review or Proposed Phase Year End System CapacitySource: North Dakota Pipeline Authority (April 2013)
  36. 36. Bakken Production vs. Total TakeawayCapacity: 2013–2015 ProjectionYear ND ProductionForecast (Bpd)PipelineCapacityRail TerminalCapacityRail CarrierCapacityND RefineryConsumptionTotalOutbound &RefineryCapacityExcess LogisticsCapacity2013 850,000 565,000 990,000 1,300,000 68,000 1,623,000 773,0002014 980,000 875,000 1,040,000 1,300,000 68,000 1,983,000 1,003,0002015 1,150,000 1,075,000 1,040,000 1,350,000 90,000 2,205,000 1,055,000Source: North Dakota Pipeline Authority, PLG AnalysisBpd = Barrels per Day
  37. 37. Crude Oil Pipelines – Existingand Planned37  Source: CAPP Report, 2012»  Current pipelines ex. Bakkenoperating below capacity»  Fixed routes and long lead times arechallenged by new dynamic NA oilmarket§  10 year commitments required for new buildpipeline projects»  Pegasus spill raising new concernsabout Keystone XL§  Special challenges of Dilbit§  Pegasus the only pipeline currently handlingCanadian oil sands bitumen to US Gulf Coast»  Several natural gas pipelineconversions planned§  Trunkline (ETP) – Patoka, IL-St. James, LA§  Freedom (KM) – Permian Basin-SouthernCalifornia§  Energy East (TransCanada) – Hardisty, AB-St.Johns, NB
  38. 38. Crude Oil by Rail vs. Pipeline$6.50$12.00$10.50$15.00  $-­‐          $2.00      $4.00      $6.00      $8.00      $10.00      $12.00      $14.00      $16.00    Pipeline toCushingRail toCushingPipeline to PtArthurRail to PtArthurDollarsPerBarrelSource: PLG analysis 38»  Rail cost: 50-100% more expensive thanpipeline transport»  Near-term offsetting rail advantages:§  Site permitting, construction much faster§  Lower capital cost§  Scalable§  Shorter contracts (2-3 year commitments vs. 10 yearsfor pipeline)§  Faster transit times§  Access to coastal areas not connected via pipeline§  Origin/destination flexibility§  Primary advantage: Tool of arbitrage for trading desks»  Rail pricing drivers§  Advantaged rate structures for first-movers, volume,and unit train operators§  “Floor” has been set for crude by rail pricing§  Crude price differentials more important than cost vs.pipelineCost Comparison: Bakken to Cushing and USGC
  39. 39. 39  Shale Development Impact onCrude Oil Market Dynamics»  Price differentials driving trading and logisticspatterns§  Bakken and WTI trading at ~$10-$15/bbl less than Brent; AlbertaBitumen trading at ~$30/bbl less than Brent§  E&P, midstream players willing to rapidly deploy significantcapital to enable access–  Multi-modal logistics hubs in shale plays–  New multi-modal terminals/trading hubs at destination markets (i.e.Cushing, OK, St. James, LA, Pt. Arthur, TX, Albany, NY, Bakersfield,CA)–  Lease and purchase of railcar fleets–  Pipeline expansions, reversals, new construction§  Refineries installing unit train receiving capability - particularlycoastal refineries previously captive to waterborne imports (i.e.Philadelphia, PA, St. John, NB, Anacortes, WA, Ferndale, WA)§  Constantly changing trading and logistics patterns for light/sweetmid continent crudes–  Original crude-by-rail primary destination of Cushing now beingbypassed–  Crude by rail now supplying ~20% of east coast refining demand–  200 M/bpd or 40% of Bakken crudes via rail are being delivered to St.James, LA39Source: Petromatrix
  40. 40. 40  Logistics Challenges of Light/Sweet vs. Heavy/Sour Crudes»  Not all crudes are created equal – light/sweet vs. heavy/sour§  Brent, WTI, and US shale play crudes (Bakken, Permian, Niobrara, Permian) are light/sweet§  Heavy/sour crudes include Western Canada, Venezuela, Mexico, Alaska North Slope (ANS),Middle East (light/sour)§  Light/sweet requires less downstream processing§  Heavy/sour has higher sulfur content§  Bakken has higher gas, jet, and distillate yield than peer crudes»  Refineries are generally configured to run certain types of crude§  Significant investments made ($48B since 2005) at select refineries to install coker units that willallow processing of heavy/sour§  Major heavy/sour refining clusters: Corpus Christi, Houston, Chicago, southern Illinois, Ohio,California§  US is close to saturation point on light/sweet crude at mid-continent and USGC refining areas»  The special case of the Canada Oil Sands§  Heavy/sour crude has a natural home in Midwest and US Gulf Coast (~2.8 MM bpd demand atUSGC)§  Pipeline capacity to US Midwest refining centers is at capacity§  Pipeline developments to coasts, US markets still 2+ years away, while tank car supply constrainsrail options§  Option to ship dilbit in GP oil-spec tank cars, OR undiluted bitumen in coiled, insulated cars§  Canadian bitumen trading at ~$30 discount vs. Mexican Maya§  Estimated transport cost via rail $22-30/bbl; $14-16/bbl via pipeline40
  41. 41. 41  Looking Ahead: NorthAmerican Crude Oil»  The gusher of new US light/sweet shale oil production madepossible by fracking has upended the traditional oil logistics andtrading patterns§  Result: “Wrong place/wrong oil” supply displacements, i.e. Cushing overflow§  Rapid investment in new logistics infrastructure, routes, modes, and terminals–  Bakken now sufficiently developed; next immediate areas for significant investment are Utica, OilSands, Permian, coastal areas and intermediate routes and facilities that support bitumen transportin particular»  The biggest current bottleneck: Railcars§  Current order backlog runs to early 2015§  Major purchases by oil majors and midstream companies§  Extremely tight market with very high lease rates§  Current crude by rail fleet ~30,000 railcars, or 1-1.5 MM bbl/day equivalent»  A “new normal” in crude oil flows will emerge in conjunction withcontinued North American oil production over the next five years§  Continued shifts of mid-continent light/sweet to coastal destinations§  New modes and infrastructure to get Canadian bitumen to USGC, with or withoutKeystone XL§  Permian, Eagle Ford to meet USGC light/sweet demand; Bakken flows primarily east-west§  Eventual government approval of crude oil exports on a limited basis, similar to LNG§  Primary risk to crude-by-rail business: WTI-Brent spread 41KeyDriversDestinationMarketsOilPriceLogisticsCapitalSource: CME and Morningstar
  42. 42. Looking Ahead: Crude Oil AnticipatedProduction Growth and Product Flows42= Light/Sweet= Heavy/Sour= Pipeline= Marine= Rail= Storage terminal(s)= Refinery cluster – LightSweet/Intermediate= Refinery cluster – HeavySour/Intermediate= Current b/d (000)= Future b/d (000) additional by 2017+420123Bakken+855704Oil Sands+9821,615Eagle Ford+1,087352Permian+607514Source: BENTEK Energy, CAPP, Railroad Commission of Texas, PLG Consulting
  43. 43. Thank You!For follow up questions and information, please contact:Taylor Robinson, President+1-508-982-1319 / trobinson@prologisticsgroup.comGraham Brisben, CEO+1-708-386-0700 / gbrisben@prologisticsgroup.comJean Arndt, Vice President+1-630-505-0273 / jarndt@prologisticsgroup.comJeff Dowdell, Senior Consultant+1-732-995-6696 / jdowdell@prologisticsgroup.comGordon Heisler, Senior Consultant+1-215-620-4247 / gheisler@prologisticsgroup.comJeff Rasmussen, Senior Consultant+1-317-379-5715 / jrasmussen@prologisticsgroup.comJay Olberding, Analyst+1-636-399-5628 / jolberding@prologisticsgroup.comThis presentation is available at:WWW.PLGCONSULTING.COMProfessional Logistics Group43  

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