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.

1. Professional Logistics Group
Oil & Natural Gas:
The Evolving Freight
Transportation Impacts
Prepared for
May 22, 2013 Chicago, IL
State of Freight
Summit 2013

2. » Boutique consulting firm specializing in logistics, engineering, and
supply chain
§ Established in 2001
§ Over 100 clients and 250 engagements
» Headquarters in Chicago USA, with team members throughout
the 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 equity
About PLG Consulting
2

3. 3
The Shale Development
Revolution – Big Picture
Disruptive
Technologies
• Hydraulic Fracturing
• Horizontal Drilling
Continuous
Evolution
• Constant Change
• Rapid Change
Market Dynamics
• Supply & Demand
• Customers
• Price
• Logistics

4. Hydraulic Fracturing and
Horizontal Drilling
4

5. Hydraulic Fracturing
Equipment Staging Area
Source: JPTOnline.org
Frac Tanks/Fluid Storage
Chemical Trucks
Blender
Sand Storage
Unit
Pump Trucks
Data Van
5

6. US Shale Plays
6

7. Shale Driving Growth in Natural
Gas 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 2013
Feb. 2013
7.18MM bpd
U.S. Crude Oil Production
Source: EIA
GAS OIL THERMAL
Source: Baker Hughes
GAS OIL THERMAL

8. 8
Shale Development Supply Chain
and Downstream Impacts
Feedstock (Ethane)
Byproduct (Condensate)
Home Heating (Propane)
Other Fuels
Other Fuels
Gasoline
Inputs >> Wellhead >> Direct Output >> Thermal >> Fuels >> Raw Materials >> Downstream Products
Gas
NGLs
Crude
Proppants
OCTG
Chemicals
Water
Cement
Generation
Process Feedstocks
All Manufacturing
Steel
Fertilizer (Ammonia)
Methanol
Chemicals
Petroleum Products
Petrochemicals
» Shale development impact on the railcar industry is long-term, wide-ranging, and positive with only one exception

9. Hydraulic Fracturing Materials Inputs
and Logistics – Per Well
9
Materials
Chemicals
Clean Water/
Cement
Proppants
OCTG (Pipe)
Source to
Transloading
2
Local source
40
5
Transloading to
Wellhead Site
8
~1,000
160
20
47 Total
Railcars
~1,200 Total
Truckloads
Oil/Gas/NGLs
Truck, Rail,
Pipeline
Waste Water
~500 Total
Truckloads

10. 10
Correlation of Operating Rig Count
with Sand and Crude Shipments
STCC 14413 (sand) and 13111 (petroleum) Source: US Rail Desktop, Baker Hughes

11. All Sand Handled by Railroad
11
STCC 14413 Source: US Rail Desktop

12. Sand Mining Overcapacity:
New Reality
12
» Growth in Wisconsin sand mining
industry has slowed
§ 60 mine/processing operations proposed
June 2011 – June 2012
§ Four (4) proposed June 2012 – January
2013
» Transportation costs continue to
concern WI and MN sand
shippers
» Established Illinois companies
seeing significant upturns in
volumes and financial returns
» Industry consolidation continues

13. Processed Sand Total
Delivered Cost
Source: PLG analysis 13
» Benchmark cost with well-executed
performance
§ Example unit train movement from Wisconsin to
Texas 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 and
tactical issues
§ Sub-optimal logistics network design or
infrastructure
- 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. Changes in Sand Logistics
Model 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 encouraging
longer trains to Eagle Ford via pricing differentials
» Canadian and Eastern carriers are aggressively working to grow
their markets by providing very competitive pricing and securing
sand originations
§ CN/Superior Silica Sands – Poskin (Barron), WI
» Major sand providers establishing “in the play” transloading
facilities 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 maturation
14Source: PLG analysis

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 the
historical average of 2,000 – 3,000 units
» Lease market settling into familiar patterns
§ Traditional pricing behavior: Newer/286k cars more
expensive 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 should
equate to additional demand for small cube hoppers
§ General optimism that demand from sand shippers may
also strengthen
15

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 development
16

17. Shale Development Natural
Gas 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
– Fertilizer
17Source: EIASource: EIA

18. Natural Gas Displacement of Coal
for Thermal Generation
» Natural gas now supplying approx. 30% of thermal fuel
demand (~13% share capture from coal)
» Despite recent increases in prices, natural gas share
capture expected to maintain or grow
§ Environmental regulations of coal burning
§ Scheduled coal unit retirements
» Adversely affecting coal industry, railroad coal loadings
18Source: CME and Morningstar

19. Shale Related Rail Traffic Still Small
Relative to Coal Volumes
Sand
Crude
Coal
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
2008
2009
2010
2011
2012
Sand
Crude
Coal
Carloads
Quarterly Data
Railcars Handled: Sand , Crude & Coal
Sand
Crude
Coal
19
STCC 14413 (sand), 13111 (petroleum), 11212 (coal)
Source: US Rail Desktop

20. Coal, Crude & Sand Trends:
Carloads and Revenue
Total Coal Cars Handled
$0
$2
$4
$6
$8
$10
$12
$14
$16
$18
-
1
2
3
4
5
6
7
8
9
10
Billions
Carloads
Millions
Carloads Revenue
Total Crude & Sand Cars Handled
20
$0.0
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
-
100
200
300
400
500
600
700
800
900
Billions
Thousands
Sand Crude Revenue
STCC 14413 (sand), 13111 (petroleum), 11212 (coal) Source: US Rail Desktop

21. Shale Gas Driving Steel
Manufacturing Comeback in US
21
» 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 for
the 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 to
development 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, further
driving demand

22. Shale Gas Development Impact
on 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 of
nitrogen-based fertilizer more economically
» Cheap U.S. natural gas means billions in investment for
new domestic fertilizer plants, displacing ~11 MM m/t of
imports
§ 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. 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, and
prices (>$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 a
transportation fuel
23

24. LNG Export Opportunity
» Political/policy battle between domestic
industrial users and producers
» Sabine Pass, LA and Freeport, TX now
permitted for exports; more terminals in
application phase
§ 3.4 Bcf/day export capacity to come online by
2015
§ Represents ~5% of projected US dry gas
production
» 20 additional terminal applications
totaling 29 Bcf/day of export capacity
pending before FERC
» Expect only moderate volumes of LNG
exports to be approved
§ Avoids exposure of natural gas to similar market
forces that have affected oil
§ Useful foreign policy instrument for Executive
Branch
24
Source: Waterborne Energy Inc. Data in $US/MMBtu
Photo: Wall Street Journal

25. Shale Development NGL Impacts
» Leading NGL and “wet gas” plays are Eagle
Ford, Utica, Permian
§ Significant investment and expansion of gathering,
fractionation, and takeaway capacity underway in the Utica
Play
§ Takeaway capacity in Eagle Ford well exceeds current
production (4x)
» Requires fractionation facilities proximal to
production
§ “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 to
fracking has resulted in oversupply and
depressed prices
§ Chemical industry benefits
25

26. Shale Development Impact:
Chemical Industry
» Abundant ethane supplies have sparked chemical industry
renaissance
§ Ethane is “cracked” to make ethylene, the most basic building block in the
chemicals supply chain
§ Over $95B in new announced petrochemical expansions will come on-line
over the next five years, increasing ethylene capacity by 33% (11 MMmt)
§ USA is now the low-cost producer of ethylene-based chemicals due to
abundant supplies of ethane from shale plays (up to 60% raw materials cost
advantage)
§ 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 cars
26
0
500
1000
1500
2000
2500
Asia US
Historical
Saudi US
Recent
$/Ton
HDPE Calculated Cost
Sources: CMAI, TopLine Analytics, and
Alembic analysis, 2012
Source: EIA

27. Natural Gas & Petrochemical
Downstream Products
Feedstock/
Intermediary
Finished
Products
Natural Gas,
OIl
Ethane,
Naphtha, etc.
Ethylene
Miscellaneous
Vinyl Acetate
Linear
Alcohols
Ethyl
Benzene
Ethylene
Oxide
Ethylene
Dichloride
High Density
Polyethylene
Low-Density
Polyethylene
Adhesives, coatings, textile/
paper. finishing, flooring
Detergents
Styrene
Ethylene
Glycol
Vinyl Chloride
House wares, crates,
drums, food containers,
bottles.
Food packaging, film,
trash bags, diapers, toys
PVC
Antifreeze
Fibers
PET
Miscellaneous
Polystyrene
SAN
SBR
Latex
Miscellaneous
Medical gloves,
carpeting,
coatings
Tire, hose
Instrument lenses,
house wares
Insulation, cups
Siding, windows,
frames, pipe, medical
tubing
Pantyhose,
carpets, clothing
Bottles, film
27

28. Looking Ahead: NGLs
28
Source: Canadian Energy Research Institute
Source: Sunoco Logistics
» The (somewhat) hidden Condensate story
§ Used as diluent for heavy Canadian tar sands oil – critical for
transportation as “Dilbit”
§ Trades at ~$104/bbl at Edmonton
§ Significant investment in infrastructure being made to deliver
Eagle Ford, Utica condensate to Western Canada
§ Primary delivery via pipeline, but major rail volumes ex. Utica
are 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 storage
and dock facilities in Philadelphia

29. Shale Development
Crude 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 upward
29Source: Morgan Stanley, February 2013Source: Morgan Stanley, February 2013

30. Driving Toward “Oil Independence?”
» Decreasing dependency on foreign crude
§ Combination of US shale plus Canadian oil sands estimated to reduce
imports to <15% by 2020
§ West African imports already down ~70% from 2010 levels
» However, supply isn’t enough – “independence” also
relies 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 to
the total crude market
§ Bakken as case study for large crude by rail operations
30Source: BENTEK Energy

31. Bakken Oil Production and Logistics
31
North Dakota Crude Oil Production
First outbound unit
train shipment
December, 2009
~779,000 BPD February 2013
Source: EIA, PLG
» 2010-2011 discount of ~$8-12/bbl for Bakken
crude vs. peer WTI
§ Undervalued due to logistics constraints “stranding” the oil
» Early objective of crude-by-rail was to bridge
gap until pipelines built, but has now become
the primary transport mode for Bakken crude
§ ~70% rail market share
§ Pipelines operating below capacity; some project
cancelations
» Significant development of crude by rail
loading 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. Crude Oil by Rail – North
Dakota Terminals
Source: North Dakota Pipeline Authority (April 2013), PLG Analysis
North Dakota Crude Oil Rail Loading Capacity (Barrels Per Day)
Rail Terminals 2013 2014* 2015* Rail Carrier
EOG Rail, Stanley, ND (Up to 90,000 BOPD) 65,000 65,000 65,000 BNSF
Inergy COLT Hub, Epping, ND (Q2 2012) 120,000 120,000 120,000 BNSF
Hess Rail, Tioga, ND (Up to 120,000 BOPD) 60,000 60,000 60,000 BNSF
Bakken Oil Express, Dickinson, ND 100,000 100,000 100,000 BNSF
Savage Services, Trenton, ND (Q2 2012 Unit Trains) 90,000 90,000 90,000 BNSF
Enbridge, Berthold, ND (Q4 2012) 80,000 80,000 80,000 BNSF
Great Northern Midstream, Fryburg, ND (Q1 2013) 60,000 60,000 60,000 BNSF
Musket, Dore, ND (Q2 2012) 60,000 60,000 60,000 BNSF
Plains, Ross, ND 65,000 65,000 65,000 BNSF
Global/Basin Transload, Zap, ND (Estimate Not Confirmed) 40,000 40,000 40,000 BNSF
Plains All American, Manitou, ND 65,000 65,000 65,000 BNSF
BNSF Total Capacity 805,000 805,000 805,000
Plains - Van Hook, New Town, ND 65,000 65,000 65,000 CP
Dakota Plains, New Town, ND 30,000 80,000 80,000 CP
Global Partners, Stampede, ND 60,000 60,000 60,000 CP
CP Total 155,000 205,000 205,000
Various Sites in Minot, Dore, Donnybrook, Gascoyne, and Stampede 30,000 30,000 30,000
Total Crude Oil Rail Loading Capacity 990,000 1,040,000 1,040,000
*Project still in the review or proposed phase Year End System Capacity
32

33. North Dakota Class I Railroads
and Crude Oil Terminals
33
Map by PLG Consulting

34. 34
All Crude Handled by Railroad
Volume Growth
STCC 13111 Source: US Rail Desktop

35. 35
Bakken Area
Outbound Pipelines
35
35
North Dakota Crude Oil Pipeline Capacity (Barrels Per Day)
Pipelines 2013 2014* 2015*
Butte Pipeline 160,000 160,000 160,000
Butte Loop* (Late 2014) - 110,000 110,000
Enbridge Mainline North Dakota 210,000 210,000 210,000
Enbridge Bakken Expansion Program (Q1-11/Q1-13) 145,000 145,000 145,000
Plains Bakken North (Q2 2013, Up to 75,000 BOPD) 50,000 50,000 50,000
High Prairie Pipeline* - 150,000 150,000
Enbridge Sandpiper* (Q1 2016) - - -
TransCanada Keystone XL* (2015) - - 100,000
TransCanada Bakken Marketlink * (4Q 2015) - - 100,000
Hiland Partners Double H Pipeline (Q3 2014, Up to 100,000 BOPD) 50,000 50,000
Pipeline Total 565,000 875,000 1,075,000
*Project Still in the Review or Proposed Phase Year End System Capacity
Source: North Dakota Pipeline Authority (April 2013)

36. Bakken Production vs. Total Takeaway
Capacity: 2013–2015 Projection
Year ND Production
Forecast (Bpd)
Pipeline
Capacity
Rail Terminal
Capacity
Rail Carrier
Capacity
ND Refinery
Consumption
Total
Outbound &
Refinery
Capacity
Excess Logistics
Capacity
2013 850,000 565,000 990,000 1,300,000 68,000 1,623,000 773,000
2014 980,000 875,000 1,040,000 1,300,000 68,000 1,983,000 1,003,000
2015 1,150,000 1,075,000 1,040,000 1,350,000 90,000 2,205,000 1,055,000
Source: North Dakota Pipeline Authority, PLG AnalysisBpd = Barrels per Day

37. Crude Oil Pipelines – Existing
and Planned
37
Source: CAPP Report, 2012
» Current pipelines ex. Bakken
operating below capacity
» Fixed routes and long lead times are
challenged by new dynamic NA oil
market
§ 10 year commitments required for new build
pipeline projects
» Pegasus spill raising new concerns
about Keystone XL
§ Special challenges of Dilbit
§ Pegasus the only pipeline currently handling
Canadian oil sands bitumen to US Gulf Coast
» Several natural gas pipeline
conversions planned
§ Trunkline (ETP) – Patoka, IL-St. James, LA
§ Freedom (KM) – Permian Basin-Southern
California
§ Energy East (TransCanada) – Hardisty, AB-St.
Johns, NB

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 to
Cushing
Rail to
Cushing
Pipeline to Pt
Arthur
Rail to Pt
Arthur
DollarsPerBarrel
Source: PLG analysis 38
» Rail cost: 50-100% more expensive than
pipeline transport
» Near-term offsetting rail advantages:
§ Site permitting, construction much faster
§ Lower capital cost
§ Scalable
§ Shorter contracts (2-3 year commitments vs. 10 years
for 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.
pipeline
Cost Comparison: Bakken to Cushing and USGC

39. 39
Shale Development Impact on
Crude Oil Market Dynamics
» Price differentials driving trading and logistics
patterns
§ Bakken and WTI trading at ~$10-$15/bbl less than Brent; Alberta
Bitumen trading at ~$30/bbl less than Brent
§ E&P, midstream players willing to rapidly deploy significant
capital 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 - particularly
coastal 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/sweet
mid continent crudes
– Original crude-by-rail primary destination of Cushing now being
bypassed
– 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, LA
39
Source: Petromatrix

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 will
allow 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 at
USGC)
§ Pipeline capacity to US Midwest refining centers is at capacity
§ Pipeline developments to coasts, US markets still 2+ years away, while tank car supply constrains
rail 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 pipeline
40

41. 41
Looking Ahead: North
American Crude Oil
» The gusher of new US light/sweet shale oil production made
possible by fracking has upended the traditional oil logistics and
trading 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, Oil
Sands, Permian, coastal areas and intermediate routes and facilities that support bitumen transport
in 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 with
continued 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 without
Keystone 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 41
Key
Drivers
Destination
Markets
Oil
Price
Logistics
Capital
Source: CME and Morningstar

42. Looking Ahead: Crude Oil Anticipated
Production Growth and Product Flows
42
= Light/Sweet
= Heavy/Sour
= Pipeline
= Marine
= Rail
= Storage terminal(s)
= Refinery cluster – Light
Sweet/Intermediate
= Refinery cluster – Heavy
Sour/Intermediate
= Current b/d (000)
= Future b/d (000) additional by 2017
+420
123
Bakken
+855
704
Oil Sands
+982
1,615
Eagle Ford
+1,087
352
Permian
+607
514
Source: BENTEK Energy, CAPP, Railroad Commission of Texas, PLG Consulting

43. Thank You!
For follow up questions and information, please contact:
Taylor Robinson, President
+1-508-982-1319 / trobinson@prologisticsgroup.com
Graham Brisben, CEO
+1-708-386-0700 / gbrisben@prologisticsgroup.com
Jean Arndt, Vice President
+1-630-505-0273 / jarndt@prologisticsgroup.com
Jeff Dowdell, Senior Consultant
+1-732-995-6696 / jdowdell@prologisticsgroup.com
Gordon Heisler, Senior Consultant
+1-215-620-4247 / gheisler@prologisticsgroup.com
Jeff Rasmussen, Senior Consultant
+1-317-379-5715 / jrasmussen@prologisticsgroup.com
Jay Olberding, Analyst
+1-636-399-5628 / jolberding@prologisticsgroup.com
This presentation is available at:
WWW.PLGCONSULTING.COM
Professional Logistics Group
43