The document discusses the significant impact of shale development on the U.S. oil and natural gas industry, highlighting advancements in hydraulic fracturing and horizontal drilling that have increased production efficiency. It details the effects on logistics, including rail and transportation sectors, and the broader implications for industrial growth and energy markets. Additionally, it forecasts the potential growth in various sectors including chemicals, steel, and fertilizer due to abundant natural gas supplies.

1. Professional Logistics Group
Oil & Natural Gas:
The Evolving Freight
Transportation Impacts
Prepared for
July 9, 2013 Lake Geneva, WI
Midwest Association
of Rail Shippers

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
» Rapid evolution of drilling technology
 Fracking first used in 1947
 Revolutionary advances since 2009
 Time required for drilling 15,000+ ft. well cut
in half in last two years (nine days vs. 18)
 Dramatic increase in efficiency per rig,
making rig count alone no longer a significant
indicator of production
» US uniquely positioned for the
techniques
 Private mineral rights
 Drilling intensity (wells per acre)
 90% of rig fleet equipped for horizontal drilling
» Rapid ROI for E&P companies
 Typical well earns back capital cost in 1-2
years
 Depending on play productivity, “break even”
point of $40-85/bbl.
Source: L. Maugeri, Harvard Kennedy School; PLG analysis

5. US Shale Plays
5
Gas:
Marcellus
Haynesville
Barnett
Oil:
Bakken
Eagle Ford
Permian Basin
Most Active Plays
Utica (NGLs)
Niobrara
Mississippi Lime
Emerging Plays

6. Shale Driving Growth in Natural
Gas and Crude Oil Production
» 1,759 rigs in operation in USA as of June 21, 2013
» 700% increase in shale gas production since 2007
» Domestic oil production at 21-year high (7.35 MM
bbl/day)
» IEA projects US to surpass Saudi Arabia in oil output,
Russia in gas output by 2020
6Source: Baker Hughes 2013
GAS OIL THERMAL
Source: Baker Hughes
U.S. Crude Oil Production
Source: EIA
April 2013
7.35 MM bpd
Source: EIA
U.S. Natural Gas Annual Production
2012
24 Trillion cubic feet

7. 7
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
» Over $95B in new announced “energy intensive” industrial plant expansions will come on-line over the next five years
» Shale development impact on the railcar industry is long-term, wide-ranging, and positive with only one exception

8. Hydraulic Fracturing Materials Inputs
and Logistics – Per Well
8
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

9. 9
Correlation of Operating Rig Count
with Sand and Crude Shipments
STCC 14413 (sand) and 13111 (petroleum) Source: US Rail Desktop, Baker Hughes
1,695
1,814
1,270
886
939
1,073
1,299
1,467
1,604
1,6651,691
1,798
1,911
1,9721,9481,965
1,864
1,7631,7621,759
0
500
1000
1500
2000
2500
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
2007 Avg. 2008 Avg. 2009 2010 2011 2012 2013
OperatingOnshoreRigs
Carloads
Operating On Shore Rigs
All Sand Carloads
Petroleum Carloads

10. All Sand Handled by Railroad
10STCC 14413 Source: US Rail Desktop

11. Sand Mining Overcapacity:
New Reality
11
» 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

12. Processed Sand Total
Delivered Cost
Source: PLG analysis 12
» 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

13. 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
13Source: PLG analysis

14. 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
 Market is still trying to find its feet
» 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
14

15. 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
15

16. 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
» Lower gas prices have resulted in 10-
13% market share capture from coal for
thermal generation
» 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
16

17. Source: EIA, Deloitte
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
17

18. Shale Related Rail Traffic Still Small
Relative to Coal Volumes
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
2008
2009
2010
2011
2012
2013
Sand
Crude
Coal
Carloads
Quarterly Data
Railcars Handled: Sand , Crude & Coal
Sand
Crude
Coal
STCC 14413 (sand), 13111 (petroleum), 11212 (coal) Source: US Rail Desktop 18

19. 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
19
$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

20. Shale Gas Driving Steel
Manufacturing Comeback in US
20
» 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
 Potential US Steel-Republic Steel JV to produce DRI
 DRI-derived steel of higher quality than that created from recycled scrap, further
driving demand

21. Shale Gas Development Impact
on Fertilizer Market
» Natural gas is a feedstock for ammonia production
 Represents ~70% of cash costs (CF Industries)
» 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
» Rush of new plant announcements has sparked
oversupply concerns, cancelations (Yara, Agrium) 21

22. Looking Ahead: Natural Gas
» Oversupply conditions expected to persist
through 2015
» 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
22

23. LNG Export Opportunity
» Political/policy battle between domestic industrial users and producers
» Sabine Pass, LA and Freeport, TX now permitted for exports
 3.4 Bcf/day export capacity to come online by 2015
 Represents ~5% of projected US dry gas production
23
Source: Waterborne Energy Inc. Data in $US/MMBtu
Source: Congressional Research Service, EIA
Selected US Natural Gas Import & Export Infrastructure
» 20 additional terminal applications
totaling 29 Bcf/day of export capacity
pending before FERC

24. Shale Development NGL Impacts
» Leading NGL and “wet gas” plays are Eagle
Ford, Utica
 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
24

25. Source: American Chemistry Council, May 2013
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
 Planned expansions will increase US 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)
25Source: EIA
 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. 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
26

27. Looking Ahead: NGLs
27
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”
 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
 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

28. Shale Development
Crude Oil Impacts
» Dramatic increases in US production due to fracking
 7.35 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
 North America should be crude oil independent by 2018 (total bbls produced)
28Source: Morgan Stanley, February 2013

29. 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
29Source: BENTEK Energy

30. Bakken Oil Production and Logistics
30
» 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 ~$3)
North Dakota Crude Oil Production
~793,000 BPD April 2013
First outbound unit
train shipment
December, 2009
Source: EIA, PLG
Source: North Dakota Pipeline Authority, PLG Analysis

31. Crude Oil by Rail – North
Dakota Terminals
31
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
BNSF Total Capacity 740,000 740,000 740,000
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, and Gascoyne 30,000 30,000 30,000
Total Crude Oil Rail Loading Capacity 925,000 975,000 975,000
*Project still in the review or proposed phase Year End System Capacity
Source: North Dakota Pipeline Authority (June 2013), PLG Analysis

32. North Dakota Class I Railroads and
Crude Oil Terminals
32
Map by PLG Consulting

33. 33
All Crude Handled by Railroad
Volume Growth
STCC 13111 Source: US Rail Desktop

34. 34
Bakken Area
Outbound Pipelines
3434
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 (June 2013)

35. 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 850,000 565,000 925,000 1,300,000 68,000 1,558,000 708,000
2014 980,000 875,000 975,000 1,300,000 68,000 1,918,000 938,000
2015 1,150,000 1,075,000 975,000 1,350,000 108,000 2,158,000 1,008,000
Source: North Dakota Pipeline Authority, PLG AnalysisBpd = Barrels per Day
35

36. Crude Oil Pipelines – Existing
and Planned
36Source: CAPP Report, 2013
» Current pipelines ex.
Bakken operating below
capacity
 However, volumes have increased
over past 60 days
» Pipeline industry has been
challenged by new dynamic
NA oil market
 Fixed routes, long lead times
 10 year commitments required for
new build pipeline projects
 Lack of subscription interest in KM
Freedom project (Permian-
California)
» Several natural gas pipeline
conversions planned
 Trunkline (ETP) – Patoka, IL-St.
James, LA
 Energy East (TransCanada) –
Hardisty, AB-St. Johns, NS

37. 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 37
» 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

38. 38
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)
 Heavy/sour has higher sulfur content, yield for asphalt, diesel
» 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, California
» 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
 Dilbit via rail requires coiled, lined/insulated cars
» US is close to saturation point on light/sweet crude
at mid-continent and USGC refining areas 38
Source: CAPP, June 2013
Source: Turner Mason, RBN Energy
US Crude Oil Production
Growth by Grade

39. 39
Shale Development and Crude By
Rail Impact on Market Dynamics
» Price differentials driving trading and logistics patterns
» Original objectives (2009-2010) of crude by rail to “bridge the gap” until pipelines built
» By 2012, crude by rail viewed as a core mode of transportation and means of arbitrage
 Differentials made rail attractive: Bakken and WTI trading at ~$10-$15/bbl. less than Brent; Alberta Bitumen trading at
~$30/bbl. less than Brent
39
 Market response: E&P, midstream players willing to
rapidly deploy significant capital to enable access and
capitalize on spreads
– 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)
» Today: Spreads have narrowed, limiting arbitrage
opportunities and slowing crude by rail volumes

40. Crude Transportation Costs
June 2013
Oil Sands
Bakken
Gulf Coast
Refiners
East Coast
Refiners
Pacific NW
Refiners
Cushing, OK
= Pipeline
= Rail
= Marine
40Sources: Various industry sources, pipeline tariffs, PLG analysis

41. $86
Bakken wellhead
Gulf Coast Refiners
East Coast Refiners
Pacific NW Refiners
$94
Cushing, OK
= Pipeline
= Rail
$81
Oil Sands
Light/Sweet at USGC
Bakken (pipe): $96.50
Bakken (rail): $101
Brent (ship): $101.50
Heavy/Sour at USGC
Mexican Maya (ship): $96
WCS (pipe): $99
WCS (rail): $104.50
Light/Sweet at LA Gulf
Bakken (rail): $101
LLS (local): $103
LA Gulf Refiners
Light/Sweet at East Coast
Bakken (rail): $100.50
Brent (ship): $101
Light/Sweet at PNW
Bakken (rail): $98.50
Brent (ship): $101
Crude Price Differentials By Source,
Grade, and Destination – June 2013
$91
Bakken - Clearbrook
Sources: EIA, Bloomberg, Platts,
Baytex Energy, PLG analysis
Dec. 2012 Spread Current Spread Change
Brent - WTI $21.83/bbl $5.94/bbl -$15.89/bbl
LLS - WTI $20/bbl $7.90/bbl -$12.10/bbl
Mexican Maya - WCS $33.55/bbl $15.27/bbl -$18.28/bbl
WTI - Bakken (Clearbrook) $3/bbl $3/bbl $0/bbl
41

42. 42
Crude Tank Car Market Conditions
» Potential bottleneck: Railcars
 Current order backlog runs to early 2015 (~48,000 cars)
 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
 Short term demand is highly dependent on WTI – Brent
spread
» Railcar type is important
 General service 31k gallon capacity cars can hold more
crude than heavier coiled cars
 Coiled cars can transport heavier crudes that need heat to
offload
– Some shippers prefer the general purpose (GP) rail cars because the
larger capacity can be significant on their transportation cost for hauling
lighter crudes
– Some lessors prefer to have more coiled cars that have more uses than
general service cars built to hedge themselves on an oversupply of
general service tank cars if/when the crude by rail market declines
» Key question: If/is/when will the crude tank car
industry become overbuilt? 42

43. 0
500
1,000
1,500
2,000
2,500
3,000
Mar-13 Sep-13 Mar-14 Sep-14 Mar-15 Sep-15
Thousandbbl/day
Best-Case Crude by Rail Potential vs. Crude
Railcar Capacity
Other Production Sources Williston (Bakken)
Oil Sands Crude Railcar Capacity
Forecast of Crude Railcar
Supply and Demand
43
» Production increases vs.
railcar capacity increases
 March crude fleet was ~30k cars and
backlog was ~48.2k Backlog runs
through mid 2015
 If pipelines and local refining can
consume production increases in
Permian and Eagle Ford, crude by
rail will be primarily Bakken and
Canadian Oil Sands productions
» Under best-case scenario for
rail market share capture, data
suggests existing & planned
tank car fleet exceeds
demand
Sources: CAPP, AAR, NDPA,
GATX, and PLG analysis
Railcar backlog is through mid 2015,
retirement of old railcars will reduce
capacity if no additional railcars built
Q1 2013 originated rail carloads of crude
petroleum were 97,135, which equates to
755,000 barrels per day (assume 700/bbl.
average capacity)
Assumptions:
• 80% of projected Williston Basin production
• 80% utilization of Oil Sands announced 300 kbpd of rail terminals through 2014, and 80% utilization of an additional 300
kbpd for 2015
• 30,000 crude railcars in March and build rate of 21,500 railcars/year through 2015 with attrition rate of 7,800
railcars/year
• 700 bbl. average railcar capacity and average 17 day turn

44. 44
Looking Ahead: North American
Crude Oil Logistics
» 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
» 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 threats to crude by rail business
1. Narrow WTI-Brent spread
2. Glut of Permian and Eagle Ford light sweet oil displacing rail volumes to USGC to
Gulf Coast (but somewhat offset by new rail deliveries from Oil Sands)
3. Continued pipeline development
4. Water-borne Eagle Ford crude deliveries to USEC
44
Key
Drivers
Supply Sources
Oil
Prices
Destination
Markets
Capital
Source: CME and Morningstar

45. Looking Ahead: Crude Oil Anticipated
Production Growth and Product Flows
45
= 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
+492
871
Oil Sands
+605
1,985
Eagle Ford
+800
800
Permian
+480
1,200
Source: BENTEK Energy, CAPP, Railroad Commission of Texas, ND Pipeline Association, PLG Consulting

46. 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
46