Naftanext04242014final

Logistics Engineering Supply Chain
New Energy:
The Game Changer
in North America
ByTaylor Robinson & Graham Brisben
Prepared for:
April 24, 2014
NAFTANEXT
Energizing Sustainable
Trade Corridors Across
North America

2
Boutique consulting firm with team members
throughout North America
 Established in 2001
 Over 90 clients and 250 engagements
 Significant shale development practice since 2010
Practice Areas
 Logistics
 Engineering
 Supply Chain
Consulting services
 Strategy & optimization
 Assessments & best practice benchmarking
 Logistics assets & infrastructure development
 Supply Chain design & operations
 Hazmat training, auditing & risk assessment
 M&A/investments/private equity
Industry verticals
 Energy
 Bulk commodities
 Manufactured goods
 Financial services
About PLG Consulting
New Energy: The Game Changer in North America
Partial Client List

3
Today’s Agenda
Taylor
 What is “new energy” and why is it a game changer?
 Impact of new crude oil, natural gas and NGL supply streams
 Downstream impact on NAFTA manufacturing industries
 What is the impact to Mexico?
 Will the rest of the world catch up in shale?
Graham
 Changes in North America energy logistics

4
What is behind the North American energy revolution?
Resources
• N.A. shale plays
• Western Canadian
oil sands
Technologies examples
• Hydraulic fracturing
• Horizontal drilling
• Steam Assisted
Gravity Drainage
(SAGD)
• Evolving exploration
and production
technologies
• Tremendous
productivity gains
drives cost reductions
• Logistics infrastructure
“re-plumbing” in
progress
• Product abundance…
overabundance
• Imports displaced…
exports grow
• Recoverable resources
grow…sustainability
• Globally competitive
power and material
cost structure
• Manufacturing
industries grow/return
to North America
Recoverable
Resources &
Enabling
Technologies
Continuous
Improvement
Energy Revolution

5
Unconventional Energy Resources
North America Shale
Source: EIA, May 2011
Western Canada Oil Sands
Source: CAPP, About Oil
Sands, June 2013
 New production technology developed by small
entities allowing numerous players to enter market
 “Mass production” methodologies developed
 Multi-billion dollar capital investments required by
few players
 Technology allowing for economic recovery of
world’s third largest reserve

6
Convergence of hydraulic fracturing and
horizontal drilling in past decade
 Fracking first used in 1947
 Revolutionary advances since 2009
 Yields 3-10x the initial production rate of conventional
wells
US uniquely positioned for the techniques
 Private mineral rights
 Drilling intensity (wells per acre)
 90% of rig fleet equipped for horizontal drilling
 Location of shale plays
Rapid ROI for E&P companies
 Typical well earns back capital cost in 1-2 years
 Depending on play productivity, “break even” price of
~$65/bbl (WTI) for oil and $3.50/Mbtu for gas
 Liquid plays providing highest returns currently and a
majority of drilling rigs are focused on liquids
 Intentional dry gas drilling still flat
ShaleTechnology Introduction
GAS OIL THERMAL
Source: Baker Hughes

7
New fracking techniques include:
More well bores per well pad
 Directional bores to multiple shale layers
 Reduced well spacing per acreage – increases
 Zipper wells – stimulating two wells in tandem
Optimal lateral lengths
 Lateral lengths had tripled since the start of horizontal
drilling, but this trend is being challenged by new practices
Zone fracturing
 Micro-fracture testing at multiple points vs. one average
test that enables highest extractions of each zone
Shorter, fatter fractures
 Bigger holes in casing combined with additional sand and
water use
Productivity gains continue!
 Time required for drilling 15,000+ ft. well cut in half in last
two years (9 days vs. 18 days)
 Eagle Ford example – new well oil production per rig has
increased by 150% over past 3 years
 Lowers break even costs drive profitability improvements
New Fracking Techniques Drive Increased Production At Lower Costs
Source: Marathon, February 2014
Source: EIA Drilling Productivity Report, April 2014

8
Oil (bitumen) recovery uses two main methods
- mining and drilling (in situ)
 20% of the Oil Sands reserves are close enough to the
surface to be mined using shovels and trucks (3% of oil
sands land area)
 80% of the Oil Sands reserves will be recovered in situ by
drilling wells (97% of oil sands land area)
Steam Assisted Gravity Drainage (SAGD) is
most popular method
 Two parallel wells are drilled
 Upper well has high pressure steam continuously injected
 Lower well recovers softened bitumen
Diluent is added to the bitumen (15~30%)
 Diluent is very light oil or “condensate”
 Enables the product to flow through pipelines and be
loaded into rail cars
Bitumen extraction has become profitable as
extraction technologies improved
 Economical at ~ $ 45 - $ 65/bbl
Oil Sands Production Processes
Mining
Source: www.epmag.com
Drilling - SAGD

9
North American Crude Oil Growth
Source: Valero Investor Presentation, March 2014
Western Canadian oil sands crude is heavy/sour
 Canada has the 3rd largest oil reserves in the world
 Largest single play in North America
 Heavy/sour crude has a natural home at US Gulf Coast with ~2.8
MM bpd demand
 Increasing exports toAsia in the future
Shale play crudes are light/sweet
 Bakken, Eagle Ford and Permian are “Big 3”
 US crude is quickly displacing much of the imports at USGC and
Midwest refineries
 US crude oil production is highest since 1988 at 7.9MMbbls/day
US crude oil cannot be exported without federal
authorization today (except to Canada)
 Petroleum products can be exported and net exports have grown
to 1,950 kbpd in 2014-Q1 (gasoline, diesel)
 Light shale crude quickly displacing foreign imports and may lead
to over-supply situation
 Large amounts of very light crude (“condensate”) from shale is
driving investment into splitters (processing units) to enable
product export from USGC
Source: Enbridge Investor Presentation, April 2014
North American Crude Supply Growth: 2013-2025

10
Shale Supply Chain and Downstream Impacts
Feedstock (Ethane)
Byproduct
(Condensate)
Home Heating
(Propane)
Other Fuels
Gasoline
Diesel
Gas
NGLs
Crude
Proppants
OCTG
Chemicals
Water
Cement
Generation
Process Feedstocks
All Manufacturing
Steel
Fertilizer (Ammonia)
Methanol
Chemicals
Petro-chemicals
Other Petroleum
Products
Inputs Wellhead
Direct
Output
Thermal Fuels Raw Materials
Downstream
Products
Jet Fuel
Availability of low cost hydrocarbons positively impact all the North American industrial
economy

11
Shale Gas History and Future Demand
Gas production has increased over past five years
with a significantly lower gas rig count
 1,000 rigs at peak down to ~300 rigs
 Drilling productivity continues to increase production per well
and lower costs
 And the Liquids (Crude, NGL) wells produce dry natural gas as a
by-product
Abundant US gas recoverable reserves
 Low cost reserves in accessible locations near population
 Marcellus gas production is the “eighth largest country” already
 US will become a net gas exporter by 2020
US gas demand will grow due to:
 Coal-fired generation plant converting to gas
 More industrial use – steel, fertilizer, methanol
 Mexican export via pipeline and LNG export overseas
 Increasing use as transportation fuel
US gas cost competitiveness is sustainable
 Supply will overwhelm demand as prices approach $5
 US government and capital constraints will likely limit LNG
export to protect US from world gas market price
Rig Count by Class vs. Gas Production
Source: Bentek, September 2013
Source: RBN Energy, January 2014

12
Shale Gas Is ImportantTo Competitive Power Costs
Natural gas is ~5X cheaper than oil on
a BTU-basis
 Innovation will convert more transportation
fuels and other energy requirements to
natural gas
US electricity prices are the lowest in
the industrial world
 US industries now have substantial power
cost advantage
 Gas drives an increasing share of the US
electricity generation capacity
 Will continue to displace coal due to stricter
environmental regulations on coal-fired
facilities
Natural gas is a cleaner burning fuel
compared to other hydrocarbons
WTI & Henry Hub Natural Gas Energy Equivalent Pricing
Source: EIA, February 2014
~5X
Source: International Energy Agency, October 2013 *estimate

13
Dry andWet GasTurn Into Downstream Products
 All shale plays have gas as a major
or minor portion of the product stream
 Processing required at each step
Raw Natural Gas
(1500+ BTU)
Processing Plant
Consumer Quality
Dry Natural Gas
Methane
Ethane
42 – 65%
Propane
~28%
Normal Butane
~8%
Iso-Butane
~9%
Natural Gasoline
~13%
NGLs
(3 -9 gallon / MCF)
Y-Grade
Key Petrochemicals
$/MMBtu
Methane $4.53
Ethane $3.64
Propane $11.41
Iso-Butane $16.01
Normal Butane $11.43
Natural Gasoline $20.35
Source: Opis, April 2014 & CME Group, April 2014
“Dry”
“Wet”
Ethane
overabundance
causing deflated
pricing

14
Processing infrastructure being installed to
handle increased NGL supply
 New facilities near shale plays
 Domestic ethane supplies to quadruple by 2025
 Exports of NGLs will continue to grow
NGLs are building blocks in chemical supply chain
 US has shifted their petrochemical supply stream to >90%
ethane-based to leverage supply/cost advantage
Overabundance of NGLsWill Grow
Source: IHS Chemical, September 2013
Source: IHS Energy

15
2008 2010 2012 2014 2016 2018 2020
Shale Development: The Evolving Transportation Impacts
Source: American Chemistry Council, February 2014
>$100B of Chemical Expansion
Announced
Phase III – “Manufacturing”:
Raw material cost driven
Phase I – Industries using gas as primary
feedstock have global cost competitiveness;
new US factories being built
Phase II – Downstream products require
significant processing facilities investment and
lead time
Phase III – US material cost advantage will
enable traditional manufacturing to return to
the NorthAmerica as about 65% of the cost of
manufactured product is material cost
Shale Gas Phased ImpactTo NA Industrial Renaissance
Phase II - Downstream Products:
Resins, Chemicals
Phase I - Gas & Power-intensive Industries:
Steel, Fertilizer, Methanol

16
Phase I - Steel, Methanol, & Fertilizer Manufacturing in US
Shale gas boom makes direct-reduced iron steel
economical
 Gas strips oxygen from iron core to make high purity/quality
pellets – lower cost vs. scrap steel
 $2B+ in new US projects announced
 DRI-derived steel of higher quality than that scrap steel
U.S. methanol production – 10 projects announced
 Methanol is used in numerous downstream chemical products
 Captures price spread between low-cost natural gas and
methanol allowing move to higher value foreign markets
 US currently represents 10% of the global market demand and
imports 89% of its supply
Natural gas is a feedstock for ammonia production
 Represents ~70% of cash costs (CF Industries)
 12MM mt new domestic manufacturing capacity announced
 Imports will quickly be displaced
Source: IHS Energy, September 2013
Falling Gas Prices a Boon to DRI
Production
Source: GE Capital presentation, November 2013

17
Phase II - Low Cost NGLs Provides Significant Cost
Advantages for Chemicals and Resins
US has a large structural cost advantage due to gas-based
ethane for downstream products
 Europe and Asia are tied to crude-based naptha as a feedstock for their
downstream processing
 US production cost of ethylene is ~40% less than Europe and Asia
However, US ethylene cracker and processing capacity is
tight and ethylene prices are inflated in the short term
 Ethane cracker margins have been as high as 50-60 cents/lb
 Additional cracker capacity expected in 2016/2017
 Margins/prices will moderate as more capacity comes online
 New US resin facilities also on the drawing board
 Excess resin capacity will promote globally competitive prices and large
export increases
ktons
ktons
Source: Townsend Solutions, December 2013
Source: Townsend Solutions , December 2013
30,000
40,000
50,000
2012 2013 2014 2015 2016 2017 2018 2019 2020
North America Ethylene Expansions
Actual Capacity Additional Capacity
Source: Townsend Solutions , December 2013

18
Phase III - Material Cost Advantage Is Key Cost Driver to
Future North American Manufacturing Growth
Materials normally accounts for 60-70% of manufacturing
cost of goods sold (COGS)
 Most product cost competition is won or lost here
 Shale gas giving NA cost advantage for steel, plastics and chemicals
Total labor cost is ~20% of COGS for NA manufacturers
 China labor cost in $ will continue to rise due to inflation and currency
appreciation
 Mexico labor has increased competitiveness vs. China, will recapture
manufacturing share for medium/high labor manufacturing
Transportation & Logistics costs are in “Other” 15%
 Asia/China has 5~10% cost disadvantage due to extra ~ 1 month shipping
lead time (major cash flow disadvantage)
 Mexico has “near shore” advantage vs. Asia
 Transportation costs continue to rise – proximity to market advantage
Energy cost is usually less than 5% for final manufacturer
 However, energy costs are buried in raw material costs and transportation
and can be more substantial in energy-intensive products
 US/Canada has a tremendous advantage vs. industrialized world
 Mexico’s power costs will become more competitive with shale gas

19
Energy Revolution ImpactTo Mexico
Shale gas exports to Mexico
 Mexico is net importer of natural gas and demand will
grow due to increased use for power generation
 US imports via pipelines will grow by ~50% over next 5
years
Privatization of Mexican oil industry may
help reverse production slide
 Shale potential in Mexico – Eagle Ford first mover?
 Increased interested in deep water oil drilling
However, western Canadian bitumen is a
natural competitor to Mexican Maya
Low cost materials to Mexico from US will
stimulate further manufacturing growth
Source: EIA, March 2014
Source: EIA, October 2012

20
December 2013 energy bill that removed the
prohibition against private investment in oil and
gas industry
 Legal framework for oil and gas development is still not finalized
which will be important for private investment to understand taxes
and contracts before investing
Mexico’s proximity to US refineries and their
relative low costs of production make it potentially
attractive to US companies
 Developers of deep water resources in Gulf of Mexico
 Developers of shale plays such as part the Mexican portion of the
Eagle Ford
Mexico still in early stages of shale oil drilling
 Only a few wells with modest results have been drilled
 Pemex plans to drill up to 75 shale exploration wells through 2015
 US companies could leverage technology and experience to
improve economics to make commercial production viable
 Estimated first private investment contracts could materialize by
2015 with first investments seen in 2016
Liberalization of Mexican Oil Industry
Source: OGJ, April 2014

21
Russia
 Siberian reserves are said to be 80X of Bakken
 Total, Shell, Exxon, Statoil all investing
 Second place soon?
China
 Reserves in remote, mountainous locations
 Technology transfer challenges
 Only one oil company involved – stifles innovation
Argentina
 Concerns with governmental regulation, price controls
 Struggling with high cost proppants
Poland
 Reserves not productive so far – Exxon, Marathon gave up
 Encouraging recent results?
UK
 Some gas reserves
 Government support, but intense environmental opposition
Is Shale Energy A North American Phenomenon?
Source: EIA, June 2013
0
10
20
30
40
50
60
70
80
Shale Oil Resources
(Billion bbls)
0
200
400
600
800
1,000
1,200
Shale Gas Resources
(Tcf)
Technically Recoverable Resources, Source: EIA, June 2013

22
Shift from coastal to mid-continent
supply points necessitated “re-
plumbing” the flow of carbon-based
energy in North America
 Pipeline reversals, repurposing, new starts
 Crude by rail comes of age – born in the Bakken
Waterborne imports being displaced
as shale oil and oil sands production
comes online
Infrastructure built rapidly to help
facilitate new energy movements
The “Re-Plumbing” of Hydrocarbons in North America
Source: Enbridge, April 2014
Oil
Sands
Bakken
Eagle
Ford
Permian
Marcellus
Source: EIA, PLG Analysis (Google Earth), April 2014

23
Repurposing and retirement of some
existing pipelines
 New natural gas production has localized the
supply of natural gas for certain areas, therefore,
decreasing the need for some existing natural gas
pipelines
 Some natural gas pipelines being converted to
crude oil
New natural gas pipelines are being
built to transport natural gas out of
Marcellus
 Together the proposedAtlantic Sunrise project
and SabalTrail project would connect Marcellus all
the way to Central Florida
 Many other smaller pipeline projects are occurring
to move Marcellus natural gas
Historic reversals of import/export
trade flows
 Northeast US-Canadian Maritimes
New Patterns in Natural Gas Supply & Demand
Natural Gas Movements

24
Natural Gas Liquids (NGLs)
Pipelines from Utica/Marcellus
 Mariner East to Marcus Hook, PA for export
 MarinerWest exports to Sarnia, ON
 ATEX to Mt. Belvieu,TX
 Proposed Utica MarcellusTexas Pipeline to Mt.
Belvieu,Texas (conversion of natural gas
pipeline for most of the route)
New NGL export projects
 Facility expansions and new construction
projects in Ferndale,WA and Port of Longview,
WA
 Further expansions proposed by Enterprise
andTarga in their Gulf Coast export facilities
 Phillips 66, EnergyTransfer,
Williams/Boardwalk and Occidental have all
proposed export facilities out of the Gulf Coast
Natural Gas Liquids Pipelines and Export
Source: MarkWest, PLG analysis, March 2014
Sarnia, ON
Mt Belvieu, TX
Marcus Hook, PA
Source: RBN Energy, January 2014

25
Basic Facts About Crude Oil – Grades and Qualities
Heavy/sour
 Higher sulfur content, yield for asphalt & diesel
 Sources include
 Western Canada (largest single play in North America)
 Venezuela
 Mexico, Alaska North Slope
 Middle East (light/sour)
 Significant investments made ($48B since 2005) at select
refineries to install coker units that will allow processing of
heavy/sour
 Heavy/sour crude has a natural home in Midwest and US
Gulf Coast (~2.8 MM bpd demand at USGC)
Light/sweet
 Brent,WTI, and US shale play crudes (Bakken, Permian,
Niobrara, Eagle Ford) are light/sweet
 US is close to saturation point on light/sweet crude at mid-
continent and USGC refining areas
Source: RBN Energy

26New Energy: The Game Changer in North America
Light/Sweet Crude Logistics
Sources: EIA, PLG analysis (Google Earth)
Pacific
Northwest
Refiners
California
Refiners
2,525
kbpd
PADDV
Demand
Midwest Refiners
3,375
kbpd
PADD II Demand
East Coast
Refiners
PADD I Demand
1,075
kbpd
LA Gulf Coast
Refiners
TX Gulf Coast
Refiners
PADD III
Demand
8,150
kbpd
Bakken
Eagle Ford
Permian
Rail
Pipeline
Marine
Light/Sweet
Heavy/Sour
ANS
Brent
Brent

Sources: EIA, PLG analysis (Google Earth)
Light/Sweet
Heavy/Sour
Pacific
Northwest
Refiners
California
Refiners
2,525
kbpd
PADDV
Demand
Midwest Refiners
3,375
kbpdPADD II Demand
LA Gulf Coast
Refiners
TX Gulf Coast
Refiners
PADD III
Demand
8,150
kbpd
Oil Sands
Heavy/Sour Crude Logistics
Rail
Pipeline
Marine
Mexican Maya

28
Refined Products Market Dynamics
U.S. shifted to net exporter of refined
products
 Mitigated the impact of declining domestic demand
 International demand increasing, especially for diesel
 Exports of diesel to Latin America and Europe
 Gasoline exports to Latin America
Outlet for increasing domestic crude oil which
cannot be exported without being processed

29
All oil sands pipelines are under
intense scrutiny and subject to court
challenges
None of these developments will
proceed at a pace that will match
anticipated production levels
Canadian Oil Producers adopting CBR
as a risk mitigation measure to ensure
access to markets in North America
and offshore
Main driver of crude by rail out of
Western Canada will be delta between
pipeline capacity and crude oil
production
Expect Keystone XL to be built but
with more delays
Western Canada Crude Oil Pipelines
Likely Built at Some Point
 Trans Mountain Express
(Kinder Morgan)
 Alberta Clipper (Enbridge)
 Keystone XL (TransCanada)
Unlikely
 Northern Gateway
(Enbridge)
 Energy East
(TransCanada)

30
Large pipeline build toTexas Gulf
Coast
 1.45 MMb/d added in 2012-2013 and 1.92
MMb/d to be added in 2014-2015
 Large pipeline projects from Cushing
including Keystone Gulf Extension and
Seaway pipelines
 Other pipeline projects from Permian,
Eagle Ford, and Midwest
Bakken pipeline export capacity
projected to increase to 715 kbpd
in 2014 from only 280 kbpd in 2010
(NDPA, January 2014)
US Crude Oil Pipelines
Pipeline Capacity to Texas Gulf Coast
Source: RBN Energy, December 2013

31
Correlation of Operating Rig Count with Sand and Crude Carloads Handled
STCC 14413 (sand) and 13111 (petroleum) Source: US Rail Desktop, Baker Hughes, Surface Transportation Board, PLG Analysis, March 2014
0
500
1,000
1,500
2,000
2,500
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
2007 Avg. 2008 Avg. 2009 2010 2011 2012 2013
OperatingOnshoreRigs
CarloadsHandled
Operating On Shore Rigs
All Sand Carloads
Petroleum Carloads

32
Shale Related RailTraffic Still Small Relative to CoalVolumes
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
Sand
Crude
Coal
Railcars Handled: Sand, Crude, & Coal
STCC 14413 (sand), 13111 (petroleum), 11212 (coal) Source: US Rail Desktop, Surface Transportation Board, PLG Analysis, February 2014

33
The Importance of Price Differentials to Crude by Rail
Differentials made rail attractive
 Bakken andWTI differential as high as ~$20/bbl vs. Brent
in 2012
 CBR enables producers to sell at trading hubs with higher
benchmarks
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 and at
destination markets (i.e. Cushing, OK, St. James, LA, Pt.
Arthur,TX,Albany, NY, Bakersfield, CA)
 Lease and purchase of railcar fleets
Refineries install unit train receiving capability
 Particularly coastal refineries previously captive to
waterborne imports (i.e. Philadelphia, PA, St. John, NB,
Washington state)
Pipeline capacity underutilized
 Rail captures 73% Bakken takeaway byApril 2013
Differentials are both an incentive – and a risk
– for crude by rail
 3Q 2013 a cautionary note
Source: North Dakota Pipeline Authority, January 2014, PLG Analysis
Source: North Dakota Pipeline Authority, PLG Analysis, April 2014
0
200
400
600
800
1,000
1,200
Jan-11
Feb-11
Mar-11
Apr-11
May-11
Jun-11
Jul-11
Aug-11
Sep-11
Oct-11
Nov-11
Dec-11
Jan-12
Feb-12
Mar-12
Apr-12
May-12
Jun-12
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mbbl/d ND Crude Production and RailTransport
ND Production Crude by Rail

34
Source: AAR, North Dakota Pipeline Association, Surface Transportation Board, PLG Analysis, February 2014
Crude by Rail Statistics
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
-
50,000
100,000
150,000
200,000
250,000
300,000
Mar-12 Jun-12 Sep-12 Dec-12 Mar-13 Jun-13 Sep-13 Dec-13 Mar-14
Petroleum & Petroleum Products (carloads/quarter) Crude Originated (carloads/quarter) Williston Crude by Rail (bbls/day)
Carloads/Quarter Bbls/Day
WTI-Brent
equilibrium
3Q3012
WTI-Brent
equilibrium
3Q3013

35
Shale Development and Crude By Rail: Current Market Dynamics
Adverse 3Q 2013 market forces have reversed
 WTI-Brent spread now ~$5.50/bbl
CBR rebound driven by Bakken to coasts
 Weak long-term outlook for Bakken CBR to USGC
 Key driver: LLS now aligned withWTI, not Brent
“Next wave” of CBR development:
Canadian Oil Sands
 Terminal investments in Alberta and PADD II and III
 Over 1,300 kbbl/day planned AB loading capacity through 2015
 NOT like the Bakken – more challenges
 Complexities of heavy/sour product handling (steaming, diluent,
unit train challenges)
 Fewer destinations
 Existing – and growing – mode competition to logical markets
(pipelines and barge)
 Tank car market reorienting to coiled/insulated
car types (~2/3 of CBR fleet order backlog)
Source: EIA, April 2014
Brent vs.WTI Spread ($/bbl)
Source: RBN Energy, April 2014

Crude RailTerminalsThrough 2017
85 load terminals
Largest and most efficient
in Bakken
69 unload terminals
Majority on the Coasts and
Mississippi River
Source: www.CBRforecast.com

37
Bakken and Oil Sands Crude OilTakeaway Forecast
Source: www.CBRforecast.com
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2013 2014 2015 2016 2017 2018
Base CaseTakeaway (kbpd)
Pipeline
Crude by Rail
Local Refining

38
High Profile Accidents Changing Crude by Rail
Rail industry has a strong safety record, but optics of
CBR accidents are overwhelming any positive statistics
Industry, government, media focus on tank car design
Railroad operating practices, maintenance equally
important
 Railroad operating rule changes on hazmat train handling
 Increased scrutiny, insurance requirements
 Short line and regional railroads in particular
 May have consequences in CBR freight rates
Increased product testing, documentation and
traceability (FRA directive)
 Oil chemistry varies by well/pad
 Concerns with extremely low flash and boiling points
 Bakken terminals at varying levels of compliance

39
Bakken Crude HigherVolatility

40
LNG Export Opportunity
Political/policy battle between
domestic industrial users and
producers
Only FERC approved LNG export
terminal is Cheniere Energy’s Sabine
Pass LNG in Sabine, LA
Proposed US LNG ExportTerminals to
FERC (in Bcfd):
There are 12 other US potential export
terminals along with 3 Canadian
proposed sites and 10 other Canadian
potential sites
Supply Sources
Oil Prices
Destination
Markets
Capital
Data in $US/MMbtu
Source: Waterborne Energy from FERC presentation, February 2014
Location Bcfd Location Bcfd
Freeport, TX 1.8 Lavaca Bay, TX 1.38
Corpus Christi, TX 2.1 Elba Island, GA 0.35
Coos Bay, OR 0.9 Sabine Pass, LA 1.40
Lake Charles, LA 2.2 Lake Charles, LA 1.07
Hackberry, LA 1.7 Plaquemines Parish, LA 1.07
Cove Point, MD 0.82 Sabine Pass, TX 2.1
Astoria, OR 1.25

Panama Canal Expansion
 Has been delayed and now expected at full
capacity by 2016
 Current Panamax vessel size excludes all but
10% of LNG vessels from using the canal
 After expansion, 80% of LNG fleet will be
able to use the canal with vessel capacities
up to 100 MMcf
Benefits for N.A. LNG Exports
 Using the expanded Panama Canal will be a
natural fit for the large number of proposed
Gulf Coast export facilities wanting to reach
the growing Asian LNG market
 Trip time cut from 64 days to 44 days,
greatly improving the competitive position
of LNG exports by reducing transportation
cost
Panama Canal Expansion and North American Exports of LNG

Logistics Engineering Supply Chain
This presentation is available at:
www.plgconsulting.com/category/presentations
-
ThankYou !
For follow up questions and information,
please contact:
Graham Brisben, CEO
+1 (708) 386-0700 / gbrisben@plgconsulting.com
Taylor Robinson, President
+1 (508) 982-1319 / trobinson@plgconsulting.com

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