Nafta next 04242014 final

Logistics Engineering Supply Chain

New Energy:

The Game Changer in North America

By Taylor Robinson & Graham Brisben

Prepared for:

April 24, 2014

NAFTANEXTEnergizing 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

Shale Technology 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


http://www.google.ca/url?sa=i&source=images&cd=&cad=rja&docid=SOCF1ROQEWbOwM&tbnid=FvuCLxhilXUYwM:&ved=0CAgQjRw&url=http://www.ramp-alberta.org/resources/gallery.aspx?galleryimage=965&ei=x8DpUojHFsHcoASJqILoCg&psig=AFQjCNFcddyIwCP7qtRHI-D-Y2Pc4BnO1A&ust=1391137351412286

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 to Asia 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 Important To 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 and Wet Gas Turn 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

Ethane42 – 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 deflatedpricing

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 NGLs Will 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 North America as about 65% of the cost of

manufactured product is material cost

Shale Gas Phased Impact To 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

k to

ns k to

ns


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 CapacitySource: 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 Impact To 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 proposed Atlantic Sunrise project

and Sabal Trail 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

Mariner West exports to Sarnia, ON

ATEX to Mt. Belvieu, TX

Proposed Utica Marcellus Texas 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

and Targa in their Gulf Coast export facilities

Phillips 66, Energy Transfer,

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 areasSource: 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

2,525kbpd

PADD VDemand

Midwest Refiners

3,375kbpd

PADD II Demand

East Coast Refiners

PADD I Demand1,075kbpd

LA Gulf Coast Refiners

TX Gulf Coast Refiners

PADD III Demand

8,150kbpd

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

2,525kbpd

PADD VDemand

Midwest Refiners

3,375kbpdPADD II Demand

LA Gulf Coast Refiners

TX Gulf Coast Refiners

PADD III Demand

8,150kbpd

Oil SandsHeavy/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

Source: Valero Investor Presentation, March 2014Source: Valero Investor Presentation, March 2014

Source: Valero Investor Presentation, March 2014

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 to Texas 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

Op

era

tin

g O

nsh

ore

Rig

s

Ca

rlo

ad

s H

an

dle

d

Operating On Shore Rigs

All Sand Carloads

Petroleum Carloads


32

Shale Related Rail Traffic Still Small Relative to Coal Volumes

0

500,000

1,000,000

1,500,000

2,000,000

2,500,0002

00

8

20

09

20

10

20

11

20

12

20

13

SandCrude Coal

Ca

rlo

ad

s

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 and WTI 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 by April 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

Ja

n-1

1F

eb

-11

Ma

r-1

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No

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-14

Mbbl/d ND Crude Production and Rail Transport

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 with WTI, 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 Rail Terminals Through 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 Oil Takeaway 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 Case Takeaway (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 Higher Volatility


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 Export Terminals 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 PricesDestination

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

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