Ge customer webinar presentation final

Logistics Engineering SupplyChain
Crude: Resources,
Regulations &
Railcars
Prepared for:
June 17, 2014

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
Crude: Resources, Regulations & Railcars
Partial Client List

3
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

4
Unconventional Energy Resources
North America Shale Western Canada Oil Sands
Source: CAPP, About Oil
Sands, June 2013
 New production technology developed by small
entities allowing numerous players
 “Mass production” methodologies developed
 Multi-billion dollar capital investments required by
few players
 Production process will harvest oil over long term
Source: EIA, May 2014

5
Convergence of hydraulic fracturing and
horizontal drilling in last five years
 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
 Oil /Gas rig count split at ~80% / 20% from ~20% / 80%
five years ago
ShaleTechnology Introduction
GAS OIL THERMAL
Source: Baker Hughes

6
More well bores per well pad
 Directional bores to multiple shale layers
 Reduced well spacing per acreage – increases well density
 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 additionalsand 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 FrackingTechniques Drive Increased Production At Lower Costs
Source: Marathon, February 2014
Source: EIA Drilling Productivity Report, May 2014

7
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

8
Shale Supply Chain and Downstream Impacts
Feedstock (Ethane)
Byproduct
(Condensate)
Home Heating
(Propane)
Other Fuels
Other Fuels
Gasoline
Gas
NGLs
Crude
Proppants
OCTG
Chemicals
Water
Cement
Generation
Process Feedstocks
All Manufacturing
Steel
Fertilizer (Ammonia)
Methanol
Chemicals
Petroleum Products
Petro-chemicals
Inputs Wellhead
Direct
Output
Thermal Fuels Raw Materials
Downstream
Products
RAIL INDUSTRY DEMAND2010 onward 2016 onward

9
U.S. Frac Sand IndustryTrends
Sand
33%
Rail - Freight, FSC
and Eqp Lease
42%
Destination
Transload &
Trucking
25%
Total DeliveredCost perTon ~ $122
Source: PLG analysis using BNSF public pricing –
does not include fixed assets at origin or
destination, December 2013
Logistics costs drive
~ 67% of total
delivered sand cost
Rapid growth and maturation of both industries
(hydraulic fracturing and sand production) over the past
5 years
Sand supply base growing and consolidating at
the same time
 Mines continue to open; supply base is consolidating
 Large fluctuations in price of sand based on
supply/demand balance
Significant production growth beyond WI in IL and MO
due to new demand for 100 mesh sand
Unit train shipping is the game-changing logistics
development – spurring investment in larger load-out
sand transload facilities
“Benchmark” high-efficiency unit train example – Illinois
to South Texas
 Single-line haul (one rail carrier), private railcars achieving two round
trips per month, origin sand facility has direct rail load-out and
destination trucking is less than 100 miles

10
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 Source: RBN Energy, January 2014
0
10
20
30
40
50
60
70
80
0
500
1,000
1,500
2,000
2,500
Rig Count with Natural Gas Production
Gas Oil U.S. Natural Gas Production
rigs Bcf/d
Source: Baker Hughes, EIA, PLG Analysis, June 2014

11
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

12
2008 2010 2012 2014 2016 2018 2020
Source: American Chemistry Council, February 2014
>$100B of Chemical Expansion
Announced
Phase I - Gas & Power-intensive Industries:
Steel, Fertilizer, Methanol
Phase II - Downstream Products:
Resins, Chemicals
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 ImpactTo NA Industrial Renaissance
SHALE
GAS
BOOM

13
The “Re-Plumbing” of Hydrocarbons in North America
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
Source: Enbridge, April 2014
Oil
Sands
Bakken
Eagle
Ford
Permian
Marcellus
Source: EIA, PLG Analysis (Google Earth), April 2014

14
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 USGulf 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

15
Light/Sweet Crude Logistics
Sources: EIA, PLG analysis (Google Earth)
Light/Sweet
Heavy/Sour
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
ANS
Brent
Brent
Rail
Pipeline
Marine

16
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
OilSands
Heavy/Sour Crude Logistics
Rail
Pipeline
Marine
Mexican Maya

17
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 2014

18
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)

19
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, Jan. ’14)
Pipeline build-out from Guernsey,WY
 230 kbpd Pony Express pipeline to Cushing
(under construction)
 Possibility of twinning Express-Platte pipeline
system through Guernsey toWood River, IL
US Crude Oil Pipelines
Pipeline Capacity toTexas Gulf Coast
Source: RBN Energy, December 2013

20
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, May 2014
0
500
1,000
1,500
2,000
2,500
0
50,000
100,000
150,000
200,000
250,000
2007 Avg. 2008 Avg. 2009 2010 2011 2012 2013 2014
OperatingOnshoreRigs
CarloadsHandled
Operating On Shore Rigs
All Sand Carloads
Petroleum Carloads

21
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
2014
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, March 2014

22
0
200
400
600
800
1,000
1,200
Mbbl/d ND Crude Production and RailTransport
ND Production Crude by Rail
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, May 2014

23
Source: AAR, North Dakota Pipeline Association, Surface Transportation Board, PLG Analysis, May 2014
Crude by Rail Statistics
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
-
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
*
*2014-Q2 quarterly rate through May 24

24
Shale Development and Crude By Rail: Current Market Dynamics
Adverse 3Q 2013 market forces have reversed
 WTI-Brent spread now ~$5.50/bbl
CBR rebound driven by Bakken to coasts
 Weak long-term outlook for Bakken CBR to USGC
 Key driver: LLS now aligned with WTI, not Brent
“Next wave” of CBR development:
Canadian Oil Sands
 Terminal investments in Alberta and PADD II and III
 Over 1,300 kbbl/day planned AB loading capacity through 2015
 NOT like the Bakken – more challenges
 Complexities of heavy/sour product handling (steaming, diluent,
unit train challenges)
 Fewer destinations
 Existing – and growing – mode competition to logical markets
(pipelines and barge)
 Tank car market reorienting to coiled/insulated
car types (~2/3 of CBR fleet order backlog)
Source: EIA, May 2014
Source: RBN Energy, May 2014
Brent vs.WTI Spread ($/bbl)
Crude Oil Differentials ($/bbl)

25
Announced Crude RailTerminals
Through 2017
85 load terminals
Largest and most efficient
in Bakken
69 unload terminals
Majority on the Coasts and
Mississippi River

26
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

27
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

28
Bakken CrudeVolatility

29
U.S. energy officials considering easing federal
laws that prohibit exports of most crude
 Rising production of light oil / condensate that is not well-
matched to current U.S. refinery capacity
 U.S. currently classifies condensate produced at well crude oil
and there is a possibility it be reclassified as condensate which
would allow for exports
Implications if export ban is lifted
 Condensate would most likely be exported toAsia as a
petrochemical feedstock
 Brent (international crude benchmark) and LLS prices would
most likely converge as they are both light crude prices on
water
 “Landlocked” crude prices (ieWTI and Bakken) would most
likely rise higher closer to international prices
 Export of Canadian crude via the U.S. would be simpler without
the complication of keeping U.S. diluent separate from
Canadian crude
 Build out of new pipelines and terminals to export the crude
 Likely a decrease in U.S. refined products export volumes and
worse economics for U.S. refineries
Possibility of Lifting Crude Oil Export Ban
Source: RBN Energy, May 2014

Logistics Engineering SupplyChain
This presentation is available at:
www.plgconsulting.com/categories/presentations
-
ThankYou !
For follow up questions and information,
please contact:
Taylor Robinson, President
+1 (508) 982-1319 / trobinson@plgconsulting.com

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