Shale gas and
petrochemical
feedstock in
Alberta
Understanding
fracking,
environmental
impacts, and
feedstock availability
February 20, 2014
Carlos A. Murillo
Economic Researcher
Canadian Energy Research Institute
(CERI)
Image Source: ATCO Midstream
1
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Presentation Outline
•
•
CERI and Our Work
Understanding Shale Gas and Hydraulic Fracturing (Fracking)
•
Key concepts and definitions
•
Potential environmental impacts and mitigation measures
•
•
Focus on water
NGLs and Feedstock Availability
•
Quick introduction to natural gas liquids (NGLs) in Canada
•
Supply sources, end-use markets, and production trends
•
Overview and recent trends
•
Natural gas market dynamics
•
NGLs market dynamics and midstream infrastructure
•
Ethane overview & outlook
•
Propane overview & outlook
•
Opportunities & challenges
Image Source: Nova Chemicals
2
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Canadian Energy Research Institute (CERI)
Founded in 1975, CERI is an independent, non-profit research institute
specializing in the analysis of energy economics and related environmental
policy issues in the energy production, transportation, and demand sectors.
Our mission is to provide relevant, independent, and objective economic
research in energy and related environmental issues. A central goal of CERI is to
bring the insights of scientific research, economic analysis, and practical
experience to the attention of government policy-makers, business sector
decision-makers, the media, and citizens of Canada and abroad.
Our core supporters include the Government of Canada (Natural Resources
Canada), the Government of Alberta (Alberta Energy), and the Canadian
Association of Petroleum Producers (CAPP). In-kind support is also provided by
the Alberta Energy Regulator (AER) and the University of Calgary.
All of CERI’s research is publicly available on our website at:
www.ceri.ca
3
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Our Work:
Current Work (2013 – 2014):
•
Natural Gas Liquids in North America: Detailed Overview and Emerging Trends
•
Natural Gas Liquids in North America: Updated Outlook
•
North American Oil Pathways (ICF Marbek, what-if?, S2S)
•
Yukon/ Northwest Territories Economic Impacts
•
Energy I/O
•
Many more…
Recently Released Reports (2012 – 2013):
•
Recent Foreign Investment in the Canadian Oil and Gas Industry
•
North American Natural Gas Pathways
•
Conventional Natural Gas Supply Costs in Western Canada
•
Many more…
Periodicals/ Monthly Reports:
•
Crude Oil Commodity Report
•
Natural Gas Commodity Report
•
Geopolitics of Energy (Subscription Service)
Annual Conferences:
•
Natural Gas Conference (March 2014)
•
Oil Conference (April 2014)
•
Petrochemical Conference (June 2014)
Kananaskis = Golf!
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Natural Gas Liquids (NGLs) Study Update:
Part I (Forthcoming: March 2014)
•
Natural Gas Liquids (NGLs) in
Canada
•
Upstream
•
•
Midstream & Downstream
•
•
Infrastructure investments in Western
Canada
Supply/ Demand Balances and
Economics
•
•
Changing natural gas dynamics in
North America
Downstream investments and
understanding global markets (NGLs
and petrochemicals)
Part II: NGLs in North America:
Updated Outlook (Spring 2014)
•
Based on four natural gas production
scenarios
5
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Understanding Shale Gas
& Hydraulic Fracturing
(Fracking)
Image from Husky
Relevant • Independent • Objective
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Shale gas within the context of
unconventional natural gas – Key
definitions
Unconventional gas resources: include natural gas
resources from coal (also known as coal bed methane
(CBM)), tight gas sands (sandstone, siltstone, and
carbonates), gas shales (shale rock), and methane
hydrates. Same substance as conventional resources
(raw gas), but different reservoir characteristics, more
difficult to extract, and usually requiring stimulation
technologies. Becomes commercially developed as
technological/ economic limitations are overcomed
Shale gas: natural gas stored in in low permeability
shale rock formations which are generally thick,
laterally extensive, dark-colored, and organic-rich.
Every shale formation is different and unique
Permeability: a rock’s capacity to transmit a fluid or
gas. Depends on porosity and pore connectivity.
Permeability may be enhanced through reservoir
stimulation
Reservoir stimulation: a process designed to enhance
reservoir permeability and stimulate production
Hydraulic fracturing (fracking): a reservoir stimulation
process designed to improve reservoir permeability by
pumping fluids (such as H2O, CO2, N2, or C3H8) at
sufficient pressure in order to crack or fracture the
rock. Fractures create migration pathways for
hydrocarbons to flow to the wellbore to be extracted
Images from EIA, CSUR, and SPE
7
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Process innovation around shale gas development
– the role of different technologies
Process innovation: a new or significantly improved
production or delivery method. Including significant
changes in techniques, equipment and/ or software
(OECD definition)
Horizontal (directional) drilling: horizontal leg exposes
more of the formation to the wellbore, improving
resource recovery and production rates
Hydraulic fracturing: pumping a fluid (gas or liquid) with a
suspended proppant (sand or ceramic beads) down the
wellbore to fracture low permeability rock. The fluid/
proppant mix fills the open fractures keeping them open
after the pressure is removed. After the fracture, proppant
stays in reservoir and fluid flows back to surface
Multi-stage fracturing: dividing the well’s horizontal leg
into sections which are fractured independently or by
stages. Plugs or packers are used to isolate each stage.
Longer horizontal laterals allow for more frac stages
leading to higher production rates
Improved micro-seismic: 3D and 4D (sound) seismic helps
reduce the incidence of dry wells, increase production
through better well location, and allows for a clear
understanding of the hydraulic fracture (frac) performance
Multi-well pad drilling: allows for economies of scale,
targeting of multiple zones, improved access to resource,
reduced land footprint, and drilling costs savings
Images from CAPP, CSUR, and Chesapeake/ Statoil
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Potential environmental impacts of shale gas production/
hydraulic fracturing operations and mitigation measures
•
•
•
•
•
•
Unconventional/ shale gas and hydraulic fracturing
(HF) operations are costly and resource intensive
Industrial process = potential environmental impacts
Water issues:
• Water quantity: usage and sourcing
• Water quality: surface and groundwater
protection, chemicals in fracturing fluid,
produced water disposal, etc.
Land issues:
• Surface disturbance and induced seismicity
Air issues:
• GHG emissions, other
Regulations and industry initiatives are designed to
mitigate environmental issues and protect the public’s
safety while maximizing economic benefits = social
license to operate
Images from: FracFocus, Natural Resources Canada, Earth Times, and EPA
Hydraulic Fracturing Water Cycle
9
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Water Quantity Issues: Usage and Sourcing
• Shale gas development can use significant volumes of H2O for the HF
process (every frac job is different at every shale formation)
• Examples: 65,000 m3 for a well in B.C’s Horn River basin but less
than 6,000 m3 for a well in the Montney area (energized with
CO2 & N2)
• Water sources: fresh (surface or groundwater), recycled, and nonpotable (saline or brackish water, not fit for human consumption:
>4,000 mg/L TDS)
• Alberta Environment and Sustainable Resource Development (ESRD) is
responsible for the allocation of freshwater for energy development
AER after spring of 2014)
• Comprehensive requirements governing the use of fresh water,
in charge of implementing best water management practices
designed to maximize water reuse/ recycling and promote use
of saline, waste water, or alternatives to fresh water in order to
minimize freshwater use
• Water use by the oil and gas industry accounted for less than 7% of
total water allocations in Alberta in 2009
(latest report available from ESRD)
• The majority of that water was fresh water
• While currently not much information is available in regards to water
use for shale gas operations in AB, trends regarding conventional and
oil sands operations point towards increased used of saline water
versus fresh water by the oil and gas industry
• Industry guidelines and best practices have been developed to map and
better understand fresh (surface and underground) and saline water
resources, as well as to minimize the use of freshwater while
continually improve upon water recycling and reusing efforts
See: CAPP’s Guiding Principles for Hydraulic Fracturing and PTAC’s
Modern Practices of Hydraulic Fracturing: A Focus on Canadian Resources
Images from: ESRD and CAPP. All information from AER, ESRD, CAPP, and PTAC
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Water Quality Issues
Well Casing and Groundwater Protection
Typical Fracturing Fluid Composition
• The Alberta Energy Regulator (AER) regulates all aspects of natural
gas development
• Hydraulic fracturing as part of natural resource development is
regulated by the AER
• Conserving water resources is part of the AER’s mandate
• Protection of groundwater is achieved through the requirement of
steel casing and cementing of wells for sections above the Base of
Groundwater Protection (BGWP), restriction of shallow fracturing
operations, prohibiting the use of toxic fluids above the BGWP, as
well as the regulation of fluidS’ storage and disposal
• Groundwater fit for human consumption found between 100 – 600m
below surface. Deeper = Saltier
• BGWP is around 300m below the surface
• Most water wells targeting shallow aquifers = <50m deep
• Hydrocarbon formations targeted for shale/ tight gas development
can be found at about 3,000m below the surface (Duvernay)
• Usually capped by several layers of impermeable rock
• Total well length can be 5,000 to 6,000m deep or about 10
to 12 times as tall as Taipei 101
• HF is not new to Alberta: over 174,000 wells fractured since the
1950’s, over 8,000 horizontal multi-stage fractured wells (as of 2013)
• Fluids injected into the formation and produced back to the surface
are required to be isolated from freshwater resources.
• Storage pits must be lined to prevent contact with the natural
environment
• Fluid composition information is a requirement and it is
publicly available at www.fracfocus.ca
• Produced fluids can be recycled or re-used. Otherwise, need to be
disposed of at authorized deep well injection sites (well below the
BGWP) or sent to authorized water treatment facilities
• Treated water cannot be introduced to Alberta’s waterways
Images from: Encana, Questerre, and FracFocus. All information from AER
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Natural Gas Liquids (NGLs)
and Feedstock Availability
Image from EnCana
Relevant • Independent • Objective
www.ceri.ca
North America
Natural Gas In North
America
Alberta
Canada
Images from US Energy Information Administration (EIA), Canadian Centre for Energy
Information, and Government of Alberta (GOA)
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Relevant • Independent • Objective
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UPSTREAM
MIDSTREAM
DOWNSTREAM
NGLs in Canada: Sources and End-Uses
Natural Gas, Crude Oil, and Crude Bitumen
Gas Plant Liquids
(C2, C3, C4s, C5+)
Refinery Liquefied
Petroleum Gases (LPGs)
(Primarily C3, C4s)
Upgrader Synthetic Gas
Liquids (SGLs)
(NGLs/ Olefins Mix)
Wellhead or Field
Condensate (C5+)
PROCESSING, TRANSPORTATION, AND STORAGE INFRASTRUCTURE
Ethane (C2)
Propane
Butanes
(C3)
(C4s)
Non-energy Use:
•Petrochemical Feedstock
•Enhanced Oil Recovery
(EOR)
Retail
•Commercial/ Institutional
•Residential
•Transportation
•Agriculture
Heating, Other
(left in gas)
Wholesale (Industrial)
•Oil & Gas
•Manufacturing
•Construction
Pentanes Plus/
Condensate
(C5+)
Non-energy use
•Gasoline blending
•Petrochemical Feedstock
•Oil sands diluent
Non-energy Use:
•Oil Sands Dliuent
•Gasoline blending
•Petrochemical Feedstock
Non-energy Use
•Petrochemical Feedstock
•Solvent Flood (EOR)
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Relevant • Independent • Objective
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NGLs Production: Identifying what is relevant…
1
900
800
765
729
744
735
757
737
699
700
664
657
666
677
kb/d
600
91%
7%
500
2%
400
300
Upgraders SGLs Mix
Refineries LPGs
Gas Plants/ Gas Production NGLs
Total NGLs
200
100
Gas Plants/ Gas Production NGLs
Refineries LPGs
Upgraders SGLs Mix
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
2
900
800
765
729
744
735
737
757
699
700
664
657
666
677
32%
33%
kb/d
600
500
400
300
14%
200
Pentanes+/ Condensate
Propane
Total NGLs
100
-
21%
Butanes
Ethane
Ethane
Propane
Pentanes+/ Condensate
Butanes
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
3
800
695
700
658
671
600
671
669
686
631
598
587
599
614
kb/d
500
9%
400
300
200
100
90%
Saskatchewan
Nova Scotia
British Columbia
Alberta
Gas Plants NGLs
1%
0%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Alberta
British Columbia Nova Scotia
Data from AER, AERSRD, BCMNGD, and Statistics Canada. Figures by CERI
(1) Canadian NGLs production declined after 2007,
bottomed in 2010 and has since recovered
• Decreases in LPGs production from refineries
and gas plant NGLs. SGLs production up
• In 2012, gas plants accounted for 91% of total
NGLs production in Canada
• Refineries (7%) and Upgraders (2%) accounted
for the remaining 9%
(2) Production of all NGLs has decreased over time
• Since 2002, C5+ and C4s have decreased the
most (in % terms and volumes)
• In 2012, C2 and C3 accounted for 65% of total
NGLs production
• This indicates the average NGLs barrel is getting
“lighter” (more C2 and C3)
(3) Gas plant production of NGLs has increased
rapidly in BC and rebounded in AB since 2010
• In 2012, AB and BC combined accounted for
99% of gas plant NGLs production
So what do we need to look at to understand these
trends?
• Focus on natural gas market dynamics
• Focus on AB & BC
• Understand changing NGLs fundamentals and
trends
• In-depth look at C2 & C3
Saskatchewan
15
Relevant • Independent • Objective
www.ceri.ca
Factors Affecting WCSB NG Production
Physical Changes: Emerging supply sources and
intra-basin gas on gas competition in North
America
Economics: Exchange rates, prices,
transportation tolls, supply cost efficiencies,
and NGLS uplift
Images from EIA, PenWell MAPSearch (edited by CERI), Strategic Concepts Inc., PTAC/ ESG, and
Pembina Pipelines
16
Relevant • Independent • Objective
www.ceri.ca
Emerging Supply Sources in the US Natural Gas Market: How it affects Canada?
1
90,000
30,000
80,000
70,000
76,008
66,667
67,823
70,365
69,727
70,753
66,935
69,386
70,061
2
Antrim (MI, IN, and OH)
81,622
25,692
Bakken (ND)
72,073
25,000
Woodford (OK)
21,273
Other US shale gas
20,000
50,000
MMcf/d
MMcf/d
60,000
40,000
Shale Gas
CBM
Oil Wells
Gas Wells
Total Gas Production
Production Exc. Shale Gas
30,000
20,000
10,000
Eagle Ford (TX)
Fayetteville (AR)
15,000
Marcellus (PA and WV)
9,517
Haynesville (LA and TX)
10,000
7,013
Total Shale Gas Production
4,816
5,000
-
1,074
1,227
1,363
2002
2003
2004
2,106
2,699
2005
2006
0
2002
2003
2004
2005
2006
2007
2008
2009
2010
80,000
2011
2012
Transportation
14,000
63,088
61,032
61,377
63,298
60,314
63,773
62,767
65,138
66,535
Lease, Plant, Pipeline
12,000
Commercial
10,000
2007
2008
2009
11,667
11,001.27
59,450
11,893
11,469
10,915
10,805
2011
10,249
9,503
8,597
Residential
40,000
Industrial
30,000
MMcf/d
9,851
50,000
2012
LNG
CAD --> US
Net CAD --> US
Total US Imports
US --> CAD
10,278
60,000
2010
12,624
69,869
70,000
MMcf/d
14,541
Barnett (TX)
8,000
8,675
8,800
9,157
9,042
8,901
8,303
4
6,000
7,042
6,962
5,938
Power Generation
5,451
4,000
20,000
Total Gas Demand
2,000
3
10,000
Marketable
Production
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
519
742
2002
2003
1,081
982
934
2004
2005
2006
1,321
1,531
2007
2008
1,919
2,024
2009
2010
2,567
2,660
2011
2012
-
(1) Raw gas production in the US up by 22% (15 bcf/d) from to 2002 (67 bcf/d) to 2012 levels (82 bcf/d) driven by shale
gas (+25 bcf/d) and CBM (+5 bcf/d) while other conventional sources continue to decline (-15 bcf/d)
(2) Rapid increase (avg. 2.5 bcf/d/yr) in shale gas production driven by unprecedented increases in the Barnett,
Fayetteville, Haynesville, and Marcellus plays
(3) Demand for natural gas in the US increased by about 7 bcf/d driven by power generation, but demand growth is
slower than supply growth thus there is less demand for gas needs above US production, mainly, LNG & Canadian gas
(4) This has resulted in a large drop in flow levels from CAD to US but also US gas moving into CAD
Figures and Analysis by CERI, with data from EIA
17
Relevant • Independent • Objective
www.ceri.ca
Canadian Natural Gas Export/ Import Flows: Inter-basin competition
GTN (Kingsgate) vs. Ruby
(Rockies gas)
Northern Border (Monchy)
vs. Bison & REX (Rockies gas)
Flows on GLGT/ Viking
(Emerson) increasing
Rockies/ USMW/ Marcellus Gas
Pushes Out Canadian gas = flow
reversal
Centre top map from ZIFF Energy/ NEB. Figures and Analysis by CERI, with background image from AER, data
from CANSIM and NEB
18
Decreased production @ SOEP +
USNE gas moving in (does not
include Canaport)
Relevant • Independent • Objective
www.ceri.ca
So what does that mean for Canada?
Canadian Natural Gas Supply & Disposition (02-12)
20,000
17,593
18,000
18,190
17,485
17,411
17,119
17,678
17,004
16,977
16,650
Total Domestic Demand
17,382
16,783
Exports
16,000
Other Imports (LNG)
12,000
13,755
6,000
14,353
14,784
14,652
16,135
16,880
16,070
16,564
16,361
8,000
US Imports
16,183
10,000
16,911
MMcf/d
14,000
Canadian Marketable Gas
Production
Marketable Gas Supply in Canada
4,000
2,000
Marketable Gas Disposition in
Canada
S
D
2002
S
D
2003
S
D
2004
S
D
2005
S
D
2006
S
D
2007
Supply Side (Grey):
Domestic marketable gas production decreasing
(-3.2 bcf/d net since 2002)
Imports increasing rapidly (mainly US) but also
some LNG at Canaport
(+2.4 bcf/d net since 2002)
Imports accounted for 18% of supply in 2012
(compared to 4% in 2002)
S
D
S
2008
S
2009
D
2010
S
D
2011
S
D
2012
Disposition Side (Red):
- Total domestic demand increasing
(+1.1 bcf/d net since 2002)
-
-
Data from CANSIM, CERI estimates. Figures by CERI
D
Driven by increases in gas use for power generation and at
the industrial level (oil & gas sector / chemicals
manufacturing) in both Alberta and Ontario
Exports to the US decreasing rapidly
(-1.9 bcf/d net since 2002)
Exports accounted for 51% of disposition in 2012
(compared to 60% in 2002)
19
Relevant • Independent • Objective
www.ceri.ca
Severe winter weather
Hurricanes Katrina & Rita
High Commodity Prices
Global Recession
1.55
(1) Prices, exchange rates, and basis
1.50
•
1.60
Prices have been volatile over last decade and
persistently low over the last few years
•
Extreme weather events
•
Global economic conditions
•
Shale gas abundance
Basis differential (HH – AECO): a function of exchange
rates and transportation costs
$CAD has appreciated rapidly since 2002 = Canadian
versus US gas no longer underpriced
•
Double-edged sword:
Increases competitiveness but erodes price
advantage
1.45
1.40
1.35
Rapid increases in US shale gas production
1.30
1.25
1.20
1.15
1.10
•
1.05
1.00
0.95
•
0.90
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012 2013
(2) Transportation tolls
•
As eastbound export flows out of Western Canada
on the TCPL system decrease, tolls continue to rise
•
More costly to move WCSB gas to distant markets
in Eastern Canada as well as USMW and USNE
Closer US supplies displaces WCSB supplies on cost
advantage basis
•
•
•
Whether this continues depends on US shale gas
potential and WCSB producers competitiveness
•
•
Transportation costs
Supply costs
WCSB producers continue to be marginal suppliers
and thus price takers in the NA market
Western Canada gas producer need to increase
profitability to increase competitiveness
8,000
2
7,000
$2.50
6,000
$2.00
$/GJ
•
$3.00
5,000
$1.50
4,000
M M cf/d
1
Basis Differential
AECO ($/GJ)
Henry Hub ($/GJ)
CAD/USD
$18.00
$17.00
$16.00
$15.00
$14.00
$13.00
$12.00
$11.00
$10.00
$9.00
$8.00
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$-
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
May
September
January
$/GJ
Exchange rates, natural gas prices, and transportation tolls
3,000
$1.00
FT @ 100% LF Empress --> Niagara Falls (Via Mainline)
FT @ 100% LF Empress --> St. Clair (Via GLGT)
IT Bid Floor Empress --> Niagara Falls (Via Mainline)
IT Bid Floor Empress --> St. Clair (Via GLGT)
Estimated TCPL Mainline Flows
$0.50
$-
2,000
1,000
-
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Data from AER, ADOE, Bank of Canada, EIA, NEB, StatsCan, and TCPL. Figures by CERI
20
Relevant • Independent • Objective
www.ceri.ca
Increasing Profitability & Competitiveness: Supply Costs
Efficiencies
1
2
(1)
(2)
Drilling multiple wells from a single pad reduces rig downtime and rig transportation requirements leading to potential
supply costs reduction of up to 30%
Increasing the number of frac stages while it add costs, can also increase initial production (IP) rates and estimated
ultimate recovery (EUR), thus yielding supply costs reductions to a certain point
More on this subject available at a recently completed report by CERI/ PSAC/ CSUG for Productivity Alberta:
“Improved Productivity in the Development of Unconventional Gas”: Link
Images from NEB, Nexen, figures by CERI
21
Relevant • Independent • Objective
www.ceri.ca
Increasing Profitability & Competitiveness: Monetizing NGLs
1
(1)
•
•
(2) Monetizing NGLs to increase revenues
•
NGLs provide per-unit uplift in revenues,
decreasing the supply costs of dry gas production
•
CERI’s supply costs = gas price needed to recover
costs (capital, operating, royalties, and taxes) plus
a 10% real ROR
•
If supply cost < prevailing market gas price =
economically viable development
•
Within the WCSB, some plays have better
economics than others
•
•
Thus under different market prices, different plays
get developed
Montney example = revenue from NGLs alone is
almost enough to cover all costs + return
Image from Keyera/ Peters & Co. Figure by CERI
WCSB Cost Competitiveness in the NA
context
WCSB plays and resources are competitive on a
supply cost basis with shale plays in the US such as
the Marcellus, Fayetteville, Barnett, Haynesville,
and the Eagle Ford
High NGLs content in the reservoir can improve the
economics of development
•
However, many other factors are equally
important such as capital costs (drilling
costs), access to infrastructure, IP rates and
EUR, as well as fiscal terms (royalties and
taxes) amongst others
2
See: CERI Study No. 136 Update (December 2013)
22
Relevant • Independent • Objective
www.ceri.ca
Changing Dynamics in NG & NGLs in Western Canada
Oil, NG, and NGL Prices
$30.00
•
CRUDE OIL - NATURAL GAS SPREAD ($/GJ)
Price Ceiling
AECO-C ($/GJ)
ETHANE ($/GJ) (CERI EST.)
PROPANE ($/GJ)
BUTANES ($/GJ)
PENTANES ($/GJ)
CERI WCSB COMPOSITE NGL BARREL ($/GJ)
CANADIAN FURNACE OIL (WHOLESALE RACK PRICE) ($/GJ)
$25.00
$20.00
•
•
$/GJ
$15.00
•
$10.00
$5.00
•
$-
•
Price Floor
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
Jan
A pr
Jul
Oct
$(5.00)
2002
2003
2004
2005
NG Wells
Completed in 2008
2006
2007
2008
2010
2009
2010
2011
2012
2013
Supply and demand dynamics have brought
down natural gas prices significantly
This has slowed down the pace of drilling activity
in Western Canada
Persistently high crude oil prices have resulted in
wider spread between crude oil and natural gas
prices (improving NGL extraction economics)
As NGL prices track substitute prices, NGL prices
have tended to track crude oil prices
Natural gas producers focus on drilling where
NGLs are found
Thus, fewer wells and lower production, but
natural gas stream with higher liquids content
(Note: Type of wells is different)
2011
Figures and Analysis by CERI, with data from AER, GOA, EIA, and MJ Ervin & Associates
2013 (J-O)
23
Relevant • Independent • Objective
www.ceri.ca
NGLs Reserves & NG Production Trends
1,800
1
80
70
1,600
74
2
1,400
63
1,200
56
50
MMcf/d
bbl/ MMcf
60
40
30
600
400
10
200
-
-
Foothills
18,000
16,000
16,228
Plains
Northern
15,902 15,922 15,868 15,696 15,668
AB Median
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
15,057
14,138
13,248 12,962
14,000
12,180
12,000
MMcf/d
800
27
20
10,000
8,000
6,000
Northern
Plains
Foothills
Total AB
4,000
2,000
-
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
3
100%
90%
80%
70%
% of Total
1,000
60%
50%
40%
Northern
30%
Plains
20%
Foothills
10%
PIA02 Foothills
PIA03 Foothills
PIA04 Foothills
PIA05 Foothills
PIA06 Foothills
PIA09 Foothills
PIA10 Foothills
PIA11 Foothills
PIA13 Foothills
PIA14 Foothills
PIA15 Foothills
PIA16 Foothills
PIA17 Northern
PIA18 Northern
PIA19 Northern
PIA20 Northern
PIA21 Northern
PIA22 Northern
PIA01 Plains
PIA07 Plains
PIA08 Plains
PIA12 Plains
PIA23 Plains
(1) Foothills area accounts for 71% of
AB’s RMG reserves (34 Tcf) and 89%
of NGLs reserves (2 Bbbl)
• More NGLs per unit of gas in the
Foothills region that any other
region (bbl/ MMcf)
(2) Production has fallen rapidly in
most areas across AB
• NW areas of the Foothills are the
only areas in the province to
exhibit production increases over
the last decade
(3) Overall Foothills area gas
production has decreased the least
and now accounts for close to 80% of
total AB production
0%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Figures and Analysis by CERI, with data from AER
24
Relevant • Independent • Objective
www.ceri.ca
Recent trends and developments in NG & NGLs in Western Canada
WCSB Gas Plant NGLs (2002 = 1)
35
WCSB Gas Production (2002 =1)
30
1.05
25
bbl/ MMcf
1.10
1.00
0.95
82%
80%
20
10
1
0.85
5
0.80
78%
WCSB bbl of GP NGLs/ MMcf Gas Produced (LHS)
bbl of C2/ MMcf Gas Processed at Empress + Cochrane (LHS)
Gas Processed/ Gas Produced (AB) (RHS)
-
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
100%
3
90%
80%
70%
60%
% of Total
2
15
0.90
50%
40%
30%
20%
10%
84%
Pentanes+/ Condensate
Butanes
Propane
Ethane
0%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Figures and Analysis by CERI, with data from AER and Industry Data
76%
AB Gas Processed/ Gas Produced (%)
1.15
86%
40
1.20
74%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
(1) NGLs production levels declining over past decade
but trend leveled-off in the last couple of years.
Overall decline not as fast as for natural gas. Thus
there is more NGLs per unit of gas produced
(2) A larger percentage of the produced gas is being
processed in Western Canada. Overall more NGLs
are being produced per unit of gas processed. Not
all producers have deep-cut (or ethane and light
ends extraction) plants, and more ethane available
in pipeline gas stream which is showing at export
straddle plants
(3) Resulted in increasing share of ethane/ propane
production as a percentage of total NGL
production
25
Relevant • Independent • Objective
www.ceri.ca
Midstream and Downstream Investments
(1) The midstream business in AB is dominated by
a few large firms. In 2012, the top 15 companies
accounted for 93% of all extracted spec NGLs
•
Top players include Keyera Energy,
Pembina Pipelines, Plains Midstream,
Inter-pipeline Fund, Spectra Energy,
and Altagas
(2) Utilization rates for both NGL pipelines and
fractionators is high and expected increases in
NGL volumes have led to over $10 billion (B) in
investments on midstream infrastructure (2011 –
2016)
•
A large portion of these investments is
in deep-cut gas processing plants
targeting incremental ethane
extraction
(3) Meanwhile, close to $4 B in downstream
investments have been announced including
petrochemical facilities and LPG export terminals
(2011 – 2016)
That is a total of over $14 B in midstream and
downstream investments to monetize NGLs
Figures and Analysis by CERI, with data from AER and Industry Data
1
2
3
26
Relevant • Independent • Objective
www.ceri.ca
Midstream Infrastructure:
From natural gas to NGLs to end-use markets
Western Canada Natural Gas Processing and Transportation Infrastructure:
•
Ample processing capacity available (~30 bcf/d)
•
Robust natural gas gathering and transportation pipeline network
•
Large volume export pipeline infrastructure (10+ bcf/d) and export sales
gas ethane extraction plants (14.7 bcf/d processing capacity and 500+
kb/d of NGLs extraction capacity)
Location
Alberta
British Columbia
Saskatchewan
Nova Scotia
Total
Alberta
British Columbia
Total
GAS PROCESSING PLANTS IN CANADA
Active Field Gas Processing Plants in Canada (2012)
#
Gas Processing Capacity (MMc/d) 2012 Gas Processed (MMcf/d) Utilization (%)
617
23,679
10,338
44%
70
5,795
3,671
63%
18
184
145
79%
1
600
314
52%
706
30,257
14,467
48%
Active Gas Re-Processing (Straddle) Plants in Canada (2012)
10
13,909
6,600
47%
1
750
627
84%
11
14,659
7,227
49%
Figure by CERI, with data from IHS Energy (University of Calgary), AER, BCME, OGJ, and SOEP
27
Relevant • Independent • Objective
www.ceri.ca
NGL Pipelines, Fractionation, and
Storage
Canadian Fractionation Capacity (kb/d)
AB, Field Spec NGL Capacity
Boreal
442
40%
AB, Fractionators
AB, Straddle Plants
325
30%
19
2%
24
2%
114
10%
ON, Sarnia Fractionator
NE BC, Field Spec NGL Capacity
NS, Point Tupper Plant
180
16%
Total: 1,104 kb/d
(WC: 971 kb/d/ EC: 133 kb/d)
Pipeline
Est. Capacity (kb/d)
Product
Raw Mix Pipelines to Ft. Saskatchewan
Peace HVP System (NGLs)
76 C2+/ C3+
Cochrane-Edmonton (Co-Ed) System
68 C3+
Brazeau NGL Gathering System
57 C2+
Peace LVP System (Condensate)
52 C5+ (Includes Crude)
Northern System
49 C2+/ C3+
Boreal
43 NGLs/ Olefins Mix
Bonnie Glen
33 C5+ (Includes Crude)
Judy Creek
30 C3+
Total Raw Mix Pipelines Est. Capacity
408
Petrochemical Feedstock Pipelines
Alberta Ethane Gathering System (AEGS)
334 Spec C2
Ethylene Delivery System (EDS)
86 Ethylene
Joffre Feedstock Pipeline (JFP)
48 NGLs
NGL Export Pipelines
Enbridge Mainline (Lines 1/5)*
Kerrobert (to Enbridge)
Alliance Pipeline
Cochin Pipeline
Petroleum Transmission Company**
Total NGL Export Pipelines Est. Capacity
NGLs Storage Capacity (MMb)
Ft.
Saskatchewan,
AB
23.0
61%
Kerrobert, SK
2.5
6%
NGL Import Pipelines
Southern Lights/ Line 13
Mariner West (Late 2013/ Early 2014)
Vantage Pipeline (2014)
UTOPIA Pipeline (2017-18)***
Total NGL Import Pipelines Est. Capacity
*Net of Kerrobert/ **CERI Estimate/ ***Announced
127
124
93
71
27
442
C3+ Mixes
C3+ Mixes
NGLs in Gas
Spec C3/ USMW E/P Mix
Spec C3/ C4
171
48
43
59
321
C5+
Spec C2
Spec C2
Spec C2/ Spec C3
Sarnia/
Corunna, ON
12.4
33%
Total: 38 MMb
Figure by CERI, with data from IHS Energy (University of Calgary), AER, BCME, OGJ, SOEP, various industry
sources . Logo from Alberta Industrial Heartland Association (AIHA) and City of Edmonton
28
Relevant • Independent • Objective
www.ceri.ca
Importance of Petrochemical Industry: Moving up the Value Chain
-
2
LDPE Film
$2,246
HDPE Injection Molding
$2,225
$2,202
$2,154
LLDPE-Hexene-1Film
$2,133
HDPE HMW Film
$2,114
LLDPE-Butene-1Film
$2,045
Propylene (Polymer Grade)
P ro d u c t
HDPE Blow Molding
LLDPE-Octene-1Film
4
6
8
Value Multiplier (x times)
10
12
16
18
20
19
18
18
18
18
17
$1,309
11
$1,305
11
Gasoline
$1,099
Kerosene
$992
•
9
8
Furnace Oil
$964
Pentanes Plus
$900
Butanes
$847
7
Light Sweet Crude
$843
7
Propane
$407
Ethane
$229
8
8
Upgrading natural gas and NGLs to various
forms of plastics and consumer products adds
significant incremental economic value
3
•
2
$120 1
0
•
19
Ethylene
Natural Gas
14
500
1,000
1,500
$/ t
2,000
2,500
Petrochemicals: Building
blocks for everyday
consumer products
•
Importance of
consumer demand
and overall economic
activity
Obtained by cracking NGLs
and other heavier
hydrocarbons
•
Importance of natural
gas and NGLs markets
Olefins & Aromatics from
hydrocarbons to
derivatives to consumer
products = value added
•
Incremental value
along the path
generates widespread
economic benefits
Image Sources: Canadian Natural Gas, Government of Alberta, American Chemical Society
Figure and Analysis by CERI, with data from EIA, NGX, CME Group, MJ Ervin & Associates, and Dewitt & Company (All prices are for 2011)
29
Relevant • Independent • Objective
www.ceri.ca
Petrochemical Industry in Alberta: Snapshot
ALBERTA
Company
Facility
Location
Main Product
Ethylene Crackers (Olefins)
NOVA Chemicals
NOVA Chemicals
NOVA Chemicals (50%)/ Dow Chemicals (50%)
Dow Chemicals
Total Ethylene Crackers
Ethylene 1 (E1)
Ethylene 2 (E2)
Ethylene 3 (E3)
Dow Fort Saskatchewan (LHC1)
Joffre Complex, AB
Joffre Complex, AB
Joffre Complex, AB
Fort Saskatchewan, AB
Ethylene
Ethylene
Ethylene
Ethylene
Aromatics Plants
Shell Canada
Total Aromatics
Shell Scotford Refinery
Scotford, AB
Benzene
Plant
Capacity
(kt/yr)
726
816
1,270
1,285
4,097
Feedstock
Required
Feedstock (kb/d)
C2/ Some C3
C2/ Some C3
C2
C2
370 Crude Oil
370
45
51
79
80
255
n/a
Ethylene Derivatives
Polyethylene and Similar Products
NOVA Chemicals
NOVA Chemicals
INEOS Oligomers
Dow Chemicals
Dow Chemicals
Celanese (AT Plastics)
Total
Ethylene Glycol
ME Global (50% owned by Dow Chemicals)
ME Global (50% owned by Dow Chemicals)
ME Global (50% owned by Dow Chemicals)
Shell Chemicals Canada Ltd.
Total
Styrene Monomer
Shell Chemicals Canada Ltd.
Required
Feedstock (kt/yr)
Polyethylene 1 (PE1)
Polyethylene 2 (PE2)
Joffre Linear Alpha Olefins (LAO) Plant
Prentiss PE
Fort Saskatchewan PE
Edmonton EVA Manufacturing Plant
Joffre Complex, AB
Joffre Complex, AB
Joffre Complex, AB
Red Deer, AB
Fort Saskatchewan, AB
Edmonton, AB
LLDPE
LLDPE & HDPE
LAO
LLDPE
LLDPE
LDPE, EVA
Prentiss I Ethylene Oxide/ Ethylene Glycol (EO/EG) Plant
Prentiss II EO/EG Plant
Fort Saskatchewan (FS) 1EO/ EG Plant
Shell Chemicals Scotford Manufacturing Monoethylene Glycol (MEG)
Plant
Red Deer, AB
Red Deer, AB
Fort Saskatchewan, AB
MEG
MEG
EO/EG
Scotford, AB
MEG
Shell Chemicals Scotford Manufacturing Styrene Monomer (SM) Plant
Scotford, AB
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
Ethylene
678
435
253
505
859
61
2,790
310 Ethylene
285 Ethylene
350 Ethylene
179
165
202
450 Ethylene
1,395
260
806
SM
450 Ethylene
Benzene
450
121
365
486
Alberta EnviroFuels (AEF)
Redwater Fractionator/ Propylene Plant
Edmonton, AB
Redwater, AB
Iso-octane
PGP
521 Field Butanes (f-C4)
68 SGLs Mix
589
Total
Other Facilities
Keyera Corp.
Williams Canada
Total
Figures and Analysis by CERI
671
431
250
500
850
143
2,845
30
n/a
n/a
Relevant • Independent • Objective
www.ceri.ca
Alberta’s Competitive Advantage
$1,400
AECO-C NG ($/t)
HH NG ($/t)
AB ETHANE ($/t)
US ETHANE ($/t)
AB PROPANE ($/t)
US PROPANE ($/t)
SAUDI LPG ($/t)
WORLD AVERAGE NAPHTHA PRICE ($/t)
$1,200
$1,000
$/t
$800
$600
$400
$200
Jan
Jun
Nov
Apr
Sep
Feb
Jul
Dec
May
Oct
Mar
Aug
Jan
Jun
Nov
Apr
Sep
Feb
Jul
Dec
May
Oct
Mar
Aug
Jan
Jun
Nov
Apr
Sep
$-
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
• From the perspective of a global petrochemical producer, AB feedstock costs are some of
the lowest and most competitive on a continental and a worldwide basis
• Given the importance of feedstock cost in petrochemical production, AB’s feedstock cost
advantage translates into lower production cost
• Low feedstock costs and strong derivative prices = favorable margins
• Improved margins and cash flows = increased levels of capital available for re-investment
• Expansions in operations could be expected
• But feedstock availability also important …
Figures and Analysis by CERI. Left image by ACC
31
Relevant • Independent • Objective
www.ceri.ca
Alberta Ethane Supply/ Disposition Balance (02-12)
275
257
257
250
C2 Shipments to ON (Cochin)*
252
237
230
Estimated AB Demand
224
223
222
225
213
211
Inventory Changes: Used (Built)
Field Plants
175
kb/d
Fractionators
Straddle Plants
125
Total Supply
75
Total Disposition
25
AB Derivative Capacity + Ethylene
Shipments to ON (Cochin)**
AB Ethylene Cracking Capacity
(25)
S
D
2002
S
D
2003
S
D
2004
S
D
2005
S
D
2006
S
D
2007
S
D
2008
S
D
2009
S
D
2010
S
D
2011
S
D
2012
*CERI estimate
** CERI estmate
By 2009, no ethane or ethylene
shipments on Cochin
Supply (grey bars):
•
Straddle plants are the main source (about 75% in 2012, 158 kb/d)
•
•
•
Re-processing plants straddling the gas transmission system at Empress (AB/SK) border,
Cochrane, Taylor (NE BC), Joffre, and Edmonton Area
Production volumes declining as gas export flows decrease. Uncertainty going forward
Fractionators (fractionate NGLs mix extracted at deep cut field plants) accounted
for 20% of supply in 2012 (43 kb/d)
•
Expected to be one of the largest sources of increased ethane volumes as various deep
cut field plants will be built
Deep-cut field plants with fractionation capacity accounted for about 5% of total
ethane supply in 2012 (14 kb/d)
Demand (red bars):
•
Primary demand in AB is ethylene crackers (capacity ~260 kb/d)
•
However ethylene crackers ethane use and ethylene production is limited to
downstream derivative plants’ capacity (estimated to be about 230 kb/d in AB)
•
Prior to 2009, there were ethane and ethylene shipments from AB to ON via
Cochin pipeline
•
Maximum derivative based demand vs. supply suggest minor feedstock shortage
•
To meet demand, supply diversification will be necessary
•
Image Source: AER. Data from AER, figure by CERI
32
Relevant • Independent • Objective
www.ceri.ca
Emerging Ethane Supply Sources: IEEP + Vantage + Others
Applicant
Dow Chemicals
Dow Chemicals
NOVA Chemicals
Williams Off-Gas Ethane Extraction Project (Phase I)
NOVA Chemicals
Hidden Lake Streaming Project
NOVA Chemicals
Harmattan Plant Co-Stream Project
Dow Chemicals
Musreau Deep Cut Project
Shell Chemicals
Shell Waterton Incremental NGL Recovery Project
Shell Chemicals
Scotford Fuel Gas Recovery Project
Dow Chemicals
Rimbey Turbo Expander Project
NOVA Chemicals
Williams Off-Gas Ethane Extraction Project (Phase II)
Dow Chemicals
Resthaven Facility Phase 1
Shell Chemicals
Shell Scotford Upgrader Off-gas Project
NOVA Chemicals
AltaGas-Gordondale Deep Cut Project
NOVA Chemicals
Judy Creek Ethane Extraction Project
Shell Chemicals
Shell Jumping Pound Project
Dow Chemicals
Project Turbo (Saturn Plant)
Total
•
•
•
•
•
•
C2 Volumes Royalty Credits
(kb/d)
($MM)
Description
Increasing the C2 recovery at the Empress V plant
7 $
23
Modification of Keyera's Rimbey Gas Plant to
5 $
16
optimize removal and extraction of C2
Installation of equipment enabling capture of ethane
10 $
33
and ethylene out of off-gases
Pipeline valve and piping cross-over installations to
3 $
9
direct NGL rich gas Alberta extraction plants
Installation of equipment and pipeline infrastructure
9 $
30
to optimize extraction and removal of C2
Project
Empress V Deep Cut Project
Rimbey Ethane Extraction Project
Installation of equipement and modfication of
existing process to maximize C2 extraction and
removal
Alteration of exisitng infrastructure at Waterton to
increase NGL recovery in Alberta at export point
Installation of various equipment and modification of
processes to extact C2 from Scotford refinery
Modification of exisitng Rimbey gas plant by
installing a turbo expander to improve C2 recovery
Increase the ethane removed from off-gases from 10
to 17 mb/d
Modification and expansion of existing gas plant for
C2 extraction in NW Alberta
Installationf of infrastructure capable of capturing
ethane off-gases from Scotford Upgrader
Construction of a new gas processing plant in NW
Alberta which will capture ethane from natural gas
production
Increase of storage capacity and plant modifications
to improve utilization of the existing facility for C2
extraction
Aggregation of several small investments to improve
efficiency at Jumping Pound facility for improved C2
extraction
Modification of the existing Saturn Gas plant with
the installation of a cryogenic turbo expander to
improve C2 extraction
16
Status
Approved (2008)
Approved (2008)
Expected Onstream
Date
Onstream
Onstream
Commissioned
by
IPF/ Plains
Keyera
Delivery Point
AEGS
AEGS
Approved (2010)
2014
Williams
Approved (2010)
n/a
NGTL
Petrochemical Facility
(via Boreal)
n/a
Approved (2011)
Onstream
Altagas
AEGS
6
$
20 Approved (2011)
Onstream
Pembina
HVP Pipeline to Ft. Sk.
(Fractionators)
1
$
3 Approved (2011)
Onstream
Shell
AEGS
1
$
4 Approved (2011)
Onstream
Shell
Petrochemical Facility
(on site)
AEGS
15
$
49 Approved (2012)
2015
Keyera
7
$
64 Approved (2012)
2015
Williams
7
$
21 Approved (2012)
2015
Pembina
3
$
27 Approved (2012)
Onstream
Shell
4
$
13 Approved (2012)
Onstream
Altagas
3
$
9 Approved (2012)
n/a
n/a
HVP Pipeline to Ft. Sk.
(Fractionators)
1
$
3 Approved (2012)
Onstream
Shell
AEGS
8
$
27 Approved (2012)
2014
Pembina
HVP Pipeline to Ft. Sk.
(Fractionators)
89
$
Petrochemical Facility
(via Boreal)
HVP Pipeline to Ft. Sk.
(Fractionators)
Petrochemical Facility
(on site)
HVP Pipeline to Ft. Sk.
(Fractionators)
351
Projects currently approved under the GOA’s Incremental Ethane Extraction Program (IEEP) have potential
to increase ethane supply in AB by about 90 kb/d over the coming years
Vantage pipeline can potentially bring up to 60 kb/d of ethane from North Dakota/ Saskatchewan to AEGS
Oil sands upgraders off-gases projects can increase ethane supply by over 20 kb/d
Together, well over 150 kb/d of incremental competitively priced ethane volumes to Alberta
Various new sources not dependent on natural gas flows = diversification of supplies + new players in the
market
CERI estimates that over $5 B in midstream investments (2011 – 2016) are related to bringing in new
ethane sources to market. Additionally, close to $1b is being spent downstream in a new PE reactor
(Increased PE requirements = increase ethylene production = increased ethane requirements)
Table and Analysis by CERI, with data from GOA
33
Relevant • Independent • Objective
www.ceri.ca
Canadian Propane Supply & Disposition
300
250
Total Exports to US
Non-energy Use
Wholesale
Retail
Statistical Adjustment
248
244
229
217
214
220
220
215
207
199
189
200
Stock Changes
Imports
Off-Gas Plants
Refineries
kb/d
150
100
50
Gas Plants/ Fractionators
Total Supply
Domestic Demand
-
Total Disposition
S
(50)
D
2002
S
D
2003
S
D
2004
S
D
2005
S
D
2006
S
D
2007
S
D
2008
S
D
2009
S
D
2010
S
D
2011
S
D
2012
Supply (Grey bars):
•
About 75% of propane supply extracted at gas plants/ fractionators in Canada, other 20% consists of production from refineries,
upgraders, imports, and stock changes
•
About 50% of propane extracted in Western Canada’s gas plants moves to Ontario as an NGL mix to be fractionated
•
Increased production of NGLs in Western Canada is being driven primarily by increases in propane production
Disposition (Red bars):
•
Domestic demand increasing rapidly driven by energy uses in the mining, oil and gas extraction, and manufacturing sectors, followed by
increase propane use as a petrochemical feedstock in Ontario, and increased use for propane in the residential and commercial sectors
•
In 2012, Ontario (46%), Alberta (32%), and Quebec (8%), combined, accounted for 86% of domestic propane demand
•
Overall exports to the US have been declining (shrinking LPG market) with the largest drop occurring in regards to exports to the US
Midwest (PADD II), while increased Canadian exports to the US northeast (PADD I) have displaced US overseas propane imports
•
Majority of exports to the US now move via rail = higher transportation costs
•
Edmonton prices are the lowest across North America
•
North America is in an oversupply position and USGC LPG export terminals are acting as a relief valve, keeping prices afloat
Figures and Analysis by CERI, with data from AER, BCMNGD, NEB and Statistics Canada
Relevant • Independent • Objective
www.ceri.ca
Increasing Demand for Propane in North America =
Feedstock Competition
1
Company
1
Location
Propane Dehydrogenation (PDH) Projects in North America
Start-up Year Output (tonnes/ yr) Output (t/ d) C3 Feed (MMgal/ yr) C3 Feed (kb/d) C3 Feed (t/d)
PetroLogistics
PetroLogistics
Dow Chemical
Houston, TX
Houston, TX
Freeport, TX
2010
2014
2015
Enterprise
C3 Petrochemicals
Formosa Plastics
Dow Chemical
Total US
Chambers Co., TX
Alvin, TX
n/a
Point Comfort, TX
USGC (TX/ LA)
2015
Williams
Total Canada
AIH, AB
Total North America
United States
640,000
640,000
750,000
685,000
n/a
2016
2018
2016
1,933
1,933
2,265
2,069
n/a
800,000
550,000
4,065,000
460
460
540
490
n/a
2,416
1,661
12,276
30
30
35
32
n/a
570
380
2,900
2,418
2,418
2,838
2,575
n/a
37
25
189
2,996
1,997
15,242
Canada
500,000
500,000
1,661
1,661
390
390
25
25
2,050
2,050
4,565,000
13,937
3,290
215
17,292
(1) Various PDH projects have been proposed in
North America to take advantage of increased C3
availability and to produce on-purpose propylene as
ethylene crackers move to lighter feeds (reducing coproduct yields)
• Including a PDH facility in AB (25 kb/d C3 feed)
aiming to attract derivative investors
2
LPG Export Projects in North America
Company
Enterprise
Targa
Other
Total Operating
(2) High global LPG prices and the promise of improved
propane netbacks in North America through an
arbitrage opportunity have also resulted in various LPG
export project proposals
• Including two in Canada with the potential to export
>60 kb/d of WCSB LPG (C3) to the Asia-Pacific market
Sunoco Logistics
Vitol
Phillips 66
Enterprise
Targa
Enterprise
Occidental
Total Proposed US
Pembina Pipeline Corp.
Altagas Corp.
Total Proposed Canada
Total Proposed North America
Total Existing + Proposed North America
Figures and Analysis by CERI, with data from Propane Research Council (PRC) and Industry
Location
Start-up Year
In Operation
United States
Houston, TX
Galena Park, TX
Miami, Norfolk,
NY, Seatlle, LA
LPG Export Capacity
LPG Export
(MMgal/ yr)
Capacity (kb/d)
3,780
1,764
247
115
26
5,570
2
363
Proposed
United States
Marcus Hook, PA
Beaumont, TX
Baytown, TX
Houston, TX
Galena Park, TX
Houston, TX
Corpus Christi, TX
2014
2014
2014
2015
2015
2016
2017
600
1,500
2,218
756
1,008
3,528
1,150
10,760
39
98
145
49
66
230
75
702
Canada
Prince Rupert, BC
BC Coast
2015
2017
620
390
1,010
40
25
66
11,770
17,340
768
1,131
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Long-Term Natural Gas Outlook
CERI’s WCSB natural gas outlook comparable to others (CAPP, AER, NEB)
• Contingent on recovering prices and export levels over the long-term
• Production focus continues to be on liquids-rich areas
• Canadian LNG exports only modeled for Horn River Area + 1 Montney based project
• Cautionary note: Increased LNG exports in Canada does not necessarily equal increased gas production in
AB or increased NGLs supply
• Downside Risk: Increasing US shale gas volumes keep displacing Canadian exports = lower production volumes
• Upside Opportunity: Increased LNG exports from USGC = relief valve (CAD gas needed in North American market)
(Note: in 2013 CERI updated the base case outlook presented above. There are now 4 scenarios for natural gas
production based on different demand factors, the NGLs outlook for those scenarios is currently being finalized)
Figures and Analysis by CERI
36
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100
91
100
500
k b /d
150
150
150
150
150
150
150
150
155
150
170
164
159
162
157
154
149
144
141
2
80
400
60
300
WCSB Pentanes Plus/ Condensate Production
WCSB Butanes Production
WCSB Propane Production
WCSB Ethane Production
Total WCSB NGLs Production
200
100
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
-
Historical Data
Outlook
C3+ Mix
C2/C2= Mix
Total SGLs in Stream (kb/d)
40
20
-
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
kb/d
104
120
600
103
128
140
141
137
160
143
878
865
851
8 34
805
8 21
771
727
751
704
6 85
673
657
6 68
65 0
6 55
643
654
67 6
663
703
725
756
645
700
72 4
800
7 05
900
78 8
180
169
1
1,000
164
WCSB NGLs Production Outlook
HISTORICAL/ ACTUAL
OUTLOOK
(1) Outlook for NGLs is promising but contingent on gas
outlook
(2) Synthetic gas liquids (SGLs) potential from upgraders
also large and not contingent on gas outlook
•
Represents an opportunity for increased
petrochemical feedstock and valued-added in AB
Note: These results are interim and subject to revisions
Figures and Analysis by CERI, with image from Williams Canada
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36 7
3 62
35 7
35 0
342
10 2
97
92
85
77
69
3 25
60
51
3 07
42
297
31
28 1
16
272
7
2 66
1
264
1
-
2 60
2 57
Scotford Off-Gas
Upgrader Off-Gas (Williams)
4
15
2 40
Excess Supply = Reject/ Expand
AB Ethane Demand
k b /d
250
2 14
206
214
21 6
2 17
-
300
247
2 36
25 1
254
12
2 30
350
3 16
1
400
33 4
Canadian Ethane Balance: Petrochemical End-Use
200
Vantage Pipeline
150
Field Plants
100
Fractionators
50
Straddle Plants
Total Ethane Supply
S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
HISTORICAL
OUTLOOK
700
2
Ethane Left in Sales Gas Stream
600
240
238
234
232
231
231
227
221
213
205
201
193
184
179
178
193
196
204
262
220
274
275
255
254
250
229
kb/d
400
235
C2 Extracted @ Field Plants
500
C2 on Alliance Gas
C2 Extracted @ Fractionators
300
C2 Extracted @ Straddle Plants
200
Total Ethane Available in WCSB Raw Gas
100
Total Ethane Recovered from WCSB Raw Gas
SDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSDSD
200420052006200720082009201020112012201320142015201620172018201920202021202220232024202520262027202820292030
HISTORICAL
OUTLOOK
(1) S/D Balance
• Production growth
expected to come from
fractionators over the next
few years as more deep cut
facilities are built
• This is expected to reduce
ethane availability at the
straddle plants
• Gas exports decrease over
the next few years further
putting pressure on ethane
production at straddle
plants
• New sources of ethane will
include off-gas ethane and
US imports (via Vantage)
• Demand to expand to about
270 kb/d
• Excess supply after 2020
Options: Invest in
petrochemical facilities or leave
in gas stream (reject)
(2) Ethane recovery from
WCSB’s natural gas is expected
to remain at ~60%
(could be higher)
Two possible propane demand scenarios
300
1
56
55
54
51
48
48
48
47
45
43
41
39
38
41
54
67
76
91
87
96
109
142
123
12 6
1 63
150
1 41
kb/d
200
92
250
100
50
-
Surplus = US Exports/ Other
Solvent Floods
Petrochemical Feedstock
Wholesale (Industrial)
Retail (Transp., Ag., Res., Comm.)
Statistical Adjustment
Imports
Nova Scotia Propane
BC & SK Field Spec Propane
Ex-Ab Refineries
WCSB Propane Production
Total Propane Supply
Total Domestic Demand
Total Dispostion
S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
HISTORICAL
OUTLOOK
2
300
Surplus = US Exports/ Other
(1) Under the first scenario, Sarnia
ethylene crackers switch to C2
(imported) feedstock as planned
and Williams PDH goes ahead.
No LPG exports means there are
about 40-50 kb/d of surplus
propane to be exported to the US
or to develop a local demand
source (another PDH?)
(2) Under the second scenario,
the most advanced LPG export
proposal (Altagas’) goes ahead,
leaving surplus volumes of
propane in the range of 20-30
kb/d for exports/ a new industry
Altagas LPG Exports
250
34
33
32
30
27
26
26
25
24
22
19
17
16
30
54
67
76
91
87
96
109
142
123
12 6
163
150
141
kb / d
200
92
Solvent Floods
Petrochemical Feedstock
Wholesale (Industrial)
Retail (Transp., Ag., Res., Comm.)
Statistical Adjustment
Imports
Upside supply potential: US
propane imports move to ON
market, creating a larger surplus
in Western Canada
Nova Scotia Propane
BC & SK Field Spec Propane
100
Ex-Ab Refineries
WCSB Propane Production
50
Total Propane Supply
Total Domestic Demand
S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D S D
Total Dispostion
Downside supply potential:
domestic demand grows faster/
more LPG export terminals go
ahead resulting in lower surplus
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
HISTORICAL
OUTLOOK
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Opportunities & Challenges:
Petrochemical Industry
Opportunities
Challenges
AB competitive feedstock = industry competitive
advantage
More ethane/ propane in US = increasing
competitiveness in US (low ethane/ propane prices)
Increasing availability of ethane/ propane given
the natural gas outlook
Are demand expansions possible? Investors? Can
natural gas outlook be significantly different?
Industry expansion and market diversification =
widespread economic benefits
Intense competition for labor, capital, and resources
with several projects in the WCSB and NA
Current and expected natural gas and crude oil
pricing dynamics favor NGLs extraction
Pricing dynamics can change, causing a shift away
from wet gas to dry gas = less ethane and propane
available in gas stream
AB as a stable and attractive investment
jurisdiction
AB to compete for investment capital with USGC and
other locations in North America and the globe
Strong global economy = increased demand for
consumer goods and energy
Economic uncertainty can dampen consumer
demand = lower demand for consumer goods
Oil sands off-gases ethane/ propane can provide
significant incremental volumes
Economics of oil sands off-gases dependent on low
natural gas prices
An opportunity exists for a propylene industry to
be developed in AB
Who will get first to the propane supplies? LPG
export projects, PDH plants, or both? What is the
impact of LNG projects on NGLs availability?
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Thank you!
Questions and/ or
Comments?
Please visit us at:
www.ceri.ca
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