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

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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

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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

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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! 4

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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

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Understanding Shale Gas & Hydraulic Fracturing (Fracking)

Image from Husky

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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

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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

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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 = 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

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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

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Decreased production @ SOEP + USNE gas moving in (does not include Canaport)

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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

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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

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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

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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

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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)

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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

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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

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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

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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

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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

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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)

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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

Relevant • Independent • Objective www.ceri.ca

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

Relevant • Independent • Objective www.ceri.ca

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

37

Relevant • Independent • Objective www.ceri.ca

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

39

Relevant • Independent • Objective www.ceri.ca

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? 40

Relevant • Independent • Objective www.ceri.ca

Thank you! Questions and/ or Comments? Please visit us at: www.ceri.ca

41

Relevant • Independent • Objective www.ceri.ca