Canadian LNG: The race to the coast

CANADA

Our views on Canadian LNG LNG interest in Canada heats up. Canada’s large natural gas resource base, friendly environment to foreign investment, attractive fiscal regime and relative proximity to key producing markets are behind the interest over the last 12 months in LNG exports off the coast of British Columbia (BC). Four LNG projects have been proposed to date, with planned total export capacity of 46.8mtpa. We see a very low probability that all four projects move forward, but believe that BC will become an LNG exporter by 2020. The Shell-led LNG Canada project is likely the first to ship gas from BC’s coast. For additional details on Macquarie’s LNG outlook see LINK.

Inside Our views on Canadian LNG BC tight gas resource Canadian LNG economics Resource consolidation The Canadian LNG projects Infrastructure – Connecting the dots Risks – Environmental and inflationary pressures abound

2 3 8 12 14 19 22

Canadian LNG – Coverage 6-Sep-12 Price

Company

Symbol

Advantage AltaGas ARC Canadian Natural Celtic Crew Encana Imperial Oil Nexen Progress Talisman

AAV CN C$3.48 C$3.75 ALA CN C$31.67 C$40.00 ARX CN C$23.18 C$25.00 CNQ CN C$30.09 C$42.00 CLT CN C$17.27 C$21.00 CR CN C$6.64 C$10.00 ECA US US$22.13US$22.00 IMO CN C$46.44 C$47.00 NXY CN C$25.06 C$27.50 PRQ CN C$21.94 C$22.00 TLM CN C$13.83 C$15.00

Target Rating N O N O O O N N N N O

Source: Bloomberg, Macquarie Research, September 2012

10 September 2012 Macquarie Capital Markets Canada Ltd.

Montney has advantage over Horn River. The Montney tight gas/shale play provides a lower-cost option for LNG players than the Horn River. This is partially a reflection of higher liquids yields over parts of the play, which leads to better economics, though it is also a function of the better-developed infrastructure along the Montney trend. The Montney producers have better access to infrastructure in the near term, while Horn River players are subject to both greater infrastructure development capital and more expensive wells. Break-even LNG liquefaction margins of $5.30/mcf. Based on our assumptions, we estimate a gross margin of $5.30/mcf as the break-even margin required for an LNG facility in BC. This figure factors in capital investment, operating costs, pipeline tolls, and shipping costs to sell LNG in Asia. Integrated break-even LNG price of $8.60–10.00/mcf. Assuming break-even supply costs of $3.30/mcf from liquids-rich Montney gas and $4.74/mcf from the Horn River, we believe the minimum LNG break-even sales price on an integrated basis will range from $8.60–10.00/mcf. If long-term LNG prices stay above this level, then producers should generate positive returns. Several LNG project owners short resource – expect consolidation. Mitsubishi and Kogas are short resource for their working interest in the LNG Canada Development project. We believe Shell/PetroChina may also look to secure addition reserves. Producers we see as potential suitors for asset sales, JVs and/or corporate sales are Celtic, Crew, Painted Pony, Talisman, Advantage, Birchcliff and Trilogy. Encana facing asymmetric economics with JV partners. To date, Encana has entered into two JV agreements for tight gas development in British Columbia: one with Kogas in the Horn River and one with Mitsubishi in the Montney. Encana is also a partner (30% W.I.) in the proposed Kitimat LNG project. However, Encana’s JV partners both have equity interests in the competing Shell-operated LNG Canada facility, and in our view, LNG Canada will proceed before Kitimat LNG. In this event, Encana’s partners could be motivated to drill gas to supply the LNG Canada facility, thus benefiting from selling crude-linked pricing off of Canada’s west coast, while Encana would be forced to sell its share of the JV gas into the domestic market at lower prices. Given this disparity, we believe that Encana could look to sell its Kitimat interest outright, ideally to a global LNG player that can lock up downstream supply agreements and move the Kitimat project ahead.

This report was prepared by Macquarie Capital Markets Canada Ltd and is being distributed by Macquarie Private Wealth Inc. Macquarie Private Wealth Inc and Macquarie Capital Markets Canada Ltd are separate affiliated corporate entities that are part of the Macquarie group of companies. Please refer to the important disclosures and analyst certification on the inside back cover of this document.

Macquarie Research

Canadian LNG: The race to the coast

Our views on Canadian LNG Attractive fiscal regime marries large resource Four LNG projects have been proposed to date, with planned total export capacity of 46.8mtpa

Canadian LNG: The race to the coast is a more detailed view of Canadian LNG. To read Macquarie’s outlook for global LNG see LINK. LNG interest in Canada heats up. Canada’s large natural gas resource base, friendly environment to foreign investment, attractive fiscal regime and relative proximity to key producing markets are behind the interest over the last 12 months in LNG exports off the coast of British Columbia (BC). Four LNG projects have been proposed to date, with planned total export capacity of 46.8mtpa, and additional participants are looking to Canada as a potential home for future investment in both the upstream resource and downstream export facilities. We see a very low probability that all four projects move forward, but believe that BC will become an LNG exporter by 2020, which will aid in diversifying supply sources for foreign buyers with growing domestic needs for natural gas. Over 1,300tcf of resource in just Montney and Horn River. BC boasts a massive natural gas resource base that is being unlocked by advances in horizontal drilling and completion technology. The province has over 1,300tcf of natural gas in place in just the Montney (700tcf) and Horn River Basins (+600tcf). Recent developments in the Liard Basin and future potential of the Cordova Embayment will only serve to bolster this number in the future. Given the nature of land sales in Canada, it is often difficult for producers to gain large contiguous land positions. These contiguous blocks are necessary for successful development of a resource for future LNG potential; as such, we have witnessed increased interest in resource capture in Canada with the recent competition for Progress Energy Resources as well as large-scale JVs with both Encana and Nexen.

The government of British Columbia has been supportive toward the development of its natural gas resource base

BC government supportive of LNG development. Under Confederation, resources in Canada are owned by the respective provinces, not the federal government, meaning that each province has control over royalties and taxation. The government of British Columbia has been supportive toward the development of its natural gas resource base since the first horizontal, multi-stage fracked well was drilled and completed in the province in 2005. Royalties in British Columbia range from 8% to 27%, depending on the local commodity price. Producers can also qualify for a Deep Gas Drilling Credit, which ranges from $800k to $4.7m depending on the location and depth of the well, while drilling in the Horn River benefits from a cost recovery royalty advantage. LNG should narrow AECO differential but not reverse it. The increased gas supply from North American resource plays has resulted in a glut of natural gas and weak domestic pricing. Given BC’s current location disadvantage to key consuming regions in the US, the realized price in BC is often among the lowest in North America. The low regional price and attractive royalty regime are key factors that make BC an attractive export market. Ultimately, the exporting of gas from BC should help to narrow the basis differential for domestic Canadian gas; however, we do not expect BC gas to trade at a premium to other markets, as the BC LNG export market will not be large enough to accomplish this. Transportation advantage compared to Gulf of Mexico exports to Asia. Although the so-called “shale gas revolution” has taken hold across North America, BC is widely considered to be the most likely site for North American LNG exports to Asia. It is estimated that an LNG shipment to Japan would take 8 to 10 days from BC compared to 13 to 15 days from Qatar, 20 to 35 days from the Gulf of Mexico (depending on access to the Panama Canal) or 6 to 8 days from Australia. This relative proximity, combined with depressed North American gas prices, improves BC’s relative attractiveness for LNG exports compared to other key US gas-producing regions.

Note: For all figures a 1.000 US/CAD exchange rate is used throughout our analysis. 10 September 2012

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Macquarie Research

Canadian LNG: The race to the coast

BC tight gas resource The majority of oil and gas production in Canada comes from the three western provinces— British Columbia, Alberta and Saskatchewan—with Alberta being the largest producer by far. Hydrocarbon production in British Columbia is predominantly in the form of natural gas, with most development taking place in the north-eastern region of the province, in the foothills of the Rocky Mountains. The primary shale / tight gas deposits being targeted by producers in the region are the Montney (silts/sands and shales), as well as the Devonian-aged shales within the Horn River, Liard and Cordova basins in the northern extremes of the province.

Fig 1

British Columbia shale gas deposits and pipeline infrastructure

Source: BC Ministry of Energy and Mines, Macquarie Research, September 2012

Three plays represent 165–325tcf of recoverable natural gas

10 September 2012

Massive natural gas resource potential. The most recent estimates for the recoverable resource potential for the Montney are 50–150tcf of natural gas, while the Horn River ranges from 60–100tcf. The Liard Basin is much earlier in the resource definition stage, but estimates from two key landowners (Apache and Nexen) place recoverable resource at 55–75tcf from these two companies alone. Combined, these three plays represent 165–325tcf of recoverable natural gas (see Fig 2). Activity in the Cordova has been relatively quiet, though operators have had positive shale gas tests in the region.

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Canadian LNG: The race to the coast

Fig 2

Northeast BC resource potential of key shale plays

OGIP OGIP / section Recoverable resource Depth Thickness Permability Porosity

(tcf) (bcf/section) (tcf)

Montney 300 - 700 50 - 125 50 - 150

Horn River 350 - 600 130 - 320 60 - 100

Liard TBD 170 - 500 55 - 75*

(ft) (ft) (mD) (%)

6,000 - 10,000 300 - 800 variable 2.0 - 8.0

7,500 - 10,000 500 - 600 0.2 - 0.3 2.5 - 6.0

10,000 - 15,000 400 - 1,000 TBD 3.0 - 8.0

* Based on Apache and Nexen combined estimates only Source: CERI, BC Ministry of Energy and Mines, company disclosure, Macquarie Research, September 2012

Devonian Shales: Horn River, Liard and Cordova basins The broader Devonian shale play in the far northern reaches of BC is actually comprised of three sub-basins. The largest, and most active to date from a development standpoint, is the Horn River Basin, which is separated from the Cordova by the Slave Point carbonate platform to the east, while to the west the Bovie Fault forms the boundary with the Liard. Operators began testing the Devonian shales in 2007 and found the quality of the rocks to be comparable to (and in some cases much better than) those in the Barnett shales of Texas. Activity within the Cordova Embayment to the east has been relatively quiet, as the play is complicated by water legs between shales. The Liard sub-basin is prospective for the same shales as the Horn River and Cordova, though at greater depths (2,500ft or more). Multiple stacked shales. The primary target within the Horn River is the Muskwa shale, though operators have also had success testing the deeper Otter Park and Evie shales. All three shales are prospective in various regions of the play, which could ultimately set up for a stacked horizontal well development program over time. Dry gas and high CO2. While the rock qualities are favourable for shale gas development, there are essentially no free liquids in the Devonian shales. Operators have focused on higher liquidsyielding plays (Eagle Ford, Montney) as natural gas prices deteriorated over the past two years. Additionally, the gas tends to be very high in CO2 (up to 20%), which reduces the heating value of the gas and requires further separation. The Horn River and Liard Basins are quite immature in terms of infrastructure

Limited infrastructure. The Horn River and Liard Basins are quite immature in terms of infrastructure build-out, which has been another factor that has hindered development. Operators have been proving up the prospective resource before aggressively committing capital to facilities and pipelines. In addition, the region is primarily winter-access only, which limits the ability to drill year-round. Cordova seeing limited activity. Operators have primarily been focusing within the Horn River region, as the area tends to have higher OGIP/section than the Cordova, while the Cordova is also challenged by a water leg within the shale horizons. Operators have drilled a handful of wells to define the resource, but the Cordova has yet to see firm plans for a commercial development.

Apache estimates there to be 48tcf of recoverable gas on its Liard lands

10 September 2012

Encouraging results from Liard in 2012. Earlier this year, Apache stunned the industry with very strong rates from a horizontal well test in the Liard. The well was completed with just six frac stages, yet tested at 21mmcf/d over the first 30 days and has an associated EUR of 18bcf. Ultimately, Apache believes the type well in the region will have an IP of 100mmcf/d with EUR of 60bcf of sales gas. Apache estimates there to be 48tcf of recoverable gas on its lands alone. The Liard is still in the very early stages of development, yet given the play’s proximity to the west coast, this region could be a viable source of supply for proposed LNG facilities. However, since the wells are considerably deeper, drilling and completion costs are high. 4

Macquarie Research

Fig 3

Canadian LNG: The race to the coast

Devonian Shale sub-basins and cross-section

Source: AAPG Explorer; Encana, Macquarie Research, September 2012

Horn River production Horn River Basin production began with just a few wells in early 2008. Production then ramped up steadily through late 2011 and hit a peak of about 300mmcfe/d. Since then, almost no new wells have been drilled and aggregate production has fallen off. Nonetheless, early producers such as Encana and Nexen have delineated much of the play and thus have established it as a viable supply source for west coast LNG.

Fig 4

Horn River Basin production by vintage

350

2012 2011 2010 2009 2008 2007 2006 Pre 2006

Natural Gas Production (mmcf/d)

300

250

200

150

100

50

Jan-12

Jan-11

Jan-10

Jan-09

Jan-08

Jan-07

Jan-06

0

Source: GeoScout, Macquarie Research, September 2012

10 September 2012

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Canadian LNG: The race to the coast

Montney: Firing on all cylinders The Montney is by far the most active natural gas play in BC

The Montney is by far the most active natural gas play in BC, stretching from Alberta’s Deep Basin northwest into British Columbia. The play continues to expand to the northwest as operators have successfully pushed the play’s boundaries. Hybrid unconventional reservoir – three separate units. The Montney is a Triassic-aged formation, separated into three distinct units over the regional trend. The Upper and Middle Montney sequences are clastics, typically a tight siltstone / sandstone. The Lower Montney is a true shale play, having formed in a turbidite marine environment. Lower barrier to entry – many players in the arena. The Montney play is largely within or near existing conventional natural gas infrastructure. Additionally, the costs to drill and complete wells are typically between $3–5m; thus, smaller companies can step up activity in this region more easily than in higher capital-cost plays like the Horn River, where well costs can run up to $20m. The Montney is being developed by large and small cap companies alike with numerous operators on the trend. Liquids boosting economics in areas. Unlike the Devonian shales to the north, which are dry, parts of the Montney also produce associated condensate and NGLs. Given the relative strength of liquids pricing versus gas, the liquids-rich portion of the Montney trend has remained an active area of development in Western Canada. While parts of the Montney are dry, industry has identified a wet gas window that provides liquids yields ranging from 10–100bbl/mmcf. In certain more localized regions of Alberta, the Montney is also prospective for light oil.

Fig 5

Greater Montney Trend OGIP

Source: Encana, Macquarie Research, September 2012

10 September 2012

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Macquarie Research

Canadian LNG: The race to the coast

Montney producing over 1.5 bcf/d We estimate that 1bcf/d of production has been added in the Montney since January 2010

Once operators started to figure out the complexities of horizontal drilling and multi-stage fracturing completions, production from the Montney exploded. The play delivered very high growth in 2010 and 2011, reflecting improving economics, which are partially boosted by high liquids yields over parts of the play. While production has flat-lined in 2012 due to weak natural gas prices, we estimate that 1bcf/d of production has been added since January 2010. From our perspective, this speaks volumes to the play’s ability to ramp up production rates to feed LNG projects.

Fig 6

Northeast BC Montney production by vintage

1,800

2012 2011 2010 2009 2008 2007 2006 Pre 2006

1,600

Natural Gas Production (mmcf/d)

1,400

1,200

1,000

800

600

400

200

Jan-12

Jan-11

Jan-10

Jan-09

Jan-08

Jan-07

Jan-06

0

Source: GeoScout, Macquarie Research, September 2012

10 September 2012

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Macquarie Research

Canadian LNG: The race to the coast

Canadian LNG economics Minimum LNG price of $8.60/mcf required Ultimately, we see the LNG players in Canada pursuing a fully integrated model; that is, owning and developing the upstream natural gas resource as well as exporting gas via LNG terminals. We have split the economic analysis into two separate sections: ƒ What is the break-even LNG margin required to justify construction of a terminal? ƒ What is the break-even supply cost for natural gas resource from key plays in the Montney and

Horn River? The Integrated LNG break-even price is the minimum LNG price that provides break-even returns, using a 10% after-tax discount rate, to drill natural gas wells, convert the gas to liquid, and ship the LNG to Asian buyers.

LNG facility break-even margin: $5.30/mcf On our estimates (Fig 7), we calculate a break-even LNG facility margin of $5.30/mcf. We have assumed facility costs of $1,200/tpa, which is well ahead of the $650/tpa we assume for projects in the Gulf of Mexico and $900/tpa in East Africa. The Gulf of Mexico benefits from the use of existing infrastructure while Canada will be looking at greenfield projects in an environmentally sensitive region that suffers from a tight skilled labour market. Our $5.30/mcf margin is required to pay for the capital investment and derive a zero NPV (10% after-tax). The margin is the price difference between the LNG sales price and purchase price of domestic gas to use as the feedstock. Based on our assumptions of a 15% oil linked slope, an LNG project in BC would generate a 26% IRR and an NPV of $11.3bn.

Fig 7 LNG facility model assumptions Facility Project size

Pricing / Operational (mtpa)

12.0

(US$/mmbtu)

15.0

2

Gas supply cost

(C$/mmbtu)

4.00

(years)

25

F/X rate

(CAD/USD)

1.00

(yr)

2019

Facility Operating costs

(C$/mcf)

1.00

Number of trains Project life First production Peak production

LNG price

(yr)

2020

Pipeline tolls

(C$/mcf)

0.80

Total capex

($bn)

12.6

Shipping costs

(C$/mcf)

0.80

Total capex

($/tpa)

1,200

G&A

(C$/mcf)

0.10

Maintenance capex

(C$/mcf)

0.10

Profitability metrics NPV

(C$bn)

11.3

IRR

(%)

26%

x

0.90

P/I ratio

Source: Macquarie Research, September 2012

Upstream break-even prices have large impact on Integrated returns Since operators seem to be focusing on the Montney and Horn River to supply all of the proposed LNG projects, we have updated our type curves to estimate the break-even natural gas price for these plays. In order to more accurately reflect full-cycle costs (other than land), we have burdened our type curves with a proportionate share of facility and gathering infrastructure, in addition to pipeline tolls. We have prepared three type curves: 1) dry Montney; 2) wet Montney (20bbl/mmcf); and 3) dry Horn River.

10 September 2012

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Macquarie Research

We estimate breakeven natural gas prices to be between $3.30–4.74/mcf including transportation

Canadian LNG: The race to the coast

As per our assumptions (Fig 8), we estimate break-even natural gas prices (to drive a zero NPV at 10% AT) as shown. The liquids-rich Montney at $2.50/sh clearly benefits from the NGL/ Condensate revenue stream1, compared to the dry gas plays; we estimate the dry Montney to be $3.26/mcf with the Horn River at $3.74/mcf. We estimate that pipeline tolls to transport natural gas from the Montney region to the west coast will be $0.80/mcf, and given the incremental transportation from the Horn River region, we expect an additional $0.20/mcf for the Devonian shales. Factoring in pipeline tolls, we estimate a liquids-rich Montney break-even of $3.30/sh, with the dry Montney at $4.06/mcf and the Horn River at $4.74/mcf.

Fig 8

Montney and Horn River Economic assumptions Montney Montney (Dry) (Liquids) 5.0 5.0 4.0 4.5

IP (mmcfe/d) Recovery (bcfe) Liquids yield (bbl/mmcf)

1

-

20

5.5 4.3 9.8

5.5 4.3 9.8

18.0 4.3 22.3

3.26 0.80 4.06

2.50 0.80 3.30

3.74 1.00 4.74

Drill, complete & tie-in cost ($m) Facility expenditures/well ($m) Total cost ($m) Break-even pre transport ($/mcfe) Transportation cost ($/mcf) Break-even ($/mcf)

Horn River 15.0 15.1 -

1. We assume that liquids production receives 60% of WTI pricing on a fixed long-term basis of US$95/bbl Note: USD/CAD x-rate assumed at 1.000

Source: Company reports, Macquarie Research; September 2012

Canadian Integrated LNG break-even price: $8.60/mcf Integrated LNG players need to sell LNG at a price high enough to justify field development in addition to construction of the LNG facility. The Integrated break-even price is the sum of the upstream and LNG facility break-even prices. Our generic liquids-rich Montney well has a breakeven supply cost of $3.30/mcf (including tolls); thus, the Integrated break-even (on our $5.30/mcf facility margin) is $8.60/mcf. On the upper end, the Horn River upstream break even is $5.74/mcf, driving an Integrated break-even LNG price of $10.04/mcf for this play. We see potential for upstream efficiency gains to further reduce drilling costs, and hence, to improve overall economics. However, we see some risk that LNG cost overruns and inflation on the facility side could potentially erode returns.

1

10 September 2012

NGL/Condensate revenue assumed at 55% discount off of a long-term WTI price of $100/bbl. 9

Macquarie Research

Fig 9

Canadian LNG: The race to the coast

Integrated LNG project break-even prices

Fig 10 Project NPV sensitivity to LNG pricing $30.0

12

$25.0

$20.0

LNG facility margin 8 Pipeline toll

NPV (C$bn)

Breakeven price ($/mmbtu)

10

6 Supply cost

$15.0

Montney (liquids-rich)

$10.0

Montney (dry)

$5.0

4

Horn River

$0.0

2 ($5.0) $9.00

$11.00

0

$13.00

$15.00

$17.00

$19.00

$21.00

LNG Price (US$/mmbtu)

Montney (liquids-rich)

Montney (dry)

Horn River

Source: Macquarie Research, September 2012

Source: Macquarie Research, September 2012

Input sensitivities The factors that have the greatest effect on our LNG project NPV are: 1) LNG product pricing and 2) the USD/CAD exchange rate. The chart on the left hand side of Fig 11 shows the effect on NPV of increasing and decreasing each individual input (See Fig 7 for our base case assumptions) by 10% while holding all other inputs constant. The chart on the right hand side of Fig 11 shows the range of IRRs that result from changing both the LNG price (from $15/mcf) and LNG facility capital costs (from $1,200/tpa).

Fig 11

LNG input sensitivities CAPITAL COSTS F/X (C$/US$)

IRR

30%

20%

10%

0%

-10%

-20%

-30%

LNG PRICE

-30%

10.7%

11.7%

12.8%

14.1%

15.7%

17.5%

19.7%

-20%

14.5%

15.7%

17.0%

18.6%

20.4%

22.6%

25.3%

-10%

17.9%

19.3%

20.8%

22.6%

24.7%

27.2%

30.3%

0%

21.1%

22.6%

24.3%

26.3%

28.7%

31.5%

34.9%

10%

24.1%

25.7%

27.6%

29.8%

32.4%

35.5%

39.2%

20%

26.9%

28.7%

30.7%

33.1%

35.9%

39.2%

43.3%

30%

29.6%

31.5%

33.7%

36.2%

39.2%

42.8%

47.1%

GAS SUPPLY COST

CAPITAL COSTS

LNG PRICE

DISCOUNT RATE

Increase factor by 10% Decrease factor by 10%

-30%

-20%

-10%

OP COSTS

0%

10%

20%

30%

NPV Sensitivity

Source: Company reports, Macquarie Research, September 2012

10 September 2012

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Canadian LNG: The race to the coast

Advantage: Montney The liquids-rich Montney presents a clear advantage for Integrated LNG players

10 September 2012

In our opinion, the Montney—in particular, the liquids-rich Montney—presents a clear advantage for Integrated LNG players in Canada relative to the Greater Horn River region further to the north. In the longer run, should multiple LNG projects actually proceed, we see some potential for the Horn River as a supply source, but in the near term, the Montney appears most ‘development-ready’ and should have a first-mover advantage. 1.

Better economics – liquids yield a bonus. In some regions of the liquids-rich Montney, the liquids yield alone may pay for the cost of the well, leaving the gas steam going to the west coast as pure profit. The Horn River, being dry, deeper, and more expensive to drill, doesn’t provide this same benefit. To take advantage of the liquids yields, producers will favour pipeline projects that allow them to benefit from liquids delivery.

2.

Better developed infrastructure. The Montney is situated near existing pipeline and facility infrastructure. Comparatively, the Horn River Basin requires substantial future investment—not only in pipelines, but also in natural gas plants and related gathering facilities. While producers have been keen to speak of improving half-cycle economics in the play, we believe the full-cycle costs (including facilities) put the Horn River Basin at a disadvantage relative to the Montney.

3.

Lower transportation. Feeding into Point #1 above, Horn River operators may face incremental pipeline tolls to transport gas over a greater distance to the west coast.

4.

Lower op costs. Admittedly, the Horn River hasn’t achieved the economies of scale seen in the Montney. However, Horn River gas typically has high CO2 levels (thus lower heat content), which requires further separation and processing.

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Canadian LNG: The race to the coast

Resource consolidation M&A activity has been heating up As producers successfully proved the resource potential of the Montney and Devonian shales, visibility for large-scale, long-term natural gas supply improved dramatically. Nearly $8bn of JV activity. There have been a number of joint venture deals signed since 2010, with total cash plus carry commitments nearing C$8bn. The majority of the deals have been signed with Asian NOCs wanting to secure longer-term natural gas with an ultimate view of securing LNG export capacity. Fig 12 contains a list of some of the recent notable natural gas joint venture agreements.

Fig 12

British Columbia tight gas joint ventures

Date Announced

Buyer

Seller

Location

WI Acquired

Capital Carry

%

%

Cash Cash Offer Total Value Component %

(C$mm)

(C$mm)

March 1, 2010

Korea Gas Corp

Encana Corp

Montney / Horn River

50%

100%

0%

$0

$565

August 24, 2010

Mitsubishi Corp

Penn West Exploration

Horn River / Cordova

50%

50%

56%

$250

$450

Sasol Ltd

Talisman Energy

Montney

50%

75%

25%

$263

$1,050

December 20, 2010 March 8, 2011

Sasol Ltd

Talisman Energy

Montney

50%

75%

25%

$263

$1,050

PETRONAS

Progress Energy Resources

Montney

50%

75%

25%

$268

$1,070

November 29, 2011

INPEX

Nexen Inc

Horn River / Liard / Cordova

40%

50%

50%

$350

$700

February 17, 2012

Mitsubishi Corp

Encana Corp

Montney

40%

50%

50%

$1,450

$2,900

$2,844

$7,785

June 2, 2011

Total

Source: Company reports, Macquarie Research, September 2012

The Talisman JVs are somewhat unique in that Sasol was looking to secure natural gas supply for a proposed facility utilizing its proprietary GTL (gas to liquids) technology. However, Talisman has since decided not to proceed with the GTL facility, and has indicated that it is evaluating LNG options for its remaining Montney resource. Corporate take-overs heating up. In addition to JV activity, there have been two recent transactions that have seen Montney / Horn River resource owners being bid for by Asian NOCs. In June 2012, PETRONAS made an all-cash bid for Progress Energy, securing Progress’s expansive and strategically situated land position for ultimate integration into an LNG export facility. This followed on the June 2011 JV announcement between PETRONAS and Progress. In a second transaction, CNOOC has made a bid to acquire Nexen in a $15.1bn deal. While Nexen has producing assets in a number of regions globally, CNOOC stands to acquire Nexen’s Horn River, Liard and Cordova shale gas resource. Of note, neither Nexen nor CNOOC are currently part of any planned LNG facility in Canada, but could potentially partner with other proposed LNG projects.

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Canadian LNG: The race to the coast

Lots of resource left for consolidation The LNG Canada Development consortium is short up to 11.5tcf of recoverable resource

We believe that a number of owners of planned LNG projects in Canada remain short upstream natural gas resource. There is rampant industry speculation that there are more NOCs looking to consolidate resource, though multi-national oil companies are also believed to be on the hunt to lock in longer-dated gas resource. We discuss in further detail on pg.14 how the LNG Canada Development consortium is short up to 11.5tcf of recoverable resource according to its July 2012 regulatory filing. We present a summary of some of the larger natural gas resource owners in Western Canada in Fig 13. The list is not meant to be exhaustive, but highlights some of the key names we believe are at the top of the list for future JVs or consolidation given their respective defined resource and / or large, contiguous land bases.

Fig 13 Key Canadian companies with natural gas resource Horn River

Liard

Cordova

Contingent Prospective Contingent

Apache

Tcf

Tcf

9.2

48.0

4.3

Nexen

5.0

EOG

6.9

Quicksilver

10.0

13.0

Canada 2P*

Tcf

tcf

Tcf

3.5

60.7

29.0

1.9

30.9

8.1

10.0

22.4

Tcf

Talisman Encana

Montney Contingent

3.0

8.1

Petronas / Progress Devon

6.6 4.1

ARC Canadian Natural

Total

1.3

22.3

6.2

13.1

Comments

10tcf in Sasol JV lands; 19tcf in other Montney

Midpoint estimates as per company disclosure

0.3

10.3

1.7

9.8

1.0

7.6

2.4

6.5

Northeast BC Montney

5.8

5.8

916,000 net acres in Montney. Contingent resource not disclosed.

Contingent resource is only for Town. We estimate total resource of 20tcf

Birchcliff

2.6

1.4

4.0

Alberta Montney

Advantage

1.4

1.3

2.7

Alberta Montney

2.1

2.1

363,000 net acres in Horn River Basin + Montney

0.2

1.7

ConocoPhillips Paramount

0.4

1.1

1.4

1.4

No contingent resource estimate.

0.5

1.2

3.3 TCF OGIP on 56 sections (of 220 total Montney sections)

0.1

0.7

Painted Pony

0.7

0.7

No contingent resource estimate.

Celtic

0.6

0.6

No contingent resource estimate.

Imperial Oil/Exxon

0.4

0.4

340,000 net acres in Horn River Basin

Trilogy

0.4

0.4

No contingent resource estimate.

Tourmaline 0.7

Crew Storm

0.6

* Apache, Quicksilver, EOG, and Devon are Proved (1P) only as per SEC filings

Source: Company reports, Macquarie Research, September 2012

In addition to the companies listed in Fig 13, we note several other companies that have significant positions in the Horn River Basin or Montney. Canadian Natural Resources claims 916k net acres in the Montney; ConocoPhilips has 363k net acres in the Horn River Basin and Montney combined; and Imperial Oil and Exxon have about 340k net acres in the Horn River Basin.

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The Canadian LNG projects We do not believe that all four projects will go ahead as planned

Project profiles W.I.

LNG Canada Royal Dutch Shell PetroChina Mitsubishi Kogas Petronas LNG Kitimat LNG Apache EOG Encana BC LNG Co-op

Fig 15 Project NPV sensitivity to LNG pricing 7.0

Max. Capacity (mtpa)

Gas equivalency (bcf/d)

# of trains

Expected Startup

Location

24.0

3.2

4

2019

Kitimat

6.0 5.0

40% 20% 20% 20% 11.0

1.5

3

2018

Prince Rupert

10.0

1.4

2

2017

Kitimat

40% 30% 30% 1.8

0.25

2

2015

Natural gas (bcf/d)

Fig 14

As previously mentioned, there are four projects currently planned for the west coast of British Columbia totalling 46.8mtpa. Given the current LNG landscape, we do not believe that all four projects will go ahead as planned, with expectations that Shell’s LNG Canada project is the best positioned to be the first to ship natural gas from the west coast, followed by PETRONAS’s Lelu Island facility. We summarize all planned projects below. In addition to the projects listed below, we note that BG has commissioned a feasibility study for an LNG facility in Prince Rupert.

LNG Canada 4.0 PETRONAS 3.0 Kitimat 2.0

BC LNG

1.0

Kitimat

0.0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Source: Company reports, Macquarie Research, September 2012

Source: Company reports, Macquarie Research, September 2012

LNG Canada development LNG Canada is the largest LNG terminal currently being proposed in Canada

LNG Canada is the largest planned export facility. In July 2012, LNG Canada Development Inc. submitted a regulatory application for a licence to export LNG from a terminal in Kitimat, BC. LNG Canada Development Inc. is a partnership composed of Shell Canada Energy (Royal Dutch Shell – 40% W.I. and operator), Diamond LNG Canada (Mitsubishi Corp. – 20% W.I.), Kogas Canada LNG (Korea Gas Corp. – 20% W.I.), and Phoenix Energy (PetroChina – 20% W.I.). The project is the largest LNG terminal currently being proposed in Canada, with ultimate design and export capacity of 24mtpa LNG from four trains, which is equivalent to ~3.2bcf/d, over a 25-year period. To put this into perspective, total natural gas production in Canada was ~14.5bcf/d in 2011. First gas planned for 2019. The project is designed for four 6mtpa (~800mmcf/d) trains. The first train is expected to begin shipments in 2019, with the second train coming six months later. Specific timing has not been provided for the last two trains, as the consortium will take into consideration market conditions before committing to the timing of these trains; however, in its regulatory filings, LNG Canada has stated that it fully intends to build all four trains. Prior to the regulatory filing, expectations were for only two trains.

LNG Canada is short between 9.5–11.5tcf to fill four trains

10 September 2012

Resource-shy; acquisitions likely to backfill commitments. Based on four trains, LNG Canada stated in its regulatory filing that it would need 34tcf of gas reserves over the life of the project. The consortium has released conflicting reserve data. As of year-end 2011, the LNG Canada participants have 28tcf of recoverable gas reserve and resource in western Canada, according to third-party engineering evaluations. Using the reserve engineers’ blowdown of these reserves starting in 2019, gas resources total 24.5tcf, which is slightly ahead of the regulatory filing showing 2P reserves plus 2C contingent resources of 22.5tcf. Looking at either the blowdown of assets post 2019 or the regulatory filing, LNG Canada is short between 9.5–11.5tcf to fill four trains.

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Fig 16 shows the partners’ current Canadian gas resource estimates relative to supply commitments. The most notable deficiency comes from Kogas (5.8tcf), which currently has relatively few upstream resources in Canada. This overall resource deficiency suggests that there is more M&A or JV activity to come in Canada by the consortium in the future. The partners have stated that they would be willing to process third-party gas but our belief is that there will be an increased emphasis on ownership of the full value chain meaning M&A and/or JV activity. Given the long-dated nature of the LNG project, immediate action is not necessary but we would expect all resource to be in place over the next 24 months. (See our M&A/Resource section on pg 12.)

Fig 16

LNG Canada Partners’ natural gas reserves

Shell/PetroChina Corp. Supply Pool Marketable Gas Volumes (2019) As of Dec 31, 2011 Reserves Bcf Total 2P 1,637 Contingent (2C) 17,018

Mitsubishi Corp. Supply Pool Marketable Gas Volumes (2019) As of Dec 31, 2011 Reserves Bcf Total 2P 366 Contingent (2C) 4,473

Korea Gas Corp. Supply Pool Marketable Gas Volumes (2019) As of Dec 31, 2011 Reserves Bcf Total 2P 9 Contingent (2C) 951

Total 2P + 2C

18,655

Total 2P + 2C

4,840

Total 2P + 2C

Supply commitment

20,400

Supply commitment

6,800

Supply commitment

6,800

Surplus / (Deficit)

(1,745)

Surplus / (Deficit)

(1,960)

Surplus / (Deficit)

(5,839)

961

Source: National Energy Board, company reports, Macquarie Research, September 2012

Most attractive project proposed to date. The marriage of Shell Canada with potential offtake partners in its LNG Canada Development gives it a distinct advantage over other proposed LNG projects in British Columbia. We believe this project is the most likely to ship first gas from BC and sign a potential long-term contract for at least a portion of its gas exports.

PETRONAS – Lelu Island Up to three trains planned for Lelu Island. When PETRONAS made its initial offer to enter into a JV with Progress Energy Resources in 2011, it also announced its plans to pursue LNG off the BC coast. In June 2012, PETRONAS made an offer to acquire all of Progress (the acquisition is scheduled to close at the end of September). PETRONAS intends to construct an LNG facility on Lelu Island, which lies just to the south of Prince Rupert, with a planned export capacity of 7.4mtpa (~1.0bcf/d) from two separate trains, beginning in 2018. A third train has also been mentioned as a possible option, which would increase export capacity by 50% to 11mmpta. Progress acquisition would allow for more than sufficient resource capture. The proposed acquisition of Progress gives PETRONAS sufficient resource to go ahead with the project at a 100% working interest. We estimate that there is over 20tcf of potential recoverable resource on Progress’s land base, while current needs would see PETRONAS requiring 9.0tcf of gas to supply 7.4mtpa worth of exports over a 20-year period for two trains or 13.5tcf if three trains are constructed. As with all LNG projects in western Canada, we believe that PETRONAS could see delays to its targeted 2018 timeframe.

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We believe that PETRONAS will look to sell down part of its interest

Possible working interest sale. Given the large capital expenditures of a fully integrated LNG project, we believe that PETRONAS will look to sell down part of its interest in the integrated Lelu Island facility and the upstream assets. The most attractive partner would be an NOC with offtake requirements. We could also see PETRONAS partner with another IOC that has more upstream experience. We believe PETRONAS’s LNG background gives it an advantage over the Kitimat LNG project (see below) but still ranks below the Shell consortium. Should the global LNG market move toward a higher percentage of spot cargoes, PETRONAS is in a respectable position to take advantage of this with a large LNG fleet and an established marketing network. As with the Shell project, PETRONAS would need to secure a percentage of its offtake as firm commitments to move forward with Lelu Island. Pipeline plans expected in September 2012. PETRONAS is working with two major pipeline companies on a Detailed Feasibility Study to determine the best option for a pipeline to supply Lelu Island. A decision on the pipeline is expected in September 2012. For further details, see our Infrastructure section.

Kitimat LNG Kitimat LNG is the most advanced in terms of regulatory approvals

The proposed Kitimat LNG export terminal, to be located in Kitimat, British Columbia, is a joint venture between Apache (40% W.I. – operator), EOG (30% W.I.), and Encana (30% W.I.). It is the most advanced in terms of regulatory approvals having received a 20-year export licence from the National Energy Board and clearing all necessary regulatory hurdles. Two trains planned. Kitimat is planning two trains of 5mtpa each for a gas equivalent of ~1.4bcf/d. In order to supply the export terminal with this quantity of gas over a 20-year period, the partners must be able to draw from at least 14.0tcf of natural gas reserves; this assumes 10tcf for 1bcf/d of capacity. Horn River may not become main feedstock source. Indeed, all three of the partners in the Kitimat LNG project have significant natural gas resources, in the Horn River, which was part of advantage of this partnership; however, due to the higher development costs of the Horn River and Encana’s focus on the Montney, coupled with Apache’s recent discovery in the Liard Basin, the Horn River may not become the main feedstock source for Kitimat LNG as producers may draw from other basins. These developments further complicate the future of Kitimat LNG.

Fig 17

Kitimat partners’ natural gas reserves

Apache BC, AB, and SK Marketable Gas Volumes As of June 30, 2010 Conventional Bcf Proved Developed 1,332 Proved Undeveloped 426

Encana Horn River Marketable Gas Volumes As of Dec 31, 2011 Horn River Bcf Proved 600 Probable 600 Possible 300 Total 3P 1,500 Contingent (2C) 4,300 Total 3P + 2C 5,800

Total Proved HRB Contingent (2C) Total 1P + 2C

1,758 8,920 10,678

EOG Horn River Marketable Gas Volumes As of Oct 1, 2010 Horn River Bcf Proved 1,540 Probable 2,155 Possible 292 Total 3P 3,987 Contingent (2C) 5,705 Total 3P + 2C 9,692

Supply commitment

5,600

Supply commitment

4,200

Supply commitment

4,200

Surplus / (Deficit)

5,078

Surplus / (Deficit)

5,492

Surplus / (Deficit)

1,600

Note: Surplus/(Deficit) estimate is based on 10tcf per 1bcf/d of capacity Source: National Energy Board, company reports, Macquarie Research, September 2012

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Construction is scheduled to begin later this year

Kitimat LNG will likely face additional delays

Canadian LNG: The race to the coast

Pacific Trails Pipeline to connect Kitimat LNG. The Kitimat export terminal is expected to be connected to the Horn River via the proposed Pacific Trail pipeline, which would run 463km from Summit Lake to Kitimat. At Summit Lake, the pipeline would connect to the Spectra pipeline, which is itself connected to the larger BC/AB gas grid. The proposed Pacific Trail pipeline would have a transmission capacity of ~1.4bcf/d – exactly enough to supply Kitimat’s LNG exports. Pacific Trail Pipelines is jointly owned by the three Kitimat partners. First Nations, over whose land the pipeline will run, have the option to acquire an equity stake. The clearing and logging phase of pipeline construction is scheduled to begin later this year. Further delays coming? In June 2012, the Kitimat partners announced that the anticipated date for first gas export had been pushed back by a year to 2017. The partnership is searching for long-term demand contracts in Asia before it moves ahead with a final investment decision on the LNG terminal. We believe that delays to-date in securing these agreements as well as both EOG and Encana’s statements that they would be willing sellers of their Kitimat interests means that the project will likely face crippling delays. Ultimately, we see the LNG Canada project being the most likely to ship first gas from Kitimat. One possibility to putting Kitimat LNG back on track is for a partnership with a large NOC or IOC. Both Nexen (or CNOOC) and Imperial Oil/Exxon have significant positions in the Horn River and may ultimately show interest in the project. Without additional support, we do not believe that Kitimat LNG will move forward.

BC LNG project The BC LNG co-op aims to bring together both natural gas producers and LNG purchasers

Trying to partner independent export with independent producers. The BC LNG project is quite different than the other proposed facilities on the west coast of BC. The project is managed by the Douglas Channel Energy Partnership (DCEP), which is a 50/50 joint venture between the Haisla First Nation and LNG Partners LLC of Houston, Texas. Instead of being an integrated project, DCEP has established the BC LNG Export Co-operative. The co-op aims to bring together both western Canada natural gas producers and purchasers and distributors of LNG; members have the opportunity to supply gas to the project or to purchase LNG from the project. In theory, the project allows smaller players to take part in LNG exports without committing to otherwise prohibitive up-front capital costs. The BC LNG Export Co-operative currently has 16 members, including six BC and Alberta gas producers. Small-scale LNG – but will economics work? DCEP is looking at small-scale exports with the first train exporting only 700,000tpa (~100mmcf/d) in late 2014/early 2015, with a second train potentially adding an additional 1.1mtpa (~150mmcf/d) by early 2016. The project has already received regulatory approval from the National Energy Board to export the two-train total of 1.8mtpa over a 20-year period. We believe that exports by late 2014 is an unrealistic target. The project plans to have its liquefaction facilities located on barges in the Douglas Channel, meaning no physical land is required. BC LNG has signed for 80mmcf/d of firm transmission capacity on the existing Pacific Northern Gas (PNG) pipeline owned by AltaGas (115mmcf/d capacity) that runs from Summit Lake, BC to the west coast. In an attempt to secure sufficient pipeline capacity, BC LNG is funding a feasibility study for a potential expansion of the existing PNG pipeline to meet its total project needs of 250mmcf/d. The requirement of offtake partners to potentially supply ships is another hurdle for this project.

The size of the project does not allow for economies of scale

10 September 2012

Economies of scale are an issue. We remain sceptical about BC LNG’s plans, as break-even costs likely require a very depressed domestic natural gas market; the size of the project does not allow for economies of scale. In addition, we do not see the same depth of marketing contracts with the consortium compared to other proposed projects.

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BG Group BG Group is conducting a feasibility study

The late-comer. In February 2012, BG Group announced that it would begin conducting a feasibility study on developing an LNG terminal in Prince Rupert. The Prince Rupert Port Authority has provided the company with land access to an industrial site as it carries out an economic assessment. BG Group is the second-largest LNG player globally, behind Royal Dutch Shell, so its interest in Canada is significant. However, unlike Shell, BG Group does not own any upstream gas resources in Canada. Given the lack of upstream resources and its late expression of interest, we would be surprised to see this LNG proposal move beyond the economic assessment. Instead, if BG is to establish a presence in Canada’s LNG landscape, we expect it to be through an acquisition in another proposed facility.

Canaport Canada’s LNG import facility. The Canaport LNG terminal, located on Canada’s east coast near Saint John, New Brunswick, is Canada’s only fully operational LNG terminal. It is a partnership between Irving Oil (25%), which is a private energy company in eastern Canada, and Repsol (75%). In contrast to all of the proposed projects in British Columbia, Canaport is an LNG import terminal. The terminal receives shipments of LNG from its supplier, Repsol Energy Canada, and has a maximum gas send-out capacity of 1.2bcf/d. The gas is used to supply eastern Canadian and northeastern US markets. While the Canaport terminal does factor into the global LNG supply/demand equation, it is far removed from developments on the other side of the country. With North American gas prices hovering below US$3/mcf, the economics of LNG imports are challenging.

Other potential entrants Nexen/CNOOC and Imperial Oil/Exxon may also still enter the LNG race

Nexen/CNOOC/Inpex. In November 2011, Nexen announced a joint venture agreement with Inpex Corp. of Japan in order to develop Nexen’s vast shale gas holdings in northeast BC. The joint venture lands include 366sq km in the Horn River Basin, 517sq km in the Liard Basin, and 333sq km in the Cordova Basin. The Horn River and Cordova lands are estimated to have 4–15tcf of recoverable contingent resource, while the Liard Basin lands are estimated to contain 5–23tcf of prospective resource. Under the terms of the joint venture, Inpex earned a 40% W.I. for consideration of C$700m. Inpex is a global LNG player, with large projects in Indonesia and Australia. It is also Japan’s largest E&P company, with over 400mboe/d of global production. Inpex and Nexen had agreed to investigate the feasibility of an LNG project on Canada’s west coast at the time of the joint venture announcement. In July 2012, CNOOC made an all-cash bid of ~US$15.1bn to acquire all of the outstanding shares of Nexen. While we believe that CNOOC is mainly after Nexen’s oil resources both inside and outside of Canada, it will likely pursue LNG export feasibility with Inpex while continuing to prove up the resource in BC. Imperial Oil/ExxonMobil. In May 2012, Imperial Oil hinted about the possibility of pursuing a west coast LNG facility. Such a project would certainly involve ExxonMobil, its parent company. While details from the company have been very light, it is worth noting that Imperial Oil has about 340sq km of land in the Horn River Basin. We view the prospect of Imperial Oil’s entrance onto the LNG scene as a longer-dated possibility than the other projects listed above. As with BG, we believe that Imperial will need to look at acquiring a position in either the Kitimat LNG project or PETRONAS’s proposed Lelu Island facility if it wants to become an early player in BC’s LNG landscape.

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Infrastructure – Connecting the dots Services may become increasingly tight

Services may become tight if projects go ahead. BC has excellent access to drilling and completions equipment, given Canada’s status as a mature basin for oil and gas development and as a leader in adopting horizontal stage frac technology. Although access to rigs and completion crews are plentiful today, these services may become increasingly tight as producers move towards first gas through their export facilities, and additional rigs and horsepower will be required. In addition, the remote location of the majority of these reserves means that the labour market for skilled personnel will become tight, and labour costs will again face upward pressure. New pipelines required. Another hurdle to development is pipeline access and infrastructure. Currently there is a small natural gas pipeline owned by Pacific Natural Gas (subsidiary of AltaGas) that ships 115mmcf/d from the Spectra pipeline to Prince Rupert, BC. Although this line flows gas for domestic consumption, it is not appropriately sized to handle the volume of gas required to satisfy the demand of a potential liquefaction plant. Instead, two new pipelines have been proposed: the Coastal GasLink project for the Shell consortium and the Pacific Trails Pipeline Expansion project for Kitimat LNG. To date, PETRONAS has not announced its pipeline plans for Lelu Island.

Fig 18

Significant BC natural gas infrastructure

Source: Douglas Channel Energy Partners

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Handling of sensitive environmental issues will be critical. An important consideration when looking at BC’s infrastructure picture is the sensitive environment that the pipelines will need to cross. There are numerous river crossings in addition to significant elevation changes and the potential for some horizontal drilling off mountain passes. Power requirements are more straightforward, and we anticipate gas-fired baseload generation will be developed in the area to support LNG projects. The energy infrastructure companies pursuing pipeline projects also have significant experience in gas-fired power projects. The LNG Canada project alone may need 500–1,000 MW of power including redundancies—a significant amount. Although oil pipelines are meeting significant political and local opposition, natural gas pipelines have not been met with anywhere near the same level of scrutiny and we believe the regulatory environment is actually favourable toward LNG projects. Demonstrating its support for LNG in BC, the province’s premier has exempted LNG projects from complying with its restrictive Clean Energy Act.

Coastal GasLink Supplying LNG Canada Development. The Coastal GasLink project is in its infancy, with Shell and its partners selecting TransCanada to design, build, own and operate the pipeline. TransCanada is working towards an agreement and a contract is expected to be in place by yearend. The final pipeline route will be determined after taking into consideration First Nations input as well as the environmental and economic impacts. No applications for approvals have been submitted yet; however, we believe the regulatory environment is supportive. We estimate a twoto three-year construction period is needed for Coastal GasLink, which means that there is sufficient lead time before first gas shipments in 2019. TransCanada has the local expertise for this project despite the anticipated physical challenges. More capacity needed if plan is for Transportation by Others. The pipeline is initially being sized to 1.7bcf/d but will likely be expanded, as Shell’s plans are to ultimately build four trains with total capacity of 3.2bcf/d. The line would connect to the larger TransCanada owned system in BC (ie, NGTL), providing LNG shippers with access to a liquid market hub to sell NGLs. Transportation By Others (or TBO), and interconnection with the broader WCSB gas pipeline network, is expected to be an important consideration in the approval process due to geographical limitations and the desire by government to not have any one pipeline block west coast access of another. Given the improved economics of producing liquids, we believe that any successful line will need some outlet for potential liquids volumes. We anticipate a toll in the range of $0.70–0.80 per mcf

Tolls estimated between $0.70–0.80/mcf. Based on TransCanada’s estimate of capital requirements for the pipeline, and using a 40% equity thickness and ROE of 9.7%, we anticipate a toll in the range of $0.70–0.80 per mcf. As expected for most pipeline projects, the contemplated fee structure will flow through all operating costs and prudently incurred capital costs to the shippers, meaning TransCanada will bear no operating cost or capital risk in developing or operating the pipeline.

Fig 19 Coastal GasLink Pipeline Project Pipeline owner

TransCanada Corp.

LNG project owner

LNG Canada - Shell (40%), PetroChina, Mitsubishi, Kogas (20% each)

Capacity

1.7bcf/d

Pipeline length

~700km

Receipt point

Near Dawson Creek, BC

Delivery point

LNG Canada facility near Kitimat, BC

Projected cost

$4 bn

Projected completion

2018 or later

Expected toll

$0.70 - $0.80 per mmcf/d

Fee structure

Cost-of-service, 40% equity thickness and 9.7% ROE

Approvals

No applications have yet been filed

First Nations consultations

Underway

Other notes

Interconnection to NGTL line potentially allows for "Transmission by others"

Source: Company reports, regulatory filings, Macquarie Research, September 2012

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Pacific Trail Pipeline The Pacific Trail Pipeline project would supply Kitimat LNG

Kitimat LNG’s pipeline plan. The Pacific Trail Pipeline project is nearly a mirror image of the Coastal GasLink project with the difference being that it is expected to service the partners of Kitimat LNG. While the Kitimat LNG facility has an export licence and the pipeline has all major environmental approvals, as previously mentioned, the LNG project is still seeking an offtake partner and we believe that there are significant risks that this project will face debilitating delays. Securing a long-term Purchase and Sales Agreement with an offtake partner that has oil-linked pricing is a precondition necessary to make a Final Investment Decision. Connecting to existing infrastructure expected to lead to lower tolls. Despite the risks related to the Kitimat LNG project, the PTP could result in lower tolls than Coastal GasLink as it leverages some existing infrastructure. The pipeline will connect to the existing Spectra Energy Transmission system at Summit Lake, BC meaning that the line is only 463km in length compared to 700km for the Coastal GasLink line. The line is expected to carry at least ~1.4bcf/d of gas.

We estimate tolls in the $0.50–0.55/mcf range

We estimate tolls in the $0.50–0.55/mcf range based on expected revenue disclosures. PNG, a subsidiary of AltaGas with existing transmission and distribution assets in the area, will operate the pipeline under a seven-year operating agreement with options to extend. We note that while the project is more advanced than the Coastal GasLink project, it has faced some First Nations opposition, although not nearly to the same extent as the Enbridge Northern Gateway oil pipeline.

Fig 20 Pacific Trails Pipeline Pipeline owner

PTP Limited Partners

LNG project owner

Kitimat LNG partners - Apache (40%), EOG (30%), Encana (30%)

Capacity

>1.4bcf/d

Pipeline length

463km

Receipt point

Spectra Energy's transmission system at Summit Lake, BC

Delivery point

Kitimat LNG plant near Kitimat, BC

Projected cost

$1.1bn

Projected completion

2015 or later

Expected toll

$0.50 - $0.55 per mmcf/d

Fee structure

Cost-of-service

Approvals

All major environmental permits received

First Nations consultations

49-year lease with Haisla First Nation; some opposition from others

Other notes

Pacific Northern Gas will be operator under a 7-year agreement w/ renewal options Kitimat LNG partners are still seeking an offtake agreement

Source: Company reports, regulatory filings, Macquarie Research, September 2012

What about Prince Rupert? PETRONAS will likely consider a separate pipeline

Looking at other options. It is likely that PETRONAS will consider a separate pipeline alternative to the Coastal GasLink and/or Pacific Trails Pipeline. The company stated that two major pipeline companies are conducting a separate Detailed Feasibility Study. The study is expected to be completed by early September, which will give us a better picture as to PETRONAS’s deliverability plans. Given the relative proximity of PETRONAS’s upstream assets a link with the Spectra transportation network would likely be the most logical. Is more than one line needed? The BC government is keen to see at least two pipelines constructed to the coast so that one company does not have a monopoly on deliverability. Although we appreciate this viewpoint, we could envision a scenario where only one major trunkline is constructed to Terrace BC (near the coast) and then a fork is built where the southern leg extends to Kitimat and a northern leg to Prince Rupert. Should more than two major projects proceed, a second line may be required. Any project connecting to NGL takeaway infrastructure would have an advantage over another competing line without this optionality.

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Risks – Environmental and inflationary pressures abound Pricing Securing long-term agreements. Kitimat LNG has already faced delays from its initial planned start-up due to difficulties in securing a long-term supply agreement. Suppliers are hoping to secure 20+ year contracts based on oil indexation, but as offtakers becoming increasingly put off by oil indexation we believe that suppliers will need to become more flexible. By 2025 an additional 650mtpa of new liquefaction capacity is planned, which exceeds our projected demand by nearly 30%. We expect slippage in the timing of projects both in Canada and abroad, but it serves to highlight that a lot of proposed supply is set to hit the market at the end of this decade and the early part of next. The anticipated onslaught of supply has led to a delay in offtake agreements being signed. Buyers are starting to push back on oil indexation for new contracts. Acknowledging this trend, there are reports that Qatar is dropping its historical insistence on an oil-linked slope of 16% (equivalent to a 1:6.25 oil:gas ratio) and instead are offering more attractively priced medium-term cargoes in order to secure longer-term buyers (see our report titled Global LNG outlook). We believe that oil indexation at historically high pricing is unlikely and instead suppliers are going to have to become more flexible on pricing. We expect to see a hybrid model of oil-linked pricing and spot cargoes for Canadian projects. Some level of indexation is likely required to obtain project financing. A move to greater spot cargoes also means that offtakers are going to have to grow accustomed to greater volatility in delivered gas volumes.

Construction Delays, cost overruns, and emerging markets are real threats

10 September 2012

The business of LNG development on BC’s coast is fraught with execution and financial risks. Delays, cost overruns, and emerging markets are real threats, and could undermine project economics. Cost overruns. Similar to Australia, Canada has a small and expensive labour force. It is likely that liquefaction construction will compete directly with oil sands construction. Currently, there is $205bn of unrisked oil sands projects planned between 2013 and 2020. We have risked these expenditures to $91bn, but these projects, combined with increased upstream drilling activity and potential construction of liquefaction capacity, will put enormous strain on the current labour pool and could have significant consequences for project costs.

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Canadian LNG: The race to the coast

Fig 21 Unrisked oil sands expenditures 45.0

Upstream Oil Sands Spending ($Bns)

40.0 35.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 2011

2012

2013

2014

2015

Unrisked Incremental Capacity Adds (Mining)

2016

2017

2018

2019

2020

Unrisked Incremental Capacity Adds (In Situ)

Source: Company reports, regulatory filings, Macquarie Research, September 2012

Cost inflation is not a uniquely Canadian problem. We looked at five LNG projects in Australia that have been built or announced since 2004; the average capital cost increase over initial estimates for those projects has been about 24%. Canada holds some advantages over its peers in the US as it is able to export to non-Free Trade Agreement nations whereas only one project in the US has approval to do so. The flexibility of Canadian exports, proximity to Asian markets and vast resource are all clear advantages for LNG in Canada, but companies cannot ignore (and are not ignoring) the labour situation in Canada as well as the remote location where both the resources and liquefaction facilities will be located. Emerging markets. One of the most significant threats to LNG development in Canada is the potential for significant natural gas domestic discoveries in Asia to push out LNG demand. Also, recent discoveries in East Africa are believed to have enough gas in place to support LNG facilities, which are expected to be constructed at lower costs than Canadian LNG.

Environmental Overview. Oil and gas development activity in Canada inevitably brings environmentalist opposition. Regarding development in BC, much of the opposition is focused on two main issues: 1) the sensitive terrain over which pipelines must travel from the east of the province to Kitimat/ Prince Rupert; and 2) the potential for shipping disasters in the Douglas Channel. The only pipeline that currently runs from eastern BC to the Kitimat region is the Pacific Northern Gas pipeline, which has a natural gas transmission capacity of 115mmcf/d. The pipeline takes the most direct route through the Coast Mountain range, which is the essentially the same path that the proposed pipelines to the coast would follow.

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Macquarie Research

There has been little opposition to date for the proposed natural gas pipelines

Canadian LNG: The race to the coast

Separating opposition of oil pipelines versus gas lines. Once Enbridge declared its intent to develop the Northern Gateway pipeline for transporting crude oil from Alberta to Kitimat, many stakeholders and activists began to take a very critical view of its risks. The path to Kitimat crosses substantial watershed regions and rugged foothills. It is argued that a spill there would cause irreparable damage to the pristine landscape and local fauna, and would have the potential to contaminate groundwater. The opposition to Northern Gateway has only grown over time, and has become something of a cause célèbre. A significant number of First Nations tribes have declared that they will never allow the pipeline to cross their lands, and even Hollywood has entered the fray. In comparison, there has been little opposition to date for the proposed natural gas pipelines. A large part of the reason for the difference in the level of opposition has to do with the differing degrees of risk. Compared with crude oil pipelines, a natural gas pipeline’s risks are seen as being fewer. A natural gas leak would release methane—a significant greenhouse gas—into the atmosphere. Explosions and fires are possible under certain circumstances but are relatively rare. Though these are certainly serious risks, they are not as serious as a large crude oil spill. Negotiating delays are a real possibility and could increase the cost of getting gas to BC’s coast.

The Douglas Channel would see significant tanker traffic

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Shipping risk. The second major environmental risk, the potential for shipping disasters in the Douglas Channel, rises with each additional project added in the Kitimat area. The Douglas Channel is an inlet about 140km long that narrows to just over 2km wide in certain places. If the LNG Canada, Kitimat LNG, BC LNG Co-op, and Northern Gateway projects were to all be approved, then the Douglas Channel would see significant tanker traffic. We note that the port at Kitimat also already has three deep-sea terminals that service ships from other industry products, including alumina, methanol, and condensate. Greater tanker traffic increases the risk of an unfortunate accident in the Douglas Channel, which has many environmentalists concerned. Fig 22 shows the planned terminal sites for each of the proposed projects near Kitimat. We believe that the heightened tanker traffic in the Douglas Channel is part of the reason for PETRONAS and BG to look at Prince Rupert as potential homes for their LNG facilities.

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Fig 22

Map of Kitimat Arm

Source: Douglas Channel Energy Partners

Political Canada’s federal government favours oil & gas development…

Political climate supportive. Canada’s political climate at the federal level is viewed as favouring oil and gas development. The Prime Minister’s office has been actively courting Asian countries for foreign investment since the Conservatives came to power in 2006, which has had a major impact on the western Canadian energy sector. Energy M&A activity has been growing steadily ever since, culminating in two large takeover bids announced in 2012: China-based CNOOC’s $15.1bn offer for Nexen, and Malaysia-based PETRONAS’s $5.8bn offer for Progress Energy Resources.

…but the Canadian public has proven to be wary

Risks remain. The Canadian public has proven to be wary of large foreign corporate takeovers, as evidenced by BHP Billiton’s failed takeover of Potash Corp. Additionally, there will be a federal again election in 2015, and the leftist New Democratic Party (NDP) has been polling in line with the Conservatives as of late. The NDP has a platform that is considerably less pro-business than the Conservatives’. At the provincial level, the BC government, which is run by the centre-left Liberal Party, has been very supportive of natural gas and LNG developments. There will be an election in BC in 2013, in which the NDP is currently polling in the lead; if they are elected then LNG development may face increased scrutiny. Ultimately, we see less local opposition for natural gas development and exports in BC, as the province will benefit from the economic activity along the entire value chain.

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Macquarie Research Important disclosures:

Canadian LNG: The race to the coast

Recommendation definitions

Volatility index definition*

Financial definitions

Macquarie - Australia/New Zealand Outperform – return >3% in excess of benchmark return Neutral – return within 3% of benchmark return Underperform – return >3% below benchmark return

This is calculated from the volatility of historical price movements.

All "Adjusted" data items have had the following adjustments made: Added back: goodwill amortisation, provision for catastrophe reserves, IFRS derivatives & hedging, IFRS impairments & IFRS interest expense Excluded: non recurring items, asset revals, property revals, appraisal value uplift, preference dividends & minority interests

Benchmark return is determined by long term nominal GDP growth plus 12 month forward market dividend yield

Very high–highest risk – Stock should be expected to move up or down 60–100% in a year – investors should be aware this stock is highly speculative. High – stock should be expected to move up or down at least 40–60% in a year – investors should be aware this stock could be speculative.

Macquarie – Asia/Europe Outperform – expected return >+10% Neutral – expected return from -10% to +10% Underperform – expected return +10% Neutral – expected return from -10% to +10% Underperform – expected return 5% in excess of benchmark return Neutral – return within 5% of benchmark return Underperform – return >5% below benchmark return

Low – stock should be expected to move up or down at least 15–25% in a year. * Applicable to Australian/NZ/Canada stocks only

Macquarie - USA Outperform (Buy) – return >5% in excess of Russell 3000 index return Neutral (Hold) – return within 5% of Russell 3000 index return Underperform (Sell)– return >5% below Russell 3000 index return

Recommendations – 12 months Note: Quant recommendations may differ from Fundamental Analyst recommendations

EPS = adjusted net profit / efpowa* ROA = adjusted ebit / average total assets ROA Banks/Insurance = adjusted net profit /average total assets ROE = adjusted net profit / average shareholders funds Gross cashflow = adjusted net profit + depreciation *equivalent fully paid ordinary weighted average number of shares All Reported numbers for Australian/NZ listed stocks are modelled under IFRS (International Financial Reporting Standards).

Recommendation proportions – For quarter ending 30 June 2012 Outperform Neutral Underperform

AU/NZ 55.67% 30.50% 13.83%

Asia 61.00% 22.11% 16.89%

RSA 53.43% 36.99% 9.59%

USA 42.58% 52.41% 5.01%

CA 69.23% 28.02% 2.75%

EUR 46.60% (for US coverage by MCUSA, 9.05% of stocks followed are investment banking clients) 33.69% (for US coverage by MCUSA, 8.14% of stocks followed are investment banking clients) 19.71% (for US coverage by MCUSA, 0.45% of stocks covered are investment banking clients)

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Canadian LNG: The race to the coast

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