Special Report: Encana doubles down on B.C., investing $600M in Montney
january / february 2015
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Pipeline News North analyzed the proposed LNG projects on the West Coast to bring you the latest on those that are on track and the ones that face delays. Currently 20 projects are vying to export Alberta and British Columbia’s natural gas to Asia.
A lot has happened since Pipeline News North’s LNG update last April. The number of projects grew by five, to 20, and there is a good chance we will see some Final Investment Decisions in 2015. This is our overview of the West Coast’s 20 LNG projects, and where they stand today. By David Dyck and Matt Lamers. R001697746
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PNN
NUMBERS
The following figures were taken from the stories in this issue of Pipeline News North.
US$600 to $700 million: What Encana plans to invest in B.C.’s Montney this year. Story on Page 6 $2.5 billion: The price tag for a plant in Chetwynd that would use natural gas, hydrogen and oxygen from water. It would be followed by a $1.8 billion methanol plant. Story on Page10
Pacific NorthWest LNG facility. It would be fed by TransCanada’s Prince Rupert Gas Transmission Project pipeline. Story on Page 13 $6.8 billion: The price tag for the proposed Jordan Cove LNG in Oregon. It would liquefy and export gas from Alberta and B.C. Story on Page 15
24 million: The number of tonnes LNG Canada has been permitted to export per year if it gives the project the go ahead. Story on Page 12
2015: The year Triton LNG hopes to make a Final Investment Decision for its proposed LNG project to meet the target in-service date of 2017. Story on Page 16
$11 billion: The price tag for the proposed
US$2.7 billion: The price Woodside
paid to acquire Apache’s assets in Northern B.C. and in Australia. Story on Page 19 2018: The year Steelhead LNG told PNN they plan to make a Final Investment Decision on their proposed LNG project. Story on Page 21 $8.77 billion: The price tag of the approved Site C dam, which is about 6 km southwest of Fort St. John. Story on Page 26 $25 billion: The amount of money it would take to bring WCC LNG online if Exxon gives the project the green light. Story on Page 27
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jonny wakefield photo
The Alberta-B.C. LNG 5 discount (chart)
U.S. gas price 5 (chart)
pnn 08
B.C. land auction 5 (chart)
19 Kitimat LNG (KM LNG): An overview
Alberta petroleum 5 land auction (chart)
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Encana investing 5 $600 million in Montney The West Coast’s 20 6 LNG projects Some fun stats 8 on pipelines
EAO issues procedural order 12 for Grassy Point
Aurora LNG enters 12 pre-application phase Pacific NorthWest LNG: 13 An overview
19 WCC LNG: An overview 21 Prince Rupert LNG: An overview 24 Oilsands competitive with other N.A. oil: Analyst 25 Koch Oil Sands $123m project
3.8B refinery in 10 works for Chetwynd EAO accepts LNG 12 Canada EA application
16 Jordan Cove Energy Project: An overview 16 Triton LNG: An overview
Japan gas 5 price (chart)
14 Woodfibre LNG Export: An overview
26 B.C. going ahead with $8.77 billion Site C dam
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27 WCC LNG outlines $25 billion spending plan 28 Midstream company Veresen enters Northeast B.C. 30 BC EAO accepts EA application from Woodfibre LNG fb.com/pipelinenewsnorth
Published monthly by Glacier Ventures International Corp. Pipeline News North is politically independent and a member of the B.C. Press Council. The Pipeline News North retains sole copyright of advertising, news stories and photography produced by staff. Reproduction is prohibited without written consent of the editor.
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the charts
#oilsands
alberta O&G land auction Alberta’s oil and gas land tender pulled in $12.93 million on Dec. 3 and $27 million on Dec. 17. The next land sales are Jan. 14 and Jan. 28. Source: Alberta Energy Regulator December 2013 to January 2015
alberta-b.c. lng discount The Alberta-B.C. Natural Gas Discount (ABCD) is the difference in price that a BTU of natural gas costs in Tokyo compared to Alberta. It sits at a four-year low of $9.45. December 2013 to December 2014
Alberta spot gas price The AECO “C” spot price, the Alberta gas trading price. Source: Natural Gas Exchange
December 2013 to January 2015
Encana investing $600M in Montney shale Jonny Wakefield Staff Writer
Encana Corporation is selling around 500 kilometers of pipeline and seven gas compression stations ahead of a major reinvestment in the Montney shale, the company announced in late-December. According to a release, the company has sold around $412 million in “natural gas gathering and compression assets” to Veresen Midstream. The pipeline and compression stations were part of Encana’s Cutbank Ridge partnership with Cutbank Dawson Gas Resources, a Mitsubishi subsidiary. Doug McIntyre, an Encana media relations officer, said the sale of the midstream assets would allow Encana to reinvest upstream in the Montney—in the actual extraction of gas from the ground. “It frees us up to redirect our capital into our core business, which is upstream production,” he said. “Otherwise, that capital would have been required to build that sort of infrastructure in the Montney over the next five years.” Encana plans to invest between US$600 and $700 million in the Montney in 2015. McIntyre said it was too early to say how many jobs that investment would create in the
South Peace. Encana employees will continue to operate the compression stations, which can handle around 675 million cubic feet per day. McIntye said the change in ownership would have “absolutely no staff impacts” on Encana employees. Veresen plans to invest around $5 billion in midstream facilities “to support development within the Montney,” according to the release. It will operate as a partnership with KKR, a private equity firm. McIntyre said that despite tumbling oil prices, Encana planned to invest more in South Peace gas plays in the coming year. The Montney is one of Encana’s four major resource plays, in addition to the Duvernay in Alberta and the Eagle Ford and Permian in Texas. Encana diversified its fossil fuel holdings in the past year, meaning Dawson Creek has been largely insulated from the impact falling oil prices have had on the company. “We’ve really reshaped our portfolio — we’ve got oil, we’ve got natural gas and we’ve got natural gas liquids,” he said. “So having that range of options sort of makes us much more resilient in the face of lower commodity prices.” The companies plan to close the deal in early 2015, pending regulatory approval. reporter@dcdn.ca
b.c. o&g land auction
japan lng import price The Japan LNG Import Price fell to lows unseen since 2011 in December falling oil prices. Source: World Bank December 2013 to December 2014
December 2013 to December 2014
The BC Oil and Gas Commission’s monthly land tender pulled in a record $209 million in October and a respectable $38 million in December. The next sales are Jan. 21 and Feb. 25.
Oil price brent crude price
u.s. spot gas price
The price of Brent crude has fallen dramatically in the past six months, losing more than half its value. Source: U.S. Energy Information Agency
Left, the Henry Hub Natural Gas Spot Price (dollars per Million Btu). Source: U.S. Energy Information Agency 49 December 2013 to January 2015
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May 2010-January 2015
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The West Coast’s 20 L and where they stand jonny wakefield photo
William Julian Regional Manager 250-785-5631 wjulian at pipelinenewsnorth.ca
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Pipeline News North analyzed the proposed LNG projects on the West Coast ones that face delays. Currently 20 projects are in the mix to export Alberta an
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LNG projects, d today david dyck photo
courtesy photo
A lot has happened since
Pipeline News North’s last
LNG update. Pacific NorthWest LNG delayed its decision in December, but this could be the
year the West Coast unlocks
its natural gas potential. Story
by David Dyck and Matt Lamers.
to bring you the latest on those that are on track and the nd British Columbia’s natural gas to Asia. Turn to Page 13
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f u n s t at s o n p i p e l i n e s The speed natural gas moves through a pipeline.
40 kph Design
20 500 BC The first recorded use of pipelines to transport natural gas — the pipelines were constructed of bamboo.
and ph
otos b
y by M
att Lamers
The number of LNG projects on the West Coast that propose liquefying and shipping natural gas produced in Alberta and British Columbia.
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$3.8B refinery in works for chetwynd Business in Vancouver
Two “green” oil refineries proposed for the B.C. northwest coast may have some serious competition in Chetwynd: a refinery that would make gasoline from natural gas and hydrogen, not oil. Juergen Puetter, president of Aeolis Wind Power Corp. and CEO of Blue Fuel Energy Corp., has been quietly assembling a multibillion-dollar, two-phase plan to build a gasoline refinery in Chetwynd, followed by a methanol plant a couple of years later. “We have the land, we have the First Nations on board, we are in the middle of permit-
ting,” Puetter said. The company also has two former senior Methanex Corp. (TSX:MX) executives on board: Michael Macdonald, Methanex’s former senior vicepresident of global operations, and Ron Britton, former senior vice-president, who is Blue Fuel’s new chief technology officer. The first phase of the project would be a refinery at a cost of $2 billion to $2.5 billion that would use natural gas – readily available in Northeast BC – and hydrogen and oxygen from water. It would be followed by a $1.8 billion methanol plant. Using technology licensed from ExxonMobil, the plant would make methanol from natural gas, which would then
be made into a low-carbon gasoline, using the hydrogen and oxygen parsed from water. The energy inputs to separate the hydrogen and oxygen atoms in a water molecule are high. Puetter said the Sundance Fuels project will require 150 megawatts of power (about one-seventh the capacity of the Site C dam), which it would get from the grid. Aeolis, which developed the Bear Mountain wind farm, also has several other large wind farm prospects, and Puetter hopes that some of the power needed could eventually come from wind. He said all of the chemical processes that would be used are tried and true, they just haven’t been put together before on any large scale to pro-
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duce gasoline from natural gas. “There are some major technological steps forward and putting it together is not easy,” he said. “We’ve been at this for five years. Nobody’s done this on this scale before.” Such a plant would not be feasible in many other jurisdictions. But Puetter said B.C. has the right combination of resources and policies that make it viable. In North America, natural gas is abundant and cheap. B.C. also has relatively lowcost electricity and a low carbon fuel standard. Low carbon fuel standards are designed to address the life cycle of carbon dioxide produced in the process of extracting oil, refining it into
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reporter@pipelinenewsnorth.ca
matt lamers file Photo
Oil refinery proposals face gas refinery competition: Local companies planning multibilliondollar gas and methanol facilities in Chetwynd gasoline and then burning it. One of the reasons Alberta oilsands bitumen has such a negative reputation is that its life cycle is more carbon-intensive than gasoline made from conventional oil, according to the Natural Resources Defense Council. Using “renewable” hydrogen from water would help lower the carbon intensity of the gasoline the Sundance Fuels plant would produce to meet low carbon fuel standards. “In Alberta this wouldn’t work, because if you did the same thing in Alberta, and used Alberta grid power – it’s all made from coal – the carbon intensity would go up,”
Puetter said. The site in Chetwynd is also advantageous. The company has acquired 1,065 acres of private land just outside of the town that has rail access. The fuel and methanol it produced could therefore be shipped by rail. “We don’t require a pipeline, so we think we’re going to be ahead of any LNG project,” Puetter said. Chetwynd Mayor Merlin Nichols said the project would be a welcome economic development. “We’re supportive,” he said. “The nature of the plant, the nature of the product and the nature of the jobs created – long-term, high-quality,
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high-paying jobs – it would be good for the town.” Local First Nations are also on board, Puetter said. Under an agreement with First Nations, Sundance Fuels would provide waste heat, which First Nations could use in greenhouses. “You wouldn’t normally think of building greenhouses in the Peace region, because it’s so cold,” Puetter said. “But if the energy is free, it becomes a totally different ball game because land is very cheap there and making it a fully First Nation-owned business turns out to be extraordinarily attractive.”
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EAO accepts LNG Canada EA application David Dyck
JANUARY 16, 2015
EAO issues procedural order for Grassy Point
Aurora LNG enters pre-application phase
David Dyck
Staff Writer
David Dyck
Staff Writer
On Nov. 7, 2014, the B.C. EAO accepted LNG Canada’s application for an environmental assessment of their proposed export facility in Kitimat, B.C. The project would initially start with two units, each with a capacity to produce 6.5 million tonnes of LNG per year. There were several open houses in Kitimat, on Nov. 25 and 26 as part of the public comment period. As of Dec. 23, the public comment portion of the assessment has closed. All of the comments, along with the proponent’s responses, can be viewed on the EAO website. The project has been approved by the NEB to export a maximum of 24 million tonnes of LNG per year. The environmental application is still under review by the EAO.
Staff Writer
On Nov. 28, the EAO issued the Grassy Point LNG a procedural order that establishes the scope, procedures and methods concerning the environmental assessment. The project is in the pre-application stage of the environmental assessment process. On the same day, the federal Minister of Environment announced that the B.C. EAO’s assessment would be sufficient oversight of the process, rather than both the provincial and federal offices assessing the project, provided certain conditions were met. Woodside, Australia’s largest independent oil and gas company, is currently exploring this site as a possible location for either landbased or floating LNG export facility. In August 2014, the proponents filed for an environmental assessment certificate with the BC EAO.
On Dec. 16, the EAO issued a procedural order for the environmental assessment process, putting the project in the pre-application phase. Aurora LNG announced in Nov. 2014 that it will study the viability of building an export facility on Digby Island, which the company said is more suitable than the northern Grassy Point location. On Jan. 9 2015 the project pulled its environmental application for the Grassy Point facility. The NEB approved the project to export 24 million tonnes of LNG per year. GC Corp., control the rest. Having a major international investor like CNOOC is seen as a major advantage for Aurora LNG. CNOOC controls most of China’s LNG imports - 70 percent in 2012.
Progress withdraws Farrel Creek gas project as a matter of procedure Mike Carter Staff Writer
Progress Energy has withdrawn a proposed gas plant 25 km north of Hudson’s Hope from the provincial environmental assessment process. The plant was originally proposed by Talisman Energy and submitted for environmental review in 2012. The application was transferred to Progress Energy Canada Ltd. , when the Talisman assets were purchased in March, 2014.
According to Progress Energy spokeswoman Stacie Delay, the company has withdrawn the environmental assessment application so that it can carry out it’s own studies and evaluate its needs. “Progress is currently in the appraisal phase in the development of that area,” delay said. “We are appraising the lands that we had acquired from Talisman last year, which would feed into a potential new gas plant in that area.” It’s a matter of procedure. Delay said the company simply wants to withdrawal the application submitted by Talisman so
that it can come up with its own assessment of need for the area. This does not mean the project is scraped. “Later based on the appraisal, we will determine the scope and timeline for an additional gas processing plant,” delay added. “Once [that] is complete, we will resubmit an application based on our needs at that time.” Progress expects the appraisal phase to last about one to two years. peacereporter@dcdn.ca
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cover story Pacific NorthWest LNG Final investment decision: Q1 of 2015 Partners: Petronas, Sinopec, Japex, Petroleum Brunei, Indian Oil Corp Price tag: $11.4 billion Location: Land-based facility, Lelu Island, Prince Rupert Capacity: 19.68 million tonnes per year of LNG EA: Application approved by BC EAO, still being assessed by the CEAA In-service date: Q1 2019 Export license: Approved by NEB Pipeline: TransCanada’s Prince Rupert Gas Transmission Project Pipeline details and status: 48” diameter, 900 km, near Hudson’s Hope to Lelu Island. EA application approved by BC EAO. Source of natural gas: Progress’ holdings in North Montney
The proposed Pacific NorthWest LNG project would liquefy and export natural gas produced by Progress Energy Canada Ltd. in Northeast B.C. The $11 billion facility would be fed by TransCanada’s Prince Rupert Gas Transmission Project pipeline. PacificNorthWest LNG has already arranged off-take agreements, putting the project in the best position to move forward. On Feb. 28, 2014, Pacific NorthWest LNG filed its environmental impact statement with the Canadian Environmental Assessment Agency and B.C. Assessment Office. In March 2014, India’s state-run Indian Oil Corp. agreed to buy 1.2 million tonnes a year of LNG for at least 20 years, equal to a 10 per cent stake in the project. Sinopec, China’s state-owned energy company, joined as the project’s fourth partner in April 2014, with a 15 per cent stake. The project still needs a green light from the federal government’s environmental assessment office. Latest Although the provincial EAO issued a certificate with accompanying stipulations, the federal environmental assessment is still pending. This past May, the year-long review was confronted with a seven-month delay, pending more information from Pacific NorthWest LNG. The assessment began again in December 2014, at Day 172. Final Investment Decision A final investment decision was expected in 2014, but was delayed indefinitely by Petronas in December. Most analysts expect a decision on the first half of 2015. Although their decision on whether to invest in the estimated $31 billion project was expected to come down before the New Year, North Peace MLA Pat Pimm and other officials caution skeptics not to bet against B.C.’s nascent LNG industry. “At this point I’m not disappointed,” Pimm said. “As far as I’m concerned, we’re right on track. They’ve made it clear that they have to dot a couple more ‘i’s and cross a couple more ‘t’s and that’s just good business sense.” Oil is often used as a benchmark to determine LNG import prices. Lower oil prices means lower LNG prices, which makes the economics of exporting natural gas more challenging for proponents in places in British Columbia, the United States, Australia and others. But Bill Gwozd, Senior Vice President of Ziff Energy, said the short-term price of oil would not have affected Petronas’ decision to delay. Analysts say it’s the long-term price of oil that’s important, not a temporary drop. “When I hear financial analysts and some, what I would call ‘reasonably astute’ consultants yapping and chatting that the oil price is not right for LNG exports, well maybe that’s for a current project that’s operating in Yemen or North Africa or Australia, but has nothing to do with the Canadian projects on the West Coast,” he said. See LNG PROJECTS on PAGE 14
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LNG PROJECTS from PAGE 13
Woodfibre LNG Export Pte. Ltd. Final investment decision: Autumn 2015 Partners: Pacific Oil & Gas Price tag: $1.7 billion Location: Squamish, B.C. Capacity: Export 2.1 million tonnes of LNG per year EA: Application accepted by EAO subject to conditions, CEAA assessment in progress In-service date: 2017 Export license: Approved for 2.1 million tonnes of LNG per year for 25 years Pipeline: Existing FortisBC gas pipeline will be expanded; BCEAO initiated 180-day Application review process pipeline.
The Woodfibre LNG Project is a proposed small-scale LNG processing and export facility located near Squamish, B.C. The facility would be built at an existing industrial site, the former Woodfibre pulp mill, which the proponent says is suited for conversion into an LNG facility. The site has access to power and an existing natural gas pipeline. Woodfibre LNG is the Canadian subsidiary of Pacific Oil & Gas, an 11-year-old energy company based in Singapore and Jakarta that has the backing of Indonesian billionaire Sukanto Tanoto. Currently Woodfibre LNG is acquiring a site from Western Forest Products that is subject to the completion of remediation of the site (e.g. dredging, removal of asbestos) and the issuance of a Certificate of Compliance from the Ministry of Environment. In November 2013, Woodfibre LNG filed a Project Description with the Canadian Environmental Assessment Agency and the B.C. Environmental Assessment Office to initiate the environmental assessment process. On Feb. 19, the BCEAO request for substitution of the environmental assessment process was accepted by the minister of the environment. In September 2014, Woodfibre LNG awarded a contract for engineering and procurement. On Nov. 25, the EAO approved the Application Information Requirements for the proposed project. The AIR details the information needed for a proponent’s application for an environmental assessment certificate. Latest The proponent applied for the environmental assessment certificate at the end of December. The Financial Post reported in Oct. that Woodfibre and Guangzhou Gas Group Co. Ltd. had signed a memorandum of understanding that the Chinese company would purchase 1 million tonnes of LNG per year for 25 years. The Environmental Assessment Office initiated the 180-day Application review process for the proposed Woodfibre LNG Project on Jan. 13, 2015. Final Investment Decision Visiting Squamish for an LNG education seminar in Dec. 2014, Minister of Natural Gas Development Rich Coleman said that he expects Woodfibre to announce a final investment decision in 2015.
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cover story Jordan Cove Energy Project Final investment decision: Q1 2015 Partners: Jordan Cove Energy Project L.P., Veresen Inc. Price tag: $6.8 billion Location: Coose Bay, Oregon Capacity: Liquefaction capacity of 6.6 million metric tons per year EA: Expected in early 2015 Export license: Has permits from Canada’s NEB, DOE in U.S. Pipeline: Alberta Ethane Gathering System, Alliance Pipeline, Pacific Connector Gas Pipeline (450 km, proposed) Source of natural gas: Aux Sable Canada (owned by Enbridge and Veresen), via Encana and Phoenix Duvernay Gas (JV participant of Encana)
Located in Coos Bay, Oregon, the facility will produce up to six million tons of LNG per year for export. The facility is owned and will be operated by Veresen Inc. Jordan Cove has proposed building a 400 km Pacific Connector pipeline through southern Oregon. On Feb. 20, 2014 Jordan Cove LNG L.P. was granted approval by the NEB to export 9 million tonnes oLocated in Coos Bay, Oregon, the facility will produce up to six million tons of LNG per year for export. The facility is owned and will be operated by Veresen Inc. Jordan Cove has proposed building a 400 km Pacific Connector pipeline through southern Oregon. On Feb. 20, 2014 Jordan Cove LNG L.P. was granted approval by the NEB to export 9 million tonnes of gas per year from Western Canada to the United States for a term of 25 years. In August 2013, Black & Veatch and Kiewit completed the front-end engineering and design (FEED) work and pre-construction planning activities for the Jordan Cove Liquefaction Project. The U.S. Department of Energy gave export approval in March 2014. In June 2013, the Oregon International Port of Coose Bay and Jordan Cove Energy Project L.P. (JCEP) submitted applications for permits required to construct the marine facilities and LNG liquefaction facilities. The Federal Energy Regulatory Commission (FERC) application was submitted by JCEP earlier. FERC permit approval is expected in the 3rd quarter of 2014. The Financial Post reported it has secured heads of agreements with three unnamed Asian buyers. Latest The FERC issued a draft permit on Nov. 7, 2014, currently in the public comment period preceding the issuance of a final permit expected in early 2015. Final Investment Decision Veresen is expected to make a Final Investment Decision by the first quarter of 2015, a vice president told PNN in 2014, but it could come later in the year. LNG PROJECTS from PAGE 16
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LNG PROJECTS from PAGE 15
Triton LNG Final investment decision: 2015 Partners: AltaGas Ltd, Idemitsu Kosan Location: Floating facility, Kitimat or Prince Rupert Capacity: 2.3 million tonnes of LNG per year In-service date: 2017 Export license: Approved in April 2014 for 2.3 million tons of LNG per year Pipeline: PNG’s Looping Project Pipeline details and status: 24” diameter, 525 km, Summit Lake to Kitimat. Pre-application under BC EA.
AltaGas Ltd. and Idemitsu Kosan are doing preliminary work for the design and construction of a floatiAltaGas Ltd. and Idemitsu Kosan are doing preliminary work for the design and construction of a floating LNG facility that would either be placed in the vicinity of Kitimat or Prince Rupert. “The LNG production will be offloaded from the FLSO vessel through a loading arm to LNG carriers for transport to export markets,” according to the application to the NEB. On April 17, 2014 Triton LNG Limited Partnership (Triton LNG), a subsidiary of AIJVLP, received permission from the National Energy Board to export up to 2.3 million tonnes of LNG per year. Triton LNG has also said that it is preparing preliminary engineering designs for the construction of the liquefaction facilities and is considering potential locations. Latest AltaGas Ltd. executives said that they were happy with the announcement of the LNG tax in October, and said at that time they were optimistic of their chances of getting a facility built. This is one of three liquefaction facilities AltaGas is proposing. Douglas Channel LNG is for export while AltaGas has also proposed British Columbia’s first natural gas liquefaction facility for Dawson Creek, which will be for local consumption. Final Investment Decision To meet the target in-service date of 2017, a final investment decision would have to be made sometime in 2015.
Kitsault Energy Final investment decision: Proponent claims to have made decision in 2014 Partners: N/A Location: Floating and possibly land-based facilities, Kitsault EA: N/A In-service date: 2018 Export license: Applied December 2013 for 20 MTA Pipeline: N/A
The Kitsault Energy project is unique in that it proposes turning an abandoned village near British Columbia’s border with Alaska into a massive LNG export hub. The company says an export terminal at Kitsault will require the shortest natural gas pipeline for the projects currently proposed in the region, saving 100 to 300 kilometers for a cost savings of up to $3 billion. Kitsault also has infrastructure ready: About 90 empty houses, 150 condos for some 1,000 residents, along with a recreation center, medical clinic, shopping center, post office, bank, restaurants and a supermarket. On Dec. 18, 2013 Kitsault Energy Ltd. applied for a permit to export up to 20 million tons of liquefied natural gas per year for a term of 25 years. That application is still under review. Latest President Krishnan Suthanthiran was in Asia at the beginning of 2015 to line up partners for this project. He said that he expects partnerships to be announced by June of 2015. Final Investment Decision Sales contracts and regulatory work has to be completed, and no environmental assessments have been conducted, although the site was once home to a major mining operation, meaning an EA process might not take as long. Suthanthiran told PNN that he is moving forward with the project, so “in essence the FID has been made more than a year ago.”
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cover story LNG Canada Gas Final investment decision: 2016 Partners: Joint venture partnership between Shell Canada Ltd., PetroChina Company Limited, Korea Gas Corporation (KOGAS) and Mitsubishi Corporation Price tag: $40 billion Location: Land-based facility, Kitimat EA: Application under review by EAO In-service date: Construction will take 4-5 years after a final investment decision is made, with shipments beginning soon after. Export license: Approved by NEB for 24 million tonnes of LNG per year Pipeline: TransCanada’s Coastal GasLink Pipeline Ltd. Pipeline details and status: 48” diameter, 650 km, near Dawson Creek to Kitimat. B.C. EA certificate issued October 2014.
Announced in 2012, LNG Canada proposes building an LNG export terminal, including marine facilities, facilities for storage and a gas liquefaction plant. This project is has the support of backers with deep pockets. On Feb. 24, 2014, the British Columbia Environmental Assessment Office approved LNG Canada’s Application Information Requirements. The document identifies the information required in its application for an Environmental Assessment Certificate under the BC Environmental Assessment Act. Latest On Nov. 7, LNG Canada’s environmental assessment was submitted to the BC EAO, entering the 180-day application review phase. Final Investment Decision Royal Dutch Shell announced on Nov. 7 that it expects to make a final investment decision by 2016. [Shell is the 50 per cent owner of the consortium; PetroChina Co Ltd. (20 per cent), Mitsubishi Corp. (15 per cent), Korea Gas Corp Ltd. (15 per cent).
Oregon LNG Final investment decision: 2016 Price tag: $6 billion Partners: Backed 80% by Leucadia National Corp. Location: Warrenton, Oregon Capacity: Up to 9 million metric tons of LNG per year EA: Draft Environmental Impact Statement expected Q1 of 2015 In-service date: Draft Environmental Impact Statement expected Q1 of 2015 Export license: NEB and USDOE (FTA and non-FTA) have been received Pipeline: Spectra/BG Group’s Westcoast Connector Gas Transmission Project
This project began in 2004 as an LNG import facility. Changing economics has allowed it to change gears to become an export and liquefaction facility. Most of the gas would be produced in Canada. In May 2014, Oregon LNG Marketing Company received a 25-year license to export 473 Bcf of natural gas to the U.S. per year, where it will be liquefied and shipped to Asia. Oregon LNG is on schedule to export Canadian supplies through its terminal by 2020, the company said. Latest In June 2014 Oregon LNG filed their LNG export application with the Federal Energy Regulatory Commission (FERC), and expects that it will be approved in 2016. In May 2014, the NEB approved an export license for 11.1 Mt per year for 25 years. Final Investment Decision Officials said a FID, previously expected in 2015, has now been delayed to 2016.
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WesPac Tilbury Marine Jetty Project Final investment decision: 2016 Price tag: $140 million Partners: WesPac Midstream — Vancouver LLC Location: Expansion of existing FortisBC facility, Delta Capacity: 3 million tonnes of LNG per year EA: N/A In service date: 2017-2018 Export license: Under review by the NEB Pipeline: The Spectra system from northern British Columbia
This project takes advantage of existing LNG infrastructure, as a potential expansion of the Fortis BC Tilbury LNG Plant on Tilbury Island on the Lower Mainland. Fortis Inc. reportedly currently has capacity to liquefy up to 4.24 mmcf/day. FortisBC is said to be planning a $400-million upgrade to increase LNG storage and output at the plant. The Globe and Mail reported that the upgrade was scheduled for facility even before the WesPac application was filed. WestPac is majority owned by Highstar Capital LP. FortisBC is a subsidiary of Fortis Inc. Latest The project is currently conducting studies that it will use for permit applications and consultation with First Nations and the public. Its application to export LNG is under review by the NEB. Final Investment Decision With construction set to begin by the first half of 2016, the FID will be made in early 2016, officials told PNN.
Aurora LNG Final investment decision: 2017 Partners: Nexen (CNOOC), INPEX, JGC Corporation Location: Grassy Point or Digby Island, near Kitimat Capacity & license: Export license approved by NEB in May 2014 for 25 MTA per year. EA: Responded to Request for Expression of Interest from province in 2013 In-service date: 2021, according to Chinese newspaper Caixin Pipeline: N/A Source of natural gas: Nexen assets in Horn River and Cordova basins
Nexen (CNOOC) controls 60 percent of the venture, while its Japanese partners, Inpex Corp and JGC Corp., control the rest. Having a major international investor like CNOOC is seen as a major advantage for Aurora LNG. CNOOC controls most of China’s LNG imports - 70 percent in 2012. Nexen says that third-party evaluators estimated its joint venture lands in Horn River and Cordova basins near Fort Nelson hold between four trillion and 15 trillion cubic feet of recoverable contingent resources, and that the Liard joint venture lands contain an estimated five to 23 trillion cubic feet of prospective resources. CNOOC has set a production goal of 40 million tonnes annually by 2020. It remains to be seen whether Nexen’s resources in Northeast B.C. could play a key role in meeting that target. So far nine coastal LNG receiving stations have been built in China and another 11, including six controlled by CNOOC, are either planned or are under construction. CNOOC bought Nexen in 2013 for $15.1 billion. In November 2013, Aurora LNG agreed to pay $12 million to the province and another $12 million one year later for the exclusive right to develop 614.9 hectares of land on the northern part of Grassy Point, near Kitimat. On Nov. 29, 2013 Aurora Liquefied Natural Gas Ltd. applied to the National Energy Board to ship 24 million tonnes of LNG per year from the coast of British Columbia for a term of 25 years. In May 2014 that application was approved. Nexen says it expects to engage in “comprehensive consultation” with First Nations and stakeholders over the next few years. Latest On Aug. 21 2014 the CEAA announced that it would begin an environmental assessment of the project. Aurora LNG announced in Nov. 2014 that it will study the viability of building an export facility on Digby Island, which the company said is more suitable than the northern Grassy Point location. So far the company has paid the province $18 million in sole proponent agreements. Final Investment Decision A Final Investment Decision can’t be made until the proponent secures more off-take agreements and acquires the requisite environmental permits. 2016 at the earliest.
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cover story Kitimat LNG (KM LNG) Final investment decision: H2 2016 Partners: Chevron/Woodside Petroleum 50/50 equity Location: Land-based facility, Bish Cove, Kitimat EA: Complete under BC EA (2008) Export license: Approved by NEB for 10 MTA Pipeline: Pacific Trails Pipeline Pipeline details and status: 42” diameter, 462 km, Summit Lake to Kitimat. BC EA Certificate issued June 2008. Must begin construction by June 2018. Source of natural gas: Chevron/Woodside’s holdings in Horn River, Liard gas basins
Kitimat LNG is currently in the Front End Engineering and Design (FEED) phase. In January 2014, JGC/ Fluor was awarded the engineering, procurement and construction contract. The project has all major provincial and federal environmental approvals in place. Fifteen First Nations had signed on to the project as of April 2014. The proposed facility would be built on land leased from the Haisla Nation. The facility will include two liquefaction trains to cool gas to a liquid state. Latest Apache sold its 50 per cent stake in the project to Woodside Petroleum Ltd., an Australian company, in December 2014. Activist investors forced Apache’a hand in the sale of its stake because they did not approve of the $1 billion related to the front-end engineering and design of the export terminal. That deal will close in the first half of 2015. Woodside paid $2.7 billion USD for the Kitimat project and Apache’s interest in the Australian Wheatstone LNG terminal, as well as upstream oil and gas reserves. Apache will get $1 billion over and above that to compensate for expenditures in the Wheatstone and Kitimat projects between June 30, 2014 and the close of the deal in Q1 2015. Final Investment Decision The companies say an FID will require firm LNG sales contracts and more agreements with First Nations. No off-take agreements have been announced, which currently is this project’s biggest hurdle (now that Apache’s sale is resolved). Because the BC EA Certificate was issued June 2006 and is only good for 10 years, construction on the facility must begin by June 2016. Presumably an FID would be in the works for 2016.
WCC LNG Final investment decision: 2017 Partners: Imperial Oil/Exxon Mobil Price tag: $25 billion in first phase Location: Floating or on shore facilities, Tuck Inlet, Prince Rupert EA: In pre-application stage of BC EAO; hopes to secure provincial EA certificate by the end of 2016. Export license: Approved by NEB for 30 MTA Pipeline: N/A
Exxon, the world’s largest energy company, and its Canadian subsidiary, Imperial Oil, have proposed to develop an LNG project under a venture known as WCC LNG Ltd. Judging by the export permit and regulatory filings, this is a massive project. Much about the project came to light in a report filed by Exxon in January 2015 with the B.C. Environmental Assessment Office that shed light on the first phase of the project. On Dec. 16, 2013, WCC LNG was granted a license to export 30 million tonnes of LNG per year for a term of 25 years. Latest In July 2014 WCC LNG hosted an open house for North Coast residents, in which they provided a brief outline of their project, and disclosed the location for the facility, just north of Prince Rupert. At the beginning of December 2014 the City of Prince Rupert rezoned District Lot 444 for the LNG facility, and incorporated it into the Official Community Plan. On Jan. 7, BC EAO announced that WCC LNG had entered the pre-application phase of their assessment. Three days later, Exxon’s report filed with the B.C. Environmental Assessment Office shed light on the first phase of the project, particularly on the number of jobs, capital cost estimates and First Nations consultations. EAO has submitted a request to conduct a substituted environmental assessment on behalf of the federal government for the proposed WCC LNG Project, on Jan. 13, 2015. Final Investment Decision For the first time, in January 2015 Exxon came out with a rough estimate for a final investment decision: 2017. See LNG PROJECTS on PAGE 20
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PUMPING SOLUTIONS
LNG PROJECTS from PAGE 19
Cedar LNG Final investment decision: 2017 at earliest Partners: Haisla First Nation Location: Kitimat or Prince Rupert Capacity: 14.5 million tonnes of LNG per year EA: N/A In service date: 2020 Export license: Applied for three separate licenses Pipeline: PNG’s Looping project
Latest Run by the Haisla First Nation near Kitimat, Cedar LNG is actually three separate companies, with separate project applications made to the National Energy Board. The first, Cedar 1 LNG Export, would export a maximum 2.9 million tonnes per annum, while 2 and 3 would export 5.8 million each, totaling 14.5 million tonnes of LNG. Each project would have its own gas producers, purchasers, investors, pipeline companies, and shippers, aimed at Asian markets. Cedar LNG said in their NEB application that they are in talks with Golar LNG to commission the construction of the flotillas at the Keppel Shipyard in Singapore. There would be six jetties in total on the Douglas Channel. One where the presently troubled Douglas Channel LNG project lies, a second near where the Triton LNG project is planned, and the other four around where the Kitimat LNG project is, and in the mountains around Bish Cove. The Haisla First Nation are also partners in the stalled Douglas Channel LNG. Final Investment Decision With a projected in-service date of 2020, the FID would need to come down around 2017 or 2018.
E H T T E E M S O R P
Orca LNG Final investment decision: 2017 Location: Floating facility, near Prince Rupert In service date: 2019 Capacity & license: y24 million tonnes of LNG per year Partners: N/A EA: N/A In-service date: N/A Pipeline: N/A
A relative newcomer to the BC LNG game, Orca is nevertheless one of the larger proponents. Orca LNG is the Canadian subsidiary of a company that is based out of Cypress, Texas. According to the company, the facility would be made up of six floating liquefaction storage and offloading vessels.
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cover story Prince Rupert LNG Final investment decision: 2017 at earliest Price tag: $16 billion Partners: BG Group Location: Land-based facility, Ridley Island, Prince Rupert Capacity: 21.6 million tones per year of LNG EA: Currently being assessed by both the CEAA and the BC EAO In-service date: Pushed back to about 2022 Export license: Approved by NEB for 21.6 MTA Pipeline: Spectra/BG Group’s Westcoast Connector Gas Transmission Project Pipeline details and status: 36”- 48” diameter, 870 km, up to 2 pipelines. Cypress to Ridley Island. Environmental Assessment Certificate granted November 2014.
BG Group’s LNG facility on Ridley Island will be one of the biggest on the West Coast if it is built. The plan so far is to construct the facility overseas in modules and ship it to Prince Rupert for assembly. The facility will be supplied by gas produced in Northeast B.C., and piped to the facility via Spectra’s Westcoast Connector Gas Transmission Project. Latest In August 2014, Prince Rupert LNG submitted their project description to the CEAA and the BC EAO. In November 2014 it was widely reported that BG had delayed the FID from 2016 to 2017, however that had been known for most of 2015. The real story was that activity would be decelerated. Executives said in October 2014 that they were going to slow this particular project in light of shifting global market conditions. Interim executive chairman Andrew Gould said that they would continue working on the project in 2015, but not at the same pace as they did in 2014. He said that generally weak gas prices and a higher estimated rate of LNG production from the United States might result in a more saturated market by 2020. In November of 2014 the 850-km long Prince Rupert Gas Transmission Pipeline was granted environmental assessment approval by the BC EAO. Final investment decision Although the British company does not speculate on when a final investment decision will be made, 2017 would be the earliest possible at this point. That is consistent with comments made by Roger Ayton, director of investment appraisals at BG’s North American unit, to the Financial Post. “Realistically we’re looking at about 2017,” he said in February 2014.
Steelhead LNG Final investment decision: 2018 Partners: Steelhead LNG and Huu-ay-aht First Nations Price tag: $30 billion Location: Land-based facility, Sarita Bay, Vancouver Island Capacity: 24 million tonnes per year EA: N/A In-service date: 2022 Export license: Under review by the NEB Pipeline: N/A
This Vancouver-headquartered LNG project was announced in March 2014, and has made aggressive progress in selecting a site and moving forward in tandem with the Huu-ay-aht First Nations, near Bamfield on Vancouver Island, where the facility would be located. It is one of the largest projects to be proposed. Latest On March 18, Steelhead LNG appointed former B.C. Attorney General Geoff Plant as a member of its board of directors. On October 2, 2014, the former managing director of LNG Canada, Victor Ojeda, joined Steelhead LNG as their new president. November 29 saw Huu-ay-aht citizens vote in favour of continuing to explore the project. The vote approved the lease on Huu-ay-aht land where the facility would be built and the execution of environmental, traditional-use and technical studies. Steelhead LNG said they are currently working with pipeline companies on how to get the gas to the facility, and entertaining the possibility of another 6 million tonne per year export facility along the route. Final Investment Decision Steelhead LNG told PNN that they anticipate making an FID in 2018.
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Douglas Channel LNG Final investment decision: Was expected in 2014. Delayed. Partners: BC LNG Export Cooperative, Haisla Nation, LNG Partners Price tag: $500 million Location: Floating facility, Kitimat EA: Not required In-service date: Was expected in 2015. Delayed. Export license: approved by NEB for 1.8 MTA Pipeline: PNG’s existing pipeline and proposed PNG Looping Project Pipeline details: 10” diameter, Summit Lake to Kitimat. PNG Looping Project in pre-application under BC EAO.
This small-scale, $500 million project was once thought to be the front-runner to make a Final Investment Decision and begin exporting LNG. However, insolvency filings in British Columbia by LNG Partners LLC in October 2013 put the project in limbo. Original plans had construction beginning in 2015. In March 2014, the Financial Post reported that the project could be split into two. A deal was in the works whereby Calgary-based AltaGas would partner with Antwerp, Belgium-based Exmar NV and EDF Trading Ltd., a gas marketer. The other project would be led by the Haisla First Nation and Golar LNG Ltd., a Bermuda-based LNG shipper. No further details have been released, and the project’s website has been taken down. Latest An AltaGas investor presentation released in November listed the Douglas Channel LNG project as part of their progress into the new year. A spokesperson from AltaGas told PNN that this was not yet finalized, but to expect an announcement about the progress of this project in Q1 2015, after court proceedings have concluded. Final Investment Decision Delayed.
Stewart Energy Final investment decision: 2014 Partners: On its website, Stewart lists as partners: CSSC, CWA Engineers Inc., Foster Wheeler, Flowco International Inc., Beijing Energy Investment Holding Co., Ltd., Skaugen China, Stanley LNG Carriers, Stewart World Port and a number of Chinese companies for which no translation was available. Location: Floating and land-based facilities, Stewart Capacity: 30 million tonnes, five on floating vessels, 25 on land-based facilities EA: N/A In-service date: 2017 Export license: Application submitted March Pipeline: N/A
Stewart is a small community about 300 km north of Prince Rupert that was put on the LNG map when Canada Stewart Energy Group Ltd. proposed establishing an LNG liquefaction and export facility there in March 2014. Without providing details, Stewart Energy said in a regulatory filing that it has signed off-take agreements with energy groups in two major Chinese cities. It also said there are plans for an 800-kilometre pipeline to transport natural gas to Stewart, although no details have been announced. Latest On March 5, 2014, Canada Stewart Energy Group Ltd. applied for a permit to export 30 MMt of natural gas per month for a period of 25 years from a liquefaction terminal. That application status is currently listed as incomplete on the National Energy Board website. Little has been made public since then. Final Investment Decision Stewart Energy LNG says it hopes to be in service in 2017. Its website states that a final investment decision would be made in 2014, but that deadline came and went with no word from the proponent.
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cover story Discovery LNG Final investment decision: 2018 Partners: Quicksilver Location: Land-based facility on Campbell River, Vancouver Island In service date: 2021 Export license: Under review by NEB Capacity: Up to 20 million tonnes of LNG per year EA: N/A Pipeline: N/A
Latest Still in very early stages, this project seeks to transform the Catalyst Paper Mill on Campbell River into an LNG export facility. The company says that the mill, which has been unused since 2009, is a perfect site for the facility, citing a deep water port, proximity to local labour, and existing infrastructure as assets. A jetty and offloading facility would still have to be built. A pipeline would also have to be constructed from the Lower Mainland to Vancouver Island to transport the gas to the facility. Quicksilver Resources Canada Inc. told PNN that it is currently looking for partners. Final Investment Decision Although unwilling to speculate on an FID, Discovery LNG expects the environmental assessment process to take approximately two years, only after which the final decision would be made.
Watson Island LNG Final investment decision: N/A Partners: Watson Island LNG Corporation Location: Land based facility, Watson Islan EA: N/A Pipeline: N/A
Latest In July the city of Prince Rupert entered into an exclusivity agreement with Watson Island LNG to put a facility on Watson Island. There is no timeline on the project, and no information on when exporting is planned to begin. Although very few details have been released, the provincial government describes the project as “small.” Sun Wave Forest Products Ltd. operated a pulp mill on the island, which was being decommissioned by the city over the summer of 2014. Final Investment Decision There is no information on when a final investment decision might be made.
Grassy Point LNG Final investment decision: N/A Partners: Woodside LNG Price tag: $1o-15 billion for first phase Location: Grassy Point, near Kitimat EA: Applied for permits from the BC EAO and CEAA, currently under review Pipeline: Up to 20 million tonnes of LNG annually
Woodside, Australia’s largest independent oil and gas company, is currently exploring this site as a possible location for either land-based or floating LNG export facility. In August 2014, the proponents filed for an environmental assessment certificate with the BC EAO. Latest In Nov. 2014 Woodside signed a three-year Sole Proponent Agreement with the provincial government for exclusive rights to access land at Grassy Point with the intent of building an LNG export facility there. In December 2014 Woodside purchased Apache’s stake in Kitimat LNG. It is unlikely that Woodside will pursue two projects simultaneously. Expect clarity on Grassy Point LNG only after the Apache stake acquisition is finalized. Final Investment Decision Uncertain.
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Oilsands competitive with other N.A. oil: Analyst Despite some investor misconceptions, Canada’s oilsands are competitive with other North American unconventional oil plays, an analyst told an industry audience in Calgary this week. The belief that oilsands crude is the world’s highest-cost source of oil is common today, as is the idea that the industry is susceptible to production shut-ins, said Randy Ollenberger. Yet, despite oil prices that continue to lose ground, Ollenberger, who is head of equity research director for BMO Capital Markets,said the chances that Canadian oilsands producers will shut in production are “very, very remote.” Addressing the Canadian Institute’s Oilsands Symposium, he said oilsands plays compete well with other unconventional North American oil plays, such as the Permian Basin in Texas, North Dakota’s Bakken and the Niobrara, to name only a few. At the same time, investor interest in the oil and gas sector has been muted, largely due to lower
oil prices, but also thanks to misconceptions about high costs, the chances of shut-ins as prices slip further, and concerns about producers’ carbon emissions. The latter have been highlighted by recent moves by governments in Ontario and Quebec to impose a laundry list of conditions on TransCanada Corporation’s proposed Energy East project. Recapping his analysis, Ollenberger noted oilsands project costs depend on many factors, including whether a project is mining or in situ, with the latter showing lower average costs (see chart). Estimating full-cycle supply costs on mining projects average $85 per bbl, he said smaller, more manageable in situ developments have helped cut average industry supply costs to about $70 per bbl, with in situ projects coming in at about $65 per bbl.” Cash costs are another story, and these are reported to average about $24 per bbl on in-situ developments. He said these costs are well below current oil prices. — Daily Oil Bulletin
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Alberta
reporter@pipelinenewsnorth.ca
tns photo
Koch Oil Sands $123m SAGD project KOSO has submitted an application to the Alberta Energy Regulator for the Dunkirk commercial demonstration project, a $123-million, steam-assisted gravity drainage (SAGD) project. If approved, the commercial demonstration project would produce 2,000 bbls per day of bitumen starting in the first quarter of 2017. The proposed Dunkirk CDP will be located in the West Athabasca oilsands region in W ½ 17-91-18 W4M, about 76 kilometres northwest of Fort McMurray and 111 kilometres from Wabasca-Desmarais, within the Municipal District of Opportunity No. 17. The first stage of the two-stage project is meant to establish the technical and economic viability of bitumen resource in the Wabiskaw reservoir before proceeding with the Dunkirk in-situ project (Stage 2). The proposed schedule is based on a 12-month regulatory review and approval process, which will allow KOSO to begin construction of the access road and clear the site in the fourth quarter of 2015. Drilling and completion of the first SAGD well pairs would begin in the first-quarter of 2016 with
first steam anticipated in the fourth quarter of 2016. If approved, the Dunkirk CDP will operate for about five years, after which it would be shut down and decommissioned, with the initial well pairs integrated into anticipated commercial development. The CDP is expected to take about one year to construct. Koch said it expects a total land disturbance of around 144 hectares (355 acres) of which 119 hectares (294 acres) is new disturbance, including one well pad with up to four well pairs. The Dunkirk CDP will include a central processing facility (CPF) with trucking facilities; an adjacent well pad (with up to four well pairs); water-source and waste-water-disposal wells with associated pipelines; a construction and operation camp; borrow pits and an associated access road. The project is designed to use proven SAGD technology in an area with thick bitumen net pay and
minimal lean and gas zones, says the application. “While SAGD is a commercially proven in-situ recovery method operating in numerous bitumenbearing reservoirs within the Athabasca oilsands area, the Dunkirk CDP is a necessary step to demonstrate that commercial production rates from the Wabiskaw reservoir can be attained from the KOSO OSL,” it says. During operations, the Dunkirk CDP is expected produce from one well pad consisting of up to four production and four injection wells. Up to 12 observation wells will be drilled to monitor steam chamber development. Dilbit from the Dunkirk CDP is planned to be transported by truck to a nearby oil terminal. No firm arrangements have yet been finalized with the proposed pipeline in the area. Once acceptable transportation arrangements have been made, the dilbit will likely be
shipped to the oil transportation hub near Edmonton, said KOSO. Stage 2
Assuming that Stage 1 is successful and the Dunkirk in-situ project (Stage 2) proceeds as currently anticipated, production capacity from the KOSO OSL is expected to increase to 60,000 bbls per day. The project will be constructed in two phases of 30,000 bbls per day. KOSO has conducted initial planning of Stage 2, and considered the placement of future well pads and infrastructure when selecting access road and pipeline ROW routes for the commercial demonstration project. The selected CPF location will not result in sterilization of Stage 2 bitumen resources, according to the application. KOSO anticipates that its Stage 2 regulatory applications will be submitted in late-2015. — Daily Oil Bulletin
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B.C. going ahead with $8.77 billion Site C Pending six lawsuits, the revised construction start date is summer 2015 and is slated to end in 2024. According to BC Hydro, if constructed the dam would produce 1,100 megawatts of energy
William Stodalka Staff Writer
In December, the province announced that it would invest upwards of $8.77 billion to build a third hydroelectric dam on the Peace River, this one approximately 7 km southwest of Fort St. John at Site C. It will likely be the most expensive public infrastructure project in Canada currently underway. The decision to go ahead with the project marks the first firm decision from the provincial government on the dam. The revised construction start date is summer 2015 and is slated to end in 2024. At the announcement in Victoria, Premier Christy Clark spoke of the benefits the dam would
have for future generations of British Columbians. “Today we’re all here to talk about a decision that is going to make a real difference for 100 years in the future of our province for so many many people,” the premier said. “The Site C Clean Energy Project won’t be built in a day and won’t be built in a year, but once it is built, it will benefit British Columbians for generations.” According to BC Hydro, if constructed the dam would produce 1,100 megawatts of energy for the province. Blair Lekstrom, former MLA for Peace River South, has been in favour of Site C, and sees a big economic impact on Fort St. John. “I think the business sector, obviously, the impact most directly
felt will be Fort St. John, being right on their back door,” he said. “I think this has been discussed for the better part of 30 years, and one way or the other a decision had to come.” “I know that there will be people that support this decision, and those who have made their voice heard all along that don’t support it,” the former MLA added. In a closed media session, Energy and Mines Minister Bill Bennett said the question “what’s best for the ratepayer?” largely drove his decision. “The answer turned out to be the Site C project,” he said. “It’s clear that to keep rates low, we must choose the option of building Site C.” “We’re proud to make this decision despite the fact that there’s impacts to people in the northeast,” Bennett said. In information given to media, the government upped their capital estimate of the project from BC Hydro’s $7.9 billion to about $8.335 billion. They also included an extra $440 million in their budget — bringing the total to $8.77 billion. The decision, however, does not mean the dam will actually be built. It still faces several legal challenges from First Nations and
affected landowners, which claim to be negatively impacted by the dam. The dam’s merits and economics have split public opinion for years. A BC Hydro commissioned poll said that 49 per cent support the dam without preset conditions, and that 30 per cent would support it “under certain circumstances.” David Conway, a BC Hydro spokesman, said before the decision that “BC Hydro has conducted a thorough analysis of alternatives to meet electricity demand. (This analysis) found that Site C provides the best combination of financial, technical, environmental and economic development attributes compared to alternatives.” Some business leaders and others have spoken in favour of the project going forward. The project still has considerable hurdles it must overcome before shovels enter the ground next summer. It faces legal challenges on both the federal and provincial levels. reporter@dcdn.ca A version of this article appeared in print in The Alaska Highway News. —Ed.
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Blair Lekstrom, former MLA for Peace River South, has been in favour of Site C, and sees a big economic impact on Fort St. John. DAVID DYCK PHOTO
JANUARY 16, 2015
reporter@pipelinenewsnorth.ca
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WCC LNG outlines $25 billion spending plan
WCC LNG waded into the environmental assessment process on Jan. 7 when B.C.’s Environmental Assessment Office notified the proponent that an environmental assessment certificate was required for the proposed project to move ahead. SUBMITTED IMAGE
Matt Lamers, David Dyck Staff Writers
The first phase of Exxon Mobil Corp.’s foray into British Columbia’s nascent liquefied natural gas industry could see it spend up to $25 billion. That would increase substantially if the energy giant proceeds with the second phase of the proposed WCC LNG project. WCC LNG forecasts the employment of up to 6,000 workers at peak construction for the first phase of the project, which has an initial capacity to ship 15 million tonnes a year of LNG from its Tuck Inlet, Prince Rupert port facility to buyers in Asia. The information was obtained from a Project Summary filed with the BC Environmental Assessment Office on Jan. 11. Exxon, the world’s largest energy company, and its Canadian subsidiary, Imperial Oil, have proposed to develop the LNG project under a venture known as WCC LNG Ltd. Judging by the export permit and
regulatory filings, this is a massive project. On Dec. 16, 2013, WCC LNG was granted a license to export 30 million tonnes of LNG per year for a term of 25 years. They have been in ongoing talks with local First Nations groups in the area since 2011. For the first time, the filing came out with a rough estimate for a final investment decision: 2017 and construction would begin almost immediately. The report also said that WCC LNG would seek to use either Spectra Energy Corp.’s 7.5-billion Westcoast Connector Gas Transmission project or TransCanada’s Corp.’s $5-billion Prince Rupert Gas Transmission line to tap into Northeast B.C.’s natural gas. WCC LNG wades into EA process WCC LNG waded into the environmental assessment process on Jan. 7 when B.C.’s Environmental Assessment Office notified the proponent that an environmental assessment
certificate was required for the proposed project to move ahead. Exxon, the world’s largest energy company, and its Canadian subsidiary, Imperial Oil, have proposed to develop an LNG project under a venture known as WCC LNG Ltd. WCC LNG Project Ltd. proposes constructing and operating a liquefied natural gas export facility and associated marine terminal on Tuck Inlet, currently owned by Prince Rupert Legacy Inc., and within the city limits of Prince Rupert. A Project Description was submitted to the Canadian Environmental Assessment Agency, according to Doug Caul, Associate Deputy Minister, Environmental Assessment Office. On Dec. 16, 2013, WCC LNG was granted a license to export 30 million tonnes of LNG per year for a term of 25 years. The permit was approved by the federal government in March 2014. reporter@dcdn.ca
For the first time, the January filing came out with a rough estimate for a final investment decision: 2017 and construction would begin almost immediately.
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Midstream company Vere
FIDs on Sunrise & Tower plants in months Veresen Inc.’s new midstream company will see growth driven by the wealth of Montney resources within an Area of Mutual Interest (AMI) in the Dawson Creek area of Northeast British Columbia: CEO
Elsie Ross
Daily Oil Bulletin
“Development in this region is constrained not by natural gas prices but by gathering and processing infrastructure,” Don Althoff, president and CEO, said in a conference call following the December 22 announcement of the formation of a new entity, Veresen Midstream Limited Partnership. The new company will be owned equally by Veresen and affiliates of Kohlberg Kravis Roberts & Co. L.P. (KKR), a global investment firm.
Veresen Midstream has entered into definitive agreements to acquire natural gas gathering and compression assets supporting Montney development in the Dawson area. The assets will be purchased from Encana Corporation and the Cutbank Ridge Partnership (CRP), a partnership between Encana and Cutbank Dawson Gas Resources Ltd., a subsidiary of Mitsubishi Corporation. “This was something Encana had been thinking about over the summer and they went out and asked for proposals,” Althoff said in response
to a question from an analyst on the conference call.” Commercial terms include a 30-year production dedication to Veresen Midstream’s gathering system for all of Encana and CRP’s Montney natural gas production within the AMI which contains approximately 240,000 acres of Montney rights and encompasses Encana and CRP’s Dawson South, Dawson North and Tower plays. Upon closing, Veresen Midstream will acquire from Encana approximately 500 kilometres of gas gathering pipelines and 675 million cubic
feet (mmcf) per day of compression capacity from Encana and CRP in the Dawson region. This infrastructure currently gathers Encana and CRP’s Montney gas production in the region and delivers it to various processing facilities, including the Hythe and Steeprock plants. Veresen Midstream also will acquire the 200 mmcf per day Saturn compression station which is currently under construction and scheduled for completion in mid2015. There are a number of additional projects under construction and in development, all in close R001949962
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DAWSON CREEK
esen enters Northeast B.C. proximity to Veresen’s existing asset base at Hythe/Steeprock. When the transaction is complete, Veresen will have acquired operating assets, assets under construction and future rights for growth in a large area of mutual interest. An independent engineering report prepared by GLJ Petroleum Consultants Ltd. for Veresen effective July 1, 2014, estimates that CRP and Encana have 23 trillion cubic feet (tcf) of dedicated Montney natural gas reserves and unrisked best estimate contingent and prospective resources within the AMI. “The great thing about these assets are that they are not condensate-dependent,” said Althoff. “They have actually produced gas at sub$2 (per thousand cubic feet (mcf)) levels and Encana and CRP have been making significant advancements in dropping their costs so we think . . . these are going to flow a lot of gas and a lot of liquids.” The Montney is the most prolific and actively developed natural gas play in Canada and one of the most competitive gas supply basins in
North America, he added. Current production of roughly 3.5 bcf per day is up 300 per cent from approximately 1.2 bcf per day in 2007 and gaining momentum, analysts heard. Veresen Midstream has committed to fund up to $5 billion of new infrastructure within the AMI to service Encana and CRP’s planned production growth under a 30-year fee-for-service arrangement. In the near-term, plans include the construction of the Sunrise gas plant (400 mmcf per day) and the Tower gas plant (200 mmcf per day), greenfield sweet gas compression and processing plants with natural gas liquids recovery (shallow cut), and associated incremental gathering pipelines. Construction of the Sunrise and Tower plants is scheduled to begin in 2015, with in-service dates anticipated in 2017. The projects are in the final stages of development with a final investment decision expected early next year, said Althoff. The estimated total cost of the Saturn, Sunrise and Tower plants is $1.5 billion.
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MONTNEY BC EAO accepts EA application from Woodfibre LNG
reporter@pipelinenewsnorth.ca
R001956865
“I have concluded that the Application, including the additional information provided to EAO, provides an appropriately meaningful treatment of the requirements in the AIR.” Matt Lamers Staff Writer
Toll Free: 1.855.4ENFORM (436.3676) Phone: 250.785.6009 Email: bc@enform.ca www.enformbc.ca
Enform Pipeline News 4.645x6.429.indd 1
Woodfibre LNG Limited took an important step forward in late November. On Dec. 29, the B.C. Environmental Assessment Office confirmed that proponent submitted an application on Nov. 28 for an environmental assessment certificate for the proposed Woodfibre LNG Project. The Woodfibre LNG Project is a proposed small-scale LNG processing and export facility located near Squamish, B.C. The facility would be built at an existing industrial site, the former Woodfibre pulp mill, which the proponent says is suited for conversion into an LNG facility. Regulatory filings state that the Project Assessment Manager, Alanya Smith, identified a number of items which required clarification or additional information in order to meet the requirements of the AIR, such as: clarification regarding accidents and malfunctions section; addition
2015-01-13 4:18 PM
of technical reports and memos to be appended to the Application; additional information regarding regulatory context and requirements; alarification of heritage assessment; additional information provided in Part C; clarification of the key author qualifications; addition of a map of the Areas of Environmental Concern associated with the site contamination; clarification of the temporal boundaries for each valued component (VC); and clarification of proposed dredging activities. “I have concluded that the Application, including the additional information provided to EAO with respect to the above issues, provides an appropriately meaningful treatment of the requirements in the AIR,” Smith noted in the filing. “Therefore, I have determined to formally accept the Application for detailed review.” The document also spells out Woodfibre LNG’s reporting requirements regarding aboriginal consultation and public consultation activities.
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