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b.c. pulls in massive haul in land sale Government pulled in a whopping $209 million in November’s Crown Petroleum and Natural Gas Public Tender auctions
The oil and gas industry has announced it loudly with their wallets: the boom is back. The B.C. government pulled in a whopping $209 million in November’s Crown Petroleum and Natural Gas Public Tender auctions. The average price of $2,723 per hectare this year to date is higher than any year except for 2008. The November auctions were dozens of times better than previous months of 2014.
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NOVEMBER 14, 2014
54th Annual Fort St. John Petroleum Association Oilmen’s Bonspiel
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Nov. 12-15, 2014
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PNN
NUMBERS
The following figures were taken from the stories in this issue of Pipeline News North.
2,500 The number of people who will be based at a work camp at its peak. It would have more people than most of the Peace Region’s municipalities. Story on Page 5. $14.12 The so-called Alberta-B.C. Natural Gas Discount (ABCD) is the difference in price that a BTU of natural gas costs in Tokyo compared to Alberta. Chart on Page 5. $8.6 billion The value at which Canadian Natural Resources Limited has set its 2015 budget , up from an initial budget of $7.7 billion set for 2014. Story on Page 8.
$209 million The vane of the B.C. government’s revenue in November’s Crown Petroleum and Natural Gas Public Tender auctions, putting the amount made from drilling permits and leases at almost $350 million so far in 2014. Story on Page 10. $4.7 billion The price of TransCanada’s Coastal GasLink Pipeline Project, which was recently granted an environmental assessment certificate. Story on Page 13. $2.7 billion The price tag for the Canadian Mainline system to connect growing Marcellus gas production in
the United States to Eastern Canadian markets. Story on Page 20. $10 billion The price of the proposed Pacific Future refinery for the B.C. North Coast, to be built in modules, which would initially process 200,000 bbls of bitumen per day, converting it into gasoline, diesel, kerosene and other distillates. Story on Page 22. $210 million The value of Pembina Pipeline Corporatio’s expansion to its pipeline infrastructure in northeast British Columbia. Story on Page 30.
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The Alberta-B.C. LNG 5 discount (chart)
U.S. gas price 5 (chart)
pnn 26
B.C. land auction 5 (chart)
15 Natural gas sector foots bill for massive transmission system
Alberta petroleum 5 land auction (chart)
16 Site C recommendation by Christmas: Bill Bennett
Massive camp being built 5 near Dawson Creek LNG seminar in 7 Fort St. John CN Sets 2015 budget 8 at $8.6 billion
B.C pulls in record $209 11 million in land sale
13 Pipeline passes environmental assessment 13 LNG projects in Alberta, B.C. & Oregon
Japan gas 5 price (chart)
12 Apache’s production continues to decline
19 Province takes steps to power LNG growth
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Work continues on 11 Sturgeon Refinery
21 TransCanada Planning $2.7 Billion in NGTL System Expansions 22 A green refinery? 26 North Montney Pipeline Hearing Underway Email reporter@ pipelinenewsnorth to share your story idea.
Blackbird acquires 10 more 11 Montney sections
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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.
NOVEMBER 14, 2014
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the charts
#oilsands
alberta land auction Alberta’s oil and gas land tender pulled in $41 million in early August, the second best showing so far this year. Source: Alberta Energy Regulator December 2013 to November 2014
The alberta-B.C. lng discount
December 2013 to November 2014
The so-called AlbertaB.C. Natural Gas Discount (ABCD) is the difference in price that a BTU of natural gas costs in Tokyo compared to Alberta. Sources: Natural Gas Exchange, Bloomberg
Alberta gas price The AECO “C” spot price, the Alberta gas trading price. Source: Natural Gas Exchange
December 2013 to November 2014
2,500 person camp being built near Dawson Creek Jonny Wakefield staff writer Construction has begun on an oil and gas work camp that at its peak could house more people than most of the Peace Region’s municipalities. Encana recently started work on the Sunset Prairie Lodge, a camp roughly 55 kilometres from Dawson Creek that could eventually host up to 2,500 people working on the company’s Montney shale natural gas projects. The site is undergoing early stage “dirt work,” according to Encana spokesperson Brian Lieverse. Workers could start moving in within the first few months of 2015, he added. “We’ve got a number of large construction projects that will be happening over the next two to three years, so that’s the need for the camp,” he said. The influx of work camps to the region has been a source of angst for local businesses, who fear they’ll be cut out of a resource “boom.” The new “shadow” population of transient workers has also overwhelmed local infrastructure, including hospitals, most elected
officials say. Local businesses especially have trouble competing for contracts to supply worker camps, Dawson Creek Chamber of Commerce Executive Director Kathleen Connolly told the Alaska Highway News. “That’s free enterprise, they can hire whoever they want,” said Connolly. “But we have some concerns about the impact that has on our community infrastructure.” In addition to construction supplies, camps require food service, medical, security and administrative personnel. Connolly said chamber members had learned the Encana camp needed 36 janitors, for instance. Most of those services are awarded on a contract basis. The chamber recently passed a motion at the B.C. Chamber of Commerce that asked the province to encourage camp operators to procure contracts locally where possible. Whether the chamber’s worker camp motions will have and impact remains to be seen. The Peace River Regional District also wants improved information on when and where camps are built. See CAMP Page 26
b.c. land auction
Japan gas price The Japan LNG Import Price reached an all-time high in October. Source: World Bank
December 2013 to November 2014
December 2013 to November 2014
The BC Oil and Gas Commission’s monthly land tender pulled in only $3 million in August, the lowest total this year, reversing the upward trend line. Source: BC Oil and Gas Commission
Oil price
U.S. gas price Left, the Henry Hub Natural Gas Spot Price (dollars per Million Btu). Source: U.S. Energy Information Agency
May 2010-August 2014
The price of oil fell below the psychologically important level of $100 per barrel in early August, but is still trending upward for the time period 2010-2014. Source: U.S. Energy Information Agency
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energy seminar in
Science World discussed the science of energy, not just LNG – where it comes from, how it is stored, how it is released, how it is
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David Dyck Staff Writer
The B.C. government’s proposed tax plan for LNG has been announced, and in preparation for the industry to become a much bigger part of British Columbians’ lives, the province is putting on a series of seven free LNG literacy seminars across the province, including one in Fort St. John. The local event was held on Nov. 4 and 5 at the North Peace Cultural Centre. Over those two days, there
were panels with both government and LNG proponents to answer any questions the community has about the tax plan, the industry or the LNG extraction process in miniature. There was also fun to be had, an educational side to the event, as the province recruited Science World to engage in energy literacy using scientific demonstrations. Bryan Tisdall, CEO of Science World, said that his organization didn’t come to tell people what they should think about LNG.
Rather, they wanted to inform the community so residents can better determine their own positions on the issue. “What we’re all about is the belief that science and technology is vitally important for the future health and prosperity of B.C., and we wish to show that to folks and demonstrate it in topics that matter to them,” said Tisdall. There were lots of loud noises and bright lights: “We showed how energy is released through explosion and through
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transported and how it is used.
Getting the basics down is the first step in understanding LNG.
flame, and we showed how energy is transmitted through the air, efficiently and inefficiently through sparks, but all of those are to illustrate larger principles,” he said. Science World was there to discuss the science of energy, not just LNG – where it comes from, how it is stored, how it is released, how it is transported and how it is used. Getting the basics down, said Tisdall, is the first step in understanding specific forms of energy, like LNG. “We believe that for individuals to ask questions and to make
informed decisions, they have to have some basic knowledge,” he said. However, that doesn’t mean that Science World will be avoiding the tough questions. Although proponents will be on hand to discuss the specifics of the Northeast’s energy plan, Tisdall’s team will explain the basic science behind LNG, and answer questions such as: how do you liquefy natural gas? How is it transported? How do you deliquefy it? How do you get energy out of it? See Fort St. John on Page 25
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alberta
Canadian Natural Sets 2015 budget at $8.6 billion Canadian Natural Resources Limited has set its 2015 budget at $8.6 billion, up from an initial budget of $7.7 billion set for 2014. It is forecasting production growth of 11 per cent in 2015 over 2014 levels to 893,000 BOE a day.
Cash flow is targeted to be $9.4 billion in 2015, and free cash flow is forecast at $800 million, after 2015 capital spending. About $2 billion of the 2015 capital budget represents funds the company can reallocate over the course of 2015, if required. Conventional oil and NGL Total crude oil and NGL production is forecast to increase by nine per cent to 571,000-611,000 bbls a day in 2015. The company’s North America oil and NGL division includes light oil, primary heavy oil and Pelican Lake heavy crude. Primary heavy oil production is expected to be comparable to
forecasted 2014 levels, ranging between 144,000 and 147,000 bbls a day with targeted 2015 capital spending of $1.1 billion. That includes the drilling of 732 net primary heavy oil wells in 2015. CNRL said primary heavy oil is the most flexible part of its portfolio.
Oilsands Combined output from thermal bitumen operations and the Horizon oilsands mine is forecast at 237,000-261,000 bbls a day for 2015. Thermal oil output is targeted to grow 14 per cent in 2015 to 126,000-140,000 bbls a day as a
result of the ramp-up of production at Kirby South and production associated with pad developments at Primrose. Total spending on thermal oil in 2015 is expected to be $1.1 billion.
Natural gas Canadian Natural is Western Canada’s largest gas producer and a significant owner and operator of gas infrastructure. Total gas production is forecast at 1.79-1.83 bcf a day, a 16 per cent increase from 2014 forecasted volumes. This increase can be attributed to a liquids-rich drilling program, as well as opportunities
derived from the gas-weighted Devon acquisition completed in 2014. Targeted 2015 gas spending of $920 million will continue the concentrated liquids-rich gas drilling program and advance the optimization of acquired assets. CNRL plans to further optimize acquired assets with facility consolidations, well reactivations and facility turnarounds. These activities are expected to generate significant free cash flow at average annual strip pricing. North America gas operating costs are targeted to decrease to a range of $1.30-$1.40 per mcf in 2015. — Daily Oil Bulletin
NOVEMBER 14, 2014
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British Columbia
#LNGinBC
B.C. pulls in record $209 million in land sale
Northneast B.C. as seen from above.
David Dyck Staff Writer
The oil and gas industry has announced it loudly with their wallets: the boom is back. The B.C. government pulled in a whopping $209 million in November’s Crown Petroleum and Natural Gas Public Tender auctions, putting the amount made from drilling permits and leases at almost $350 million so far in 2014. The Nov. 5 auction saw 28 parcels covering over 28,000 hectares of land sold to the highest bidders at an average price of $7,267. That price is almost double the average price of any auction in 2014, soundly beating February’s $4,246 average. The total take was almost as much as the $225 million the province made in all of 2013 from oil
matt lamers photo
and gas land auctions, although still significantly down from the peak year of 2008, when auctions earned as much as $610 million in July en route to a nearly $2.7 billion take for the year. (B.C. also put much more land up for grabs before 2011 than after, including about 757,000 hectares in 2008 compared to just 126,598 hectares so far in 2014. Apples to apples, the average price of $2,723 per hectare this year to date is higher than any year except for 2008, which took in only somewhat more at $3,518 per hectare.) Still, the November auctions were dozens of times better than previous months of 2014. August’s permit sales came in at just over $3 million for 7,737 hectares, for an average of $386 per hectare. April’s sales were better, but still only $10.4 million for 9,507 hectares, an average of $1,091 per hectare. Peace River North MLA Pat Pimm attributed the high land sales to the fact that companies are
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getting closer and closer to making their final investment decisions on facilities. Last month, the B.C. government announced the rate at which the LNG industry would be taxed. Pimm called that announcement “one contributing factor” for the spike in land prices, part of a trend that he believed would continue. “This particular land sale was in an area where there’s lots of proven properties close by, and I think these companies are looking to future investment, looking to get involved in the supply of natural gas for the future LNG facilities,” he said. To put it in perspective, just one “four-train” facility like the one LNG Canada is considering building on the coast would require 4 billion cubic feet of natural gas to operate, Pimm explained. “We’ll have to double the amount of gas that we have in our system today, just for one plant,” said Pimm. Comparing the numbers to the same month a year ago, the province sold permits on 12,052 hectares of land in November 2013, for a total of $54.5 million – which made up a good chunk and an average price per hectare of $4,522. Charter Land Services made the largest bid on a single permit this month, for a parcel 60 kilometres north of Hudson’s Hope, in the KobesTownsend-Halfway area. The company spent just under $124 million on 8,350 hectares, for an average of $14,808 per hectare. Windfall Resources paid the most per hectare for a parcel in the same area as the Charter purchase. That 3,710-hectare tract went for almost $67 million, or $18,008 per hectare. The province made the vast majority of its total in November – more than $190 million of the total $209 million – on those two purchases alone. Windfall also purchased a drilling license for a 1,115-hectare piece of land 150 kilometres northwest of Fort St. John for just over $5 million. Of the 30 parcels offered, only two were not sold. Almost all of the parcels on sale were related to oil and gas exploration – drilling licences give exclusive rights to explore by drilling wells for between three and five years. However, also up for bid was one lease, which provides the right to produce petroleum and gas for either five or 10 years. The lease sold in the Nov. 5 auction went to Scott Land & Lease for just over $1.6 million. While the successful bidders and the amount paid are made public, information on just how many bidders and who the losing bidders were is kept confidential. Even with this relatively large sale, the December sale has the potential to beat it in terms of land sold, with 31,888 hectares being offered over 39 parcels to the highest bidders. peacereporter@ahnfsj.ca
NOVEMBER 14, 2014
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alberta briefs
mct photo
file photo
Work continues on Sturgeon Refinery
Blackbird acquires 10 more Montney sections
Apache’s production continues to decline
Work is progressing on Canadian Natural Resources Limited’s 50 per cent owned refinery with site preparation and deep underground construction slated to be completed in the fourth quarter, the company said. Being built near Edmonton at an estimated cost of $8.5 billion, the so-called Sturgeon refinery will convert 50,000 bbls a day of bitumen to diesel fuel and other products. Startup is slated for September 2017. Canadian Natural has a 50 per cent interest in the North West Redwater Partnership, which will process 12,500 bbls a day of bitumen for CNRL and 37,500 bbls a day from the Alberta government’s bitumen-royalty-in-kind program. The other 50 per cent owner is North West Upgrading Inc. In July, the North West Redwater Partnership issued $500 million of 3.20 per cent Series A secured bonds due July 2024 and $500 million of 4.05 per cent Series B secured bonds due July 2044. — Daily Oil Bulletin
Blackbird Energy Inc. has acquired a 100 per cent working interest in 10 additional sections (6,400 net acres) of Montney rights from four separate vendors that are contiguous or within one mile of its existing western Elmworth acreage, which represents a 28 per cent increase. With the completion of these multi-transactional series of acquisitions, Blackbird now holds 100 per cent working interest in 46 contiguous sections (29,440 acres) and a total of 50 sections of Montney rights at Elmworth. The sections that have been acquired are on the western border of Blackbird’s existing Elmworth block and are within three miles of its 6-26-7007W6 Middle Montney well that was spud on Oct. 20, 2014. “This significant acquisition in the western portion of our core area of Elmworth continues to demonstrate Blackbird’s determination in becoming a significant Montney player in the Elmworth/Gold Creek area,” Garth Braun, chief executive officer, said in a release. — Daily Oil Bulletin
Primarily the results of divestitures, Apache Canada Ltd.’s third quarter Canadian output fell 36 per cent year-over-year to 73,187 boe per day from 113,819 boe per day during the same period last year (see tables). Production is reported as net after royalty. Total production was down five per cent from the second-quarter 2014 due to the closing of the previously announced sale of the Ojay, Noel and Wapiti areas in Alberta and British Columbia on April 30, 2014, and third-party downtime. The production associated with the downtime is now online. The divestitures were primarily dry gasproducing properties comprising 622,600 (328,400 net) acres. In the Wapiti area, Apache retained 100 per cent of its working interest in horizons below the Cretaceous including rights to the liquids-rich Montney and other deeper horizons. — Daily Oil Bulletin
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LNG Canada Files
Environmental Assessment LNG projects in Alberta, B.C. & Oregon Following is brief summary of the LNG projects on the West Coast. For a full up-to-date report pick up next month’s issue. Awaiting application In July, the City of Prince Rupert entered into an exclusivity agreement with Watson Island LNG to repurpose the island for a small LNG export terminal. There is no timeline on construction or when export will begin.
LNG Canada’s application for an Environmental Assessment (EA) certificate for its proposed LNG export facility in Kitimat, B.C., has been filed with the B.C. Environmental Assessment Office (EAO) and entered the 180-day application review phase. LNG Canada is a joint venture company comprised of Royal Dutch Shell plc (50 per cent) and affiliates of PetroChina (20 per cent), Korea Gas Corporation(15 per cent) and Mitsubishi Corporation(15 per cent). The EAO’s acceptance of LNG Canada’s application marks the culmination of more than three years of environmental studies, design work, and engagement with local communities and Aboriginal groups. The application includes details regarding the proposed project’s economic and social benefits, environmental effects, and mitigation measures to avoid or reduce those effects. “Our application’s
emitting LNG facilities in the world. “The Haisla people strongly support this project but have always believed that it should be as ‘green’ as possible, and this use of clean hydro power is good news. This also adds more certainty to the context around the project in which we will participate — our people are keen to realize the significant employment and other economic benefits to come,” said Chief Councillor Ellis Ross, Haisla Nation “Coastal First Nations welcomes this decision by LNG Canada,” added Art Sterritt, executive director of the Coastal First Nations. “Minimizing the environmental impact of the B.C. LNG industry is our primary concern and LNG Canada’s choice of a power solution demonstrates tangible action to address it. The region’s abundant renewable energy should be an important component of a B.C. LNG industry.” — Daily Oil Bulliten
acceptance is a significant milestone for our proposed project and a demonstration of LNG Canada’s commitment to consider local knowledge and insight to inform how the project can benefit local First Nations and communities, and for the region to achieve its social, economic and environmental aspirations,” said Andy Calitz, CEO, LNG Canada. LNG Canada has selected natural gas turbines for the liquefaction process to minimize fuel use and greenhouse gas emissions. LNG Canada also recently signed a power agreement with BC Hydro to use clean, renewable electricity from BC Hydro for the electricity needed for the facility. LNG Canada estimates the proposed facility will have a greenhouse gas emission intensity of about 0.15 tonne CO2e/tonne LNG produced, which is lower than benchmarks recently introduced by the B.C. government and among the lowest CO2
courtesy IMAGE
In July, Petrox Resources Corp. announced a cooperation framework with Qingdao Sinoenergy of China and Asiafic Clean Energy of Hong Kong to establish an Alberta joint venture company called Gascana AB Energy Ltd. Liquefaction would take place in Sturgeon County, Alberta, and the LNG would be transported to the West Coast for export via a rail link. Pending export decisions In July the Canadian unit of Fort Worth, Texas-based Quicksilver Resources applied to the National Energy Board to export up to 20 million tons per annum (mtpa) of LNG. The project is named Discovery LNG and would be based near the Campbell River on Vancouver Island. In July, Woodside Energy Holdings, a unit of Australia’s Woodside Petroleum, applied to the NEB for a license to export 20 million tonnes of super-chilled gas per year for 25 years from a proposed terminal on the Northwestern coast. Last January Woodside purchased rights from the B.C. government to build an export facility at Grassy Point. On July 8, 2014, Steelhead LNG applied for five licenses to export LNG from Vancouver Island for 25 years. On June 20, 2014, WesPac Midstream Vancouver LLC applied to export up to 400 million cubic feet of liquefied gas a day from a liquefaction plant to be built in Delta, B.C. See LNG on Page 18
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Pipeline
$4.7 billion pipeline passes environmental assessment
TRANSCANADA photo
“Achievement of an environmental assessment certificate is a significant milestone for both
Blaze King
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Coastal GasLink and TransCanada.” Staff Writer
The province has issued an environmental assessment certificate for TransCanada’s Coastal GasLink Pipeline Project, which would run 675 kilometres from just west of Dawson Creek to a proposed liquefied natural gas (LNG) export facility near Kitimat. There are 32 legally-binding conditions attached to the certificate, including avoiding caribou habitats – and providing up to $1.5 million for monitoring caribou and their predators – another $500,000 for the protection of grizzly bears, an assurance that marketable timber will be salvaged, and continuing consultations with Aboriginal groups. They have also been instructed to develop a plan to minimize social and economic effects on local infrastructure and services. Environment Minister Mary Polak and Natural Gas Development Minister Rich Coleman issued the certificate, which was announced last week. The ministers concluded that the project will be constructed, operated and decommissioned in a way that will present minimal adverse effects, except those on caribou
and from greenhouse gas emissions. The project is estimated to cost $4.7 n, and will operate for 30 years. Once completed, the pipeline will create 150 direct and indirect jobs in British Columbia. As well, TransCanada claims that the project will provide $20 million per year in property tax revenues for local and provincial governments. “Achievement of an environmental assessment certificate is a significant milestone for both Coastal GasLink and TransCanada,” said Russ Girling, the president and CEO of TransCanada, in a press release. “The scope of this application was substantial, involving thousands of hours of work to date for all involved. We appreciate the contributions and input from all those who participated in the environmental assessment process.” This is just one step in the process of approving the pipeline, albeit a large one. Applications have been submitted to the B.C. Oil and Gas Commission for permits to build and operate the pipeline, and a decision on those is expected to come down early next year. Pending final approval, the anticipated start of construction is 2016, with the pipeline ready for use by 2020. peacereporter@ahnfsj.ca
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NOVEMBER 14, 2014
dawson creek
Natural gas sector foots bill for massive Staff Writer
Taxpayers won’t be left holding the bag if the oil and gas industry does not end up using power from a massive new transmission system rising west of Dawson Creek, a BC Hydro representative told a gathering of local business owners. Hydro is developing two major
upgrades to its transmission system in the South Peace to supply power to oil and gas customers. Work started last fall on the Dawson Creek/Chetwynd Area Transmission Project (DCAT), a nearly $300 million network of high voltage power lines from the W.A.C. Bennett Dam’s GM Shrum generating station to industrial customers in the Groundbirch Area. Crews are currently
installing transmission towers along Highway 97. The second piece, the Peace River Electricity Supply project (PRES), will replace existing lines from the generating station to DCAT with a higher capacity system. “[Growth in demand] is far greater here than anywhere else in the province,” said Lesley Wood, a public relations advisor
with BC Hydro, at a Dawson Creek Chamber of Commerce event. “We haven’t seen anything like this for decades.” “This area is experiencing some of the most dramatic single industry regional load growth we’ve seen in the last 50 years,” Wood wrote in a followup email. “Over the next 10 years, the annual rate of load growth in the
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Jonny Wakefield
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transmission system near DC South Peace is forecasted to be 10 times greater than for BC Hydro’s system as a whole. “What we’re looking at is growth that’s driven by the gas industry.” A new sitting of the Legislative Assembly kicked off Oct. 6, and the government’s main, repeatedly stated objective is to pass a tax on LNG extraction and new emissions standards for the industry. (Petronas executives have
said the proposed 7 per cent tax on LNG exporters is too high.) Shell, Encana, Murphy, Air Liquide and ARC resources all paid security deposits. The payment is to ensure that power will be used, Wood said, and is not a contribution to the overall cost of building the project. She added that BC Hydro is obligated to expand their network when customers ask for more
power. “As they buy the power, their power bills then take into account that they already put the security down. So basically you’ve got the industry primarily paying for this,” she said. To lay the transmission lines for DCAT, the utility negotiated land usage rights with around 90 landowners. In three cases, BC Hydro took the relatively unprecedented
step of expropriating landowners who refused to budge. However, in no case was anyone removed from their property against their will, Wood said. The DCAT system will be finished in 2015, she said, while the PRES project is still undergoing design and consultation work. Its scheduled completion date is between 2021 and 2023. reporter@dcdn.ca R001642872
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NOVEMBER 14, 2014
SITE C
site c recommendat
David Dyck Staff Writer
B.C. Minister of Energy and Mines Bill Bennett said that he will make his recommendation on the Site C hydroelectric dam project to the provincial cabinet by Christmas. Bennett answered the side question at a press conference that announced the $83 per MW-h that BC Hydro plans to charge the LNG industry for power, as well as announcing an agreement made with the LNG Canada project to use
BC Hydro electricity and build energy infrastructure to support a proposed export facility in Kitimat. Asked how Site C might figure into the BC Hydro decision, Bennett said that last year’s tenyear demand forecast was for 3,000 gigawatthours (GW-h) of electricity for the entire LNG industry. He said LNG Canada, if it goes ahead with a final investment decision, will need 2,000 GW-h all by itself, implying that the industry’s power needs could end up being even higher than officially anticipated. “We’ll be at a point later, sometime in the next
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SITE C
reporter@pipelinenewsnorth.ca
tion by christmas: Bill Bennett
10 years, where our demand forecast is probably going to have to be adjusted,” he said. Bennett did say that B.C. currently has a current surplus of power, making the need for Site C uncertain at this exact moment. “If we do need new generation, I know we would certainly acquire that electricity through Site C for less than $83 [the rate Hydro will be charging the LNG industry]. It remains to be seen if we can acquire new electricity for less than $83 from other sources.” He added that as of now, he has been asked to make his recommendation on Site C to cabinet sometime before Christmas, though his
17
“marching orders may change.” The Chiefs and Councils of the Doig River and Blueberry River First Nations released a statement that they were united in their opposition to the proposed dam. “Our ancestors were the first signatories to Treaty 8 in this province, signing the Treaty with Canada in 1900 on the banks of the Peace River at Old Fort,” Doig River Chief Norman Davis said in the release. “That river is a central part of our history and we strongly oppose its destruction. The river valley contains many culturally important sites, including the burial site of one of our former chiefs, Chief Attachie.” peacereporter@ahnfsj.ca
18
• PIPELINE NEWS NORTH
NOVEMBER 14, 2014
#LNGinBC
LNG from Page 12 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 to be located near Stewart. 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 25 years. Export approvals On May 1, 2014, Oregon LNG Marketing Company received permission from the NEB to export 473 Bcf of natural gas to the U.S., where it will be liquefied and shipped to Asia. The export point is the vicinity of Kingsgate B.C. On May 1, 2014, Aurora Liquefied Natural Gas Ltd. received permission from the NEB to export 2.3 million tonnes of LNG per
year for a 25-year term from a terminal near Prince Rupert, B.C. On April. 16, 2014 Triton LNG Limited Partnership received permission from the NEB to export 2.3 million tonnes of LNG per year for a 25-year term from a floating processing plant. On Feb. 20, 2014 Jordan Cove LNG L.P. was granted approval by the NEB to export 9 million tonnes of gas per year to the U.S. for 25 years, where it will be liquefied and shipped to Asia. On Dec. 16, 2013, Prince Rupert LNG Exports Limited was granted a license to export 21.6 million tonnes of per year for a term of 25 years. On Dec. 16, 2013, Pacific NorthWest LNG received permission from the NEB to export 19.68 million tonnes of LNG per year. Pacific NorthWest LNG has emerged the frontrunner, potentially making an FID by
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year-end. 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. On Dec. 16, 2013, Woodfibre LNG Export Pte. Ltd. earned a license to export 2.1 million tonnes of LNG per year for 25 years. On Oct. 13, 2011, KM LNG was granted a 20-year permit by the NEB to export an annual volume of 10 million tonnes of LNG. It was the first LNG export license issued by the NEB since the deregulation of the natural gas market in 1985. On Feb. 2, 2012, BC LNG Export Co-operative LLC received a 20-year license from the NEB to export 1.8 million tonnes of LNG per year. On Feb. 4, 2013, LNG Canada was awarded a 25-year permit from the NEB to export 24 million tonnes of LNG per year at a terminal that will be built near Kitimat.
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PIPELINE NEWS NORTH •
19
British Columbia
Province takes steps to power LNG growth The power coming
from BC Hydro will amount to about
20 per cent of the total electricity
required for the LNG
David Dyck Staff Writer
The provincial government has announced that BC Hydro will charge a significantly higher rate to developers of liquefied natural gas projects than it currently charges most industrial customers, while at the same time unveiling a deal that will allow a proposed LNG export facility near Kitimat to use electricity from the Crown utility. Hydro plans to charge $83.02 per megawatt hour (MW-h) of electricity to the LNG projects, which are currently in their design stages, which would bring fuel drilled from the North and transport it to export facilities on the Pacific coast. That’s a good deal higher than the 2014 industrial average of $54.34 per MW-h. Also, beginning in 2015, that rate will rise by 2 per cent per year until 2024, at which time it would freeze until matched by provincial industry rates. The power coming from BC Hydro will amount to about
20 per cent of the total electricity required for the LNG Canada project, the venture confirmed, as the turbines used to cool natural gas into LNG will be powered by LNG itself. Minister of Energy and Mines Bill Bennett, speaking at the press conference where the announcements were made, explained that higher rates were necessary to offset Hydro’s cost to obtain the new energy that LNG growth will require. The higher rates didn’t appear to faze LNG Canada, a joint venture between Shell Canada, PetroChina, Korea Gas and Mitsubishi that made what Bennett and Natural Gas Development Minister Rich Coleman called the first power agreement of its kind between the province and industry. The project’s developers have agreed to pay the full cost of connecting to the BC Hydro grid, as well as any transmission upgrades that may be required. Work will likely include the trunk transmission line that goes from Prince George to
courtesy PHOTO
Terrace, which could need major upgrades – to be paid for by LNG Canada – to handle the expanded energy needs, the ministers said. But that doesn’t mean the industry will now be required to pay for every power infrastructure project that it benefits from, Bennett said. “There is some work required between the Terrace substation and the Kitimat substation, and that work has to be done regardless of whether there’s LNG or not, so that work will be done under the ordinary course of BC Hydro,” he said. “BC Hydro will pay for the upgrade of that particular line.” The minister continued that with the electricity rate now set, LNG developers can now begin planning how much they will need to budget for power, one more step in helping make final investment decisions. Officials also said that the province’s new rate system will ensure that other customers will not finance added power demand from industry. peacereporter@ahnfsj.ca
Canada project.
Lieutenant-Governor Judith Guichon is greeted by Premier Christy Clark. courtesy PHOTO
Lieutenant-Governor Judith Guichon opened the third session of the 40th Parliament of British Columbia and read the speech from the throne. courtesy PHOTO
• PIPELINE NEWS NORTH
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The company announced that it is preceding with the next step of Canadian Mainline system enhancements to connect growing Marcellus gas production in the United States to Eastern Canadian markets. In Western Canada, TransCanada said it has received requests from multiple parties for significant volumes of new firm services on the NGTL system. This demand for services is expected to result in a total of approximately four bcf per day of incremental firm service contracts of eight to 10 years, Karl Johannson, executive vice-president and president, natural gas pipelines, said in a conference call to discuss third quarter 2014 results. Approximately 3.1 bcf per day of this volume relates to firm receipt service from about 21 different receipt sites and projects
and about 900 mmcf per day relates to firm delivery service, he said. “All this receipt volume is organic growth and is not contingent on any LNG projects going forward,” said Johannson. “It is meant to go into our overall system and NIT (NOVA Inventory Transfer) system and the various markets on our system.” The requests reflect the significant growth in unconventional natural gas supplies in northwestern Alberta and northeastern British Columbia and in delivery markets in the Western Canadian Sedimentary Basin, primarily driven by oilsands development and increased demand for gasfired electric power generation. “These new customer requests cover supply and market areas that are core to the NGTL system’s geography and services,”Russ Girling, TransCanada president
NOVEMBER 14, 2014
PIPELINE NEWS NORTH •
21
planning $2.7 billion system expansions
Trans Canada PHOTO
Trans Canada PHOTO
will contract approximately four bcf per day of firm new
contracts that will lead to a system expansion of up to $2.7 billion through to 2017, TransCanada said.
and chief executive officer, said in a prepared statement. “Capturing these incremental volumes and constructing the new facilities will position NGTL well into the future and enhance the long-term economic viability of the system.” The 2016/2017 expansion program has an estimated capital cost of approximately $2.7 billion. The investment includes multiple projects totalling 540 kilometres (336 miles) of 20- to 48-inch diameter pipeline, seven compressors, 40 meter stations and other associated facilities. NGTL plans to file applications to construct and operate the various components of the expansion program with theNational Energy Board between the fourth quarter of 2014 through the third quarter of 2015. Subject to regulatory approvals, construction should start in 2016 with all facilities
expected to be in service by the second quarter of 2017. In the first nine months of this year, NGTL has placed approximately $285 million of system-related capital projects into service. Including the new 2016/17 facilities capital requirements, NGTL has approximately $6.7 billion of projects in development or under construction, which have been, or will be, filed with the NEB for approval. This includes the $1.7 billion North Montney Mainline and the $1.9 billion Merrick Mainline pipeline, along with other new supply and demand facilities. In Eastern Canada, TransCanada is proceeding with its Vaughan pipeline project and associated facilities as part of $475 million in pipeline and facility expansions within the Eastern Triangle portion of the Canadian Mainline system. The next step of
development for natural gas infrastructure in southern Ontario, it is the result of collaboration between TransCanada,Enbridge Gas Distribution, Gaz Metro and Union Gas. Construction of TransCanada’s Kings North connection, Parkway West connection and Hamilton area project are expected to cost about $255 million and be in service in November 2015. The Vaughan pipeline and associated facilities are expected to cost approximately $220 million and have an in-service date of November 2016. “Over the past year, TransCanada has announced plans to invest almost $2 billion in facility enhancements to allow growing supplies of Marcellus gas to reach Ontario and Quebec markets,” Girling said in a news release. “These enhancements help minimize the duplication
of infrastructure, reduce delivery costs and improve the diversification of gas supply to markets in Eastern Canada.” These projects are backed by long-term, binding agreements (15 years based on two open seasons) and have been developed to respond to changing market needs. All of these projects are subject to regulatory approval. “TransCanada has been delivering natural gas to Canadians for more than 60 years. Over the past few years we have seen significant changes to where our customers get the gas they need, and the configuration they need to get it,” Girling said. “These enhancements demonstrate how we are responding to changing market needs, building new capacity to meet demand and maximizing the efficiency of our Canadian Mainline system.” — Daily Oil Bulliten
22
• PIPELINE NEWS NORTH
NOVEMBER 14, 2014
Special report
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green refinery Although global oil prices have dropped in recent months, it is not a concern to Pacific Future Energy Corporation and its proposed refinery for the West Coast of British Columbia, says company top brass.
Samer Salameh, executive chairman, told the Bulletin that “as long as the margin between crude and refined remains constant, it is a concern to the patch and to the producers, but it is not for us.” In June, Pacific Future announced its $10 billion “green refinery” for the B.C. North Coast, to be built in modules, which would initially process 200,000 bbls of bitumen per day, converting it into gasoline, diesel, kerosene and other distillates. “We believe that this refinery will really bridge the gap … between Alberta and Asia,” Salameh said, adding Asia is the only market that has a huge and growing demand for oil. “We believe our project on the coast of B.C. is the facilitator between getting the oil out of here and into Asia.” Refineries operate on a 50- to- 100-year lifecycle, Salameh noted, and so predicting what long-term markets will call for Pacific Future
Peter Facy PHOTO
products at the end of the century is probably beyond most forecasters’ abilities. However, he said, his company has a good idea of where growth will originate in the near-term. “For the foreseeable future, we see huge demand from Japan and from Southeast Asia in general. China and South Korea, maybe or maybe not, but for the rest there is huge demand. To that end, we will come online in about eight years. That is the perfect time.” While Japan has shut down nuclear reactors that power its refineries and there is also huge demand potential for refined Canadian crude products in India, Salameh said, China and South Korea both contain strong refining infrastructure that might impede demand for refined imports. Still, he added, Asia is a market treasure trove that would likely grow its demand over time. See REFINERY on Page 28
NOVEMBER 14, 2014
PIPELINE NEWS NORTH •
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Oil production growth relies heavily on oilsands Canadian oil production growth will rely heavily on output from the oilsands to achieve the anticipated increase from four million bbls per day in 2013 to 7.4 million bbls per day in 2040, the second largest rise among non-OPEC countries after Brazil, the International Energy Agency said in its World Energy Outlook 2014. The main uncertainty over this projection is not related to the resource base, but rather to the transport capacity required to get the oil to market, bearing in mind the reduced import needs of the United States, Canada’s traditional export market. Total oil production in Canada is expected to hit 5.3 million bbls by 2020, driven by oilsands output of three million bbls per day. Oilsands production of 5.2 million bbls per day is forecast for 2040.. Oil demand rises by 14 million bbls per day to reach 104 million bbls per day in 2024 in the New Policies Scenario, the central scenario in the report. (This scenario describes a pathway for energy markets based on the continuation of existing policies and measures as well as the implementation — albeit cautiously — of policy proposals, even if they are yet to be formally adopted. The scenario only
takes account of policies that were enacted as of mid-2014.) The pace of demand growth decreases markedly, from an annual average of 0.9 per cent over the period to 2020, down to 0.3 per cent per year in the 2030s, moving toward a plateau in oil consumption. Prices that reach $132 per bbl in 2040 (in real terms) and policy measures to improve energy efficiency and promote fuel switching constrain oil use. By 2040, nearly 75 per cent of oil use is concentrated in just two sectors where substitution is most challenging: transport and petrochemicals, the IEA stated. The net growth in oil demand comes entirely from non-OECD countries: for each bbl of oil eliminated from demand in OECD countries, two additional bbls of oil are consumed in the developing world. India and Nigeria are the countries with the highest rates of oil demand growth. China becomes the largest oil consuming country in the early 2030s, but higher efficiency and lower rates of growth in industrial activity and in demand for mobility (as population numbers level off in the 2030s) mean that by 2040, oil demand growth all but comes to a halt in China. See JOBS on Page 30
NOVEMBER 14, 2014
PIPELINE NEWS NORTH •
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• PIPELINE NEWS NORTH
NOVEMBER 14, 2014
PIPELINE
reporter@pipelinenewsnorth.ca
Connolly said chamber members had heard of two other companies looking to build camps in the area, though neither the PRRD nor the Oil and Gas Commission were aware of any applications. CAMP from Page 5 Under the current system, worker camps are approved by a patchwork of government agencies including the Oil and Gas Commission. Who gets a say on camps depends on whether the camp is on private or Crown land. Connolly said chamber members had heard of two other companies looking to build camps in the area, though neither the PRRD nor the Oil and Gas Commission were aware of any applications. That came as no surprise to Connolly. “There are camps all over the place nobody knows about,” she said. At a community meeting about
the camp this spring, Lieverse told business owners that his company would work to procure goods locally when possible. At that time, Encana expected Sunset Prairie Lodge would create between 15 and 25 permanent jobs in Dawson Creek. Encana expects to invest $1 billion in its Montney holdings in the next year. If the camp grows to the expected size, it would have as many or more residents than most of the region’s incorporated areas. Its population would rival Chetwynd and Tumbler Ridge, which each had a little more than 2,500 residents in 2011.
North pipeline
courtesy PHOTO
NGTL describes the proposed North Montney
the North Montney supply basin northeast British
R001697732
Two natural gas pipelines operating in British Columbia are squaring off before the National Energy Board over toll treatment at a first phase of a public hearing on NOVA Gas Transmission Ltd.’s proposed North Montney pipeline. In the first phase of the hearing in November that addresses the commercial aspects of the $1.67 billion project, Westcoast Energy Inc., which operates as Spectra Energy Transmission, is opposing the proposed toll treatment for the project, urging the board to require that it be treated as a stand-alone project for tolling purposes. It its filings, Westcoast argues that NGTL’s proposal for rolled-in tolling rates, under which all shippers on its system would share the cost of the new pipeline, is inappropriate for the North Montney Mainline and that it would adversely affect competition and
could result in stranded assets. Also opposed to NGTL’s tolling proposal are FortisBC Energy Inc. and the Pacific Northwest Group comprised of the Export Users Group, Northwest Industrial Gas Users and Northwest Pipeline GP, who cite concerns about their ability to access gas supply in northeastern B.C. Progress Energy Canada Ltd., the anchor shipper on the pipeline, has intervened in the hearing in support of NGTL. In its opening statement, NGTL describes the proposed North Montney pipeline as a “critical component” in the infrastructure chain between prolific and growing production in the North Montney supply basin in northeast British Columbia and existing and new natural gas markets, notably emerging LNG markets off Canada’s West Coast. “This project will enable NGTL shippers and others to efficiently and
NOVEMBER 14, 2014
PIPELINE NEWS NORTH •
27
PIPELINE
Montney hearing underway
courtesy PHOTO
pipeline as a “critical component” in the infrastructure chain between prolific production in Columbia and existing natural gas markets, notably emerging LNG markets off Canada’s coast. cost-effectively access this significant new source of supply,” says NGTL. The proposed North Montney pipeline, an extension of the Groundbirch Mainline on the NGTL system, is designed to transport two bcf per day of sweet gas from the North Montney area to the NOVA Inventory Transfer (NIT) and through the NGTL system. It also will transport gas to the proposed Prince Rupert Gas Transmission (PRGT) pipeline that will transport gas to the proposed Pacific NorthWest LNG facility at Prince Rupert operated by PETRONAS Carigali Canada BV, which owns Progress. NGTL is seeking NEB approval to construct and operate the system and to include the costs of the project in its rate base for the NGTL system. Rates for service would be determined in accordance with the existing system rate design methodology. The proposed North Montney extension provides for two integrated 42-inch segments. One segment consists of approximately 180.9 kilometres of pipeline from an interconnection with the existing Saturn section of the Groundbirch Mainline at 14-21-80-20W6 to a point in 44-L-94-A-13 (Aitken Creek section).
The second segment consists of approximately 125 kilometres of pipeline from a point in 44-L-94-A-13 to a point in 39-C-94-G-10. In addition, the project includes three new compressor stations with bi-directional capability (two on the Aitken Creek section and one along the existing Groundbirch Mainline), along with 15 new meter stations. Once the PRGT pipeline goes into service, Mackie Creek will be established as an export delivery point, similar to Empress/McNeill and Alberta/B.C. Contracted NGTL customers have requested an in-service date of April 1, 2016, for the Aitken Creek section and April 1, 2017, for the Kahta section. To meet these requests, pipeline construction of the Aitken Creek section is scheduled to begin in the third quarter of 2015, subject to regulatory approvals. The facilities phase of the North Montney pipeline hearing begins Nov. 18, 2014, in Fort St. John, B.C., and will involve a number of First Nations that are concerned about the impact of the proposed pipeline on their traditional lands. In its filing, Progress says that PETRONAS is scheduled to make a final investment decision
(FID) in December 2014 on the LNG project and the NEB’s decision on the rolled-in tolls is a critical factor in the economic assessment of the project and its decision on the facilities is a critical factor in the feasibility assessment of the project. “Regulatory delay will have a significant consequence on the FID and whether the project proceeds,” it says. Should the company decide to proceed, LNG facility construction is scheduled to start in the first quarter of 2015 with the first LNG cargo expected to ship in the fourth quarter of 2018 or first quarter of 2019. In its evidence, Westcoast argues that the proposed toll treatment for gas transportation service on the North Montney Mainline to the existing NGTL system at the terminus of the Saturn section is “fundamentally inconsistent with the cost causation/user pay principle.” If the board were to approve it, a producer seeking to move its gas out of the region to Saturn would pay a FT-R (firm transportation receipt) toll that is approximately equal to (pre-Mackie Creek) or lower than (post-Mackie Creek) the FT-R toll paid by a producer at a downstream receipt point in the Groundbirch area, says See PIPELINE on Page 29 Westcoast.
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• PIPELINE NEWS NORTH
NOVEMBER 14, 2014
REFINERY from Page 22 “The first tranche of the refinery is 200,000 barrels, and the reason we did it that way is because we know there is enough demand today for refined product from 200,000 barrels. As we ramp up this thing and receive both … the supply that is available to us and the demand growth, then we can go to our next phase, which is another 200,000- barrel tranche, and up to the full five tranches for one million barrels.” He said the next step for his company is to negotiate long-term take agreements on the production side, and long-term procurement agreements in the oilpatch, although Pacific Future is also doing a lot of work ensuring the people of B.C. realize that the proposed refinery is as environmentally responsible as it is economically feasible — and he believes it is very economically feasible. “There is this notion for some reason that once a refinery crosses Canadian airspace, then all of the sudden it starts losing money. However, if you look at refineries comparable to ours — ones built in the last 30 years that are nowhere close to as efficient or flexible as ours — they are taking Canadian crude from the oilsands and making $25.30 per barrel profit. They are having bumper years.” Technology employed in the Pacific Future design is time-tested in existing facilities throughout North America, Salameh said, but since there has not been a new refinery built in either Canada or the U.S. for several decades, his project would be the first time these new innovations would be used domestically for an entire project, fully capturing the environmental and efficiency benefits. “The technology exists and has been employed in different phases in different places. Usually it is deployed as an add-on to an existing facility where they deploy carbon capture and storage [CCS] technology.” He added: “This is a greenfield refinery to be built this way, which means it is cheaper and the economies of scale are much better.” Aside from CCS, Salameh said the new refinery would be fired up with natural gas and biofuel to emit far lower emissions than a typical facility of similar scope.
there should be ample feedstock. “Once all these things start to happen, then the oilpatch will be looking to export east to Europe — if there are takers — and certainly west. To the extent that there is more than one refinery on the West Coast, then great! That is better for everyone.” However, Salameh is especially confident about the prospects for the Pacific Future project, which has received endorsements from financial backers and attracted to its management team the likes of retired political heavyweight Stockwell Day. The former International Trade minister and Treasury Board president, and one-time federal opposition leader, joined Pacific Future as senior advisor, director and chairman of the company’s advisory committee, citing his cabinet credentials as a B.C. MP and Alberta MLA as advantageous for understanding the necessary steps for helping Alberta crude gain international market access. First Nations engagement is key to project success; proposed refinery has three possible locations During the 2014 Calgary Energy Roundtable, Day told the conference that important to the success of the Pacific Future project is that it works to address concerns raised by environmentally-minded
Multiple refinery projects don’t worry Pacific Future, as there is market potential for all: Salameh The Pacific Future refinery is the second one proposed for the B.C. North Coast, as newspaper publisher David Black hopes to build a 550,000 bbl-perday refinery at Kitimat. With demands in Asia, Salameh said, production in the oilsands could double and maintain a multitude of new refineries on the West Coast. Therefore, he said, the prospect of another proposed refinery project in northern B.C. does not worry him, as
Cumulus Clouds PHOTO
B.C. citizens. In addition, from the start, he said, engaging First Nations communities has been integral to project planning. “One of the things that is key and principal to our project is not just discussions, but real-time and future planning that goes into the future for many generations with the indigenous people, and with First Nations,” he said, adding it was important to Pacific Future that First Nations communities not be considered as an afterthought once the project was announced, but instead as partners to the project’s success. “This is real, this is important, and this has to be meaningful.” According to Day, about 110 per cent of lands in B.C. have First Nations land claims, and so ignoring those aboriginal communities when working towards developing a refinery project is both unwise and disrespectful. “We’re saying this does not close the door. It actually opens the door, because it shows a pathway forward, and that pathway we are taking is bringing us real results. We’re showing genuine understanding and accommodation.” — Daily Oil Bulletin
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Pipeline
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PIPELINE from Page 27 However, in its reply argument NGTL says shippers will not be paying a near-zero toll as a result of the proposed rolled-in tolling. Each shipper on the project will pay the full FT-R toll that is applicable at each receipt point, with tolls at or near the maximum for the system prior to deliveries at Mackie Creek and are expected to be closer to the average FT-R tolls after deliveries begin at Mackie Creek. The intervenors’ submission also ignores that tolls will be paid for delivery service and the combined FT-R and FT-D tolls on project facilities are expected to be more than 30 cents per mcf, says NGTL. On an annual basis, starting in 2019, Progress alone will pay more than $200 million per year through tolls, which exceeds the incremental cost of service associated with the project, according to the NGTL submission. In its reply response, NGTL also rejects suggestions the North Montney pipeline will be simply a “bullet line” to PRGT. The facilities, it says, are bidirectional and are designed to be integrated into the overall system by enabling transportation of the additional supply received on the project to other delivery points throughout the system and enables supply from elsewhere on the system to flow to Mackie Creek and the Aitken Creek storage facility. NGTL acknowledges that Westcoast competes with it for sales gas transmission service in northeast B.C. and wants to connect new supply to its
29
system. However, in this case, the shippers underpinning the project seek access to the NOVA Inventory Transfer market, not the Westcoast Station 2 market, through a direct connection to the NGTL system, it says. “Westcoast seeks to frustrate that commercial outcome by having the board abandon its long-standing tolling principles and instead impose a new tolling model on NGTL that would make it significantly more expensive to access NIT through this or any other future extension of the NGTL system.” Intervenors have asserted that NGTL’s proposal “tilts the playing field in NEBC,” says the company. “NGTL disagrees that fair competition requires identical commercial models.” As long as the components of service are just and reasonable, pipelines can have different basic rules influencing their ability to compete fairly with each other, it says. In its opening statement, NGTL argues that the current toll design represents a balanced allocation of costs that reasonably reflects the primary cost drivers on the NGTL system and reflects the unique commercial and physical structure and operation of the system and the diverse nature and interests of its shippers. The NEB, it says, has consistently approved treating the costs of pipeline extensions on a rolled-in basis where the extension is integrated with the remainder of the system and the nature of the service offered on the extension is consistent with the existing services offered. In this case, the project will be physically and operationally inte-
grated with the facilities that comprise the existing NGTL system and the services offered will be the same as those offered elsewhere on the system. “Users of the NGTL system will benefit from the application of this approach to the project through access to new sources of supply, connection of the system to a substantive new long-term market, access to another large storage facility in Western Canada and reductions in overall tolls,” says the company. In its reply evidence, NGTL rejects intervenor submissions that the North Montney project will result in underutilization and stranding of assets in the region. These claims ignore the substantial resource base (an estimated 137 tcf of marketable gas) in the Montney formation, the significant market connected to Westcoast’s T-South and the low T-North toll compared to other paths to that market, it says. In addition, Westcoast is connected to large, stable and captive markets, NGTL notes. In response to a question posed by Alliance Pipeline Ltd.,another intervenor, NGTL confirmed that it will not proceed with the North Montney pipeline with any approvals that may result from the hearing if the LNG exports and associated facilities forecast in the application either develop at a significantly slower pace than forecast or not at all. The company said it will not begin construction of the pipeline unless Progress has made a positive final investment decision on the proposed LNG project within 15 months of an NEB report on the proceeding, unless the board directs otherwise. — Daily Oil Bulletin
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employment
Major pipeline expansion means more jobs in B.C. Pembina Pipeline Corporation says that it has entered into binding agreements to proceed with a $210 million expansion to its pipeline infrastructure in northeast British Columbia. The pipeline will transport condensate and natural gas liquids for various producers in the liquids-rich Montney resource play. The project entails the construction of approximately 160 kilometres of up to 12-inch diameter pipeline with a base capacity of up to 75,000 bbls per day. It will parallel the company’s Blueberry pipeline system northwest of Tay-
lor, B.C., to the Highway/Blair Creek area of B.C. Subject to regulatory and environmental approval, Pembina anticipates bringing the expansion onstream in the second quarter to fourth quarter of 2017 timeframe. The expansion project is underpinned by a long-term, costof-service agreement with an anchor tenant. Volumes aggregated by the NEBC expansion will feed into Pembina’s Phase III pipeline expansion downstream of Taylor. “Pembina has been actively engaging with producers regarding the development of the Mont-
ney play,” Jason Wiun, Pembina’s vice-president, conventional pipelines, said in a news release. “With significant exploration in the area, our customers are looking for a solution for their liquids production,” he said. “The NEBC expansion will allow us to provide customers with a cost-effective transportation solution for this production and access to Pembina’s existing infrastructure at Taylor, B.C., which feeds into the Edmonton, Alberta, area market hub.” The expansion also is a great opportunity for Pembina as it fur-
ther supports the economics of its Phase III expansion, according to Wiun. “We have been expanding our infrastructure across the Alberta portion of the Western Canadian Sedimentary Basin and are very excited to have the opportunity to extend our service to our customers in B.C.,” he said. “The project not only benefits our customers, it also benefits our investors as we are able to add additional value through our integrated service offering.” — Daily Oil Bulletin
JOBS from Page 24
leash” tight oil production from the Burgos and other basins from 2025. For Mexico, the IEA projects over 400,000 bbls per day of tight oil production in 2040.
Growth in the Americas led by U.S. tight oil, the oilsands in Canada and Brazilian deepwater output, pushes non-OPEC production higher until the early 2020s. As U.S. tight oil output flattens then starts to fall back, Canadian oilsands emerge as the engine of North American supply, the IEA stated. Despite a gradual spread of tight oil production to Argentina, Russia, China and elsewhere, nonOPEC supply falls back to 51 million bbls per day by 2040, slightly higher than today’s levels but on a declining trend. Mexico offers some potential upside to the nonOPEC outlook following recent energy sector reforms.
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Tight oil Although development started later in Canada than south of the border, interest in tight oil is growing in Canada with production of around 330,000 bbls per day in 2013. This is expected to grow gradually to more than 700,000 bbls per day in the mid-2020s, before falling back below 300,000 bbls per day in 2040. The growth rate is, to some extent, slowed by the competition for capital with oilsands projects and by the constraints on access to markets other than the United States. Mexico has good shale resources and the ongoing reform of the upstream sector could “un-
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Natural gas market Global gas use continues to grow in all scenarios compared with today’s levels, although consumption trajectories diverge strongly, especially post-2020, depending on the way that government policies evolve. In the New Policies Scenario, gas demand of 5.4 tcm in 2040 means that gas draws level with coal as the second-largest fuel in the global energy mix. The main regions pushing global gas demand higher are China, which becomes a larger gas consumer than the European Union around 2035, and the Middle East. Gas plays an important role in mitigating coal use and related air pollution in China’s cities and in limiting oil use for power generation in the Middle East. Within the OECD, U.S. gas demand grows to 900 bcm by 2040 and becomes the largest fuel in the U.S. energy mix, while Japan consumption falls back to pre-Fukushima levels, in both cases influenced by new policy announcements affecting the outlook for power generation. Gas consumption in Europe returns to 2010 levels only in the early 2030s, with the outlook likewise heavily contingent on policy action, notably on CO2 pricing.” — Daily Oil Bulletin
NOVEMBER 14, 2014
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