Pipeline News North November 2014

R001697746

VOL. 6 ISSUE 11 DIST: 16,000 SERVING THE OIL & GAS INDUSTRY IN NORTHERN B.C. AND ALBERTA

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Special Report: $4.7 billion Coastal GasLink pipeline wins environmental permit

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.

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

2 • PIPELINE NEWS NORTH NOVEMBER 14, 2014

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Al Seib / MCT

The following figures were taken from the stories in this issue of Pipeline News North.

PNN NUMBERS

2,500The 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.

$14.12The 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 billionThe 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 billionThe price of TransCanada’s Coastal GasLink

Pipeline Project, which was recently granted an environmental assessment certificate.

Story on Page 13.

$2.7 billionThe 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 billionThe 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 millionThe value of Pembina Pipeline Corporatio’s expansion to its pipeline infrastructure in

northeast British Columbia. Story on 0.


PNN The Alberta-B.C. LNG

discount (chart)

U.S. gas price (chart)

B.C. land auction

(chart)

Japan gas price (chart)

Alberta petroleum

land auction (chart)

Massive camp being built near Dawson Creek

LNG seminar in Fort St. John

CN Sets 2015 budget

at $8.6 billion

B.C pulls in record $209 million in land sale

Work continues on

Sturgeon Refinery

Blackbird acquires 10 more Montney sections

12 ApAChe’S pRoDUCTioN CoNTiNUeS To DeCLiNe

13 pipeline passes environmental assessment

13 LNG projects in Alberta, B.C. & oregon

15 Natural gas sector foots bill for massive transmission system

16 Site C recommendation by Christmas: Bill Bennett

19 province takes steps to power LNG growth

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.

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Look for pNN on Twitter @pipelineNN

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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.

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#oilsands the charts

Oil price

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 compa-ny’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 re-source “boom.” The new “shad-ow” population of transient workers has also overwhelmed local infrastructure, includ-ing hospitals, most elected

officials say.Local businesses especially

have trouble competing for con-tracts to supply worker camps, Dawson Creek Chamber of Com-merce Executive Director Kath-leen 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 im-pact that has on our community infrastructure.”

In addition to construction supplies, camps require food service, medical, security and administrative personnel. Con-nolly said chamber members had learned the Encana camp needed 36 janitors, for instance. Most of those services are award-ed on a contract basis.

The chamber recently passed a motion at the B.C. Chamber of Commerce that asked the prov-ince to encourage camp opera-tors 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 Dis-trict also wants improved in-formation on when and where camps are built.

See CAMP Page 26

2,500 person camp being built near Dawson Creek

Jonny Wakefieldstaff writer

Left, the Henry Hub Natural Gas Spot Price (dollars per Million Btu). Source: U.S. Energy Information Agency

The Japan LNG Import Price reached an all-time high in Octo-ber. Source: World Bank

The AECO “C” spot price, the Alberta gas trading price. Source: Natural Gas Exchange

Alberta gas price

The so-called Alberta-B.C. Natural Gas Dis-count (ABCD) is the dif-ference in price that a BTU of natural gas costs in Tokyo compared to Alberta. Sources: Natural Gas Exchange, Bloomberg

The alberta-B.C. lng discount

Japan gas price

U.S. gas price

December 2013 to November 2014



The price of oil fell below the psychologi-cally important level of $100 per barrel in early August, but is still trending upward for the time period 2010-2014. Source: U.S. Energy Infor-mation Agency

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

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

alberta land auction

b.c. landauction

Oil price



May 2010-August 2014


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energy seminar in fort st. john

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

The B.C. government’s pro-posed tax plan for LNG has been announced, and in prep-aration for the industry to be-come a much bigger part of British Columbians’ lives, the province is putting on a se-ries 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 govern-ment and LNG proponents to answer any questions the com-munity has about the tax plan, the industry or the LNG extrac-tion process in miniature.

There was also fun to be had, an educational side to the event, as the province recruit-ed Science World to engage in energy literacy using scientific demonstrations.

Bryan Tisdall, CEO of Science World, said that his organiza-tion didn’t come to tell people what they should think about LNG.

Rather, they wanted to in-form the community so resi-dents can better determine their own positions on the issue.

“What we’re all about is the belief that science and tech-nology is vitally important for the future health and prosper-ity 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

David DyckStaff Writer


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energy seminar in fort st. john

transported and how it is used.

Getting the basics down is the first

step in understanding LNG.

flame, and we showed how en-ergy 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 dis-cuss 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 Tis-dall, is the first step in understand-ing specific forms of energy, like LNG.

“We believe that for individu-als 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 ba-sic science behind LNG, and an-swer questions such as: how do you liquefy natural gas? How is it transported? How do you deliq-uefy it? How do you get energy out of it?

See Fort St. John on Page 25

DAvE DyCK PHOTOS


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 NGLTotal crude oil and NGL pro-

duction 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.

oilsandsCombined output from ther-

mal 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 produc-tion at Kirby South and produc-tion associated with pad develop-ments at Primrose.

Total spending on thermal oil in 2015 is expected to be $1.1 billion.

natural gasCanadian 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 at-tributed 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 con-solidations, well reactivations and facility turnarounds. These activities are expected to generate significant free cash flow at aver-age 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

Canadian Natural Sets 2015 budget at $8.6 billion

alberta


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R001681295

#LNGinBCbritish columbia

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 Natu-ral 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

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 be-fore 2011 than after, including about 757,000 hect-ares 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 some-what more at $3,518 per hectare.)

Still, the November auctions were dozens of times better than previous months of 2014. August’s per-mit 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

B.C. pulls in record $209 million in land sale

northneast B.C. as seen from above. matt lamerS Photo

David Dyck Staff Writer

getting closer and closer to making their final in-vestment 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 in-vestment, 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 cu-bic 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 Kobes-Townsend-Halfway area. The company spent just under $124 million on 8,350 hectares, for an aver-age of $14,808 per hectare.

Windfall Resources paid the most per hectare for a parcel in the same area as the Charter pur-chase. 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 north-west 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 be-tween 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 Decem-ber 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.

[email protected]


R001697755

alberta briefstwitter.com/pipelinenn#LNGinBC

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 Alber-ta and British Columbia on April 30, 2014, and third-party downtime. The produc-tion associated with the downtime is now online.

The divestitures were primarily dry gas-producing 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

Apache’s production continues to decline

Blackbird Energy Inc. has acquired a 100 per cent working interest in 10 additional sections (6,400 net acres) of Montney rights from four sep-arate 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-transac-tional 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 6-26-70-07W6 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 be-coming a significant Montney player in the Elm-worth/Gold Creek area,” Garth Braun, chief exec-utive officer, said in a release. — Daily Oil Bulletin

Blackbird acquires 10 more Montney sections

MCT PHOTO

Work is progressing on Canadian Natural Re-sources Limited’s 50 per cent owned refinery with site preparation and deep underground construc-tion 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 Septem-ber 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 govern-ment’s bitumen-royalty-in-kind program. The other 50 per cent owner is North West Upgrading Inc.

In July, the North West Redwater Partnership is-sued $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.


Work continues on Sturgeon Refinery

WALTER SIEGMUND PHOTO

B.C. pulls in record $209 million in land sale

FILE PHOTO


facebook.com/pipelinenewsnorth

LNG Canada’s application for an Environmental Assess-ment (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 applica-tion review phase.

LNG Canada is a joint ven-ture company comprised of Royal Dutch Shell plc (50 per cent) and affiliates of Petro-China (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 en-vironmental studies, design work, and engagement with local communities and Ab-original groups.

The application includes details regarding the pro-posed project’s economic and social benefits, environmen-tal effects, and mitigation measures to avoid or reduce those effects.

“Our application’s

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 en-vironmental aspirations,” said Andy Calitz, CEO, LNG Canada.

LNG Canada has selected natural gas turbines for the liquefaction process to mini-mize fuel use and greenhouse gas emissions. LNG Canada also recently signed a power agreement with BC Hydro to use clean, renewable elec-tricity from BC Hydro for the electricity needed for the facility.

LNG Canada estimates the proposed facility will have a greenhouse gas emission in-tensity of about 0.15 tonne CO2e/tonne LNG produced, which is lower than bench-marks recently introduced by the B.C. government and among the lowest CO2

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 wel-comes this decision by LNG Canada,” added Art Ster-ritt, executive director of the Coastal First Nations.

“Minimizing the environ-mental impact of the B.C. LNG industry is our primary concern and LNG Canada’s choice of a power solution demonstrates tangible ac-tion to address it. The re-gion’s abundant renewable energy should be an impor-tant component of a B.C. LNG industry.”

— Daily Oil Bulliten

LNG Canada Files Environmental Assessment

CourteSy ImaGe

LNG projects in Alberta, B.C. & Oregon

Following is brief summary of the LNG proj-ects 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 Is-land LNG to repurpose the island for a small LNG export terminal. There is no timeline on construction or when export will begin.

In July, Petrox Resources Corp. announced a cooperation framework with Qingdao Sinoen-ergy of China and Asiafic Clean Energy of Hong Kong to establish an Alberta joint venture com-pany called Gascana AB Energy Ltd. Liquefac-tion would take place in Sturgeon County, Al-berta, 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 ap-plied 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 North-western 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 van-couver LLC applied to export up to 400 mil-lion 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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LNG Canada Files Environmental Assessment

The province has issued an environ-mental assessment certificate for Trans-Canada’s Coastal GasLink Pipeline Proj-ect, which would run 675 kilometres from just west of Dawson Creek to a pro-posed liquefied natural gas (LNG) export facility near Kitimat.

There are 32 legally-binding condi-tions attached to the certificate, includ-ing avoiding caribou habitats – and providing up to $1.5 million for moni-toring caribou and their predators – another $500,000 for the protection of grizzly bears, an assurance that market-able timber will be salvaged, and con-tinuing consultations with Aboriginal groups.

They have also been instructed to de-velop a plan to minimize social and eco-nomic 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 con-structed, operated and decommissioned in a way that will present minimal ad-verse 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 Co-lumbia. As well, TransCanada claims that the project will provide $20 million per year in property tax revenues for lo-cal 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 participat-ed 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 pipe-line, and a decision on those is expected to come down early next year.

Pending final approval, the anticipat-ed start of construction is 2016, with the pipeline ready for use by 2020.

[email protected]


TRANSCANADA PHOTO

$4.7 billion pipeline passes environmental assessment

“Achievement of an environmental assessment certificate is a significant milestone for both Coastal GasLink and TransCanada.”


dawson creek

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Taxpayers won’t be left holding the bag if the oil and gas indus-try 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 sys-tem 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 indus-trial customers in the Ground-birch Area. Crews are currently

installing transmission towers along Highway 97.

The second piece, the Peace River Electricity Supply proj-ect (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 experienc-ing 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 an-nual rate of load growth in the

Jonny WakefieldStaff Writer

Natural gas sector foots bill for massive transmission system near DC


dawson [email protected]

R001642872

Natural gas sector foots bill for massive transmission system near DCSouth 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, repeat-edly stated objective is to pass a tax on LNG extraction and new emissions standards for the in-dustry. (Petronas executives have

said the proposed 7 per cent tax on LNG exporters is too high.)

Shell, Encana, Murphy, Air Liq-uide and ARC resources all paid security deposits. The payment is to ensure that power will be used, Wood said, and is not a contribu-tion to the overall cost of building the project.

She added that BC Hydro is ob-ligated 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 secu-rity 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 land-owners. In three cases, BC Hydro took the relatively unprecedented

step of expropriating landowners who refused to budge.

However, in no case was any-one removed from their property against their will, Wood said.

The DCAT system will be fin-ished in 2015, she said, while the PRES project is still undergoing design and consultation work. Its scheduled completion date is be-tween 2021 and 2023.

[email protected]

Jonny WakeFIeld Photo


site c

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 pro-vincial 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 indus-try for power, as well as announcing an agree-ment made with the lnG Canada project to use

BC hydro electricity and build energy infra-structure 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 ten-year demand forecast was for 3,000 gigawatt-hours (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


site c recommendation by christmas: Bill Bennett


site [email protected]

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 un-certain 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 oth-er sources.”

he added that as of now, he has been asked to make his recommendation on Site C to cabi-net sometime before Christmas, though his

“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 his-tory 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.” [email protected]

site c recommendation by christmas: Bill Bennett


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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. ap-

plied 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 Natu-ral 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 pro-cessing plant.

On Feb. 20, 2014 Jordan Cove LNG L.P. was granted approval by the NEB to export 9 mil-lion 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 Ex-

ports Limited was granted a license to ex-port 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

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 mil-lion 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 an-nual volume of 10 million tonnes of LNG. It was the first LNG export license issued by the NEB since the deregulation of the natu-ral gas market in 1985.

On Feb. 2, 2012, BC LNG Export Co-opera-tive 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.


british columbia

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 cur-rently in their design stages, which would bring fuel drilled from the North and transport it to export facilities on the Pa-cific coast.

That’s a good deal higher than the 2014 industrial aver-age 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 elec-tricity 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 ap-pear 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 transmis-sion upgrades that may be required.

Work will likely include the trunk transmission line that goes from Prince George to

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 infra-structure project that it ben-efits from, Bennett said.

“There is some work re-quired 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 un-der 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 help-ing make final investment decisions.

Officials also said that the province’s new rate system will ensure that other cus-tomers will not finance added power demand from industry.

[email protected]

Province takes steps to power LNG growth

CourteSy Photo

The power coming

from BC Hydro will

amount to about

20 per cent of the

total electricity

required for the LNG

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



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TransCanada planning $2.7 billion in NGTL system expansions

NOVA Gas Transmission Ltd.,

the wholly-owned subsidiary of

TransCanada Corporation,

The company announced that it is preceding with the next step of Canadian Mainline system en-hancements to connect growing Marcellus gas production in the United States to Eastern Cana-dian markets.

In Western Canada, TransCanada said it has received requests from multiple parties for significant volumes of new firm services on the NGTL sys-tem. This demand for services is expected to result in a total of approximately four bcf per day of incremental firm service con-tracts of eight to 10 years, Karl Johannson, executive vice-pres-ident 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 re-ceipt service from about 21 dif-ferent receipt sites and projects

and about 900 mmcf per day re-lates to firm delivery service, he said.

“All this receipt volume is or-ganic growth and is not contin-gent on any LNG projects going forward,” said Johannson. “It is meant to go into our overall sys-tem and NIT (NOvA Inventory Transfer) system and the various markets on our system.”

The requests reflect the signifi-cant growth in unconventional natural gas supplies in north-western Alberta and northeastern British Columbia and in delivery markets in the Western Canadian Sedimentary Basin, primarily driven by oilsands development and increased demand for gas-fired 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

tranS Canada Photo


TransCanada planning $2.7 billion in NGTL system expansions

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. “Cap-turing these incremental vol-umes 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 pro-gram has an estimated capital cost of approximately $2.7 bil-lion. 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 vari-ous components of the expansion program with theNational Energy Board between the fourth quarter of 2014 through the third quar-ter 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 approxi-mately $285 million of system-re-lated capital projects into service. Including the new 2016/17 facili-ties 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 facil-ity expansions within the Eastern Triangle portion of the Canadian Mainline system. The next step of

development for natural gas in-frastructure 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, Park-way West connection and Ham-ilton area project are expected to cost about $255 million and be in service in November 2015. The vaughan pipeline and asso-ciated 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 diversifi-cation of gas supply to markets in Eastern Canada.”

These projects are backed by long-term, binding agreements (15 years based on two open sea-sons) and have been developed to respond to changing market needs. All of these projects are subject to regulatory approval.

“TransCanada has been deliv-ering natural gas to Canadians for more than 60 years. Over the past few years we have seen sig-nificant changes to where our customers get the gas they need, and the configuration they need to get it,” Girling said. “These en-hancements demonstrate how we are responding to changing mar-ket needs, building new capacity to meet demand and maximizing the efficiency of our Canadian Mainline system.”

— Daily Oil Bulliten

tranS Canada Photo tranS Canada Photo


fb.com/pipelinenewsnorthsPecial rePort

green refineryAlthough 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 con-cern 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 pro-cess 200,000 bbls of bitumen per day, converting it into gasoline, die-sel, 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

products at the end of the century is probably beyond most forecast-ers’ 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 like-ly grow its demand over time.

See reFInery on Page 28

Peter Facy Photo


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Canadian oil production growth will rely heavily on output from the oilsands to achieve the anticipated in-crease 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 pro-jection is not related to the resource base, but rather to the transport ca-pacity 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 ex-pected to hit 5.3 million bbls by 2020, driven by oilsands output of three mil-lion 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 Sce-nario, the central scenario in the re-port. (This scenario describes a path-way for energy markets based on the continuation of existing policies and measures as well as the implementa-tion — albeit cautiously — of policy proposals, even if they are yet to be formally adopted. The scenario only

takes account of policies that were en-acted as of mid-2014.)

The pace of demand growth de-creases markedly, from an annual av-erage 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 mea-sures 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 challeng-ing: transport and petrochemicals, the IEA stated.

The net growth in oil demand comes entirely from non-OECD coun-tries: for each bbl of oil eliminated from demand in OECD countries, two additional bbls of oil are consumed in the developing world. India and Ni-geria are the countries with the high-est 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

Oil production growth relies heavily on oilsands


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[email protected]

CamP from Page 5

Under the current system, worker camps are approved by a patchwork of government agen-cies 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 mem-bers had heard of two other com-panies 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 lo-cally 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 bil-lion in its Montney holdings in the next year.

If the camp grows to the expect-ed 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 resi-dents in 2011.

Two natural gas pipelines op-erating in British Columbia are squaring off before the National Energy Board over toll treatment at a first phase of a public hear-ing 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 oppos-ing 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 ship-pers on its system would share the cost of the new pipeline, is in-appropriate for the North Mont-ney 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 pipe-line, has intervened in the hear-ing in support of NGTL.

In its opening statement, NGTL describes the proposed North Montney pipeline as a “critical component” in the infrastruc-ture chain between prolific and growing production in the North Montney supply basin in north-east British Columbia and exist-ing and new natural gas markets, notably emerging LNG markets off Canada’s West Coast. “This project will enable NGTL ship-pers and others to efficiently and

North Montney pipeline hearing underway

CourteSy Photo

NGTL describes the proposed North Montney pipeline as a “critical component” in the infrastructure chain between prolific production in the North Montney supply basin northeast British Columbia and existing natural gas markets, notably emerging LNG markets off Canada’s coast.

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.


PiPeline

North Montney pipeline hearing underway

CourteSy Photo

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 North-West 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 de-termined in accordance with the existing sys-tem 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 intercon-nection 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 approximate-ly 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 ca-pability (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 request-ed 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, pipe-line 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 tra-ditional 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 sig-nificant 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 seek-ing 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 Westcoast. See PIPelIne on Page 29

CourteSy Photo

NGTL describes the proposed North Montney pipeline as a “critical component” in the infrastructure chain between prolific production in the North Montney supply basin northeast British Columbia and existing natural gas markets, notably emerging LNG markets off Canada’s coast.


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reFInery from Page 22

“The first tranche of the refinery is 200,000 bar-rels, 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 avail-able 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 mil-lion barrels.”

He said the next step for his company is to ne-gotiate long-term take agreements on the produc-tion side, and long-term procurement agreements in the oilpatch, although Pacific Future is also do-ing 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 de-sign 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 econo-mies 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.

multiple refinery projects don’t worry Pacific Future, as there is market potential

for all: SalamehThe Pacific Future refinery is the second one pro-

posed for the B.C. North Coast, as newspaper pub-lisher David Black hopes to build a 550,000 bbl-per-day refinery at Kitimat.

With demands in Asia, Salameh said, production in the oilsands could double and maintain a multi-tude 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

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 Al-berta crude gain international market access.

First nations engagement is key to project suc-cess; proposed refinery has three

possible locationsDuring the 2014 Calgary Energy Roundtable, Day

told the conference that important to the success of the Pacific Future project is that it works to ad-dress concerns raised by environmentally-minded

B.C. citizens. In addition, from the start, he said, engaging First Nations communities has been in-tegral 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 proj-ect 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 to-wards developing a refinery project is both unwise and disrespectful.

“We’re saying this does not close the door. It ac-tually opens the door, because it shows a pathway forward, and that pathway we are taking is bringing us real results. We’re showing genuine understand-ing and accommodation.”


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PIPelIne from Page 27

However, in its reply argument NGTL says ship-pers 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 appli-cable 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 com-bined 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, Prog-ress 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 sugges-tions the North Montney pipeline will be simply a “bullet line” to PRGT. The facilities, it says, are bi-directional 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 north-east B.C. and wants to connect new supply to its

system. However, in this case, the shippers un-derpinning the project seek access to the NOvA Inventory Transfer market, not the Westcoast Sta-tion 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 ac-cess NIT through this or any other future exten-sion of the NGTL system.”

Intervenors have asserted that NGTL’s proposal “tilts the playing field in NEBC,” says the compa-ny. “NGTL disagrees that fair competition requires identical commercial models.”

As long as the components of service are just and reasonable, pipelines can have different ba-sic 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 alloca-tion 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, connec-tion 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 Pipe-line Ltd.,another intervenor, NGTL confirmed that it will not proceed with the North Montney pipe-line with any approvals that may result from the hearing if the LNG exports and associated facili-ties 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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R005898440

JoBS from Page 24

Growth in the Americas led by U.S. tight oil, the oilsands in Can-ada and Brazilian deepwater out-put, pushes non-OPEC produc-tion 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, Rus-sia, China and elsewhere, non-OPEC supply falls back to 51 mil-lion bbls per day by 2040, slightly higher than today’s levels but on a declining trend. Mexico offers some potential upside to the non-OPEC outlook following recent en-ergy sector reforms.

tight oilAlthough development started

later in Canada than south of the border, interest in tight oil is grow-ing 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 ex-tent, 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 re-sources and the ongoing reform of the upstream sector could “un-

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.

natural gas marketGlobal gas use continues to grow

in all scenarios compared with to-day’s levels, although consump-tion trajectories diverge strongly, especially post-2020, depending on the way that government poli-cies evolve. In the New Policies Scenario, gas demand of 5.4 tcm in 2040 means that gas draws lev-el with coal as the second-largest fuel in the global energy mix.

The main regions pushing glob-al gas demand higher are China, which becomes a larger gas con-sumer 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 genera-tion in the Middle East.

Within the OECD, U.S. gas de-mand grows to 900 bcm by 2040 and becomes the largest fuel in the U.S. energy mix, while Japan consumption falls back to pre-Fu-kushima levels, in both cases in-fluenced by new policy announce-ments affecting the outlook for power generation. Gas consump-tion in Europe returns to 2010 lev-els only in the early 2030s, with the outlook likewise heavily contin-gent on policy action, notably on CO2 pricing.” — Daily Oil Bulletin

Major pipeline expansion means more jobs in B.C.

Pembina Pipeline Corporation says that it has entered into bind-ing agreements to proceed with a $210 million expansion to its pipeline infrastructure in north-east British Columbia.

The pipeline will transport con-densate and natural gas liquids for various producers in the liq-uids-rich Montney resource play.

The project entails the con-struction of approximately 160 kilometres of up to 12-inch diam-eter 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 envi-ronmental approval, Pembina an-ticipates bringing the expansion onstream in the second quarter to fourth quarter of 2017 timeframe.

The expansion project is un-derpinned by a long-term, cost-of-service agreement with an an-chor tenant. volumes aggregated by the NEBC expansion will feed into Pembina’s Phase III pipeline expansion downstream of Taylor.

“Pembina has been actively en-gaging 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 look-ing 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 Pem-bina’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 Al-berta portion of the Western Ca-nadian Sedimentary Basin and are very excited to have the op-portunity to extend our service to our customers in B.C.,” he said.

“The project not only ben-efits our customers, it also ben-efits our investors as we are able to add additional value through our integrated service offering.” — Daily Oil Bulletin

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