PNN NOV 17 2017 by Pipeline News North

IN PHOTOS: The first reclaimed tailings pond, seven years later / 8 NOVEMBER / DECEMBER 2017

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Natural gas production surges to highest level in a decade, and becomes a lot more competitive in Ontario; Enbridge looks to lower emissions at McMahon; and getting to yes on Canada’s Northern Corridor BE PREPARED AND BE SAFE AT THE WORKPLACE WITH RIP’S CLEATS

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2017 FSJPA Christmas Party & Monthly Meeting Thursday, December 14 at 6:00 PM - 11:59 PM Tickets are for sale for $25.00 ea and spouses welcomed.

The tickets can be purchased in advance at Pimms, Epscan and Ditmarsia and remaining tickets will be sold at the door. We encourage members to buy tickets in advance. Please call the lido and book a booth or tables in advance. ONLY 150 Tickets available so please buy in advance if you can Elections for 2018 will also be held during the event

NOVEMBER 17, 2017

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COMMUNITY

Tourmaline hands local charities $28,000 boost It was a big day for two local charities on Nov. 1 as Tourmaline Oil Corp. handed the Fort St. John Hospital Foundation and the United Way of Northern BC $14,000 each to support their operations. The funds were raised through the company’s ninth annual golf tournament in July, where $28,000 was raised and the proceeds split evenly between the two charities. The donation to the Fort St. John Hospital Foundation kicked off the foundation’s annual Be An Angel campaign, where it hopes to raise $250,000 this holiday season to buy medical equipment needed at the hospital and Peace Villa care home. Tourmaline added the local United Way branch to its beneficiary list this year after learning its Calgary office supports the agency but that the dollars raised there only stay in that community. “We thought … we can do that for Northeast B.C., because it stays in B.C. and affects quite a few communities,” said Dee Kraeleman, office manager of Tourmaline’s branch in Fort St. John. “We wanted it to stay local. We have lots of issues in our city.” Monies raised for the United Way of Northern BC stay local to help supports 38 programs in the community, including programs

for children, those with disabilities, people in crisis, and seniors. Niki Hedges, United Way’s community development and campaign officer for the Northeast, called Tourmaline’s donation significant. “With the support from our donors we can be more effective in funding community programs and services,” Hedges said. “Every dollar counts to bring about lasting change.” Tourmaline raised $11,000 for the hospital foundation at its 2016 golf tournament. This year’s $14,000 donation gives the foundation a significant start to its ambitious campaign this year. “We are very excited to announce that already on the first day of the campaign, the foundation has received two significant donations towards this year’s Be an Angel,” foundation executive director Jennifer Moore said, noting another $3,059 donation from Chances casino. “Every donation and every dollar makes a difference.” The foundation will hold its Be An Angel gala on Nov. 18 at the Pomeroy Hotel. Learn more by calling 250-261-7563 or by visiting fsjhospitalfoundation.ca. Learn more about the United Way of Northern BC by visiting their website at unitedwaynbc.ca.

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Above: Leanne Bausman, Niki Hedges, Dee Kraeleman, Dorran Smith, Bonnie Green, and Marcel Ducharme with a big $14,000 cheque for the United Way of Northern BC.

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OUTLOOK

PNN

In situ oilsands to grow by at least one million barrels per day: NEB

MISSION STATEMENT Our mission at Pipeline News North is to provide the most current, interesting, and relevant news and information about the oil and gas industry in Northeast B.C. and Northwest Alberta. Have an interesting story to share or a news lead? Email us at editor@ahnfsj.ca.

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DEBORAH JAREMKO JWN Energy

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Despite lower oil prices and stricter restrictions on carbon emissions, in situ oilsands production is expected to grow by at least one million barrels per day between now and 2020, according to the National Energy Board. Canada’s energy regulator released its annual outlook report on Canada’s Energy Future, which examines three different paths the market could follow. Here’s a snapshot of what each of these looks like, and how the oilsands plays out. REFERENCE CASE • The NEB says its reference case is based on a current economic outlook, a moderate view of energy prices and climate and energy policies that have been announced at the time of analysis. • Brent oil pricing reaches US$75/bbl in 2022 and then averages US$80/bbl between 2026 and 2040. • The Canadian price for carbon is held at $50/ tonne between 2022 and 2040. • No new oilsands mining projects are built, and mining production stays flat at about 1.5 million bbls/d between 2020 and 2040. • In situ operators do not broadly implement steam/solvent processes. • In situ oilsands production increases from 1.4 million bbls/d in 2016 to 3.0 million bbls/d in 2040. • The average in situ steam to oil ratio (SOR), a key measure of efficiency, goes from 3.0:1 currently to about 2.25:1 • Oilsands production increases from 2.5 million bbls/d in 2016 to 4.5 million bbls/d in 2040. HIGHER CARBON PRICE CASE • This case assumes the Canadian price for carbon increases steadily by $5 per tonne per year after reaching $50 per tonne in 2022, to $90/tonne in 2030 and $140/tonne in 2040.

• Brent averages reaches US$75 in 2022 and then holds steady there to 2040. • No new oilsands mining projects are built and mining production stays flat at about 1.5 million bbls/d between 2020 and 2040. • In situ operators do not broadly implement steam/solvent processes. • The average SOR drops from 3.0:1 to about 2.25:1. • Oilsands production reaches 4.0 million bbls/d in 2040, supported by a 1.1 million bbl/d increase for in situ volumes, from 1.4 million bbls/d in 2016 to 2.5 million bbls/d in 2040. TECHNOLOGY CASE • The NEB’s final case considers, in addition to higher carbon prices, the impact on the Canadian energy system of greater adoption of select emerging production and consumption energy technologies. • This includes greater cost decreases for solar and wind electrical generating capacity, faster uptake of electric vehicles, greater electrification of space and water heating commercially and residentially, and increasing use of carbon capture and storage. • Brent reaches US$22/bbl in 2022 but then starts decreasing, approaching $60/bbl in 2040. • In this case, the NEB assumes that in situ oilsands operators increasingly implement steam/solvent processes. This actually results in slightly higher production than the middle case as bitumen production rates increase while natural gas consumption declines (exact figure not given). • Higher production is more than offset by lower SORs, with in situ oilsands energy demand 6.5 percent lower in 2040 than the higher carbon price case. • The average SOR goes from 3.0:1 currently to 2.0:1 in 2040. The NEB’s analysis assumes that “all energy production will find markets and infrastructure will be built as needed.”

NOVEMBER 17, 2017

PIPELINE NEWS NORTH •

OUTLOOK Ashford 30

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Canadian natural gas production surges to highest level in a decade DEBORAH JAREMKO JWN Energy

The flow of natural gas from Western Canada has reached rates not seen since April 2007, according to analysts with GMP FirstEnergy. Since the end of October, supplies from Alberta and British Columbia have grown by a combined 1.2 billion cubic feet per day, pushing total gas from western Canada near 17 billion cubic feet per day. “The surge that has been seen for natural gas supplies in Western Canada over the past few weeks is nothing short of remarkable,” GMP FirstEnergy said in a research note on Monday, attributing the rise to “the potent combination of new gas wellhead and gas processing capacity in the Montney and related plays, and accompanying pipeline capacity to move this gas to market.” The supply surge has resulted in the highest gas flows through the Empress export point on

Alberta’s eastern border in nearly three years, analysts wrote. There has also been an uplift in flows of about 1 billion cubic feet per day since the new long-term tolling agreement on the TransCanada Mainline took effect in November. The increased flow of gas through Empress appears to be benefitting AECO prices the most so far, GMP FirstEnergy noted, with AECO currently trading around $2.69/mcf, up from about $0.90/mcf a week ago. However, “AECO’s two pricing brethren in the Western Basin have yet to show real signs of an uplift given the full capacity on related pipelines leaving the region for those pricing points,” analysts noted. “Station 2 prices continue to struggle under C$1/mcf, while prices at the Alliance ATP have staged some recovery, but have generally held under C$2 per mcf. More cold weather and deeper storage withdrawals in B.C. are going to be required to generate more recovery for these two price markers.”

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NOVEMBER 17, 2017

OPERATIONS

Compressor upgrades at McMahon would lower emissions MATT PREPROST editor@ahnfsj.ca

Enbridge plans to upgrade halfcentury old, obsolete technology at its McMahon processing plant in Taylor. The company, which acquired Spectra Energy in 2016, is looking to replace six reciprocating engines with two turbine engines as part of its Compressor Station 1 Modernization project. The turbines would replace original engines first installed at the plant in 1957. “The benefit is it will lower emissions while still moving the same volume of gas, lower our maintenance, and improve system reliability,” said Mike Greenway, Enbridge’s area leader for Fort St. John, during an open house in Taylor Oct. 26. Station 1 compresses and moves roughly 500 million cubic feet of gas per day into the McMahon plant for processing before it’s sent back to the station as marketable gas, where it’s compressed again and shipped through sales pipeline networks across B.C. and Alberta. The station uses natural gas to fuel its engines and compression operations. However, the reciprocating units work much like a car engine, explained April Hauk, a senior atmospheric environmental specialist working on the project for Stantec Consulting, with fuel and oxygen thrown into the mix at inconsistent levels. High emissions are the result of high combustion temperatures,

ENBRIDGE

and the new turbines will give the plant better control of the combustion for a “leaner burn” that could cut emissions by up to 50 per cent, she said. “You can control the temperature of combustion better and reduce

your emissions,” she said. Enbridge says the emissions decrease will be “substantial,” but that it won’t know the full impact until emissions modelling is complete. The company still has to sanction

the project, and it expects to file an application to the National Energy Board by the end of November. If approved, work would begin next summer or fall, with the new engines expected to come into service in late 2019.

How ARC Resources plans to spend $690 million in 2018 ARC Resources is budgeting investment next year to keep its plants full and position itself for further production growth in 2019. The Montney-focused company has announced a $690 million capital program for 2018. This compares to $830 million in 2017, which was revised upward midyear from an initial $665-million plan. Approximately $565 million of the 2018 program will be spent on ARC’s northeast British Columbia Montney assets. The 2018 budget is “a continuum”

of the work the company has being doing in 2017, according to CEO Myron Stadnyk. This year ARC completed the largest facility construction in its history, the $250 million Dawson Phase 3 natural gas and liquids plant, which has processing capacity of 90 mmcf/d of natural gas and 7,500 bbls/d of liquids. The project was completed ahead of schedule in mid-June. As a result, ARC’s production increased in the third quarter of 2017 to 129,526 boe/d, up from 115,129 boe/d in the second

quarter. “Think of 2018 as really reducing the capital from 2017, from $830 million down to $690 million but still funding the next growth initiative, which is the Sunrise expansion,” Stadnyk says. ARC is currently building its Sunrise Phase 2 facility, which is expected to add 180 mmcf/d of natural gas processing capacity in mid-2019. On the natural gas liquids side, Stadnyk said the focus will be on a “material project” at Attachie, an early stage property where a pilot

was conducted in 2017. In all, ARC plans to drill 64 wells in 2018 including 16 crude oil wells at Tower and Ante Creek and 46 liquids-rich natural gas and natural gas wells primarily at Sunrise, Dawson, Parkland, and Attachie. ARC expects 2017 production to stay flat near 130,000 boe/d. The company reported net income of $48.5 million for the third quarter of 2017, up from $28.3 million in the 2016 period. —JWN Energy

NOVEMBER 17, 2017

PIPELINE NEWS NORTH •

OUTLOOK

Western Canada’s gas just got a whole lot more competitive in Ontario DEBORAH JAREMKO JWN Energy

Just in time for the winter heating season, TransCanada says that additional natural gas volumes secured through a new lower-priced shipping agreement are now flowing on its Mainline from Empress, Alta. to Dawn, Ont. It is the successful conclusion of a proposed reduced toll agreement to get Western Canadian volumes to their large legacy market in Eastern Canada; high transportation costs had left the system operating under capacity and the area increasingly saturated by growing US production from the Marcellus and Utica plays. Previously it cost about $2.00/ GJ to transport natural gas on TransCanada’s system from Alberta to Ontario. In October 2016, TransCanada proposed to drop tolls to a range of $0.75/GJ to $0.82/GJ, but that didn’t get

enough support from producers to move forward. The company then proposed a simplified single toll rate of $0.77/GJ in February 2017, which was accepted by shippers. The National Energy Board approved the toll agreement in September following a hearing where the Canadian Association of Petroleum Producers argued that without the deal, the future of Western Canada’s natural gas industry would be in jeopardy. Shippers under the deal have agreed to long-term contracts that will transport 1.5 billion cubic feet per day, which is enough natural gas to heat more than six million North American homes daily, TransCanada noted in a statement. “With the growth of natural gas production in the WCSB, TransCanada is [also] working closely with our partners to continue to expand pipeline capacity to get their natural gas to market.”

DARCY SHAWCHEK PHOTOGRAPHY

Growing interest in Canada’s liquids-rich natural gas boosts 2018 drilling forecast The cautious optimism and uptick in activity that led two increases in Canada’s drilling forecast for 2017 is carrying through to 2018, according to the Petroleum Services Association of Canada (PSAC). PSAC released its projections for next year, forecasting a total of 7,900 wells to be drilled in Canada in 2018 compared to its revised estimate of 7,550 wells for 2017. The 2018 forecast is based on crude oil prices of US$53/barrel (WTI), average natural gas prices of C$2.50/ mcf (AECO), and the Canadian dollar averaging US$0.82. “Budgets set with initial optimism for a gradual climb in prices by yearend continue with their plans as drilling and completion efficiencies improve,” PSAC president Mark Salkeld said in a statement. “Due to pressure to stay low, costs for services continue to be suppressed, affording better margins for producers. For 2018, confidence

that oil will stay in the low-to-mid US$50 range as markets tighten and inventories reduce, along with growing interest in Canada’s vast liquids rich natural gas, should support a 4 - 5 per cent increase in activity levels.” PSAC noted that while activity is expected to increase next year, it will still be down about 30 percent from 2014. “The cancellation of TransCanada’s Energy East pipeline is another blow to investor confidence in Canada and so PSAC will continue to advocate hard for market access and a competitive environment,” Salkeld said. “The world’s energy needs are growing and polls show that countries would prefer Canadian oil and gas that is responsibly-developed and working to reduce carbon emissions through innovation.” —JWN Energy

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NOVEMBER 17, 2017

ENVIRONMENT

What the first reclaimed oilsands tailings pond looks like, seven years later DEBORAH JAREMKO JWN Energy

In 2010, Suncor Energy became the first oilsands mining operator to successfully reclaim a tailings pond to a solid surface. It was, in fact, the first tailings pond in the industry, opened along with the original operations of Suncor predecessor Great Canadian Oil Sands in 1967 Tailings ponds are essential to the oilsands mining industry’s waterbased extraction process, according to the Alberta Energy Regulator, as they act as both holding basins from which process water can be recycled and as settling basins where solids can be separated from tailings. But the ponds occupy a large surface area and are a main concern of environmental groups opposed to oilsands development. Tailings ponds currently occupy more than 170 square kilometres of the mineable oilsands region in northern Alberta. For Suncor, Tailings Pond 1 became Wapisiw Lookout, named for the Cree who first introduced bitumen to European settlers. It was officially opened in a ceremony in September 2010 that included blessings from local First Nations leaders and greetings from thenpremier Ed Stelmach. “This is a day that many of us have been looking forward to, and I’m extremely pleased to see it come to fruition,” the late Rick George, former Suncor CEO, said at the event. “Once surface reclamation is complete, this 220-hectare area will be transformed into mixed wood forest and small wetland capable of supporting a variety of plants and wildlife. And then, over the next two decades, we will closely monitor progress on the site.” It’s now been seven years since the opening of Wapisiw Lookout, and the company is pleased with its progress. It is unlikely that the site will be returned to the Government of Alberta, officially certified reclaimed and opened for public access in the near term, Suncor says, because it is inside the gates of its base plant and in close proximity to its ongoing operations. Here’s a look at the transition from Tailings Pond 1 to Wapisiw Lookout, after seven years of growth.

Above: Tailings Pond 1 in 2002. Below: Wapisiw Lookout in 2010

SUNCOR ENERGY

NOVEMBER 17, 2017

PIPELINE NEWS NORTH â&#x20AC;¢

ENVIRONMENT

DEBORAH JAREMKO

Wapisiw Lookout in September 2017.

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NOVEMBER 17, 2017

OPERATIONS Chevron pushes go on Duvernay development

Chevron is moving ahead with commercial development on its Duvernay shale acreage, six years after commencing exploration activities in the play. The company says the Duvernay — an early-stage liquids rich natural gas resource in west-central Alberta — is “considered one of the most promising shale opportunities on the continent.” Chevron says the initial development will take place at East Kaybob, on about 55,000 of the 330,000-acre Duvernay position it shares with KUFPEC Canada Inc., a subsidiary of Kuwait Foreign Petroleum Exploration Company. Chevron owns 70 percent of the partnership and is the operator, while KUFPEC holds the remaining 30 percent. The program will utilize long-term infrastructure development and service agreements with Pembina Pipeline Corporation and Keyera

Corporation, with service expected to be available during the second half of 2019, Chevron says. Pembina also announced that it will construct and operate $290 million of Duvernay infrastructure under an agreement with Chevron. This includes Duvernay II, a replica of Pembina’s existing Duvernay facility. Chevron commenced an exploration program in the Duvernay in 2011, subsequently drilling 16 horizontal wells and completing 13 wells using multi-stage hydraulic fracturing, it says. “In the second half of 2014, Chevron commenced a pad drilling program to evaluate well production rates and reservoir performance. Drilling continued during 2016 on an appraisal and land retention program. A total of 53 wells had been tied into production facilities by early 2017,” the company says. —JWN Energy

Tidewater to proceed with new $210M Montney plant Tidewater Midstream says that it will proceed with a new gas plant near Grande Prairie, Alta. with processing capacity that is tailored for the region’s liquids-rich Montney natural gas production. The project has an estimated capital cost of approximately $210 million. Located in the Pipestone area, the 100 MMcf/d sour gas plant will have acid gas injection and 20,000 bbls/d of NGL processing capability, as well as an extensive gathering pipeline network, the company says. The project will have two anchor

customers with five-year take-orpay agreements for up to 55 percent of plant capacity. Tidewater says that it is finalizing commitments from “several other producers” for the remaining plant capacity, and that “due to significant interest” it is considering a phase two expansion. The company says the project is expected to have one of the highest operational onstream times in the area, regardless of regulated pipeline outages, due to storage access. Operations are targeted to start up in mid-2019. —JWN Energy

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Trade tariffs punish Canadian LNG STEVEN CHUA Squamish Chief

Liquefied natural gas proponents are speaking against a federal anti-dumping tariff that they say could stifle the industry’s growth in Canada. Dumping refers to when manufacturers export a product to another country at a price below the normal price. At question is a ruling made in May by the Canadian International Trade Tribunal that found the dumping of some goods from China, Korea, and Spain have had a negative impact on Canada’s economy. As a result, anti-dumping fees have been imposed on fabricated industrial steel components from those countries. These tariffs could reach up to 45.8 per cent. Fabricated industrial steel components, also known as FISC, include parts that are needed to construct LNG facilities. The BC LNG Alliance declared imposing fees on FISC from foreign countries will hurt Canadian LNG ventures, as it is necessary for local industry to import these parts. “There are no Canadian

manufacturers able to manufacture the large complex modules required by Canada’s LNG sector,” an alliance representative said. “In order to proceed, LNG projects in B.C. cannot face additional costs that our competitors do not.” Woodfibre LNG, a member of the alliance, has expressed similar concerns. “As a member of the BC LNG Alliance, Woodfibre LNG is working with government to address some competitiveness issues,” wrote spokesperson Jennifer Siddon. “Competitiveness issues are barriers to B.C. LNG projects that LNG projects in other jurisdictions are not facing, which is why new projects are being built in other jurisdictions even when natural gas prices are down.” The tariff imposed will vary depending on a number of factors. The Canada Border Services Agency said exporters that fully cooperated with investigations will not be hit with dumping penalties. The anti-dumping duty will only apply if the normal value is greater than the price of goods imported into Canada, an agency representative said.

OGC takes action on seven dams Following more recent inspections of dams used by the oil and gas industry in northeast British Columbia, the BC Oil and Gas Commission has issued three compliance orders to ensure they are safe and pose no threat to the environment. The commission found there were no incidents of failures or release of water or sediment from any dams. However, some emerging issues were noted at seven sites, and Orders were issued to three companies. One order was issued to Nexen Energy, requiring the company to remove all live water storage at four dams, approximately 130 kilometers north of Fort Nelson. The inspection found that some of its dams displayed

slumping, surface erosion and surface water channel erosion. Saguaro Resources was issued one order to remove all live water storage at two dams, approximately 140 kilometres northwest of Fort St. John. The inspection determined that one of its dams displayed slumping inside the berm, pooling water and erosion. Conoco-Phillips was issued one order to remove all live water storage at one dam, approximately 110 kilometres northwest of Fort St. John. The inspection found that the dam displayed surface erosion. All three companies have until December 15, 2017 to comply with the orders. —BC Oil and Gas Commission

NOVEMBER 17, 2017

PIPELINE NEWS NORTH •

LNG

Did China just blow B.C.’s LNG hopes out of the water? NELSON BENNETT Business in Vancouver

Just three and a half months after Petronas and its partners pulled the plug on a $36 billion liquefied natural gas project in B.C., one of the partners has reappeared in Alaska. And what Sinopec has planned for Alaska could blow B.C.’s LNG ambitions right out of the water, if it ever gets a final investment decision, according one industry analyst, because it could sew up the market in China for LNG that B.C. projects were hoping to capture. On Wednesday, November 8, Alaska Gasline Development Corp. – a state-owned entity – announced a joint development agreement that would see Chinese companies and banks partnering in a US$43 billion LNG project in Alaska. The ALASKA LNG announcement coincided with The Alaska LNG project would require a 1,200-kilometre pipeline to bring gas from Alaska’s North Slope to Cook Inlet. U.S. President Donald Trump’s visit to China. The Chinese partners include Shell-led LNG Canada, have touted The Alaska LNG project would Shaffer said. “I don’t see them as China Petrochemical Corp. the so-called “B.C. advantage” require a 1,200-kilometre pipeline having an issue with scale. (Sinopec), which held a 15% stake in when it comes to developing an to bring natural gas from Alaska’s “Rather, I think it’s more likely this the now-dead Petronas-led Pacific LNG industry here, compared with North Slope to a three-train LNG is a sign they’re now buying North NorthWest LNG project. American competitors on the Gulf plant in Nikiski in Cook Inlet. American LNG as part of a bigger The financing partners include Coast. Building the pipeline would be strategy. I wouldn’t be surprised to the China Investment Corp. – a Those advantages include an costly, Shaffer said, due to the higher see movement on LNG Canada in sovereign wealth fund with US$800 ocean of gas in northeast B.C., costs of working in the remote the not-too-distant future.” billion in deployed investments – short shipping distances to Asia, north, and the lack of ancillary Traya doesn’t think Canadian and the Bank of China. and a cold climate, which reduces infrastructure that would need to be projects can compete with Alaska “As the most internationalized the energy input costs for chilling built – roads, processing plants, and LNG, however, because the project bank in China, Bank of China is natural gas to minus 160 Celsius. feeder networks, all of which B.C. would have the Government of willing to facilitate the China- Alaska has those same advantages. already has. Alaska as an equity partner, whereas U.S. energy cooperation and The B.C. advantage does not Traya disagrees. He said he in B.C. the government’s main role provide financial solutions for this appear to be sufficient to keep expects the pipeline would be built has been as a would-be tax collector. transaction by taking advantage of major energy players interested with Chinese steel, which would He said the former Liberal its vast experiences and expertise in B.C. Asian energy companies, reduce the costs. government made a fatal mistake in international mega-project including Chinese companies, have “I can assure you that the need when it signaled to the industry that financing,” the Bank of China said been voting with their feet. for U.S.-made steel for this project it was viewed as a cash cow, and in a joint press release. In mid-September, just two is not going to matter,” he said. “It’s established a special LNG tax that The project also has the backing months after Petronas announced going to be all Chinese steel, valves LNG producers don’t face in other of the Alaskan government, which it was pulling the plug on its and engineering.” countries. would have a 25% stake in the Pacific NorthWest LNG project in The American Energy Information “Why did all the B.C. advantage project through the government Prince Rupert, Nexen, owned by Administration (EIA) predicts China dwindle? It dwindled because of owned Alaska Gasline Development China’s CNOOC Ltd. (NYSE:CEO), will account for more than a quarter the rent-seeking behaviour of the Corp. announced that it too was done of the global growth in LNG demand province,” Traya said. “They’ve taken an equity stake,” with B.C., and called a halt to the out to 2040. “How did the Alaska project – said Jihad Traya, manager of feasibility study that had been Its current imports of 3.5 billion which was really out there and never natural gas consulting for Solomon underway on its Aurora LNG plant cubic feet per day (bcf/d) are thought to be a consideration – how Associates. “It takes away all that on Digby Island. projected to grow to 11 bcf/d by did that become viable? It tells you agency issue and all that other Blake Shaffer, a former director of 2040, s China tries to move off of how much fumbling and missteps discussion around LNG taxes and energy trading for Transalta Corp., coal power. Shaffer said the Alaskan happened in B.C. where companies fiscal certainty. You’ve now created now at the University of Calgary’s LNG plant, if built, would supply 2.5 are jumping and bailing on their fiscal certainty.” Department of Economics, said the bcf/d. projects. So not only does the project agreement announced is far from a He points out that B.C. projects “The B.C. government needs to have the financial backing of one done deal. It is not much more than also have Chinese partners. get its head up out of the sand and of the world’s biggest banks, and a memorandum of understanding. PetroChina, for example, is one of realize if it doesn’t provide fiscal a government equity partner, it Although he agrees Alaska has the partners in the LNG Canada certainty and potentially an equity also has all of the advantages B.C. some of B.C.’s advantages, he said project. stake in LNG, it doesn’t have a boasted. the project’s costs would be much “I don’t see China buying (Alaska) project.” LNG advocates, including the higher than any project in B.C. LNG as a substitute for BC LNG,”

• PIPELINE NEWS NORTH

NOVEMBER 17, 2017

INFRASTRUCTURE

Canada’s Northern Corridor: The National Dream 2.0 $100 billion, 7,000-kilometre multi-modal right-of-way a nation-building enterprise NELSON BENNETT Business in Vancouver

China has its $900 billion Belt and Road Initiative; Saudi Arabia has its $500 billion Neom megacity project. So what does Canada have in the way of a new nation-building exercise? It’s called the Northern Corridor—an ambitious $100 billion plan to connect Canada’s far and near north to the rest of the country with a 7,000-kilometre multi-modal right-of-way that would blaze a path for new roads, railway lines, pipelines, power transmission lines and telecommunications. More than just an infrastructure project, however, it is being described as a potential starting point for a new era of reconciliation with First Nations, because it could not be built without their consent and participation. According to a feasibility study published by the University of Calgary’s School of Public Policy, each link would end at tidewater: Prince Rupert, Churchill (Hudson Bay), Mackenzie River basin (Northwest Territories), the Saint Lawrence Seaway and northern Labrador. An idea that has been around for decades, the Northern Corridor got support this summer from the Senate Standing Committee on Banking, Trade and Commerce, which recommended the federal government earmark $5 million for further study. It also recommended that two of the six proposed links should be given priority: the B.C. link, which would connect northern Alberta to Prince Rupert, and a new right-of-way connecting northern Saskatchewan and Manitoba’s Port of Churchill. “The most critical access in the short term would be to the West Coast and the Hudson Bay because of their proximity to growing and increasingly open Asian and European markets,” the committee recommends. The Northern Corridor would bring infrastructure to northern and First Nations communities and ease pressure on the major ports of Vancouver and Eastern Canada by providing more tidewater access to foreign markets for Canada’s major exports: grain, lumber, minerals and oil and gas. “If you look back through the economic history of Canada, when it comes to transportation, we’re in some ways economically a country that’s built on these big infrastructure projects,” said study co-author Garret Kent Fellows. He pointed to projects like the Canadian Pacific Railway, the Saint Lawrence Seaway and TransCanada Highway as examples. The proposal would require senior government investments in the negotiation of the rights-of-way and the building of public roads and utilities, with other infrastructure – pipelines and railways,

U OF CALGARY SCHOOL OF PUBLIC POLICY

The Northern Corridor would create new right-of-ways through Canada’s far and near north, all ending at tidewater.

for example – built by the private sector. Canada has been busy negotiating free trade agreements with the European Union, South Korea and other trading partners. But Fellows said Canadian ports, like Vancouver’s, are already becoming congested. Currently, almost half of all exports in Canada (48%) move through B.C. ports. “Those free trade agreements are great, but if we don’t have the physical capacity to get our goods to those markets, you’re really not going to capitalize on this negotiation work that we’re doing to secure the free trade agreements. The Port of Metro Vancouver is a very important port to Canada, but it’s also a port that’s running out of land. If you’re looking to expand that port, it’s really hard to do it. Further up the coast, Prince Rupert, you don’t have that problem.” Should the federal government approve the Senate committee’s recommendations, it would earmark $5 million for a more detailed series of studies by the School of Public Policy and Quebec’s Center for Interuniversity Research and Analysis of Organizations. These studies would address issues like the environmental and engineering challenges of building new roads and railways on permafrost. The recent failure of multibilliondollar oil and liquefied natural gas projects in B.C. highlight how difficult it can be to build greenfield transmission projects in Canada. Such projects might be easier to get approval for if they followed a right-of-way established by senior government – a process that would deal with environmental and First Nation issues up front.

“In our scoping study, we stress the idea of a multi-modal right-of-way,” Fellows said. “So you establish your right-of-way, you do all your negotiations ahead of time, and then we sort of have this idea of where the backbone will be, when we get to the point where either you’ve got public funds to fund infrastructure or, in some cases, private projects, like a rail line.” Negotiating such a right-of-way could be done as part of a broader First Nation reconciliation exercise. First Nations have argued that the current environmental review process for projects like pipelines focuses only on project-specific impacts and does not properly consider cumulative impacts. Establishing new rights-of-way could address some of those concerns. “They’ve got claims to a lot of land,” said Sen. Dave Tkachuk, who chairs the Senate standing committee. “Why don’t we just solve this problem and say, ‘Well, let’s be partners through all of this?’” The B.C.-based First Nations Major Projects Coalition (FNMPC), which includes members from 37 B.C. First Nations, has taken no position on the Northern Corridor, but told the Senate committee earlier this year that the project would need to involve First Nations from the outset. “The message that [First Nations have] said loud and clear in the last couple of years is ‘Involve us right from the beginning,’” Corrina Leween, chief of the Cheslatta Carrier Nation, told Business in Vancouver. “Maybe this is a good thing for the economy of the people that live there. At the same time, maybe it is not a good idea.”

NOVEMBER 17, 2017

PIPELINE NEWS NORTH •

PIPELINES

Cenovus ready to ship more crude by rail as pipeline squeeze looms DEBORAH JAREMKO JWN Energy

JOEY PODLUBNY/JWN ENERGY

Bruderheim, Alta. “Cenovus is very well positioned in the event that it does take longer than we would certainly like, and the industry needs, for pipelines to come on board. At the current differentials we are moving volume out of our Bruderheim terminal, and we are staffed for fairly significant growth if we see a really robust opportunity. At this point we haven’t seen an uptick... but we do see that day coming.” Cenovus acquired the

Bruderheim terminal from Canexus Corporation in September 2015 for $75 million. Located about 50 kilometres northeast of Edmonton, the terminal offers strategic value due to its connections to the Cold Lake and Access pipeline systems, as well as its links to the rail lines of both Canadian Pacific Railway Limited and Canadian National Railway Co. Cenovus started moving oil through the facility in 2014.

Canadian crude by rail volumes averaged about 127,000 bbls/d from January to July 2017, according to the latest data from the National Energy Board. Traffic peaked in September 2014 at 178,000 bbls/d; at the time, the WTI-WCS differential averaged about US$16/bbl. The NEB estimates there is approximately one million bbls/d of crude by rail transloading capacity in Canada.

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Thermal oilsands heavyweight Cenovus Energy is prepared to increase the amount of oil it ships by rail in expectation of a coming widening of the price spread between Canadian heavy oil and US light benchmark WTI. The spread between WCS and WTI, which is currently about about US$13/bbl, has tightened over recent months on stronger demand for Canadian heavy, but Cenovus does not expect this to last as production from Alberta grows. A key factor will be the start up of Suncor Energy’s new Fort Hills oilsands mine, which will come onstream before year-end and is expected to be operating at 90 percent of its 194,000 bbl/d capacity by October 2018. “We have seen some strength in WCS heavy crude due to activity on a larger global sale, but as production comes online we do expect a widening of WCS-WTI over time until more pipe comes on,” Bob Pease, Cenovus’s president, downstream told an analyst call. He added that there is likely to be an increase in crude-by-rail traffic as a result, including from Cenovus by way of its terminal at

• PIPELINE NEWS NORTH

NOVEMBER 17, 2017

IN BRIEF

Feds award $5.3M to projects aimed at methane cuts The federal government has announced an investment of $5.3 million for seven projects aimed at tackling methane emissions from Canada’s oil and gas sector. The industry is the country’s largest emitter of methane, which accounts for about 15 percent of Canada’s GHG emissions. Ottawa says it is partnering with Clearstone Engineering, the Alberta Energy Regulator, Petroleum Technology Alliance Canada, the University of British Columbia and the University of

Calgary to support research aimed at improving our ability to detect methane leaks, improve emissions reporting and enhance efforts to reduce emissions in oil and gas production. “These investments will help Canada meet its target of reducing greenhouse gas emissions by 30 percent below 2005 levels by 2030 and create well-paying jobs for middle-class Canadians,” Natural Resources Canada said in a statement. The projects are being funded through Natural Resource Canada’s Clean Energy Innovation Program, which received $25 million over two years to accelerate clean technology development. —JWN Energy

CNRL leads oil sector R&D spend At over half a billion dollars in research and development investment in 2016, Canadian Natural Resources Limited was in a league of its own among energy sector R&D investors and the fourth biggest corporate research spender in Canada. Canadian Natural’s $558 million was close to triple the next largest spender in the energy sector, Suncor Energy Inc., which invested $200 million, according to Research Infosource Inc., which released its annual corporate R&D spending

ranking this week. Imperial Oil Limited was a close third at $195 million, followed by Cenovus Energy Inc. at $69 million and Syncrude Canada Ltd. at $62 million. Pipeline companies TransCanada Corporation ($23 million) and Enbridge Inc. ($18 million) placed 71 and 86 respectively in the top 100 list. Other notable oil and gas industry companies in the top 100 include software companies Pason Systems Inc. ($23 million, 74th overall), Computer Modelling Group Ltd. ($18 million, 85th) and services companies Trican Well Services ($15 million, 94th) and Canadian Energy Services & Technology Corp. ($15 million, 95th

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• Distributed to the community in general through these ﬁne publications, Alaska Highway News, Dawson Creek Daily and Fort Nelson News. • Distribution by mail and direct drop-off to Oil & Gas companies,and related businesses and organizations, in the following communities: BRITISH COLUMBIA – Arras, Baldonnel, Cecil Lake, Charlie Lake, CHETWYND, Clayhurst, DAWSON CREEK, Farmington, FORT NELSON, FORT ST. JOHN, Goodlow, Groundbirch, HUDSON HOPE, Moberley Lake, Pink Mountain, Pouce Coupe, Progress, Rolla, Rose Prairie, Sunset Prairie, Taylor, Tomslake, TUMBLER RIDGE, and Wonowon. ALBERTA – Baytree, Bear Canyon, BEAVERLODGE, Berwyn, Bezanson, Bonanza, CLAIRMONT, Eaglesham, FAIRVIEW, Falher, Girouxville, GRANDE PRAIRIE, Grimshaw, Grovedale, HIGH PRAIRIE, Hines Creek, Hythe, LaGlace, MANNING, McLennan, PEACE RIVER, Rycroft, SEXSMITH, Silver Valley, Spirit River, VALLEYVIEW, Wembley, and Worsley, Zama City.

NOVEMBER 17, 2017

PIPELINE NEWS NORTH •

IN BRIEF

Methane plan can cut emissions by 45%, protect 7,000 jobs: CAPP The Government of Alberta has committed to reduce methane emissions by 45 per cent. Industry has a competitive plan to achieve this commitment in the most efficient way that will protect 7,000 jobs and balance environmental and economic priorities, according to an analysis conducted by the Canadian Association of Petroleum Producers (CAPP). The Alberta government and the oil and natural gas industry must work collaboratively to reduce methane emissions by 45 per cent by 2025 from 2014 levels through: 1. Creating an approach that stimulates the use of innovation and technology; 2. Recognizing early action on methane reductions by the oil and natural gas industry; 3. Establishing risk-based cost-effective methods aimed at decreasing venting and detecting leaks faster; 4. Adopting a continuous improvement

approach at new operating sites; and 5. Leveraging a fleet average approach to achieve reduction targets. This made-in-Alberta solution would cost the oil and natural gas industry $700-million over 8 years, but would result in the most competitive approach. It will prevent the cumulative loss of nearly 7,000 jobs from a prescriptive approach, see $710 million in capital reinvested in Alberta’s economy and boost our gross domestic product by $2.5 billion. This flexible approach will achieve the emissions reduction target, prevent inefficiencies in its application and minimize the impact on Alberta’s economy. “Canada is already leading in front of the United States on methane reductions – and with smart action can protect the environment and jobs for Albertans,” CAPP President and CEO Tim McMillan said.

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