PNN JULY 2017 by Pipeline News North

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Canada late to global LNG party, but opportunity still ahead, NEB says; University study finds fracking rarely linked to felt seismic tremors; New BC NDP government sworn in, cabinet named; $9.7-billion Pembina-Veresen merger charges ahead; and Oilmen hit the gun range for their annual trapshoot

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FORT NELSON OILMEN’S GOLF TOURNAMENT this weekend (August 16-19th)

FSJPA SePtember monthly meeting Thu 5:00 PM UTC-07 · North Peace Rod & Gun Club · Charlie Lake

JULY 21, 2017

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OILMEN’S

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David Gosling takes a shot July 8 at the 2017 Fort St. John Oilmen’s Trapshoot.

Mikkelson, Rapid Wireline take top spots at trapshoot DILLON GIANCOLA sports@ahnfsj.ca

Despite a dip in attendance, the 2017 Fort St. John Oilmen’s Trapshoot was a great time of shooting for newcomers to the sport and seasoned veterans. Fifty-three shooters took part in the competition, held at the North Peace Rod and Gun Club on July 8 and 9. The event got off to a bit of a rough start as the July 7 practice session was cut short due to a storm. Shane Stirling, chairman of the Oilmen’s Trapshoot, said almost everybody was able to get the shooting in that they wanted to. The July 8 events went all day with great weather to match. A new format was featured this year as 25 handicap shots were added to the 100 rounds each shooter shot, resulting in stiffer competition. Competition was indeed really close this year, as most of the awards were decided by two shots or less. Tyler Mikkelson won the high overall category with a score of 117, just two shots ahead of Luc Chretien. Terry Wilson won the

high senior category, while Stephen Forest had the dubious honour of being the low overall winner. For the teams, Rapid Wireline won by one shot over Twylight Pressure Controls. There were also six singles divisions, with awards handed out to the winners of each one. This was Mikkelson’s second time winning the trapshoot. “I think I shot well, and I’ve generally done pretty well here,” he said. The tournament was really well run this year, from the meals to the organizers and sponsors, he said. Mikkelson especially liked that newcomers show up and try their hand at the sport. “It’s really inclusive,” Mikkelson said. “There’s a bunch of people that have been doing it for many years and a lot of newcomers, so spirits were really high and everybody had fun. People get into trapshooting just for the oilmen’s trapshoot and stay with it afterwards.” Mikkelson is looking forward to having more shooters next year and continuing the growth of the event.

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Canada a ‘late entrant’ to global liquefied natural gas market: NEB Canada may have missed the boat on the first wave of opportunity to develop LNG export projects, but it could beat its biggest competitor for a slice of the second. The global LNG supply/demand balance is expected to tighten around 2020-21, which is when the National Energy Board (NEB) expects Canadian exports from the B.C. coast will join the market. It is here where Canada could take the lead from the United States, the NEB said in a report released on July 18. “Canada has the opportunity to become an LNG exporter before U.S. west coast projects. At this point, no U.S. west coast project has reached a final investment decision,” the NEB said. While Canadian west coast LNG projects may have some advantages, the NEB acknowledged the challenges they face. “Disadvantages facing Canadian projects include high costs to develop projects in remote locations with limited infrastructure, and, where the construction of new pipelines is required to supply the necessary gas. With LNG prices falling in recent years, the margins needed to justify this type of capital-intensive development have eroded. Increased competition has also made it difficult for Canadian projects to sign long-term supply contracts,” the board said. There are 24 LNG projects proposed in Canada, with 18 of these located on the B.C. coast. One of the B.C. projects—the relatively small scale (2.1 million tonne per annum) Woodfibre LNG project near Squamish—is the only Canadian project to have received corporate sanction. “There are more proposed LNG projects on the West Coast than on the East Coast. This is because there is significant gas supply

in northeast B.C. and Alberta and many of the largest LNG project proponents are also gas producers in western Canada aiming to maximize the value of their producing assets by seeking alternate markets. Secondly, the West Coast is a shorter distance to the primary target market of Asia,” the NEB says. “Most of the proposed projects in the U.S. are located along the Gulf of Mexico. However, the Jordan Cove project is located along the U.S. West Coast and would compete with Canadian west coast projects with respect to proximity to Asian markets.” The proposed six million tonne per annum Jordan Cove project is located within the Port of Coos Bay, Oregon, owned by the Calgarybased merged new combination of Veresen Inc. and Pembina Pipeline Corporation. It has yet to receive regulatory approval, although in February the Federal Energy Regulatory Commission (FERC) cleared the way for it to move through the process by approving its pre-filing application. While corporate sanction for the Woodfibre project is in place and early site work has commenced, construction is not yet underway. In October 2016 the privately-held Canadian project proponent awarded two parallel contracts for project front end engineering and design, one to KBR and the other to JGC America. At the time, Woodfibre said the FEEDs were expected to take eight months, after which it would award the construction contract. “Canada is a late entrant to global LNG markets and the next several years will be critical to the development of the Canadian LNG industry,” the NEB said. —JWN Energy

LNG Canada seeks export extension The National Energy Board (NEB) has established a comment period after LNG Canada Development Inc. applied to extend the expiration date for commencement of export from Dec. 31, 2022 to Dec. 31, 2027. On May 18, 2017, the NEB received an application from LNG Canada for an extension of the expiration date established by Condition 3 of Licence GL-330, which was issued by the board on May 27, 2016. LNG Canada stated that the requested extension constitutes a request to shift the timeframe over which exports would occur rather than a request for an extended licence term and attendant increased term export volume relative to that approved by the licence.

“The board wishes to obtain the views of parties to the original decision, and has therefore decided to establish a comment period,” the NEB stated. “The board directs LNG Canada, to serve for comment, a copy of its 18 May 2017 application on Atlantic Pacific Spaceline Enterprise Incorporated (APSE), by noon (Calgary time) on 25 July 2017,” the NEB stated. APSE must file comments with the board by noon (Calgary time) on Aug. 1, 2017. After reviewing the comments, the board may issue its ruling on this matter or have further process to deal with the request. —Daily Oil Bulletin

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LNG

WOODFIBRE LNG PHOTO

While crews have been busy cleaning up the Woodfibre LNG site, there is also a lot of work underway behind the scenes on the project. Two world class LNG engineering and design companies KBR, Inc. (KBR) and JGC America, Inc.(JGC) which are both based in Houston, Texas, are working on the Front End Engineering Design (FEED) of the Woodfibre LNG Project. Once FEED is complete, the next step is for KBR and JGC to develop proposals for an Engineering, Procurement and Construction contract for the Woodfibre LNG Project. Once that step is complete, a contract to build the Woodfibre LNG facility will be awarded, and construction can begin.

Woodfibre LNG Environmental Certificate Amendment Application Approved Woodfibre LNG Limited announced July 12 that its application to amend its Environmental Assessment Certificate (EAC) for the construction and operation of the Woodfibre LNG Project has been approved. The EAC was originally granted on October 26, 2015. Woodfibre LNG Limited applied to amend its EAC in early 2017 to address proposed design changes to the Woodfibre LNG Project. The proposed design changes were the result of the Squamish Nation selection of air cooling as the cooling technology for the Project as well as ongoing front-end engineering design (FEED) work. The design changes include: • Changing from seawater cooling to air cooling of the plant; • Upgrading an existing intake on Mill Creek rather than constructing a new intake; and, • Short-term use of water from Woodfibre Creek during construction. The design changes required an amendment to the EAC under British Columbia’s Environmental Assessment Act. “The amendment approval means Woodfibre

LNG can implement the design changes that are a direct result of the Squamish Nation process, and ongoing FEED work,” said Byng Giraud, Country Manager & Vice President, Corporate Affairs, Woodfibre LNG Limited. “We also see the approval as further acknowledgement that Woodfibre LNG is setting the standard for incorporating First Nations and community priorities into the design and operation of an industrial project in British Columbia.” The Woodfibre LNG Project is located approximately 7 km west-southwest of Squamish, British Columbia, involves construction and operation of a liquefied natural gas (LNG) export facility on the previous Woodfibre Pulp Mill site, which would have a storage capacity of 250,000 m3 and would produce approximately 2.1 million tonnes per year of LNG. Woodfibre LNG Limited is a privately held Canadian company based in Vancouver, and a subsidiary of Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies. To learn more about Woodfibre LNG, visit woodfibrelng.ca.

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RESEARCH

Scientists focus on hydraulic fracking fallout in B.C. An NDP panel on fracturing would find several studies are already well underway Provided a new BC Green Party-backed NDP minority government lasts long enough to tick off all the big priority items on its ambitious agenda, it might eventually get around to fulfilling the promise of striking a special scientific panel to study the impacts of hydraulic fracturing. “This will include assessment of impacts on water and, given recent minor earthquakes in the area, what role gas production has in seismic activity,” the BC NDP’s platform states. Such a panel will find that several B.C.focused scientific studies either have already been done or are underway. Some go even further than what the NDP plank on fracking contemplates. One study involving NASA’s Jet Propulsion Laboratory (JPL), for example, is using sniffer drones to detect methane in the region where gas wells operate – data that can then be matched with Geoscience BC’s Natural Gas Atlas, which uses carbon isotope “fingerprinting” to identify possible origins of the methane. “This is something that’s really important to us – depending on what this review of fracking might look like – is to make sure that they understand that there has been a whole lot of work already done, so they don’t have to start from scratch,” said Richard Truman, director of external relations for Geoscience BC. “There’s a lot of stuff already going on in B.C. A lot of it is stuff that isn’t going on in other places.” Hydraulic fracturing and horizontal drilling – which unlock trapped gases in shale rock – have been used for many years now in B.C. But the NDP acknowledges that oil and gas drilling in northeastern B.C. has the potential for “significant expansion.” Even if a liquefied natural gas industry never takes root in B.C., the Montney formation in the Peace region is so massive and prolific that it gives oil and gas producers there a big competitive advantage over many other regions in North America. Oil and gas companies have therefore been investing billions in the Montney. The NDP says it wants to be sure that an anticipated expansion of fracking in B.C. is done safely and in a way that protects the environment. The main concerns around fracking are induced seismicity (earthquakes), groundwater contamination, fugitive methane emissions

GEOSCIENCE BC PHOTO

A gas sniffing drone is used to detect methane levels from B.C.’s gas fields.

and water consumption. When a well is fracked, it can induce a mini-earthquake. So can geothermal energy production. The induced seismic activity from fracking in B.C. is already fairly well understood, thanks to a 2012 study commissioned by the BC Oil and Gas Commission. Most of the mini-quakes that have occurred have been in the magnitude-3 range, which is low enough that it isn’t felt. One was 4.6 on the Richter scale – powerful enough to be felt but causing no damage. “Ninety-five per cent of the events are below [magnitude] 3 that we’ve recorded,” said Carlos Salas, vice-president of oil and gas for Geoscience BC. Since the study was commissioned, the number of seismic monitoring stations in northeastern B.C. has been expanded to 13 from three, so a lot of data on seismic activity in the northeast gas fields is now available. Perhaps the biggest unknown is hydraulic fracturing’s impact on groundwater used for drinking. To address that knowledge gap, Geoscience BC has completed a groundwater mapping exercise to identify where the aquifers are and how deep they go, and the University of British Columbia’s (UBC) department of earth, ocean and atmospheric sciences is preparing a controlled natural gas leak to study the impacts on groundwater. When methane leaks into a freshwater aquifer, it can change the chemistry, said Roger Beckie, who is leading the UBC study. For example, it can increase the amount of dissolved iron in the water. That doesn’t pose a

health hazard, but it can affect the water’s taste and appearance. “There’s no real alarmist kind of thing going on here,” Beckie said, “but it’s something we want to cross off to make sure.” He said the results of the study should be available by mid-2018. As for fugitive methane emissions from gas wells, to date it has been a challenge to determine if higher levels of methane in an area are biogenic (from dairy farms, swamps or other natural sources) or thermogenic (from natural gas wells). A study published in April by the David Suzuki Foundation and St. Francis Xavier University’s department of earth sciences concluded that methane levels from B.C.’s oil and gas sector may be 2.5 times higher than previously estimated. The study found that old, decommissioned conventional wells are more prone to leaks than the “younger” unconventional wells (i.e., fracked wells). “These results reinforce the need for regulators to pay attention not only to modern equipment, but also legacy wells and infrastructure,” the study concluded. The study also noted that, compared with American natural-gas-producing regions, “natural gas activity in the Montney formation may emit both less frequently and less severely than U.S. comparators.” Geoscience BC is now experimenting with a kind of carbon isotope fingerprinting technique to identify the unique signatures of methane from specific formations. CONTINUED ON PAGE 13

JULY 21, 2017

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OPERATIONS

Fracking rarely linked to felt seismic tremors, new university study finds Researchers find only one hydrocarbon-producing area where production is linked to increased seismic activities at the regional scale It has become accepted that a recent surge in seismic activity in Oklahoma is related to saltwater injection that has been used to increase oil and gas production, but new research from the University of Alberta says the trend is an anomaly. In fact the team of researchers, led by U of A geophysicist Mirko Van der Baan, concluded that Oklahoma is the only region in the nine top hydrocarbon-producing places in the US and Canada where this is happening at the regional scale. The U of A study set out to determine the relationship between hydraulic fracturing and induced seismicity, finding that this technology--unlike saltwater injection in the specific region of Oklahoma--rarely results in tremors. Before 2009, Oklahoma might have experienced one to two low-magnitude earthquakes per year, but since 2014 the state has experienced one to two lowmagnitude earthquakes per day, according to a report last week from the US Energy Information Administration (EIA). Identify opportunities and empower your strategic decision making with the Daily Oil Bulletin. The EIA notes that most of these earthquakes are small, measuring in the three- to four- magnitude range on the moment magnitude scale; large enough to be felt by most people but not often causing structural damage. Since 2014 there have been a few instances of higher magnitude earthquakes in Oklahoma (between magnitude 5 and 6) that have caused some damage, the EIA reports. The U of A says the increase in seismic activity in Oklahoma has an 85 percent correlation to increased oil production, likely

primarily due to saltwater disposal. However, after studying the last thee to five decades of data (depending on data availability), Van der Baan’s team found that Oklahoma’s experience is unique. In a two-year study, researchers examined data from Oklahoma, Ohio, Pennsylvania, Texas, West Virginia, Alberta, British Columbia and Saskatchewan. “The other areas do not display state/province-wide correlations between increased seismicity and production, despite 8-16 fold increases in production in some states,” reads a paper by Van der Baan and U of A postdoctoral fellow Frank Calixto that appeared in the scientific journal Geochemistry, Geophysics, Geosystems. However, the researchers acknowledged that in various cases seismicity has locally increased, linked to hydraulic fracturing. “It’s not as simple as saying ‘we do a hydraulic fracturing treatment, and therefore we are going to cause felt seismicity.’ It’s actually the opposite. Most of it is perfectly safe,” Van der Baan said in a statement released by the U of A. “What we need to know first is where seismicity is changing as it relates to hydraulic fracturing or saltwater disposal. The next question is why is it changing in some areas and not in others,” he said. For example, the researchers said that while data shows that human-caused seismic activity is less likely in areas with lower existing seismic risk, the opposite is not necessarily true. “If we can understand why seismicity changes, then we can start thinking about mitigation strategies.” —JWN Energy

UNIVERSITY OF ALBERTA PHOTO

University of Alberta geophysicist Mirko Van der Baan

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POLITICS BC natural gas producers confident in biz prospects New government does little to shake confidence While Canada’s oil industry is preparing for conflict with a new government in British Columbia that has said it will use “every tool available” to stop construction of the federallyapproved Trans Mountain Pipeline expansion across its borders, natural gas producers in the province are confident that their operations will remain business as usual. BC NDP leader John Horgan inched Christy Clark’s Liberals out of power following the May provincial election by forming a coalition with Green Party leader Andrew Weaver. Horgan’s platform said that LNG is a significant opportunity for BC but criticized Clark’s “broken LNG promises.” “As it stands right now in B.C., nothing’s changed, so we’ve had no change to our spending plans,” Mike Rose, CEO of Tourmaline Oil Corp., told this month’s TD Securities Calgary Energy Conference. Tourmaline currently produces up to 55,000 boe/d from the B.C. side of the Montney play, and has a gas plant expansion underway to increase that to 65,000 boe/d. “The research we’ve done on the current NDP leader in B.C. is that he is definitely pro-jobs and definitely pro-LNG from everything we’ve heard. Whether that changes because of the Green element in his coalition, we don’t know right now but we think it’s very unlikely.” Rose added, however, that the B.C. Montney is one of its three core areas and the company is ready to “move capital around” if it needs to. Tourmaline is planning to spend $1.35 billion this year on oil and gas development across northern B.C. and Alberta. A key difference between industry’s relationships with politicians in B.C. compared to in Alberta is that companies have been working for years on engaging with the different political parties, ARC Resources CEO Myron Stadnyk told the TD conference. “Mr. Horgan who will be premier in a month, for example, was touring our fields four years ago during the last election,” Stadnyk said, adding that the BC NDP party has connections to oil and gas development, having had a hand in forming the BC Oil and Gas Commission and bringing in the province’s oil royalty system in 1999/2000. “Mr. Horgan understands our industry…A few days ago Fort St. John radio interviewed [him], and he had very positive comments about our industry and supporting the Peace River district where we are a big employer. We look forward to continuing to invest in both Alberta and BC.” ARC has a $665 million capital program planned for 2017 that focuses on its Montney assets, the majority of which are in Northeast B.C. ‘WE THINK B.C. IS BETTER’ Meanwhile, Painted Pony Energy remain optimistic.

ARC RESOURCES PHOTO

ARC Resources CEO Myron Stadnyk: “Mr. Horgan understands our industry…A few days ago Fort St. John radio interviewed [him], and he had very positive comments about our industry and supporting the Peace River district where we are a big employer.

“I have had the pleasure of working in B.C. for 40 years, and I think in that time we had 12 to 16 years of NDP rule, and they always treated the industry relatively well—they haven’t done anything to harm it,” Patrick Ward, president and chief executive officer at Painted Pony Energy Ltd., told TD Securities Calgary Energy Conference. “The NDP in B.C. is about jobs and education. They have a more socialistic approach, but they are not out to destroy the industry by any means.” Last week, the province’s Lt.-Gov. Judith Guichon confirmed that she asked NDP Leader John Horgan to form a government in B.C., backed with support by the Green Party, as she accepted the resignation of B.C. Liberal Premier Christy Clark. According to Dale Shwed, president and CEO at Crew Energy Inc., the NDP likely will not interfere with hydraulic fracturing and he does not anticipate continuation of that industry practice to be in any sort of danger. As for what to expect from the new government that could impact B.C.’s energy sector, he cited water usage and the intention of giving more rights to indigenous peoples. “From that perspective I would say fracking would be behind these concerns. I think there would be other things that could come into the equation that could affect our businesses.” Fortunately for Painted Pony, for economic purposes the company already works to recycle and reuse nearly all its frac water, and the company works well with its “indigenous partners”

Patrick Ward, president and CEO, Painted Pony

in B.C., noted Ward. He believes the province remains a great jurisdiction for his company’s operations, even with the new regime. “We chose not to be in Alberta for a reason— because we think B.C. is better,” Ward said. “The opportunities there and royalty structure is better, and the regulations are better—you can actually talk to a government official and get things done efficiently.” David Wilson, president and CEO at Kelt Exploration Ltd., told the conference that the NDP in B.C. are not “new to the game” of politics and the party knows the importance of industry. “We’ll just have to sit back and see what happens,” he said. “I think the reality is we will end up with another election in a year to two years.” —JWN Energy, Daily Oil Bulletin files

JULY 21, 2017

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POLITICS

George Heyman, Minister of Environment and Climate Change Strategy

Doug Donaldson, Minister of Forests, Lands, Natural Resource Operations & Rural Development

Michelle Mungall, Minister of Energy, Mines & Petroleum Resources

New ministers at the helm of B.C.’s resource portfolios “Internationally, Michelle worked as a National Programs Assistant for YMCA Zambia, helping to improve the lives of girls with HIV/AIDS.” George Heyman, Minister of Environment and Climate Change Strategy—MLA for VancouverFairview, Heyman previously served as the executive director of Sierra Club BC and served three terms as president of the BC Government and Service Employees’ Union. “George has been a faculty member of Simon Fraser University’s Dialogue and Negotiation program, teaching courses in multi-party negotiations and collaborative decision-making,” his bio reads. “He has guest lectured at a number of universities in B.C. and abroad, and served on advisory committees for post-graduate and undergraduate degree programs at three B.C. universities.” Heyman has been critical of the Kinder Morgan expansion on issues of coastal tanker traffic and First Nations’ rights, and has written the federal government to oppose Pacific NorthWest LNG over greenhouse gas emissions.

Doug Donaldson, Minister of Forests, Lands, Natural Resource Operations & Rural Development—MLA for Stikine, previously served as an Opposition spokesman for energy and mines. Prior to being first election in 2009, he worked for Storytellers’ Foundation, a non-profit focusing on community economic development in the Stikine. “His previous work in Stikine included jobs in forestry, tourism, education, communications and journalism,” his bio reads. “He has worked as a biologist with a forestry consulting business, as a reporter and columnist with a weekly newspaper, communications director with the Gitxsan Treaty Office, coordinator of the cultural tourism program at Northwest Community College, and instructor with the Gitxsan Wet’suwet’en Education Society. He has also owned and operated businesses in the B.C. Rockies.” —PNN

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John Horgan and his BC NDP party took the reins of the B.C. government on July 18. Horgan was officially sworn in as the province’s 36th premier alongside his new cabinet. Among the province’s new ministers that will be of interest to industry include: Michelle Mungall, Minister of Energy, Mines & Petroleum Resources—The MLA for Nelson-Creston, Mungall’s bio lists no oil and gas experience, nor experience in the mining or electricity sector, though her riding does contain hydroelectric dams and forestry. She has served as opposition spokesperson for social development. “Her university studies and her career in community development have led Michelle to champion social justice and financial security both in her community and internationally,” the bio states. “Her career has included working for the Nelson Committee on Homelessness, and managing West Kootenay non-profits including the Nelson Food Cupboard and a micro-finance organization.

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OPERATIONS

Pembina completes $2.8B capex program under budget, on schedule Pembina Pipeline Corporation marked a milestone last week as it put into service three integrated major capital projects totalling investment of approximately $2.8 billion. Driven by development of the Montney, Duvernay and Deep Basin plays, Pembina completed an expansion of its transportation system from northern Alberta to connected receipt points in the Industrial Heartland region, including a third fractionator at its Redwater complex and additional condensate connections at its diluent hub. The centerpiece of the capital program is the $2.44-billion Phase III Expansion of the company’s pipelines from Fox Creek to Sturgeon County—the largest project in its history. With the project complete, Pembina now has over 850,000 bbls/d of capacity on four pipelines allowing it to transport four distinct hydrocarbons—ethane-plus, propane-plus, condensate and crude oil—each in its own segregated pipeline, plus upstream capacity to handle higher production volumes, the company says. With the addition of a third fractionator, Pembina’s Redwater complex now has capacity of 210,000 bbls/d, making it the largest of its

kind in Canada. The overall portfolio of projects was delivered approximately eight percent under budget and either on time or ahead of schedule, CEO Mick Dilger said in a statement. “Now through 2018—including growth projects of Veresen, pending successful close of the

transaction we announced in May this year— we will be placing an additional $3 billion of assets into service on top of the $2.8 billion we announced in service today,” he said. —JWN Energy

Pembina-Veresen merger pushes ahead Pembina Pipeline Corporation and Veresen Inc. have announced the Court of Queen’s Bench of Alberta has approved plans to create one of the largest energy infrastructure companies in Canada. Closing of the transaction remains subject to certain conditions, including certain regulatory and government approvals and other customary closing conditions. Pembina and Veresen continue to expect the transaction will close late in the third quarter or early in the fourth quarter of 2017. Pembina announced May 1 it would acquire Veresen in a friendly $9.7-billion deal combined of stock and cash. It would create one of the largest infrastructure companies in Canada, with enterprise value of approximately $33 billion. On July 11, Veresen shareholders voted to approve the merger plans. “We are very pleased with the overwhelming support of our shareholders to create a leading

Canadian energy infrastructure business,” Don Althoff, president and chief executive officer of Veresen, said in a statement. “We strongly believe that the combined company is greater than the sum of its parts and will be well positioned to compete for future investment opportunities in order to drive significant growth over the long term.” “I am very pleased that Veresen shareholders recognize the merits of this transaction and showed their support at the meeting,” added Mick Dilger, Pembina’s president and chief executive officer. “With increased size and scale, and the significant operational synergies we will realize, the integration of Pembina and Veresen supports our consolidated adjusted EBITDA growth and positions us for top-tier performance going forward.” Pembina’s assets are primarily located in the Deep Basin, Duvernay, and Alberta Montney, and are well complemented by Veresen’s position in the B.C. Montney.

Pembina’s assets are primarily focused on natural gas liquids, condensate, crude oil, and heavy oil, while Veresen’s assets provide size and scale in natural gas midstream infrastructure. Veresen’s current 1.5 billion bcf/d of gas processing infrastructure that is currently under construction is very complementary to Pembina’s approximately 1.7 bcf/d of field gas processing capacity in the Deep Basin, Duvernay, and Alberta Montney, as well as its announced pipeline expansion in the B.C. Montney. Pembina is nearing completion of more than $4 billion in growth projects this year, while Veresen has approximately $1.5 billion in secured growth projects. The combined entity will continue to “build upon the momentum” of Veresen’s proposed Jordan Cove LNG project in the United States as it progresses toward key regulatory and commercial milestones. —PNN, with files from JWN Energy and Daily Oil Bulletin

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POLICY

Industry, government collaboration key to enhancing oil and gas

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The provincial government and the energy industry could create more than 24,000 new jobs for Albertans and grow the province’s economy by nearly $5 billion over the next three years by working together to enhance JOIN US FOR A FIVE-DAY, IN-DEPTH TRAINING the competitiveness of Canada’s leading trade sector, according to report, PROGRAM TO BECOME AN INDEPENDENT A Competitive Policy and Regulatory Framework for Alberta’s Upstream Oil CERTIFIED EXTERNAL AUDITOR and Natural Gas Industry, by the Canadian Association of Petroleum Producers (CAPP). Advance your career and aim high for safety Industry continues to face mounting costs and barriers to growth due to changes in provincial and federal government policies and regulations such as methane emissions, carbon pricing, municipal and corporate tax increases, wetland policy, well liability and closure, and caribou management, among others. In addition, low global commodity prices, rapidly changing market dynamics, and new policy directions in the United States Upcoming training dates: You will learn all elements of conducting have led to negative impacts on oil and natural gas investment and comCertified Health and a comprehensive audit: petitiveness in Canada. Safety Auditor Program · pre-audit preparation, submission and quality assurance review “The upstream oil and natural gas industry provides many benefits to Fort St. John, BC · conducting meetings, tours and interviews Albertans but continues to face challenges and barriers to growth and sucSeptember 18, 2017 · effective documentation and report writing cess, including policy and regulatory challenges at both the provincial and Red Deer, AB · overview of Certificate of Recognition Program (COR) and federal levels,” said CAPP President Tim McMillan. November 13, 2017 the Enform Audit Instrument “The uncertainty surrounding changes to government policies and · practicum that includes a full health and safety audit regulations have resulted in increased cost burdens to the industry, ultimately affecting the upstream oil and natural gas sector’s ability to attract Visit our website at www.enform.ca/auditortraining or contact us at investment.”” training@enform.ca for more information on fees and prerequisites. The report outlines how new competitiveness measures could be created to attract investment and create jobs in Alberta’s oil and natural gas sector, while protecting the high standards already in place for health, safety and environmental regulation. CAPP estimates the cumulative costs associated with the changes in provincial and federal government policies and regulations to conventional and unconventional development could range between $450 million and Certified Auditor Ad 1/4 Page June 5.indd 1 2017-06-26 $760 million annually in the near term. Overall capital spending in Canada is forecast to be $44 billion in 2017, a 46 per cent decrease from $81 billion in 2014. Meanwhile, spending in the U.S. is expected to rise 38 per cent to $120 billion this year. “Opportunities exist for industry and government to work together to meet a common goal – responsibly grow oil and natural gas production to strengthen the economy and get Albertans back to work,” McMillan said. “Our proposal to streamline provincial and federal policies and regulations has the potential to achieve regulatory efficiencies, eliminate duplication and create a framework for shared sustainable prosperity in Canada.” Through collaboration with government on essential policy challenges the energy sector can attract new investment to Alberta and improve our competitiveness. It is critical Alberta and Canada compare their policies and regulatory regimes with the U.S., our only major market for oil and natural gas exports, and our biggest competitor for capital. We need a madein-Alberta approach to competitiveness. By working together, CAPP estimates unemployment in Alberta can be reduced nearly 25 per cent. As well, we can generate $4.5 billion in gross domestic product, $207 million in additional income tax, and $79 million in additional royalties in the near term on an average annual basis. Canada’s upstream oil and natural gas industry needs to rebalance the playing field and restore investment while maintaining Alberta’s position as a leader in responsible development. CAPP continues to review the competitiveness of Canadian jurisdictions. In 2015, Alberta’s upstream oil and natural gas sector delivered: $2.9 billion in non-renewable resource revenues; $185 million in corporate income tax; $2.8 billion in provincial personal income tax from direct and indirect employment; $1.25 billion in municipal property tax on upstream assets alone; and support for more than 20,000 businesses in Alberta, including 327 aboriginal companies, representing about $4 billion in activity.

12:12 PM

• PIPELINE NEWS NORTH

JULY 21, 2017

TECHNOLOGY

B.C. wind + Montney gas + conventional refining chemistry = low carbon gasoline Blue Fuel Energy may be one of the best bets for meeting North America’s increasingly ambitious low-carbon fuel standards (LCFS). The problem is a lot of people just don’t get it. Juergen Puetter built Blue Fuel around the idea of using renewable power to drive a relatively conventional refining process that converts natural gas into methanol and methanol into synthetic gasoline. It’s all proven technology, and Puetter even hired former Methanex executive Michael Macdonald—a 30-year methanol veteran—as Blue Fuel’s president to help gain investor confidence in the venture. But it has been a tough sell. First, how is a fossil-fuel synthetic gasoline low carbon? How does Blue Fuel expect to build a $2.2-billion energy megaproject in the verdant hills of B.C., where so many others have failed? And how will it get its product to market from the northeastern corner of B.C.? GREEN REFINING Puetter notes people generally don’t appreciate that biofuels aren’t always low carbon. It’s debatable that ethanol from U.S. Midwest corn even produces net energy after all the inputs of planting, irrigating, fertilizing, protecting from pests and processing into fuel are accounted for. No net energy means no net carbon intensity reduction. While there are productive agricultural regions in California, Brazil and other places that yield an ethanol with a lower carbon intensity than gasoline, they have the “blend wall” to contend with. Most jurisdictions have adopted 10 per cent maximum biofuel blend to ensure that gasoline remains backward-compatible with existing vehicle engine technology. But that may not leave enough margin to achieve California and B.C.’s LCFS targets, which call for a reduction of at least 10 per cent in the transportation fuel carbon intensity by 2020. “If you do the math for gasoline, which emits 93 grams [of carbon] per megajoule and add 10 per cent of something that emits 45 grams per megajoule [ethanol], you cannot get a 10 per cent reduction in carbon intensity,” Puetter says. “Interestingly enough, that simple calculation, which most grade three students can perform, has largely gone unrecognized.” STORAGE Puetter is primarily a wind developer. His company, Aeolis Wind Power, brought on the first fully operational wind farm in B.C. in 2009 and then sold the 102-megawatt project to AltaGas. Currently Aeolis is sitting on a massive amount of potential wind energy in its northeastern B.C. land leases, approximately 5,000 megawatts. That energy, however, is essentially stranded for three reasons: BC Hydro does not have enough capacity to firm up this intermittent power, there is a lack of regional demand for the electricity and there are

no transmission lines to export it. Thinking creatively about these challenges, Puetter turned to the Holy Grail of renewable energy sources: storage. “We concluded that the most efficient way to store energy on a large scale is by transforming it into a liquid fuel,” he says. Blue Fuel was launched in 2008 based on a proposal to use wind energy to electrolyze water into hydrogen and oxygen and turn that into synthetic gasoline. The size of the emerging LCFS market in California and B.C., however, convinced Puetter’s team to abandon water electrolysis. “We realized that the scale that is required is so massive that we couldn’t possibly build enough electrolysis-derived gasoline at an economic rate,” he says. Since Aeolis’ 2,000 hectares of leased land in the Chetwynd, B.C., area are not only endowed with wind but also a massive amount of Montney dry natural gas, the business plan changed to using BC Hydro renewable energy to convert dry natural gas into methanol and running the methanol over a catalyst produced by ExxonMobil to make DME. “By doing nothing else but using a fossil fuel such as dry natural gas and using renewable energy for electric drive in your refining process, this yields you to 20 per cent reduction in carbon intensity,” Puetter says. “You end up with a fully compatible gasoline that meets [Federal Test Methods] standards. This is different than ethanol, which always has to be brought to a central location and blended into gasoline. We’re making stand-alone gasoline that you can fuel up with.” Blue Fuel’s plan is for an initial plant producing 5,000 tons/d of methanol, dehydrated to produce 2,400 tons/d of gasoline. That volume is equal to about 20 per cent of B.C.’s gasoline consumption, two per cent of Canada’s consumption and 1.4 per cent of California’s. Montney gas in the Chetwynd areas is virtually pure methane, which is ideal for Blue Fuel’s purposes. The oil and gas industry isn’t interested in it because the economics of the liquids-rich Montney are better. But for Blue Fuel, dry gas

means it doesn’t require deep or shallow-cut processing. And eventually Aeolis wind farms would replace BC Hydro renewable power. REALITIES In shopping the project to potential investors, Puetter leads with Blue Fuel’s work with the government and First Nations to gain social licence. “The idea of a refinery has been very well received in the area,” he says. “[The refining] process generates a lot of waste heat. Rather than just run it through a heat exchanger, we plan to provide this waste energy in the form of hot water to large-scale greenhouses that are fully owned by First Nations. We donated 100 acres of land for that.” As for market access, Puetter started with the assumption that it is “virtually impossible” to build pipelines in B.C. The solution is CN’s railway. The biggest hurdle, however, has been financing. Blue Fuel has done the pre–frontend engineering design and calculated the heat balances, but it needs US$50 million for the detailed engineering to move forward. That first $50 million is the hardest. Puetter believes that raising the balance would not be difficult. So far, though, the World Bank “didn’t get it.” Proponents of B.C. LNG didn’t want to hear about anything but LNG. And the big oil companies he’d approached weren’t interested. “The conclusion that I personally derived is that the majority of the large oil companies are essentially relying on lobbying to change the regulations so they don’t have to deal with the carbon intensity reduction issue,” Puetter says. So now Blue Fuel is looking for two or three strategic partners, companies that could be involved in some aspect of Blue Fuel’s business, whether upstream, midstream or downstream. “It’s been incredibly more complicated and slower than we’d ever imagined,” Puetter says. “But we believe we’re very close to being able to announce something tangible.” —JWN Energy

JULY 21, 2017

PIPELINE NEWS NORTH •

PIPELINES

Clean energy could suffer collateral damage in pipeline war Opponents committed to halting the $7.4 billion expansion of the Trans Mountain pipeline, which now includes the Government of British Columbia, often champion clean renewable energy as an alternative to “dirty oil.” But a new C.D. Howe Institute brief warns that killing oil pipelines could also have negative consequences for clean energy projects in Canada. Whether it is oil or renewable power, both need two things: billions of dollars of investment and transmission. They also need regulatory approval, and the regulatory processes by which they are approved have been under assault. The C.D. Howe brief, addressed to the new NDP government in B.C., warns that using regulatory processes to delay or halt the Trans Mountain pipeline expansion won’t just discourage investment in oil pipelines, it could also discourage private investment in clean energy projects and transmission lines. “If the oil pipeline fight establishes tools that can stop federally approved energy transport projects, those tactics will be used to stop power transmission for renewable power projects,” James Coleman, assistant professor of the Southern Methodist University Dedman School of Law, writes. C.D. Howe associate director of research Ben Dachis points out that the same National Energy Board review process that approved the pipeline expansion would be needed to approve any new interprovincial transmission lines – between B.C. and Alberta, for example. And the integrity of those processes is being challenged. The new NDP minority government has vowed to use every available tool to flout the decisions made by a federal regulatory body, which sends a negative signal to investors, whether they are oil and gas midstream companies, or independent power producers, according to C.D. Howe. “Most economic reviews have found that CONTINUED FROM PAGE 6 “What we’re trying to do is fingerprint the natural gas,” Salas said. “Each field, each pool, will have a certain geochemical fingerprint based on the carbon isotopes. If there was a fugitive gas leak … you could figure out where that molecule came from, and you could remediate that in a much more cost-effective fashion.” It also helps companies zero in on the more lucrative shale oil and gas deposits because it can tell them if a formation has only dry gas or wet gas as well. (There is far more value in wet gas.) As for detecting the methane, Geoscience BC is working with NASA’s JPL on a project that uses mini mass spectrometers mounted on a drone to sniff out methane at low altitudes. “It will measure the fugitive gas leaks in

MATT PREPROST PHOTO

Pipelines aren’t the only energy transmission system that require regulatory approval – so do interprovincial transmission lines.

stopping North American pipelines has only a marginal impact on oil production—and may have no impact at all on world oil production,” Coleman writes. By contrast, renewable power cannot reach markets without multibillion dollar investments in transmission — electricity from solar and wind cannot travel by train or truck. “Thus, a short-sighted focus on using new procedures to stop oil transport projects may ultimately do more harm than good in moving Canada to a low carbon economy.” But would a new interprovincial or intercontinental transmission line really generate the same kind of opposition as oil

pipelines? Dachis points to the opposition already mounting against the Northern Pass project – a proposed new transmission line that would connect northeastern states in the U.S. to Quebec’s hydro power – as one current example. “There will always be groups out there that oppose any kind of project that has a local impact,” Dachis said. “The process that the government puts in place for a pipeline is very much going to have an impact on the environmental policy for approval of interprovincial transmission lines.” —Business in Vancouver

real time,” Salas said. “It will give you the carbon isotopes [so] you can tell whether it’s biogenic or thermogenic.” As for the use of fresh water in fracking, that has been a fairly significant concern in B.C. simply because water is so abundant, so it’s relatively cheap. The BC Oil and Gas Commission estimates that, in 2014, the two biggest operators in B.C. used one million cubic metres in their fracking operations – enough to fill 800 Olympic-sized swimming pools. But some companies are starting to reduce their water use through things like “energized fluids” (liquefied carbon dioxide or nitrogen) or “grey water” from sewage treatment plants. “Companies, wherever possible, [are] just staying away from water,” Salas said. —Business in Vancouver

Carlos Salas, Geoscience BC

• PIPELINE NEWS NORTH

JULY 21, 2017

IN BRIEF

Fort Nelson First Nation challenges gas pipeline in an area with the most concentrated and highest known use by boreal caribou for forage, calving, rearing and protection from predators. The first nation says that throughout the application process it made “strong submissions” to the regulator regarding the proposed pipeline, including a plan to support the recovery of the caribou in that area and a consultation process specific to the proposed project application. However, it says the BC Oil and Gas Commission refused the invitation to work out a specific consultation process, and deemed it not practical to consider the band’s report. “This resulted in the BCOGC using inadequate and incomplete data to determine that the proposed pipeline poses ‘no material adverse effect’ to the caribou populations in the area. The BCOGC has not provided a clear explanation of this determination,” the first nation says. “It’s important to stress that as a nation, we support and encourage economic development opportunities in our territory,” Fort Nelson

The Fort Nelson First Nation says it supports project development, but a new pipeline approval across its territory demonstrates an “inadequate, unlawful and wholly unacceptable approach to consultation” regarding how it would impact boreal caribou. The band has filed for a judicial review of the BC Oil and Gas Commission’s June approval of a gas pipeline owned by junior Rockyview Resources. More than 80 per cent of boreal caribou habitat in B.C. is on Fort Nelson First Nation lands, the band says. “We clearly have an interest in saving and helping restore caribou populations, and for this reason, our community has chosen not to hunt caribou until the population stabilizes. We expect the same stewardship ethic from companies who wish to access our territory for economic purposes,” Fort Nelson First Nation director lands and resources Lana Lowe said in a statement. “The 39km proposed gas pipeline cuts right through core caribou habitat in our territory,

First Nation acting chief Sharleen Gale said in a statement. “We look to proactively engage both proponents and the crown on development opportunities so that they can be planned in a way that creates long-term benefits for our members while also respecting our lands, water and treaty rights.” Rockyview Resources representatives were not immediately available for comment by deadline. According to its Discovery LNG website, Rockyview Resources is an oil and gas exploration company based out of Calgary. It’s currently investigating options to build and operate natural gas liquefaction, storage and on-loading facilities, called Discovery LNG, on the north side of Campbell River on a former mill site of Catalyst Paper. “Processed natural gas would arrive at Discovery LNG through a yet to-be determined transmission method from Rockyview’s sites in the Horn River Basin in Northeastern B.C.,” the website states. —JWN Energy, with PNN files

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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.

JULY 21, 2017

PIPELINE NEWS NORTH •

IN BRIEF

Western Canada land sale revenue bounces back in first half of 2017 Over the first six months of 2017, bonus bids paid to provincial governments in Western Canada totalled $276.57 million, with industry tying up 596,481 hectares. Just over 65 per cent of that bonus haul was spent in Alberta. To the same point of 2016, industry had spent $80.18 million in Western Canada for 508,491 hectares. Producers have paid $463.66 per hectare at the six-month mark of 2017, also substantially above an average of $157.69 during JanuaryJune 2016. ALBERTA—INTEREST IN EAST SHALE BASIN DRAWS ATTENTION At the six-month mark, Alberta has collected $180.13 million on 526,080 hectares at an average of $342.39 per hectare. To the same point a year ago, Alberta had collected $63.77 million on the sale of 443,917 hectares at an average price of $143.66. In the six land sales of the second quarter of 2017, the government brought in $97.4 million

in bonus revenue. Interest in the emerging Duvernay East Shale Basin was a trend during the first six months of the year. MONTNEY LEADS RECOVERY IN BRITISH COLUMBIA British Columbia attracted the secondhighest bonus total from January-June 2017, driven by interest in the Montney, which is the dominant formation in the natural gas-prone province. For the six-month period, B.C. has brought in $70.28 million on 35,191 hectares at an average price $1,997.20. Atthe same point last year, the government had collected only $4.22 million in total, on the sale of 27,377 hectares at $154.20 per hectare. Producers spent $48.14 million tying up land in B.C. during the first quarter, and $22.15 million during the second quarter. SASKATCHEWAN JUNE LAND SALE SPARKS 2017 RECOVERY

Saskatchewan, meanwhile, has collected $25.94 million for 2017 after a strong June sale. Industry acquired the rights to 34,845 hectares at an average price of $744.49 in the first half of 2017. To the same point of 2016, the government had collected $12.04 million on 35,784 hectares at an average price of $336.59. Industry picked up 23,239 hectares at the June 2017 auction at an average price of $982.80 per hectare with a bonus of $22.84 million flowing to Saskatchewan government coffers — the largest revenue for a single public offering in almost three years. MANITOBA SALES INCREASE, THOUGH BONUS REVENUE IS MODEST For the six-month period, Manitoba has attracted $214,096 on 365.14 hectares at an average price of $586.34. To the same point of 2016 it had brought in $141,859 on the sale of 1,413.62 hectares at an average price of $100.35. —Daily Oil Bulletin

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TAKE CHARGE OF YOUR FUTURE. Online or face-to-face, we have a Lakeland education for you! Apply and start classes today Online Learning • 4th Class Power Engineering Classes start on August 15 • 3rd Class Power Engineering Classes are always open • Gas Process Operator Classes start on August 30 • Fired Process Heater Operator Classes are always open • Production Field Operator Classes start in August • Pre-physics & Math for Power Engineers Classes are always open Face-to-Face Delivery – Lloydminster • 4th Class Power Engineering Classes start on September 18 • 4th Class Steam Lab – evening Classes start on October 9 • Interpretation of Piping & Instrumentation Diagrams Visit our website for course dates • Oil & Gas Monitoring Classes start in October For details visit lakelandcollege.ca/con-ed