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Peace Region fires back at southern mayors over resource extraction Revenue-sharing clinches B.C.’s Trans Mountain pipeline approval Ridley OK’d: Drilling activity could rise with AltaGas propane export plans Investments: Montney capital spending highlights for 2017

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JANUARY 20, 2017

PIPELINE NEWS NORTH •

OUTLOOK Montney potential continues to grow, investors hear Producers should challenge their assumptions of the Montney play’s potential with the National Energy Board’s study of the basin was likely a lowball assessment, U.S. investors were told at an oil and gas conference in Colorado last year. Juan Jarrah of TD Securities Inc. gave investors at Enercon’s Oil and Gas Conference in Denver a presentation on the Montney, calling it the most “important resource play” in Canada, if not North America. “It’s pretty clear that the Montney can challenge every other play in North America. It is one of the most economic … (and) it’s been a significant source of production and reserves additions and (there has been) a decrease in operating costs for anyone who is actually focused in the play,” Jarrah said. The NEB’s last study of the Montney in 2013 estimated a recoverable resource of 449 trillion cubic feet of natural gas, 14.5 billion

barrels of natural gas liquids and 1.1 billion barrels of oil. With an estimated 4,300 tcf of recoverable natural gas in place, that equates to a recovery factor of about 10 per cent, not including liquids and condensate. “The key here is that this was 2013. A lot has changed since then,” Jarrah said. “Basically what has happened is we’re producing Montney wells horizontally from areas where we thought we would never produce. So that should call into question our entire assumptions here in terms of what kind of porosities we need to use. We need to recalibrate everything we know about the play because it’s just getting better and better with time and we’re seeing that in the reserves as companies report reserves.” After analyzing hundreds of Montney wells, Jarrah and his TD Securities team, working with geologists in Calgary, have mapped

the potential gas in place sectionby-section and believe that total could rise to more than 5,000 tcf compared to the NEB’s initial estimate of 4,300 tcf. “Our guys in Calgary did the math and said, ‘You know what? There’s probably 5,000 tcf of gas in place.” First Energy Capital Corp., now known as GMP FirstEnergy, has increased its total Montney liquids resources estimate by 46 per cent since 2014 to about 12.8 billion bbls of crude oil and NGLs. Its natural gas resource estimate has also gone up, by 14 per cent to about 282 tcf of recoverable gas. “What kind of resource is this? It’s 149 years at current rates,” analysts wrote in the firm’s Montney supply update released in mid-September. “The Montney is the most logical energy source in Canada to fuel the transition towards a low-carbon future.” The play, which is found in northeastern British Columbia and

northwestern Alberta, has an areal footprint of about 50,000-square miles: 350 miles from north to south and about 130 or 140 miles from east to west. Given its massive size, all areas of the Montney are, obviously, not created equal when it comes to potential resource endowment. Industry began experimenting with horizontal drilling in the play only in early 2006 and at the time of the 2013 NEB study there was a relative lack of accurate well control data. But that’s not the case anymore, as of 2016 more than 5,600 wells had been punched into the Montney in British Columbia and Alberta. “It went from basically zero production in 2006 and we’ve now grown this asset to just over 4.5 or five bcf a day, depending on what time of year you take that measurement, again excluding associated liquids,” Jarrah said. —Daily Oil Bulletin

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Peace River Regional District directors sat for their annual photo last week. Elected officials in the region say the Peace needs to be more vocal in its support of ‘responsible’ natural resource extraction.

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Peace Region fires back at southern mayors over resource extraction JONNY WAKEFIELD reporter@dcdn.ca

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Elected officials in Northeast B.C. are considering hiring a lobbyist, developing new communications strategies and making ad buys in Lower Mainland newspapers in a bid to get a northern voice into debates over natural resource extraction. At a Jan. 12 meeting, Peace River Regional District board members opted to move forward with a plan for communicating “Northern initiatives” to the rest of B.C. According to a report, the aim is to “get the message out and educate the rest of the province on the responsible extraction of resources.” Tumbler Ridge Mayor Don McPherson brought up the issue after last year’s Union of B.C. Municipalities meeting, where several mayors and councillors from the region held a pro-natural resources rally on the steps of the B.C. legislature. “The reason we were there is we had mayors of Victoria and Vancouver talking down on natural gas, and we were showing how united

we can be in promoting this,” he said. According to the report, the hope is to “balance information being put forward by mayors from some of the southern cities in the province.” Vancouver Mayor Gregor Robertson and Burnaby Mayor Derek Corrigan in particular have both been outspoken opponents of Kinder Morgan’s Trans Mountain pipeline, while Vancouver has announced a plan to phase out natural gas use in new buildings. The report suggests the region step up its production of media releases, buy advertising in the Lower Mainland (the report suggests a billboard in downtown Vancouver or “paid articles in magazines or news articles in the Vancouver Sun or the Province”), as well as hiring a professional lobbyist for use on a caseby-case basis. Fort St. John Mayor Lori Ackerman said the region needs to have “several different tools in our tool boxes” when it comes to advocating for services and economic development in the northeast. The board is expected to decide on the specifics of the plan in February.

JANUARY 20, 2017

PIPELINE NEWS NORTH •

OUTLOOK

Ministry confident that land sales will rebound over a period of eight years. Bruce Ralston, B.C. NDP natural gas critic, said that means government will be able to rely on petroleum revenues less and less. “It’s not only bad now in term of its immediate impact, it has a negative impact on revenue over the longer term,” he said.

JONNY WAKEFIELD 2015 was a poor year for B.C.’s oil and gas incomes, and 2016 was even worse. The province brought in just $15.5 million from its monthly land and drilling license sales in 2016—the lowest annual total in data going back to the late 1970s. It was a decline over last year’s sales, which saw totals of just over $18 million. The province announced the results of its Dec. 14 Crown petroleum and natural gas rights auction. Ten drilling licences, issued for five- to ten-year terms, went for an average price of $147.85 per hectare, while no land leases were sold. The sale of drilling rights for subsurface oil and gas accounts for 30 to 70 per cent of B.C.’s total petroleum revenues, depending on market conditions, and is typically considered an indicator of future drilling activity. Sales have been down since 2014 due to slumping oil and gas prices, as well as declining availability of high quality land. In February, the province recorded its first-ever $0 land sale. When asked for comment, a ministry of natural gas spokesperson said B.C. isn’t alone in seeing lower natural gas revenues. “Companies all over the world are cutting back on their expenditures because commodity prices are low, and the market influences our tenure sales,” the ministry wrote in an email. “As a result of the marketplace, it’s not surprising that tenure requests have been lower this year.” Alberta brought in a record low $137 million at

SCOTT LAND & LEASE TOP CROWN BUYER IN 2016 Scott Land & Lease Ltd. was the top buyer of Crown land for 2016, spending $89.27 million, with $63.26 million doled out for acreage in Alberta. The broker acquired 409,595 hectares on behalf of its clients for the 12-month period at an average price of $217.94. Scott Land picked up 306,854 hectares in Alberta from January-December 2016. The second most active Crown buyer in 2016 was Synergy Land Services Ltd. which acquired 43,955 hectares for $12.99 million at an average price of $295.45.

Ministry sees reason for optimism

—Daily Oil Bulletin

its drilling rights auctions last year. B.C.’s auction revenues peaked in 2008, when land agents plunked down $1.2 billion for the right to drill in the province. Those revenues collapsed following the financial crisis, recovering somewhat in 2014 in anticipation of liquified natural gas development. After the boom years of the mid-2000s, the provincial auditor general required petroleum revenues to be stretched out

While it’s unlikely land sale revenues will return to their previous highs, the ministry expects sales to pick up in the coming years. According to a spokesperson, the “most promising” natural gas prospects in the Montney shale formation, Horn River Basin and Liard Basin have been bought up. “The majority of companies in B.C. have carefully acquired large tracts of rights in these plays over the past several years, and now hold a portfolio for future exploration. These companies are not focusing on additional new land acquisitions right now.” However, companies could be in the market for new drilling licences if LNG projects go forward. “We are confident tenure sales will improve as the market rebounds,” the ministry said in a statement. “In addition to our LNG export prospects, we are seeing interest grow for valueadded production and investment in resource areas that are considered ‘liquids rich’—natural gas that holds market value because it is used to produce products like chemicals, plastics and cleaner fuel.” B.C. also charges royalties on natural gas extraction, which came in at $613 million in 2014.

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JANUARY 20, 2017

OUTLOOK

Montney capital spending highlights for 2017 ALTAGAS The company has approved a 2017 capital program of approximately $500 million to $550 million. AltaGas’s natural gas business will account for approximately 65 per cent to 70 per cent of the total capital spending while its utility business will account for approximately 20 per cent to 25 per cent and the power business, five to 10 per cent. The majority of AltaGas capital spend relating to its gas business will be allocated towards growth projects including Townsend Phase 2, its proposed Ridley Island propane export terminal, and the North Pine facility and North Pine pipelines. CNRL With completion of its Horizon expansion oilsands project in sight, Canadian Natural Resources Limited’s 2017 budget forecasts capital spending of $3.89 billion and production growth of six per cent over 2016. Natural gas spending is estimated at $460 million to drill 21 net wells targeting liquids-rich plays in the Montney and Deep Basin. CREW ENERGY Crew Energy Inc. will spend $200 million in 2017 on Greater Septimus drilling and completions and West Septimus facility expansion, predominantly, while also maximizing key service costs through to the end of the year. With three drilling rigs running in the first half of 2017 to complete a 28well Montney program, the company also intends to complete and tie-in 11-net previously-drilled wells that further contribute to volume growth. Crew will invest $140 million into

Montney drilling and completions, as well as equip and tie-in activities such as the planned drilling of the abovementioned 28 (26.3 net) wells and completion of 39 (37.3 net) Montney wells through the year. Key infrastructure projects that include West Septimus facility expansion to 120 mmcf per day of gas processing capacity in aggregate with Septimus and Tower will receive $40 million of 2017 capital and provide Crew with 45,000 boe per day of processing capacity for Montney gas and liquids production. DELPHI ENERGY With a 2017 capital expenditure budget of $65 million to $70 million and the addition of a second drilling rig, Delphi Energy Corp. says it plans to drill double the number of wells it drilled last year. Production also is forecast to grow to between 9,000 and 9,500 boe per day (40 per cent liquids) in 2017 from 7,300 boe to 7,400 boe per day in 2016. The 2017 development plan features the drilling of 13 (8.4 net) Bigstone Montney horizontal wells and the completion, tie-in and wellsite equipping of 14 (nine net) wells. The company drilled six (4.5 net) wells in 2016 with spending of about $43 million. Output is largely weighted to the second half of the year, with fourthquarter 2017 production expected to average 11,000 to 11,500 boe per day, representing about 60 per cent growth (absolute and per share) over that of fourth-quarter 2016. ENCANA On Feb. 16, the company intends to finalize its 2017 budget and issue guidance along with its Q4 and year-

end 2016 results. Encana is running one rig in Pipestone, while four recent Pipestone wells with an average 9,000foot lateral length delivered a 90-day initial production rate of 1,740 boe per day, including 1,000 bbls per day of condensate. Crews are ramping up Cutbank Ridge Partnership activity to prepare for the expected Q4 2017 startup of two Veresen Midstream plants at Tower and Sunrise. Construction is reportedly on schedule and under budget. KELT Kelt Exploration Ltd. has entered into a definitive purchase and sale agreement to dispose of oil and gas assets in the Karr area of Alberta. The company’s board of directors has also approved an increase to its 2017 capital expenditure budget to $144.6 million. Kelt expects to keep three rigs active in its core Montney operating areas of B.C. and Alberta during the first quarter of 2017. At spring breakup, the company will reevaluate its spending plans for the remainder of 2017. PENN WEST Penn West Petroleum Ltd. expects its 2017 total capital budget of $180 million will provide approximately 15 per cent production growth from the fourth quarter of 2016 to the fourth quarter of 2017, and ample flexibility to respond to commodity prices as it uses only 80 per cent of available funds flow from operations. This year’s 55-well plan includes 45 vertical injection wells to provide pressure support for 2015 and 2016 horizontal producers, and new horizontal producers in the second half of the year.

TRILOGY Trilogy Energy Corp. says its board of directors has approved a capital budget for 2017 of $130 million which management expects will be funded entirely from projected funds flow from operations. Trilogy plans to spend approximately $60 million into the Kaybob Montney oil pool in 2017 to drill 15 horizontal net wells, complete 18 net wells and complete infrastructure projects that will reduce ongoing operating costs in the area. Based on the encouraging completion results from its first quarter 2016 Montney horizontal oil wells, Trilogy elected to increase its Montney drilling activity in 2016 to a total of 12 wells for the year, up from the two wells that were initially planned. Nine of these wells were completed prior to the end of 2016 and the remaining three will be completed in 2017. TRINIDAD Trinidad Drilling Ltd. expects to spend approximately $40 million in capital expenditures in 2017. Trinidad’s 2017 capital budget includes maintenance capital to re-certify existing equipment and replenish drill pipe inventory, as a growing number of rigs return to work. In addition, upgrade projects are planned for eight rigs, four in Canada and four in the U.S. At Jan. 17, 2017, Trinidad had 38 rigs or 53 per cent of its Canadian fleet operating, up from an average of 20 per cent during the third quarter of 2016. Demand remains strongest in the Montney and the Deep Basin, with a growing number of rigs also operating in Saskatchewan. —Daily Oil Bulletin files

JANUARY 20, 2017

PIPELINE NEWS NORTH •

PIPELINES

Pembina’s NEBC expansion receives regulatory approval Construction has been initiated on Pembina Pipeline’s $235-million Northeast B.C. expansion project after receiving regulatory approval, the company announced Jan. 5. “With regulatory sanctioning of the NEBC Expansion, we have secured approvals for the majority of the projects within our conventional pipelines business,” said Paul Murphy, Pembina Senior Vice President, Pipelines & Crude Oil Facilities, in a statement.

“The NEBC Expansion strengthens Pembina’s presence within the prolific geology of Northeast B.C. and is located in close proximity to a variety of area producers who may have future transportation needs.” The project includes 145 kilometres of new, 12-inch diametre pipeline with a base design capacity of up to 75,000 barrels per day, the company said. It will parallel much of the existing Blueberry pipeline system northwest of Taylor to

the Highway 97/Blair Creek area near Wonowon. The project will provide a conduit for natural gas liquids and condensate produced in the liquids-rich Montney resource play to access the company’s downstream pipeline systems that feed into markets in the Edmonton and Fort Saskatchewan, Alberta area. The expansion is expected to be operational in late 2017, the company said. —Pipeline News North

Revenue-sharing clinches B.C.’s pipeline approval NELSON BENNETT

VANDALS TEAR UP PIPELINE NEAR HYTHE; DAMAGES UP TO $700K Mounties in Alberta are investigating after vandals caused more than $500,000 in damages to a pipeline under construction north of Hythe. “It is believed a piece of construction equipment was used to dig up some of the pipeline, which caused severe damage to the pipeline,” Grande Prairie RCMP Const. Michelle Mosher told the Calgary Herald. RCMP received the vandalism complaint on Jan. 15. Damage is estimated between $500,000 to $700,000. As the pipeline was under construction, no product was spilled, according to officials. “Sometimes in remote areas the people who live in the areas recognize different people and different vehicles that they don’t normally see,” Mosher told the Canadian Press. “If there’s any suspicious people or things, please come forward with that information.”

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BC will receive $25 billion to $50 million a year from Kinder Morgan Canada over two decades for environmental initiatives and a guarantee that B.C. workers will get priority for construction jobs during the $6.8 billion Trans Mountain pipeline twinning project. In making those commitments, Kinder Morgan has met the last of five conditions that B.C. established for supporting any oil pipeline B.C. GOVERNMENT PHOTO project, Premier Christy Clark said last week, after announcing Premier Christy Clark and B.C. Environment Minister Mary Polak announcing her government had issued green light for Trans Mountain expansion. the project an environmental certificate. ruled at the beginning of 2016 Morgan Canada president Ian The environmental certificate that the B.C. government still had Anderson said in a news release. B.C. issued last week comes with to issue its own environmental Clark said her government 37 conditions over and above certificate, even though it could had reached agreements on two the 157 set by the National rely on the federal NEB review main points. Energy Board (NEB). process for its decisions. “First, that [Kinder Morgan The B.C. government had Kinder Morgan welcomed Canada] will put British hoped to avoid having to B.C.’s support of the project, Columbians first when it comes do its own environmental which presumably means it to hiring for building and assessment on the pipeline thinks it will have no problem maintaining this project – that project. That became possible meeting the additional 37 they will make sure that top in 2012, when the federal conditions. qualified British Columbians government streamlined federal “We believe this represents are the ones that get these jobs environmental approvals, a positive outcome for our and contracts in our province. allowing provinces to substitute company, customers and for And two, that we will have their environmental reviews British Columbians and all an unprecedented revenuewith federal ones to avoid Canadians who will benefit from sharing agreement with Kinder duplication. the construction and operation Morgan.” But the BC Supreme Court of an expanded pipeline,” Kinder

• PIPELINE NEWS NORTH

JANUARY 20, 2017

OPERATIONS Amid overdose ‘crisis,’ oilfield medics prepare for fentanyl JONNY WAKEFIELD reporter@dcdn.ca

Just over a year ago, a 20-yearold man was found unresponsive in his room at a worker camp in Wonowon, a hub of oil and gas activity 88 kilometres north of Fort St. John. Housekeeping staff discovered the man “in a standing position, partly bent over the sink in his room” according to a coroner’s report, after he failed to report for work on Oct. 26, 2015. The medic on site called B.C. Ambulance Service crews in Fort St. John, who declared the man dead shortly after arriving at the camp. A $5 bill located in the room later tested positive for drug residue. A toxicology analysis in Vancouver found lethal amounts of cocaine and fentanyl in the man’s bloodstream. The man’s death occurred six WILL NORTON PHOTO months before B.C.’s provincial health officer declared a state of Anthony Stark of StarkLight Medical says emergency in response to a rise in oil and gas companies increasingly want fatal overdoses, and was an early overdose response plans in place. sign that fentanyl had found its way to the province’s oilpatch. The industrial medics who they’re increasingly expected to be oversee health and safety on B.C.’s trained in overdose response. remote oil and gas sites say that That includes administering while these types of overdoses are naloxone—the life-saving drug still uncommon, they’re preparing that blocks the effects of opioids. for more. “It’s becoming more popular just “For the medic in the field, they for the general public,” said Peter get it drilled in their head to treat Sidoruk, training manager with for cardiac arrest, for (breathing Dawson Creek’s Mountainview difficulties), for hypothermia, Safety Services. “They want which can look very similar to everybody to be trained in the early stages of drug abuse or naloxone.” overdose,” said Anthony Stark, Mountainview employs 40who runs a small oilfield medic 60 people, some of whom are company in Dawson Creek. paramedics already trained in In the first ten months of naloxone use. 2016, Northeast B.C. had 11 fatal As of this year, however, the overdoses linked to fentanyl. company is training its lower-level It’s hard to say whether any of industrial first aid and emergency those occurred on oil and gas sites. medical responders to administer Due to the volume of overdoses, the naloxone. BC Coroners Service has stopped “We’ve made the addition of treating overdoses as “one-off” naloxone training just more as a events, making it difficult to find reference, rather than ‘you’re going out where individual overdoses to have to use this in industry,’” he occurred. said. “But we’re preparing for the However, health and safety worst.” companies in Northeast B.C. say Stark, who employs a handful

JONNY WAKEFIELD PHOTO

Peter Sidoruk of Mountainview Safety Services demonstrates a naloxone kit at the company’s Dawson Creek office. Oilfield medics are preparing for the threat posed by fentanyl, the powerful opioid responsible for hundreds of overdose deaths in the province.

of medics through his company StarkLight Medical, says oil and gas companies increasingly want plans in place for overdoses on job sites. Because fentanyl can be laced in other recreational drugs, many of those overdoses can be accidental. Fentanyl can also be absorbed through the skin, Stark said, meaning medics have to take extra precautions to protect themselves “Statistically speaking, (overdoses) are going to start to occur no matter how good the oil company’s defences are,” he said. Those companies have beefed up those defences in recent years. In 2012, a Northern Health report on worker camps near Fort St. John found drug and alcohol abuse “can be a prevalent part of

life” in camps, some of which had “an atmosphere of partying all night.” Since then, companies have cracked down on drugs and alcohol. Most new worker camps are “dry,” and have strict drug policies. Many employ drugsniffing dogs and require monthly testing, and anyone found with drugs can be dismissed on the spot. Stark said that with people returning to work after an extended downturn, medics need to be ready. “You can’t minimize it,” he said. “You might say ‘oh that’s not going to happen on my worksite,’ because accidental overdoses on the street in Dawson are becoming more common.”

JANUARY 20, 2017

PIPELINE NEWS NORTH •

OPERATIONS

B.C. refineries target oversupplied market NELSON BENNETT Business in Vancouver

When the federal government killed the Northern Gateway pipeline project in November, residents of Kitimat, where it would have terminated, were happy with the decision. The District of Kitimat even published an open letter to Canadians in newspapers ROB KRUYT PHOTO applauding the decision. If any oil Samer Salameh, executive chairman of the moves through Kitimat, it should be Pacific Future Energy project. through a refinery, the district said. “Kitimat supports value-added opportunities across the nation that growing throughout Asia, so is its benefit our economy at the same refining capacity. time as reducing environmental Most of the world’s new refineries risks, including proposed oil in the past decade have been built refineries and LNG terminals in the in Asia and the Middle East. Twenty Kitimat region,” the district wrote. new oil refineries were planned That’s the kind of community for Asia between 2014 and 2018— support B.C. media mogul David seven in China and three in India, Black will need to raise the $10 according to a 2014 Gaffney, Cline & million he needs just to get his Associates analysis. $18 billion Kitimat Clean refinery Countries like China are proposal through the environmental prepared to over-invest in refining review process. capacity because they want the It is one of two export refineries energy security refineries provide. proposed for the Kitimat region Refineries are also a critical part and likely would never have been of the petrochemical industries in contemplated were it not for India and China. Northern Gateway, because Kitimat “For Canada to develop its own Clean was pitched as a better refining capacity now would be to alternative to an oil pipeline. increase the global overcapacity However, West Coast refineries problem and make a high-cost, built to serve Asian markets could upfront investment into a global face some challenges. While demand market that’s probably oversupplied for refined petroleum products is for some time to come,” David

Peace River thermal terminated DEBORAH JAREMKO JWN Energy

Penn West Petroleum is the third oilsands company in the last two months to ask that the Alberta Energy Regulator (AER) cancel a project— and the second to do so in the Peace River region. Penn West has been operating the Harmon Valley cyclic steam stimulation (CSS) pilot near Peace River since 2011. The project averaged about 115 bbls/d between January and November 2016, according to AER data. This week the company applied to the AER to terminate the project, stating that the pilot phase is now complete. “The ongoing data collected during the cyclic thermal operations has

been determined to be of sufficient quantity and quality to enable future technical evaluations, modelling and economic analyses associated with a potential commercial scheme,” the company said. “Penn West believe that continued thermal steam stimulation cycles would not yield incremental data of sufficient quantity or quality to change the outcome of future technical evaluations.” In early January, Murphy Oil filed a letter with the AER requesting the application for its Seal thermal project in the Peace River region be rescinded. In mid-December, Koch asked that the AER rescind approvals for its proposed Muskwa SAGD project south of Fort McMurray, citing economic and regulatory uncertainty for the decision.

Elmes, a professor at the Warwick Business School’s Global Energy Research Network, told Business in Vancouver. Any North American refinery that would make petroleum products for the Asian market would also be trying to sell into markets that use price controls that keep fuel prices below market value. “You will likely have to find a buyer willing to provide a long-term agreement for fair market value for your product, and many of these countries have regulated refined product prices or pump prices that may pose a difficult hurdle to striking a favourable deal,” said Kevin Birn, crude oil supply and markets analyst for IHS Markit. But Jacques Benoit, chief operating officer for Pacific Future Energy, points out that Chinese companies invested heavily in the Canadian oilsands with the expectation of getting access to Alberta oil via new pipelines, one of which will not be built. China

National Offshore Oil Corp., for example, acquired Alberta oilsands producer Nexen in 2013 for $15 billion. “They probably would prefer to have it as raw bitumen, but they can’t get at it, so they’ll take it as gasoline and diesel,” Benoit said. “We’re taking the feedstock from Chinese companies here in Alberta who have invested heavily into the oilsands, and who want access to their product. Right now that’s stranded in Alberta. Secondly, it’s going to the U.S., so they’re not happy with that.” Though he has nothing in writing, Black said he has been given verbal assurance from potential buyers and investors in China that they will buy Kitimat Clean’s petroleum products. “They left me with no uncertainty as to the fact that they would be delighted to buy it, if it’s cheaper than they can make it, because then they can lock in a source of refined fuel from Canada for 100 years or so,” he said.

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JANUARY 20, 2017

INVESTMENTS

AltaGas to begin construction on Ridley propane export terminal this year AltaGas will proceed with building its Ridley Island Propane Export Terminal, a $500 million facility that would export 1.2 million tonnes of propane a year to Japan and other Asian markets from Ridley Island. The company announced its positive final investment decision on Jan. 3, saying the project will be the first propane export facility on Canada’s west coast. Construction is expected to begin early this year with an in-service date in 2019. The terminal, near Prince Rupert, will cut shipping distances to Asian markets to 10 days from 25 compared the U.S. Gulf Coast, the company says. “Propane exports off of Canada’s west coast pulls together our vision of offering Canadian producers a complete energy value chain,” AltaGas President and CEO David Harris said. “Together with our northeast B.C. infrastructure, once the Ridley Export Terminal is built and operating, we will give producers new access to premium Asian markets for their propane.” Between 200 and 250 workers will be hired to build the facility, with up to 50 permanent positions once operational. The company has previously said the plant is a key “building block” in its plan to “build out” natural gas processing capacity in the Montney gas field in B.C. and Alberta. Astomos Energy Corp., Japan’s largest buyer of liquefied propane gas, has signed a memorandum of understanding for 50 per cent of the terminal’s 1.2-million tonne output. The remaining 50 per cent is set to be supplied by producers and aggregators in western Canada, the company says, adding it expects to underpin at least 40 percent of the terminal throughput under tolling arrangements with producers and other suppliers. Consultations continues with First Nations whose traditional territory is located in and around the terminal, Harris said. “Collaborating closely with First Nations and communities to create sustainable social value is of paramount importance to us and we look forward to a long and mutually beneficial relationship with the First Nations in the region,” Harris said. AltaGas currently operates a propane export facility in Ferndale, WA. —Pipeline News North

A rendering of the AltaGas Ridley Island Propane export terminal.

Drilling activity could rise with AltaGas propane export plans JONNY WAKEFIELD reporter@dcdn.ca

A propane export terminal on B.C.’s West Coast will give producers new access to world markets, but an industry group says it’s too early to say what impact the project will have on Northeast B.C. On Jan. 3, AltaGas announced its plan to build a $450-$500 million propane export terminal on Ridley Island near Prince Rupert—the first such facility on Canada’s Pacific coast. Half of the 1.2 million annual tonnes of propane will be sourced from AltaGas’s Townsend facility north of Fort St. John, which the company announced it was upgrading late last year. “Talking to the producers, things are kind of getting landlocked up there in the northeast, so anything that

provides another outlet for one of their commodities is a huge advantage,” said Dan Woznow, AltaGas vice president of energy exports. “This is one portion of the gas, the propane, but if (producers) can get a higher value for that, that may open up other opportunities for drilling in the upstream.” The Ridley Island facility will be just ten days from Asian markets, compared to 25 days from competing facilities on the U.S. Gulf Coast. AltaGas operates a similar propane export facility in Ferndale, WA. While the terminal, will provide an outlet for Northeast B.C. propane, Energy Services B.C. Executive Director Art Jarvis said it was too early to say what impact the facility will have on the region. The facility will be supplied by rail and road instead of a fixed pipeline, meaning AltaGas

will source the remainder of its product wherever it can get the best price. “It’ll be all about price, wherever they can buy that propane the cheapest,” said Jarvis, whose organization represents energy industry contractors in Northeast B.C. “As for local impact, we won’t see that until we see what the market is doing and where the price is going.” Local leaders have stressed the need to find other outlets for the regions natural gas and other commodities should the province’s liquefied natural gas plans stall. AltaGas decided to shelve its Douglas Channel LNG project last year due to low prices. Construction on the Ridley Island facility is expected to start this year. It will create 200 to 250 construction jobs, as well as 40 to 50 permanent jobs.

JANUARY 20, 2017

PIPELINE NEWS NORTH •

LNG

Petronas considering new site for PNW LNG NELSON BENNETT Business in Vancouver

Petronas may be considering an alternative site for its Pacific NorthWest LNG export terminal, according to Bloomberg News. PNW LNG spokesman Spencer Sproule said the company is reviewing the project, but would not confirm the company is specifically looking at Ridley Island for a terminal site. “Pacific NorthWest LNG is conducting a total project review over the coming months,” he said in an email. “During this time, the project is continuing to work with area First Nations, stakeholders, and regulators, to manage any potential impacts through mitigation measures and design optimization.” The $11 billion liquefied natural gas (LNG) project in Prince Rupert has been plagued by delays and controversy, partly due to the site Petronas chose. The PNW LNG proposal calls for an LNG plant to be built on Lelu Island,

with the liquefied natural gas being piped to a terminal off Flora Bank, via a suspension bridge. Flora Bank is ecologically sensitive. Flora Bank’s eelgrass beds are important salmon habitat, and the project has been vigorously opposed by local Tsimshian First Nations. Some First Nations have occupied Lelu Island with a protest camp. Citing anonymous sources, Bloomberg has reported that Petronas is now considering moving the export terminal to a site on nearby Ridley Island, which is managed by the Prince Rupert Port Authority. That site only became available when Canpotex Ltd. abandoned its plans in June to build a new potash export terminal on Ridley Island. Colin Coe, an energy consultant specializing in LNG projects, says the rumour that Petronas was considering an alternative site has been making the rounds in the industry for a while now. Moving the export terminal away from Flora Bank to Ridley Island would

make some sense, he said, although it would likely require going back to the drawing board with respect to the environmental permitting the project has already completed. Building a suspension bridge across Flora Bank would be expensive. It is estimated that locating the export terminal on Ridley Island could save the company about a $1 billion, if it did not have to build the suspension bridge across Flora Bank. “It’s probably prudent that they looked at it,” Coe said. However, he added it’s no easy task to switch sites, once all the engineering is done and environmental permitting obtained. “Sometimes companies move in and chose a site and they’re kind of locked and loaded to go through that process, and once you start your work on a specific site it’s not a trivial matter to move that site,” Coe said. “It’s a big job to go through and change the site.” But with oil and gas prices depressing Asian LNG prices, it

makes sense to try to get the project’s capital costs down, and choosing a site that does not require a $1 billion suspension bridge might go some way in accomplishing that. When LNG projects were first proposed for B.C., there was some urgency in getting them approved and built, since the companies were in a race to lock up long-term offtake agreements with Asian buyers. But those projects missed the last window, and there is now an oversupply of LNG on the market, thanks in part to new LNG projects now in production in Australia. The demand for LNG in Asia has also slowed somewhat. Analysts now predict the next wave of demand for LNG in Asia will occur between 2025 and 2030. It takes about four to five years to build an LNG plant and associated pipelines, which is why some experts do not expect to see final investment decisions on any large LNG projects until around 2018 or 2019.

LAND/ REGULATORY ENVIRONMENTAL ARCHAEOLOGY GIS ANALYSIS & MAPPING UAV AND REMOTE SENSING

roynorthern.com TERRACE FORT ST. JOHN PRINCE GEORGE FAIRVIEW

• PIPELINE NEWS NORTH

JANUARY 20, 2017

INVESTMENTS

Townsend Phase 2 gets go-ahead as AltaGas plans for ‘significant growth’ in 2017 DEBORAH JAREMKO JWN Energy

Next year AltaGas will spend the majority of its planned capital budget of up to $550 million on growth projects, the company said today. This includes doubling the size of its Townsend gas processing facility in northeast B.C., a project that received regulatory approval from the British Columbia Oil and Gas Commission on December 19. The project is expected to be fully contracted with Painted Pony Petroleum under a 20-year take-or-pay agreement. The estimated cost of Townsend Phase 2 is approximately $85 to $95 million, plus $35 to $45 million for incremental field compression equipment to move raw gas production from the Blair Creek area to the facility. Long-lead major equipment has been ordered and Townsend Phase 2 is expected to begin commercial operations in October 2017, AltaGas said. Next year the company’s gas business will account for approximately 65 - 70 percent of its total capital spend, while its utility business will account for approximately 20 - 25 percent and the power business will account for 5 - 10 percent. The company expects maintenance capital for gas and power will be approximately $15 $20 million for 2017. The majority of the capital spend relating to AltaGas’ gas business will be allocated towards growth projects including its proposed Ridley Island Propane Export Terminal, Townsend Phase 2 and the North Pine Facility and North Pine Pipelines. The proposed Ridley Island Propane Export Terminal located near Prince Rupert, British

AltaGas’ existing Townsend facility in northeast British Columbia.

Columbia is expected to be the first propane export facility off of the west coast of Canada, designed to serve growing demand in Asia while offering a new market for Canadian producers. It will be designed to ship 1.2 million tonnes of propane per year and is estimated to cost approximately $450 - $500 million. All documentation required for the project’s environmental approval has been submitted and is still under review. Site preparation at the North Pine facility near Fort St. John is expected to commence in the first quarter of 2017. AltaGas sanctioned the project, a 10,000 bbl/d natural gas liquids separation train and

associated supply pipelines, in October 2016. It has a target commercial on-stream date in the second quarter of 2018. “2017 will be a significant growth year for AltaGas as we continue to build out our northeast B.C. infrastructure and continue development of Canada’s first ever west coast propane export terminal,” AltaGas president and CEO David Harris said in a statement. “We will continue to advance our strategic initiatives and look forward to capitalizing on these opportunities.” The capital budget of up to $550 million is in line with the company’s 2016 expectations of $550 million in capital spending.

Veresen sanctions additional $195-million in capital projects at Veresen Midstream Versen Inc. announced the sanction of $195 million ($93 million net to Veresen) in new capital projects at Veresen Midstream. “With the sanction of this additional capital, Veresen now has over $1.4 billion of projects under construction,” said Don Althoff, president and CEO of Veresen. “We expect these capital projects to deliver incremental per share growth as Veresen remains fully funded without the need to access capital markets. As Veresen Midstream’s capital projects come into service, the significant increase in cash flow will reduce Veresen’s leverage and bolster our financial flexibility to fund new growth opportunities generated

from our strong footprint in the heart of the Montney play.” Two new projects have been sanctioned by the Cutbank Ridge Partnership (CRP) to facilitate ongoing development plans while also minimizing total infrastructure costs and surface footprint. The South Central Liquids Hub project has been sanctioned to allow the existing gathering system in the area to handle development anticipated over the next several years and is expected to be in service by the end of the second quarter of 2017. The South Central Liquids Hub can be expanded in the future to meet CRP’s long-term liquids handling needs as well as provide services to

third party producers in the area. The Tower Liquids Hub has also been sanctioned to provide a lower overall cost and more commercially flexible solution for the handling and storage of NGLs produced at the Sunrise, Tower and Saturn Phase II processing facilities. The project includes infrastructure to deliver the NGLs into a third party system. The Tower Liquids Hub is expected to be in service in the third quarter of 2017. Part of the Tower Liquids Hub will include capacity to handle third party NGLs that could be either trucked in or connected directly by a future pipeline. —Daily Oil Bulletin

JANUARY 20, 2017

PIPELINE NEWS NORTH •

OUTLOOK

U.S. energy market outlook a sobering read JONNY WAKEFIELD reporter@dcdn.ca

Surging exports and a declining dependence on foreign oil are two trends the Canadian oil and gas industry would welcome—if they were happening here instead of next door. The U.S. Energy Information Administration’s Annual Energy Outlook, released Jan. 5, instead presents a grim picture for Canadian oil and gas—one where producers are increasingly competing with their largest market. The report, released Jan. 5, highlights declining foreign imports and steadily growing exports as two of the big trends in U.S. energy. A net importer of energy products since 1953, the U.S. is expected to become a net exporter of energy by 2026 thanks to a major ramp up in hydraulic fracturing. The amount of oil and gas U.S. customers pipe in from Western Canada is expected to decline through 2040, while Eastern Canada is expected to buy more American natural gas due to its close proximity to the Marcellus Shale. Meanwhile, U.S. liquified natural gas (LNG) exports are expected to surge to more than 10 billion cubic feet a day. The first shipload of American LNG landed in Japan earlier this month, raising more questions about whether B.C. LNG projects can be competitive in a flooded market. The report is troubling news for businesses in natural gas producing regions like Northeast B.C., Dawson Creek Chamber of Commerce Executive Director Kathleen Connolly said. “If the U.S. is our only customer, it’s not looking very positive for us,” she said. ”If we see what they’re talking about in terms of developing reserves in America, they’re not going to need our natural gas.” Government should focus on promoting alternative natural gas products like

petrochemicals and biofuels for use in domestic markets, Connolly said. As well, the report highlighted the need to get B.C.’s natural gas to non-American markets. Connolly also worried incoming U.S. President Donald Trump’s plan to deregulate the oil and gas industry would hurt Canadian producers. “If they strip any of their existing environmental regulations, that’s really going to open up America as somewhere that’s going to be overdeveloped,” she said. “If we’re overregulated, and they’re under-regulated, where would an investor naturally go?” Chelsie Klassen, a spokesperson with the

Canadian Association of Petroleum Producers, said the report isn’t all bad news for the Canadian energy industry. While the headlines have focused on the U.S. becoming a net exporter of energy, the country will still rely on Canadian crude oil to fuel its economy. “If you read through the details of the report, what you’ll find is the U.S. will continue to be a net importer of crude oil at seven million barrels per day,” she said. Klassen added the recent approvals of the Trans Mountain pipeline and Pacific NorthWest LNG would help diversify Canada’s energy markets.

Prices for oil, natural gas ended 2016 on a high note After a dismal year, both crude oil and natural gas ended 2016 with prices reaching the highest levels of the year. During the month, producers benefited from an agreement among members of the Organization of Petroleum Exporting Countries to curtail production. Net Energy Inc. Western Canada Select (WCS) near month prices gained 21.7% to US$37.28 per barrel (bbl) for the month from $30.63 a bbl in November and were up nearly 57% from $23.77 a bbl in December 2015. However, prices for the year averaging $29.66 a bbl were down 16.6% from the average Net Energy WCS price of $35.56 in 2015 and were the lowest since the DOB began

tracking Net Energy prices in 2011. Net Energy Sweet averaged $48.37 per bbl in December, up 15.8% from $41.78 a bbl in November and 43% from $33.81 a bbl a year earlier. Prices for the year averaged $40.26 a bbl compared to $45.08 per bbl in 2015. Net Energy Syncrude prices also improved in December, gaining 16.5% to $51.12 a bbl from $43.89 per bbl the previous month. The monthly price was also the highest since June 2016 when Syncrude fetched an average of $51.52 a bbl as production was gradually brought back on in the wake of the Fort McMurray wildfire. Net Energy Syncrude prices averaged $44.01 per bbl in 2016,

down from $48.82 a bbl the previous year. On the natural gas side, AECO spot gas prices averaged $3.23 a gigajoule in December, up nearly 22% from $2.65 per gigajoule in November and 47.5% from the December 2015 average of $2.19 per gigajoule. However, the 2016 average price of $2.06 per gigajoule was the lowest in at least 15 years, down nearly 20% from $2.57 per gigajoule in 2015 as stronger second-half prices (including a fourth-quarter average of $2.95 a gigajoule) weren’t enough to offset first-half 2016 prices averaging $1.55 per gigajoule. On the New York Mercantile Exchange, natural gas futures prices were up 24% to US3.58 per mmBtu

from $2.88 per mmBtu in November as cold weather drew down gas in storage. Prices also were up 75.5% from the December 2015 average of $2.04 per mmBtu when growing shale gas volumes combined with milder than average temperatures resulted in brimming storage inventories. NYMEX gas prices averaged $3.18 per mmBtu in the fourth quarter of 2016, climbing throughout the year from the first quarter low of $1.99 per mmBtu. Gas fetched an average of $2.56 per mmBtu in 2016 compared to $2.64 per mmBtu in 2015. —Daily Oil Bulletin

• PIPELINE NEWS NORTH

JANUARY 20, 2017

EDUCATION

Provincial funding puts pipeline craft, wildlife training on the syllabus for Doig River FN Industry Training, while the University of Northern British Columbia will lead the wildlife monitoring certificate program in the Doig community. The funding is being provided through the province’s $30-million Aboriginal Skills Training Development Fund. “This project will provide Doig River First Nation participants with the training needed to work as skilled, certified and safe natural gas pipeline construction workers and wildlife monitors who maintain the safety of crews working in wilderness environments, and keep them aware of the wildlife around them,” provincial Aboriginal Relations and Reconciliation Minister John Rustad said in a statement.

The province is contributing $144,000 in funding to train members of the Doig River First Nation in pipeline craftsmanship and wildlife monitoring. The funds have already helped trained 10 members in pipeline craftsmanship, with eight employed with Surerus Pipeline on the $235-million Plateau pipeline project, according to the province. “This community-based skills training project is successfully connecting Doig River First Nations members to good jobs in the resource sector and helping to build a better future for all of us,” Doig River Chief Trevor Makahaday said in a statement. The training programs will support 21 Doig members, according the province. The pipeline training is conducted in Fort St. John by Ready4Work

—Pipeline News North

UNIVERSITY OF NORTHERN BRITISH COLUMBIA PHOTO

The University of Northern British Columbia will lead a wildlife monitoring program in the Doig River First Nation community.

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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.

JANUARY 20, 2017

PIPELINE NEWS NORTH •

ETC.

Northern Gateway rejection solves Regional district signs off on Chinook worker camp Kinuseo Falls question mark JONNY WAKEFIELD reporter@dcdn.ca

Leaders in Tumbler Ridge say they’re disappointed over Justin Trudeau’s rejection the Enbridge Northern Gateway pipeline, but the decision brings to an end uncertainty over the line’s impact on the region’s most famous waterfall. Northern Gateway, officially rejected Nov. 29 alongside federal approvals for Kinder Morgan’s Trans Mountain expansion and Enbridge’s Line 3, would have passed near Tumbler Ridge on its 1,170-kilometre route between Bruderheim, Atla., and Kitimat. Mayor Don McPherson said he was disappointed with the news, saying the project would have provided jobs at a time of uncertainty for the region’s coal industry. “It would have supplied some employment, and as you know, that’s very important to us,” he said. However, Northern Gateway would have included a crossing on the Murray River downstream from Kinuseo Falls, 65 kilometres south of Tumbler Ridge.

The route initially included a bridge to carry the pipeline over the Murray, which would have impeded views of the falls—one of the most popular sites in the district’s Global Geopark. However, McPherson said the latest design for the project included a pipeline crossing beneath the river. While hypothetical now, it’s not clear which option Enbridge would have adopted. “Their footprint through our parks network would have been very small, so we were for it,” McPherson said. Jerrilyn Schembri of the Tumbler Ridge Chamber of Commerce said that besides the questions over the impact on Kinuseo Falls, local businesses were largely in favour of the project. “Most people were relatively in favour of it, there were some questions over one of the crossings they were going to do and that was a concern for some people,” she said. “But I think as a general feeling the chamber was supportive of it, so they’re disappointed.”

JONNY WAKEFIELD reporter@dcdn.ca

A proposed worker camp northwest of Fort St. John received approval from the Peace River Regional District at a meeting earlier this month. On Jan. 12, the board signed off on a 144-person worker camp in Nig Creek on the Beatton River Airport Road. According to a regional district report, applicant Chinook Energy Inc. needs the camp to house workers on drilling, completions, and facility construction projects in the region. The company owns mineral assets in the nearbly Birley area. The camp would not allow alcohol or drugs, and would reduce traffic and driving times on the Alaska Highway to Fort St. John, the company says. The site was previously used as a tree-planting camp. The camp would include bedrooms with private washrooms, potable water and sewage treatment plans, and a fuelling station for vehicles. The board issued a three-year temporary use permit for the project Jan. 12. Because no single agency is in charge of worker camp permitting, it is difficult to say how many such camps there are in Northeast B.C.

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