Special Report: Economics vs. Environment: B.C.’s carbon capture conundrum /22 JANUARY / FEBRUARY 2016
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As winter takes hold, analysts expect companies to focus on harvesting their existing resources in place of exploration for 2016 and beyond. And in the wake of the lowest land sale totals in B.C. since 1982, LNG Canada gets a 40-year export permit, Squamish begins planning for Woodfibre LNG, and a conglomerate eyes Fort Nelson as a hub for mini-LNG facilities. South of the border, the U.S. opens up crude oil exports, and new columnist Tim Maryon looks at what that means for B.C. producers. R001697746
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NUMBERS
The following figures were taken from the stories in this issue of Pipeline News North.
1,494: Billion cubic metres of natural gas LNG Canada has been permitted to export over 40 years. Story on Page 5.
17: The number of seismic monitoring stations operated by Progress north of Fort St. John. Story on Page 14.
7,000: Cubic metres per day of water Encana expects to use in drilling four wells early this year. Story on Page 20.
$18 million: Land sale totals in B.C. in 2015. Story on Page 8.
20,000: The number of gallons of LNG expected to be produced at mini-LNG facilities planned for Fort Nelson. Story on Page 16.
2.2. million: Tonnes of CO2 produced at Spectra’s Fort Nelson plant that could be captured. Story on Page 22.
269: The number of new gas wells drilled in B.C. in 2015. Story on Page 10.
$100,000: The amount Canbriam Energy recently donated to Northern Lights College for a trades training centre. Story on Page 17.
23: Years of experience new Taylor Fire Chief Edward Albury brings to the district when he moves to town from Fort McMurray. Story on Page 30.
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justin vidamo photo
U.S. congress votes to 5 boost business
Greensmart Building 6 starts to fill up
pnn 12
2015 a rough year for B.C. 8 oil and gas land sale totals
22 Economics versus the environment: B.C.’s carbon capture conundrum
Natural gas exports dropped 12 41 per cent in 2015
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August earthquake 14 caused by fracking Fort Nelson a hub for LNG? 16 Mini LNG facilities planned
18 NEB hearings on Towerbirch pipeline to begin in spring 20 Encana gets exclusive access to treated sewer water
Drilling down in B.C., but 10 production remains high
17 Canbriam gifts $100K to NORTHERN LIGHTS college
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24 Blueberry River, TransCanada ink deal over Coastal GasLink 25 National Energy Board hearing for groundbirch 26 LNG OUTLOOK: THE $80 BILLION ENERGY QUESTION 30 From Fort Mac to Taylor
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Published monthly by Glacier Ventures International Corp. Pipeline News North is politically independent and a member of the B.C. Press Council. The Pipeline News North retains sole copyright of advertising, news stories and photography produced by staff. Reproduction is prohibited without written consent of the editor.
JANUARY 15, 2016
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opening remarks
#oilsands
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U.S. congress votes to boost business
Let’s push Canadian leaders to follow suit Tim Maryon
Special to Pipeline News North
W
ith the new year came a new law in the United States that could affect B.C.’s oil producers. For the first time in 40 years, U.S. crude oil producers can now export crude to foreign customers. This change is driven by the huge increase in U.S. domestic crude oil production over the last five years. Production of light sweet crude oil from horizontal drilling and fracking operations exceeds the capacity of U.S. refiners to process it. So inventories of light sweet crude (like benchmark West Texas Intermediate or WTI) have grown, driving down the price. In an encouraging example of give-and-take at the highest levels of government, the U.S. Congress just voted to lift the long-standing prohibition on crude oil exports to relieve the inventory overhang. So what does this mean for B.C. oil producers and what can we learn from this? 1) The selling price of our crude oil may go up. Since U.S. producers can now sell light sweet crude internationally, this will reduce the oversupply of the product in the U.S. and, over time, will lead to higher WTI prices. Since B.C. oil producers typically sell their oil pro-
duction at pricing related to WTI, this will help to increase the selling prices of B.C.-produced crude. 2) We’d be well–served to urge authorities to take note. The passage of this new law presents an opportunity for those of us in the petroleum sector to put pressure on our Canadian lawmakers and regulators to adopt a similar spirit of co-operation. The US.. government has provided constructive support to their industry. We in Canada would be well-advised to follow their lead. In Northern B.C., for example, the Pacific NorthWest LNG project is awaiting final approval. All that’s needed for the green light is an OK from the Canadian Environmental Assessment Agency. But that agency has been reviewing the project since April 2013. We need our government to adopt the U.S. model of constructive co-operation and expedite the approval of this project – bringing business growth, jobs and tax revenue to benefit all Canadians. There used to be a saying “what’s good for General Motors is good for America.” Our version of that saying right now is, “what’s good for America is good for Canada.” Tim Maryon is vice-president of sales and business development at Peace Country Petroleum in Fort St. John.
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Tenants move into refurbished Greensmart building Building sat empty since 2013
Jonny Wakefield Staff Writer
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After sitting empty for more than two years, there's new life at the old Greensmart building. On Dec. 16, the first of several new tenants moved into the sprawling, 137,000-square-foot industrial facility on Highway 2. The building, which once produced siding for modular homes, has been renamed the Gateway Industrial Park, and around 28,500 square feet of the hanger-like facility have been leased. Proline Properties bought the building at foreclosure in January, and has converted eight units into pull-through truck bays. Proline's Dixon Chow said the bays have been rented by trucking, construction and oilfield service firms. The first to move in was KEL Contracting, a Dawson Creek company. In February, Dahlen Contracting plans to move in and use the space for welding and fabrication work. Louisiana-Pacific built the facility in the
1990s as a veneer plant, but never used it. It sat empty for around a decade before it was bought by Greensmart Manufacturing, which used it to produce modular siding and worker camp shacks. The company went under in 2013, laying off around 50 employees. Dawson Creek Mayor Dale Bumstead said cheap industrial space will make the city more competitive for natural gas development. The facility is currently leasing starting at $12 per square foot. He was heartened to see "the investment confidence that these guys have displayed in our community." "The (oil and gas) industry guys tell me...for every dollar invested on the West Coast of British Columbia building an LNG (liquefied natural gas) plant, (they) will invest $7 to $10 in the upstream," he said. "The servicing of that industry, we can't do it without facilities like this." reporter@dcdn.ca
NEB hands LNG Canada first 40-year export licence
The National Energy Board has approved, subject to federal cabinet approval, LNG Canada Development’s application for a 40-year natural gas export licence with a maximum of 1,494 billion cubic metres over the term of the licence. The licence is the first 40-year natural gas export licence approved by the NEB since an amendment to the National Energy Board Act in June 2015 as well as its corresponding regulations. The amendment provides for the issuance of natural gas export licences for a term not exceeding 40 years, up from the original 25 years, if the gas to be exported meets the definition of natural gas. In 2013, LNG Canada received approval for a 25-year LNG export licence but went back to the board to ask it to consider an application for a term not to exceed 40 years. The approved export point is at the outlet of the loading arm of the $50-million natural gas liquefaction terminal to be located near Kitimat, which would liquefy natural gas from Northeast B.C. and ship it to Asia. In early January, the company became the first
LNG project in Canada to receive a facility permit from the B.C. Oil and Gas Commission. When evaluating natural gas and LNG export licence applications, the NEB said it considers if the quantity of natural gas proposed to be exported is surplus to Canadian requirements, taking into account trends in the discovery of gas in Canada. The NEB said it has determined that the quantity of natural gas proposed to be exported by LNG Canada is surplus to Canadian needs. It also is satisfied that Canada’s gas resource base, and the overall gas resource base in North America, is large and can accommodate reasonably foreseeable Canadian demand. LNG Canada is a joint venture company comprised of Shell Canada Energy (50 per cent), an affiliate of Royal Dutch Shell plc, and affiliates of PetroChina (20 per cent), Korea Gas Corporation (15 per cent) and Mitsubishi Corporation (15 per cent). The companies have not yet made a final investment decision on the project. —Daily Oil Bulletin
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City officials and potential investors toured the new Gateway Industrial Park in Dawson Creek Dec. 16. The sprawling building on Highway 2 once housed Greensmart, a manufacturer of modular home siding. The company went into receivership in 2013.
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B.C. records worst land sale totals since 1982 Jonny Wakefield
Staff Writer
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The totals are in: 2015 was the worst year for oil and gas land sales in a generation. The province auctioned off $4.2 million in drilling rights at its Dec. 9 land sale, bringing the 2015 total to $18 million. Land sale totals haven’t been that low since 1982—the days of the National Energy Program. Investors bought just $17 million in drilling rights that year. The sale is seen as an indicator of future oil and gas exploration, and land sales typically account for 30 to 70 per cent of the province’s oil and gas revenue. The December 2014 sale brought in $38 million, capping the year at $382 million. The collapse in the price of oil, anemic North American natural gas prices and uncertainty around LNG have made for a rough year in the B.C. oilpatch. Bill Gwozd, an energy analyst with HSB Solomon Associates, said exploration will likely be down for the foreseeable future. “(Companies have) defocused on the exploration aspect and are taking the existing land and trying to harvest what they’ve got, instead of going to get something new,” he said in an interview. Well completions in B.C. were down around a quarter this year, Gwozd said. “Only around seven per cent of those are exploration (wells), the other 93 per cent are development,” he said. “Ninety-three per cent of their activity is on land they already had.” In all, the province leased 62,197 hectares for drilling this year, the first time an annual total has dropped below six-digits. The average price per hectare was in the $300 dollar range, the lowest since 1999 and down from $2,574 per hectare in 2014. 2008 saw record highs in hectares disposed, average prices and overall bonuses—which reached $2.6 billion. Gwozd said he expected companies to focus on liquids-rich parcels in the Montney Shale. Companies tied to LNG projects will likely continue to drill, he said, but on existing parcels bought by land brokers at previous auctions. That means 2016 will likely continue to see weak land sales. “I would suggest 2016 will be the real worst in a lifetime,” he said. “This is just the warmup band.” Parcels are leased for terms of three to five years, depending on location. Across the border, the final Alberta sale of 2015 produced $12.57 million on 58,413 hectares at an average price of $215.25. “Overall, this [Dec. 16] land sale continued the trend of low overall bids we have come to expect during the current downturn,” said Brad Hayes, president of Petrel Robertson Consulting Ltd. “This time, however, a few sections of rights came available in the heart of the Duvernay and Montney play fairways, demonstrating that there is still substantial interest in these plays.”
JANUARY 15, 2016
PIPELINE NEWS NORTH •
year-end statistics
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Annual incomes from British Columbia’s oil and gas land sales, 1978-present. The land sale represents a large portion of the province’s income from upstream oil and gas, and money brought in through the sale goes to fund social programs and infrastructure.
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Yellow represents the portion of revenues brought in by the monthly oil and gas land sale, while red represents other oil and gas income. For 2015, the industry paid $298.74 million on 1.62 million hectares in Alberta at an average price of $184.93. For 2014, the Alberta government collected $494.03 million for 1.09 million hectares at an average of $453.46. The totals put the province at a 20-year low. —with files from the Daily Oil Bulletin reporter@dcdn.ca
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year-end statistics
bc oil and gas commission figures
In 2015, just 269 new gas wells were drilled in B.C., the lowest since 1997 when 326 wells were drilled. Despite the drop, the province produced just over 36 billion cubic metres of natural gas last year, comparable to the annual average of 38 billion cubic metres produced in the province since 2007.
Drilling down in B.C., but production remains high William Stodalka
Staff Writer
British Columbia saw the lowest number of new gas wells drilled last year than it has in nearly 20 years, according to information from the B.C. Oil and Gas Commission. Despite this, overall gas production remains high. Since 1996, the majority of new wells drilled in the province produce natural gas. In 2015, just 269 new gas wells were drilled, the lowest since 1997 when 326 wells were drilled. Last year, the province pro-
duced just over 36 billion cubic metres of natural gas. Since 2007, the province has averaged about 38 billion cubic metres of natural gas per year. OGC spokesman Alan Clay said he would have to see final year-end numbers before commenting, as some December numbers could still be arriving. “One factor would be that new gas wells have above average initial production rates compared to previous average vertical conventional wells,� he said. Since 1996, the province has seen an average of 611 new gas wells drilled annually. This
means that the number of new gas wells drilled went down by more than half the 20-year average in 2015. Oil wells have also dipped over the past 10 years, reaching their lowest point last year when only 25 oil wells were drilled. Since 2005, the province has seen about 39 oil wells drilled annually. Including all other types of wells, including service and cased wells, there were 518 wells drilled in 2015. Since 2011, the province has averaged about 585 wells drilled. reporter@ahnfsj.ca
Last year, the province produced just over 36 billion cubic metres of natural gas. Since 2007, the province has averaged about 38 billion cubic metres of natural gas per year.
JANUARY 15, 2016
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year-end statistics
Natural gas exports dropped 41 per cent in 2015 Jonny Wakefield
Staff Writer
Despite sending more natural gas south of the border, the value of B.C. energy exports saw a steep drop in 2015, according to a new report from BC Stats. Natural gas led the way with a 41 per cent decline, owing to falling prices driven by a supply glut. The report, released Jan. 6, compared the first 11 months of 2015 to the same period the year before. Natural gas fell from just under $9 U.S. in early 2014 to lows of under $2.50 through much of last year. “In the case of natural gas, lower prices for the product was the reason for the drop in value, as the quantity shipped actually climbed 1.7 per cent,” the report states. It was a bad year all around for energy exports, which fell 24.4 per cent year over year. Coal and other energy products, including oil, fell 16.3 per cent and 30.9 per cent, respectively. Electricity exports, however, grew 29.4 per cent. The fact that the quantity of gas grew while incomes shrank is explained by demand, said Art Jarvis of Energy Services B.C., an upstream oil and gas industry association. “Exports are directly tied to demand. Cold snaps have the biggest responsibility for higher consumption, of course,” he said. “That would be my suspicion (for why export volumes grew)—a cold month.” He added that producers are often locked into long-term contracts with transmission companies, meaning they have to supply a given amount of gas per day regardless of price. 2015 saw some of the weakest oil and gas land sale totals in recent memory, totaling just $18 million. The coming year looks grim too, he said. “Definitely the word from (producers in) Calgary is 2016 is going to be as bad. There’s no real positive news out there right now,” he said. B.C. largely insulated from weak commodity prices Despite falling commodity prices, overall B.C. exports were flat, “edging up only 0.1 per cent.” A 4.5 per cent growth in shipments to the U.S. offset weak demand in Mainland China, where exports fell 6.4 per cent. Also down were Japan (-3 per cent) South Korea (-13.7 per cent) the European Union (-6.8 per cent), and Hong Kong (-14.1). The biggest gains were in India, Taiwan and Mexico. B.C. exports to Mexico leaped 73.4 per cent last year. Overall, it was a good year for the forestry industry, which saw exports grow 3.8 per cent. Softwood shipments grew by two points, led by double-digit growth in veneer, plywood and panel product exports. Mineral mining was down overall, largely due to drop-offs in molybdenum ore, zinc ore, unwrought aluminum and metallic mineral product shipments. That’s despite a 1.9 per cent increase in copper ores and concentrates, which account for nearly two-thirds of B.C. mineral exports. Food product exports climbed 19.4 per cent, but that’s didn’t necessarily translate into gains for Peace Region producers. While fruit and nut, vegetable, cereal and other product shipments were up as much as 35 per cent, there was little joy for vegetable oil and meat producers. According to the report, exports of those products were down 0.7 per cent and 7.5 per cent respectively. reporter@dcdn.ca
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operations
August earthquake caused by fracking: OGC Jonny Wakefield
Staff Writer
Fluid injection during hydraulic fracturing caused a 4.6 earthquake north of Fort St. John this summer, the B.C. Oil and Gas Commission (OGC) has found. The regulator released a report on the Aug. 17 quake on Dec. 15. There were reports of shaking from the epicentre north of Wonowon to Charlie Lake, just outside Fort St. John. “The event was the largest seismic event in B.C. caused by hydraulic fracturing investigated by the commission,” OGC spokesperson Alan Clay wrote in an email. “We can’t speak for (quakes in) other jurisdictions.” The quake occurred on a well site where Progress Energy was fracking, the OGC said in an industry bulletin. The company completed the job using reduced pumping rates. According to the commission, a 4.6 quake will cause “brief shaking felt at the surface,” but does not pose a risk to people or the enviPipeline News.fh10 1/6/16 12:27 PM Page 1
ronment. There were no reports of damage or injuries at the surface. An earlier OGC report tied 231 seismic events in the Montney shale formation between August 2013 and November 2014 to oil and gas activity. Only 11 of those could be felt at the surface, and only two events in the Upper Montney were greater than 3.5 magnitude. Progress Energy, a downstream subsidiary of Petronas, is among the most active drillers in B.C. The company drilled 203 wells in 2014— roughly 30 per cent of all wells drilled that year. The company is proving resources ahead of a final investment decision on Petronas’s Pacific NorthWest liquefied natural gas plant in Prince Rupert. According to minutes of a community meeting in Pink Mountain, Progress’s activity contributes to roughly 2,800 jobs in the region. They plan to run between 10 and 15 rigs “consistently over the next few years.” The commission says it stepped up monitoring of seismic events in recent years, and now
requires any driller that causes an earthquake greater than 4.0 magnitude to stop operations. The well did not leak, Clay said. This summer, the OGC announced a 4.4 quake in August 2014 was also caused by Progress fracking operations. It was among the strongest fracking-induced quakes ever recorded at that time. “The commission recognizes these events are a concern to the public and is working to ensure there is no risk to (the public), by implementing effective regulatory measures and mitigation procedures to reduce the frequency and magnitude of induced events,” Clay wrote. Progress spokesperson Stacie Dley said the company has 17 seismic monitoring stations in the area. “We will continue to be diligent and monitor our activities and adjust our operations as needed, such as decreasing fluid volume and pressure,” she wrote in an email. reporter@dcdn.ca
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Above: A drilling rig north of Fort St. John. Fracking operations caused one of the largest magnitude earthquakes on record this August, the B.C. Oil and Gas Commission announced Dec. 15. Below: The location of the earthquake. R0011080173
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investments A video screenshot of KT Energy’s proposed mini LNG modular plant system.
Fort Nelson a hub for LNG?
conglomerate plans mini-LNG facilities William Stodalka Staff Writer
A conglomerate of seven Chinese companies and one Canadian company is looking to build miniature LNG facilities in Fort Nelson. Kai Tian Energy Group (KT Energy) has outlined preliminary plans for the facilities on its website, however, would not elaborate on its plans when contacted Jan. 6. “We don’t have anything definite to be announced to the public for now,” said a woman who answered the telephone at KT Energy Vancouver office, and who declined to give her name. “When time is appropriate we will contact you and give some information.”
On its website, KT Energy says it plans to build several “mini LNG modular plants” to meet Canadian domestic demand. The first plant is proposed for Fort Nelson, the company states, with an initial production of 20,000 gallons per day in its first phase. That would increase to 60,000 gallons per day in its second phase, the company states. “We have the ability to build Mini LNG Modular Plants close to customers to meet their specific applications, which will significantly reduce costs and ensure a stable supply of LNG,” the company says, adding “it provides more economic and environmental friendly energy choice to the customers in Northern B.C., Yukon and Northwest Territories. The company’s website states that its first
production is expected to come by the end of the year. A listing on the website shows KT Energy is made up of seven Chinese companies and another one established last year in Vancouver. The Environmental Assessment Office has not received an application from KT Energy, according to a spokesperson with the Ministry of Environment. “If the company decides to proceed with the project, the Environmental Assessment Office is available to meet with KT Energy Corp. to review information about the proposed project and discuss how the Environmental Assessment Act may apply,” the spokesperson said. reporter@ahnfsj.ca R001697755
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MIKE CARTER photo
Canbriam gifts $100K to college for training centre
Mike Carter
Staff Writer
Canbriam Energy Inc. donated $100,000 to Northern Lights College Dec. 22. The money will go towards a fund for a proposed trades training centre. With combined donations from Shell Canada, Encana Corp. and TransCanada, the college now has about $800,000. “Canbriam Energy believes that a modern learning environment will increase long term opportunities for certified trades personnel,” said Donna Phillips, Canbriam’s executive vice president of corporate development. NLC president and CEO Dr. Bryn Kulmatycki said progress towards making the proposed
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centre a reality is possible because of donations like this one. “We appreciate the support,” he said. The province is investing $185 million in new infrastructure and equipment to support trades and skills training. NLC offers two intakes each year for Foundation Trades programs in September and February with various start dates for its apprenticeship programs. The proposed new trades training building came into the conversation after B.C.’s Minister of Advanced Education Andrew Wilkinson visited the Dawson Creek campus in July. “The facilities that exist now in Dawson Creek were built post-World War Two,” he said during his visit. “They are old, they are de-
ficient in terms of power supply (for training equipment). Some of our large equipment is unable to take the power supply with the current wiring.” The buildings formed a portion of Canada’s Distant Early Warning radar system during the Cold War. In the wake of significant private investment, which is a success story for the college, funding from his ministry has yet to be announced. The northeast is critical to the province, Wilkinson said. “We need to make sure that we’ve got skilled people out there who can continue to contribute to that.” dcreporter@dcdn.ca
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pipelines
NEB hearings on Towerbirch pipeline to begin in spring
Mike Carter Staff Writer
The National Energy Board has approved a list of participants, commentators and intervenors who will take part in a 15-month hearing on the Nova Gas Transmission Line (NGTL) Towerbirch expansion project. At the end of the hearing, a three-member panel will make recommendations and decisions on whether the project should proceed and under what conditions. The need, economic feasibility, potential commercial impacts, appropriateness of the general route, as well as the potential impacts on aboriginal interests and landowners are among the 12 issues that will be considered at the hearing. The NEB’s report will be filed no later than March 22, 2017. NGTL, a wholly-owned subsidiary of TransCanada Corp., is proposing to add a northbound expansion line to its existing Groundbirch Mainline Loop. The project will involve the construction of
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87-kilometres of new gas pipeline and associated facilities. Open houses on the project were held in Groundbirch and Bonanza in August. The NEB says it believes the project is “likely” to affect four species listed on Schedule 1 of the Species At Risk Act. These include: the Canada warbler, olive-sided flycatcher, yellow rail and the Western toad - all of which are listed as either “threatened” or of “special concern.” Among the intervenors are the Fort St. John Metis Society, Metis Nation of British Columbia, Saulteau First Nations and West Moberly First Nations. Several energy companies have also applied and been granted intervenor status, including Cenovus Energy Inc., ConocoPhillips Canada, the Cutbank Ridge Partnership, Progress Energy Canada Ltd. and Talisman Energy Inc. The Canadian Association of Petroleum Producers will also have a voice in the hearing as an intervenor. Arc Resources, BC Metis Federation, Black Swan Energy, Canbriam Energy Inc., Environment Canada and Health Canada are among
the 13 commenters. Intervenors will submit written comments, ask questions in writing about evidence brought forward by other parties, submit and respond to motions and make final arguments. Commenters will be allowed to file one letter of comment. NGTL’s project application was filed with the NEB in September. By January 15, it must file any additional written evidence to supplement its application which it will also be required to give to all intervenors. The oral portion of the hearings will take place in the spring. Dawson Creek has been suggested as a possible location for the hearing, however, the date, location, venue and anticipated length of the oral hearing will be determined at a later date. July 2016 is when intervenors and NGTL will present final argument, but this may also be combined with the oral portion of the hearing the NEB said. dcreporter@dcdn.ca
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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operations
Photo Copyright © Encana Corporation. All rights reserved
An Encana drilling rig in the Montney.
Encana gets exclusive access to treated sewer water for operations
Jonny Wakefield
Staff Writer
Encana Corp. has been given exclusive access to treated sewage water from the city of Dawson Creek for a fracking operation early this year. On Dec. 21, city council approved a request from the oil and gas company to allow exclusive access to water from the city’s reclaimed water facility between Jan. 22 and Feb. 29. During that time, Encana will be hydraulically fracturing at a well site six miles south of Dawson Creek, and needs up to 4,000 cubic metres of water a day from the city—the maximum the reclaimed water facility is able to produce. Encana spokesperson Brian Lieverse said the company will be drilling four wells and could use up to 7,000 cubic metres daily. For comparison, a standard Olympic-
sized swimming pool contains 2,500 cubic metres of water. A slowdown in the oilpatch has led to lower demand for the water, which is treated from the city’s sewage lagoons. That makes it feasible to offer all the water to one producer, city staff say. In a letter to council, Encana wrote that the reclaimed water is “integral” to its operations south of Dawson Creek. It says four Dawson Creek companies have bid on a water hauling contract. Mayor Dale Bumstead supported the idea, saying “it’s why we sell water, and the more we sell, the better it is from a whole bunch of perspectives.” Shell, which built the facility, is guaranteed up to 3,400 cubic metres a day. Shell OK’d Encana’s request in principle, saying it doesn’t need the water for its own operations. The idea for the facility came about in
2007, according to Kevin Henderson, the city’s director of development services. “We saw an escalation in water use by industry and started to look for alternatives (to fresh water) and how we were going to manage it in the future,” he said. “The idea popped up whether we could just use water out of the lagoons.” The idea was deemed feasible, and the city asked local oil and gas companies if they would be interested in building a facility in exchange for guaranteed access to treated water. Shell ultimately won a request for proposals to build the facility. The water is valued at around $250,000, or $10,000 a day if Encana takes the maximum amount allowed. The city sells the water at $2.50 a cubic metre. reporter@dcdn.ca
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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feature economics vs. environment
B.C.’s carbon capture conundrum Spectra Energy wants to build a $500-million carbon capture and sequestration plant at its Fort Nelson gas processing plant. What’s the holdup? Nelson Bennett
Business in Vancouver
When it’s burned to generate power, natural gas has about half the carbon intensity as coal, which is why the B.C. government has promoted a liquefied natural gas (LNG) industry as an important bridge fuel for addressing climate change. But when it’s extracted and processed, natural gas produces significant amounts of carbon dioxide (CO2) and methane, both of which are greenhouse gases. And that could pose a serious problem for B.C.’s nascent LNG industry under new greenhouse-gas reduction requirements that the federal government plans to impose. A single large LNG plant would produce eight million to 13 million tonnes of greenhouse gases, according to a study published for the B.C. Climate Action Secretariat in 2013. The Pembina Institute estimates three LNG plants would produce 27 million tonnes of CO2. About one-quarter of the CO2 emissions would come from upstream extraction and processing. Most of the CO2 produced in the gas fields could easily be sequestered – typically stored underground – according to organizations like the Pembina Institute and CMC Research Institutes. “It’s an easy get, and it’s one where B.C. could actually be one of the world leaders,” said Richard Adamson, president of the CMC Research Institutes. As he points out, carbon capture and sequestration is a process that lends itself much more readily to natural gas processing than other industrial processes because in natural gas processing, the CO2 is already being captured. Last year, Saskatchewan became the first jurisdiction in the world to commission a large-scale carbon capture and sequestration (CCS) project
for a coal-fired power plant – an $850 million project that removes one million tonnes of CO2 per year from the Boundary Dam Power Station. Last month, Alberta officially commissioned the first CCS project for the oilsands: a $1.35 billion CCS plant that will capture one million tonnes of CO2 annually from Shell Canada’s Scotford heavy oil upgrader in Fort Saskatchewan and sequester it underground. And now the pressure is on B.C. to make it a triumvirate of western Canadian provinces leading the way on carbon capture and storage by implementing it in B.C.’s natural gas industry. B.C. already has a project on the books and a willing industrial partner. Spectra Energy (NYSE:SE) has had plans on the drawing board since 2009 for a $500 million CCS plant for its Fort Nelson gas processing plant, which is B.C.’s largest emitter. For half of what it cost to build either of the Alberta and Saskatchewan CCS projects, Spectra Energy’s Fort Nelson project could store twice as much CO2 – 2.2 million tonnes per year. CCS for coal power plants and oil processing is costly because it requires adding a step to the industrial process to strip out CO2. That extra step is already there in a natural gas processing plant. Before it can go into a pipeline, natural gas coming out of the ground must have the CO2 and hydrogen sulphide removed to produce a clean stream of methane. So there is already a pure stream of CO2 being produced at more than 100 gas processing plants in B.C. But in B.C., most of that CO2 is simply vented into the atmosphere. All that a natural gas processing plant needs for carbon sequestering is to add compression and pipeline infrastructure to transport the CO2 and inject it deep underground into a saline aquifer or depleted gas reservoir, where it can be stored indefinitely. Spectra already carries out CCS with six of its smaller, newer plants.
But the Fort Nelson plant, which was built in the 1970s, doesn’t have CCS, and it’s the biggest CO2 emitter in B.C. That’s not an indication of bad performance, it’s just an indication that the practices they run are emissions-intensive. It’s also a result of the Horn River gas processed by the plant having a much higher carbon content than the gas coming out of the Montney. About 12 per cent of Horn River gas’ composition is carbon, compared to just 1 per cent in Montney gas. Spectra has been sequestering 100,000 tonnes of CO2 per year in deep saline aquifers at its six other small gas processing plants. But the older Fort Nelson gas plant produces 2.2 million tonnes of CO2 per year that isn’t being sequestered. The company’s plan for a $500 million CCS project at that plant is on the back burner, for a number of reasons. “The big challenge is the economics, and right now there isn’t a business case for it,” said Matt Horne, the Pembina Institute’s associate regional director for B.C. “They have to separate the CO2 already. Right now there’s no incentive to do anything other than vent it to the atmosphere, which is what they do.” Unlike Shell, which owns the oil it upgrades – and therefore the CO2 liability – Spectra doesn’t own the gas it processes. It’s strictly a processing and pipeline company, so, it doesn’t own the CO2 liability – the companies that own the gas do. And there are currently no regulations or incentives to require or encourage carbon capture and storage. In Alberta and Saskatchewan, the two big CCS projects were made possible with massive provincial and federal government subsidies. One way to make capture and storage viable in B.C. would be to put a price on the venting of carbon. B.C.’s carbon tax only applies to combus-
Spectra has been sequestering 100,000 tonnes of CO2 per year in deep saline aquifers at its six other small gas processing plants. But the older Fort Nelson gas plant produces 2.2 million tonnes of CO2 per year that isn’t being sequestered.
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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spectra energy photo
The Fort Nelson gas processing plant produces more than two million tonnes of carbon dioxide a year that could be captured and stored.
tion; it doesn’t apply to the CO2 produced by upstream activities such as venting. Non-combustion CO2 was excluded from the carbon tax when it was first introduced in 2008. Horne said the province didn’t have good data on the CO2 produced in the extraction and processing of natural gas when it introduced its carbon tax. Now that the B.C. government is updating its climate plan, Pembina and CMC Research Institutes want the carbon tax extended to non-combustion carbon sources and increased from its current price of $30 per tonne. Gary Weilinger, vice-president of external affairs for Spectra Energy, agrees that applying the carbon tax to upstream CO2 would be an incentive for natural gas companies to finance CCS, although he said it would likely have to be higher than $30 per tonne. But unless other gas producers in the U.S. and Alberta are also paying an equal carbon price, it would put gas producers in B.C. at a disadvantage. So what about finding a customer for the CO2 in the form of carbon credits to help finance CCS?
“Currently there is no market for that,” Weilinger said. “There’s no ability to offset against anything and the only buyer in British Columbia is the government of British Columbia. Frankly, they’ve got all the offsets they need to meet their target.” He referred to B.C.’s carbon-neutral policies, under which schools, hospitals and other public institutions that can’t hit carbon-neutrality targets must pay a penalty to the government in the form of carbon offsets, which are used to buy credits to help finance carbon-reduction initiatives, like preserving forests. But it’s not just a policy problem for the Spectra Energy CCS project – there’s also market uncertainty. The Fort Nelson plant processes gas from the Horn River basin, and developers have been voting with their feet there – avoiding the Horn River and plowing all new investment in the Montney. The Montney is richer because it has liquids such as gas condensate. Horn River gas is dry. So not only does it have a higher carbon content than Montney gas, but it’s also less valuable.
Should a liquefied natural gas industry develop in B.C., it could provide the additional demand that will make the Horn River worth investing in again. But until then, Spectra Energy said it would be hard to justify a $500 million investment in a plant that may have poor long-term prospects. “We’re the only ones who are processing any gas right now coming out of the Horn River basin,” Weilinger said. “So the one thing that we would need is security of natural gas supply. Will, in fact, that area be developed in the future that would justify a large-scale capital investment?” In October, the B.C. government amended the Petroleum and Natural Gas Act to allow for carbon capture and storage. Whether it plans to require it or encourage it through its new climate plan remains to be seen. A framework plan will be released this month for review. The Ministry of Environment has not said whether it will include extending the carbon tax to upstream activities for the natural gas sector.
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Blueberry River, TransCanada ink deal over Coastal GasLink project
William Stodalka Staff Writer
TransCanada announced Dec. 10 it has signed a financial deal with the Blueberry River First Nations over the Coastal GasLink project. The Coastal GasLink project is a natural gas pipeline that would run from an area just north of Dawson Creek to Kitimat. This agreement outlines financial and other benefits and commitments that will be provided to the band for as long as the pipeline is in service, a TransCanada release stated. “We believe the pipeline project will benefit our members today and for future generations, both financially and in terms of employment for our members,” said Blueberry River First Nation Chief Marvin Yahey in a statement. “The relationship we have established with TransCanada is just as important as the agreement, and we are confident that the relationship we have built will continue to the benefit of both parties for years to come.” Blueberry River isn’t the only First Nation to sign onto the project. Both Doig River and Halfway River also signed deals with TransCanada over this project in June. The company also announced a deal with two other First Nations, including the Burns Lake Indian Band and the Lheidli T’enneh First Nation. reporter@ahnfsj.ca
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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national energy board hearing for groundbirch
Mike Carter Staff Writer
Your Peace Region
Dealer
Landowners in the Groundbirch area are concerned that a compressor station related to the North Montney mainline project could affect the current and future use of their lands. Their concerns have sparked further hearings on the project by Canada’s national energy regulator. William Brooke and Danielle Cobbaert, represented by Grande Prairie law firm Darryl Carter & Company, detailed their concerns in filings with the National Energy Board this summer. Brooke and Cobbaert oppose the proposed construction timeline, and the method with which the pipelines would connect to the proposed compressor station, those filings show. The NEB said Dec. 4 it will hold a “detailed route hearing” in 2016 in response to landowners concerns with the Nova Gas Transmission Ltd. (NGTL) pipeline. NGTL is a wholly owned subsidiary of TransCanada Corp. In written statements to the NEB dated July 24, TransCanada lawyers tried to have the landowners concerns dismissed, saying Brooke and Cobbaert had “participated extensively in the Board’s hearing for the Project in 2014.” This included making written and oral submissions to the Board, submitting written information requests to NGTL, and cross-examining NGTL’s witness panel during the oral hearings in Fort St. John. The company’s lawyers argued that allowing the landowners to reargue their concerns in hopes of a different result would amount to “an abuse of process” and should not be allowed by the NEB. The board disagreed. “The board is not persuaded, based on the evidence before it, that your statement of opposition should be disregarded as being frivolous, vexatious or not made in good faith,” the NEB said in an October letter to the landowners. The arguments the landowners made “arguably related to the determining of the best possible detailed route of the pipeline and most appropriate methods and timing of construction,” the board added. The NEB is accepting applications to participate in the hearing until Jan. 8. It will not reconsider matters that were addressed in the North Montney project hearing, such as the need for the project. dcreporter@dcdn.ca
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lng
THE $80 BILLION ENERGY QUESTION Final investment decisions are expected in 2016 on two LNG projects that would bring billions of dollars worth of investment into B.C. Nelson Bennett
Business In Vancouver
This could be a watershed year for the energy sector and the economy in B.C. It is a year when critical decisions are expected on tens of billions of dollars’ worth of major oil and gas projects, including the Trans Mountain pipeline expansion. It’s also the year when Shell and Petronas are expected to pull the trigger on final investment decisions on two large liquefied natural gas projects that, combined, would result in an $80 billion investment. And on the electricity front, construction of the $8.3 billion Site C will begin in earnest. Combined, the Site C dam, Trans Mountain pipeline and two large LNG projects represent about $90 billion worth of investment in energy over a period of about eight years. Starting in January, the National Energy Board (NEB) will convene public hearings in Burnaby to hear from interveners in the Trans Mountain pipeline twinning proposal. The $6.8 billion project proposed by Kinder Morgan Inc. (NYSE:KMI) involves twinning the pipeline, which runs from the Alberta oilsands to Burnaby. The project would nearly triple the pipeline’s current capacity, with most of the additional oil destined for foreign markets. The NEB must submit its final recommendations on the project to the governor-in-council by May 20, 2016. Even more significant for B.C. than the Trans Mountain pipeline would be final investment decisions on LNG projects. “I think that there’s a possibility, if we can make sure that they’re globally competitive, that we could have one or two in 2016,” said David Keane, president of the BC LNG Alliance. “I’m going to hedge my bet and say the middle of the
year.” Natural Gas Minister Rich Coleman is even more optimistic. He thinks four LNG projects could get the green light in 2016. “I think it’s possible to see two major, larger plants FIDed in 2016 and two smaller ones,” Coleman said. Brad Hayes, president of Petrel Robertson Consulting Ltd., is less optimistic. Companies struggling with low oil and gas prices are re-evaluating major investments, he said, and if B.C. is not considered to be as competitive as some other countries, they may move their money elsewhere. If any projects go ahead, he said, they will be Petronas’ Pacific NorthWest LNG project in Prince Rupert and Shell’s LNG Canada project in Kitimat. Those two projects alone would require investments of roughly $80 billion and would create thousands of construction jobs over a fiveyear build-out period. “To me, these two are the two most likely ones that would go ahead in B.C.,” Hayes said. “But I don’t think it’s out of the question that Petronas and Shell look at them and say, ‘OK, well, they’re not the ones that top the list for us to invest in on a worldwide basis, so we’re not going to do that.’ “Every one of these companies has a competition within their project base worldwide and they choose the ones that make most sense to them.” Keane said his members are concerned about the tax rates in B.C., which is the only jurisdiction where an LNG sector would have to pay both a carbon tax and a special LNG tax. “I think there are fiscal issues that need to be looked at,” he said. That’s not going to happen, Coleman said. He pointed out that Petronas agreed to the tax and royalty structure that the province has put in place. “They’ve done all that competitive analysis,”
he said. “Their numbers work with Canada, and they’re comfortable with it.” Without at least one LNG project moving forward, northeastern B.C. would be stuck with a lot of new wells and processing plants that would be producing gas at prices that might not justify the investments being made. Drilling and exploration has fallen off dramatically in the region. In 2015, natural gas land sales fell to their lowest in 33 years, according to Pipeline News North. Land sales amounted to just $18 million in 2015, compared with $382 million in 2014. Low oil and gas prices have forced oil and gas companies to throttle back on new exploration. While gas well drilling activity has slowed, companies continue to build new gas processing infrastructure. Construction has already begun on the new $860 million Sunrise gas processing plant near Dawson Creek, and construction is expected to start in 2016 on a $715-million gas plant near Fort St. John. Both are being built by the Cutbank Ridge Partnership, comprising Veresen Inc. (TSX:VSN), Encana Corp. (TSX:ECA) and a subsidiary of Mitsubishi Corp. The biggest uncertainty right now for the oil and gas sector is how long oil prices will stay as low as they are now. As Hayes pointed out, it doesn’t take much for oil prices to bounce. Civil conflict in Middle East oil-producing countries like Saudi Arabia or a hurricane that shuts down refineries in the Gulf of Mexico can be all it takes for oil prices to spike. “The surplus capacity [of oil] in the world compared to the demand is pretty small,” Hayes said. “You don’t need to knock much production off stream to change the equation right away. We’re one unforeseen event away from something being quite different.”
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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lng
Woodfibre and district start planning for LNG plant Jennifer Thuncher Staff Writer
The District of Squamish is now moving ahead with discussions with Woodfibre LNG in case the project goes ahead. With two major conditional approvals behind the liquefied natural gas project, council passed motions Dec. 8 at its committee of the whole directing district staff to have preliminary planning discussions with Woodfibre LNG representatives on issues of concern to both parties, should the liquefied natural gas export facility be built. One motion was for staff to work with the proponent to come up with terms of reference for a socio-economic study on the impact the plant and its construction would have on Squamish. The other motion was for district staff to begin preliminary talks with Woodfi-
bre LNG on a number issues such as marine considerations, a property tax agreement and community services that may be impacted. The socio-economic study terms of reference and an outline of work district staff will need to do for the project will be presented at a future council meeting. “Generally we are saying we need to create this dialogue, we need to understand the impacts and where those impacts will happen within the process,” said Mayor Patricia Heintzman. On Oct. 14, the Squamish Nation chiefs and council granted conditional approval of the project, and on Oct. 26, the provincial government issued the project its conditional Environmental Certificate. Councillor Doug Race said discussions are necessary at this point. “We want to have this discourse, because
we can’t just stick our heads in the sand and pretend this is just not going to happen.” The motions came after a presentation by Woodfibre LNG’s Byng Giraud, vice-president of corporate affairs, which was followed by a question and answer session in front of a packed chamber. Giraud said he anticipates conditional federal approval will be granted within the next few months. Councillor Karen Elliott said she was concerned about the amount of time staff would dedicate to the liquefied natural gas project before the final investment decision by Woodfibre LNG. “I don’t disagree that if the final investment decision is made, then we want a really close relationship and so maybe there are some preliminary conversations that need to happen, but I am just really concerned with an Official Community Plan review and the Oceanfront
JANUARY 15, 2016
PIPELINE NEWS NORTH •
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‘I would be mistaken if I were to say to you right now that the economics aren’t tough, but we are not pulling away from this project. What we are trying to do is manage our costs, from the purchasing of that gas, the cost of the transportation and pipeline, the cost of liquefaction.’ deal and other major developments in town where exactly our staff have any sort of substantial time,” she said. “So I am just trying to figure out how we resource this.” Chief administrative officer Linda Glenday agreed staff time is an issue. “Definitely this is going to take more resourcing than we currently have capacity for,” said Glenday. Councillor Jason Blackman-Wulff objected to the idea of calculating how much district staff time for Woodfibre LNG would cost. “Why would we not do something similar, for example, for the Great Wolf Lodge?” he asked. “We haven’t directed staff to scope out what the potential future cost might be of staff time and things like that. I think that is just the way of doing busi-
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ness, you have an application before you, you deal with it…. I am concerned that the costing will then become a political football to throw around for those who may not want to see the project move forward.” “As far as I’m concerned,” said Councillor Ted Prior, “this is the first meeting we’ve had where it looks like we might be getting an LNG plant... There were still doubts up until a little while ago.” Giraud answered several questions from council and from a few audience members, including a question from Councillor Peter Kent on the viability of the project, given the falling price of natural gas. “I would be mistaken if I were to say to you right now that the economics aren’t tough, but we are not pulling away from
this project,” said Giraud. “What we are trying to do is manage our costs, so from the purchasing of that gas, the cost of the transportation and pipeline, the cost of liquefaction.” Giraud said purchasers of liquefied natural gas who want to have a supply over the long term are going to have to pay the costs. “So what you may see is utilities looking at companies like ours and companies in the northwest saying, ‘If you can help us manage our long-term costs… then perhaps we can provide you a price that will allow you to make this project viable.’” The company owners are set to make a final investment decision sometime in 2016. — Squamish Chief
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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.
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Bronwyn Scott Staff Writer
JANUARY 15, 2016
From Fort Mac to Taylor
The District of Taylor has hired a new fire chief. Edward Albury, a captain firefighter with over 23 years experience, is looking forward to taking over the role Feb. 1. “This is going to be a brand new venture, an exciting venture,” he said. Albury will be leaving Wapose Emergency Services in Fort McMurray, which is one of the largest private providers of fire, medical and occupational health services in the country. It will be a new experience for him, as he’s only been to the Peace region “a few times.” “I haven’t spent any significant time in that area by any means, but the community seems very family oriented, something I’d like to be a part of,” he said. Albury was born and raised in the Bahamas. During high school, his family relocated to Vancouver Island, where they settled in Mill Bay. As a young adult he joined the Mill Bay Fire Department while also working as a mechanic, and rose in the ranks, advancing his career to become captain and training officer. He received his 20 year medal with that department, according to a District of Taylor press release. He would later branch off to become an industrial firefighter, which he said can be fun, scary
Albury will be leaving Wapose Emergency Services in Fort McMurray, which is one of the largest private providers of fire, medical and occupational health services in the country.
and exciting. He describes it as a rewarding component to his career. Albury replaces Capt. Bert Eisler, who temporarily served the post for two-and-a-half months after former chief Alan Stebbing was relieved of his duties in the fall. Stebbing had been fire chief for four years. During the interview process, the district was “very inviting, everybody I met throughout the process was overly nice, which was a good thing. I had a really good feeling coming out of it,” Albury said. Mayor Rob Fraser said “it’s great to have a new fire chief hired,” but added the district had all its bases covered in the event of emergency. “We had a good plan in place, and we’ve got a good department. We had a captain step up as an interim chief, so we were covered and we were pretty happy with the coverage that we had, but it’s certainly good to be through the process.” The district considered 28 applications before deciding that Albury is the right fit for the role. “He’ll add to all the firefighting in the region actually, I think he’ll be a good fit for everybody,” Fraser said. Albury’s significant other will be joining him in Taylor. She is currently looking for work in the area. peacereporter@ahnfsj.ca
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