Special Report: Trend to longer Montney wells and bigger fracs / pg. 6 FEBRUARY / MARCH 2017
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BIG MONTH: January land sale raises $39.6 million—more than every auction in the last two years combined; PSAC raises its 2017 drilling forecast 31%; $1.7B North Montney Mainline receives provincial environmental approval; Petronas official confirms LNG site may relocate; and Pembina Pipeline enriches local United Way of Northern BC with $26K donation BE PREPARED AND BE SAFE AT THE WORKPLACE WITH RIP’S CLEATS
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FEBRUARY 17, 2017
FORT ST. JOHN
PETROLEUM ASSOCIATION Come out and support the
14th Annual FSJ Oilmens 4 on 4 Hockey Tournament
April 5, 6, 7, & 8, 2017
Cabre Oilfield took home the title at the 13th Annual Fort St. John Petroleum Association 4-on-4 hockey tournament 13th Annual April 7 to 9 2016. Cabre won the final 9-5 against Fort Motors.
March 9
SAVE THE DATES:
March General Meeting @ 6:00 pm - 10:00 pm FSJ Curling Club
April 13
February General Meeting @ 6:00 pm - 10:00 pm FSJ Curling Club
FEBRUARY 17, 2017
PIPELINE NEWS NORTH •
COMMUNITY
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SUPPLIED PHOTO
Avi Sinclair, foreman of operations, and Darrell Babkirk, supervisor of the Fort St. John office, present a cheque for $26,388 to UWNBC Community Development & Campaign Officer Niki Hedges.
Pembina’s $26K donation enriches local United Way
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MATT PREPROST editor@ahnfsj.ca
The United Way of Northern BC has received a $26,388 donation from Pembina Pipeline. The donation was raised through the local office’s annual workplace campaign, which the company matched 100 per cent. “The United Way is one of the cornerstone charities we support throughout our Canadian operations,” said Darrell Babkirk, supervisor of the Fort St. John office. The United Way will direct the funds into local programs it supports in the community. “When directly working with United Way of Northern BC, donors continue to help support critical community programs,” said Niki Hedges, United Way’s community development and campaign officer for the northeast. “Corporate leadership allows us to do much more and bring about social change. United Way of Northern BC is well positioned with a strong understanding of issues facing the communities we serve. Funds raised will be invested into local community programs to bring about long-term solutions.” Hedges’ enthusiasm on the ground in Northeast B.C. rubs off on the people she meets, Babkirk said. “We feel we’re getting a lot of bang with our dollars in hitting those charities locally that are very important,” he said. “It’s a very good vehicle.” To learn more about local programs supported by the United Way, visit www.unitedwaynbc.ca.
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FEBRUARY 17, 2017
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January land sale raises more in one day than last two years JONNY WAKEFIELD reporter@dcdn.ca
When bidding closed on B.C.’s oil and gas land sale last month, Gregg Scott was pleasantly surprised. For two years, the monthly auctions have been anemic. Oil and gas companies have cut drilling programs since the collapse in prices, and with demand slack, companies like Scott Land & Lease are spending less on drilling rights and leases for their clients. Then, in a single sale Jan. 18, B.C.’s petroleum and natural gas rights auction raised more money than every auction in the last two years combined. Eight drilling licences brought in $39.6 million, including a record-setting $35 million parcel east of Dawson Creek. “My reaction was a bit of surprise,” said Scott in an email. “It’s been over two years since any company placed a bid of that size in any province. I was pleased the client chose us to represent them with such a sizeable bid and hope it’s a sign of things to come.” The last two years saw the lowest land sale incomes on record due to a severe downturn in the oil and gas sector attributed to a glut of supply on the world market. The 24 sales held in 2015 and 2016 brought in just $34 million in total. It remains to be seen whether January’s strong result heralds a rebound in B.C.’s oil and gas sector. Scott guesses the uptick is a “combination of
more optimism in the industry, combined with available prospective land and the competitive forces of the land sale system.” But unless the trend keeps up, demand for land and drilling licences are is still well below 2014 levels. That year, producers snatched up $383 million in drilling rights in anticipation of liquefied natural gas development in Northeast B.C. Depending on market conditions, the sale of drilling rights for subsurface oil and gas accounts for 30 to 70 per cent of B.C.’s total petroleum revenue. That money goes to fund provincial programs including highways, health and education. Many consider the sale an indicator of future drilling activity. Whether or not the trend hold, January’s result is a heartening sign for the B.C. oilpatch, which has shed hundreds of jobs since the start of the downturn. Last February, the sale brought in $0 for the first time in history. While subsequent sales added some $15 million to the provincial treasury, 2016 was the worst year on record for auction incomes. Late last month, the Petroleum Services Association of Canada revised its 2017 drilling forecast, predicting a 31 per cent bump in drilling activity in B.C. over estimates released last fall. Still, oilfield activity is expected to be well below 2014, when oil and gas prices were higher. The best-ever land sale was held in July 2008 and brought in $610 million. In the past three years, the January 2017 sale placed second overall, behind a $209 million sale in Nov. 2014.
Village seeks drilling conditions Officials in Pouce Coupe say they’ll be keeping a close eye on potential oil and gas development near the village after a recordsetting drilling licence sold at auction last month. On Jan. 18, a $35 million drilling licence near Pouce Coupe sold at the province’s monthly oil and gas land sale. According to Gregg Scott of Scott Land & Lease, it was the highest-priced sale in Western Canada in the two years since the oil and gas downturn. However, any company that acquires the drilling rights will be subject to several caveats. According to Ministry of Natural Gas documents, the land is located near and possibly within Pouce Coupe park and campground, a popular recreation destination in the region. Pouce Coupe Chief Administrative Officer Christopher Leggett said the village flagged the parcel in a letter to the ministry, saying special
care needs to be taken to mitigate any impact on the nearby park. “When we looked at the map, (the drilling licence) didn’t seem to overlap Pouce Park, it was the area starting on the other side of the river and going back,” he said. Any prospective driller will need to minimize odours, noise and light from any development near the park, he said. “Any drilling there obviously can’t impact the visual quality of the park. We don’t want the park being lit 24 hours a day by a drill rig.” Pouce Park was washed out in the floods this summer and is still covered in several feet of silt and debris. Leggett said the village is reviewing its options when it comes to repairing the park and mitigating any future floods. Leggett said cleaning up the park and adding flood mitigation features could cost upward of $1 million. —Jonny Wakefield
FEBRUARY 17, 2017
PIPELINE NEWS NORTH •
OUTLOOK
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More drilling expected as oilpatch recovers reporter@dcdn.ca
PSAC predicts 31% increase over preliminary forecast
Things are looking up for B.C.’s battered oilpatch. More than two years into one of the most severe downturns in a generation, two industry groups say drilling and other activity levels are climbing thanks to improved oil and gas prices. On Jan. 30, the Petroleum Services Association of Canada (PSAC) released its revised 2017 outlook, calling for a 23 per cent increase in the number of wells expected to be drilled in Canada this year. The group forecasts Canadian producers will drill 5,150 wells in 2017, up 975 from a preliminary forecast released in November. PSAC expects 367 of those wells will be in B.C., a 31 per cent increase over the preliminary forecast of 280. Mark Salkeld, the association’s president and CEO, said oil prices are increasing thanks to stabilizing OPEC production levels. The cartel opted to keep production levels high over the past two years to drive out higher cost North American producers, which have
gobbled up market share since the advent of improved hydraulic fracturing technologies. “The geopolitics settled down,” he said. “The global supply and demand was the biggest factor. Saudi Arabia and OPEC got it under control to a certain degree, or at least enough to encourage investor confidence, which puts money back into the industry which improves the drilling forecast.” Natural gas producers in B.C. are seeing a similar bump. While prices have not improved to the same degree as oil, several producers in the region are able to make money at $3 natural gas, Salkeld said. Energy Services B.C. Executive Director Art Jarvis is also seeing improvement. “2016 was the worst of the downturn, and we’re on our way out of it,” he said. “There’s lots of activity on the highways, and in the outlying areas where they’re doing gas drilling facility manufacture. The followthrough that happens after drilling is very active right now.” Forty-five per cent of B.C.’s fleet of 71 rigs
JONNY WAKEFIELD
was drilling the week of Jan. 23, according to the Canadian Association of Oilwell Drilling Contractors. B.C.’s rig utilization rates haven’t topped 45 per cent in a single month since March 2015. While that’s an improvement, Salkeld said the industry is still a long way off from predownturn employment and investment levels. “We’re waiting on the LNG decisions,” he said. “Those are the ones that are going to really make a difference for B.C. on the gas side of things.”
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FEBRUARY 17, 2017
OUTLOOK Trend to longer Montney wells and bigger fracs JAMES MAHONY JWN Energy
COPYRIGHT © ENCANA CORPORATION. ALL RIGHTS RESERVED
An Encana drilling rig in the Montney.
Western Canada’s Montney producers have long found that lengthier horizontal wells mean more production and greater efficiency, a trend that is continuing, according to two producers that outlined 2017 drilling plans recently. A smaller player than it was a year ago, Paramount Resources Ltd. is focusing on getting the most of its remaining 158 sections of Montney land, and management is adopting a new well design that chief executive Jim Riddell described as “transformational.” “As most of the industry had, we realized, back in 2014 and 2015, that drilling longer wells, doing bigger fracks and making wells much tighter-spaced was a recipe for better wells and values,” he told the annual CIBC investor conference in Whistler, British Columbia. Instead of drilling a one-mile horizontal with 20 frack stages of 60 tonnes per stage, and putting some 1,200 tonnes of proppant into the formation, Paramount recently drilled a two-mile lateral, using 50 fracks of 100 tonnes each, Riddell said. “We’d gone into the downturn, [but] didn’t drill any new wells though 2015, until the beginning of 2016. The first [chance] we got to show the new well design, we placed four times the frack intensity in a well, compared to what we were doing before,” he said. Following the sale last year of production and lands in the Musreau-Kakwa area of westcentral Alberta, Paramount’s current production is roughly 11,000 boe per day, down from some 50,000 boe per day in last year’s first quarter. While the company sold 310 net sections, including 155 Montney sections, its remaining Montney lands are of key interest. Within that acreage, the current focus is on the company’s Karr-Gold Creek lands. “We’re in the throes of doing a 25well program, started last August, and it should be done by May [2017],” Riddell said. By year-end, 2016, 12 to 15 of those wells were finished drilling, and the program continues, as the company expands its natural gas processing capacity.
Other Montney players, including NuVista Energy Ltd., are also planning longer wells and more frack intensity, the conference heard. NuVista will be using extended-reach wells that are 50 per cent longer than before. The company is focused on the Wapiti area, south of Grand Prairie. “When we go forward, we expect double the length [and] double the production, but it so happens these [extended-reach] wells have outperformed even that,” Jonathan Wright, president and chief executive, told the conference. “That’s our big marker pointing to Gold Creek, because [there], we have tons of room to do a whole bunch of extended reach wells.” Denser frack-spacing is also part of NuVista’s plan. “We’re going from about 100 metres to about 50 metres, based on the results we’ve had so far,” Wright added. “We think that’s going to be the economic sweet spot, and we’re going to prove that up this year, with a number of side-by-sides, where we’ve got the identical wells side by side, with one well on 100-metre well spacing, and the other on 50-metre spacing.” On these wells, the company will be approaching two tonnes per metre of frack. “To the extent that these little experiments — going longer and denser with the fracking — work perfectly, then we would end up exceeding our annual plan, and … we would end up with more production or you can reduce your capital and get the same production…,” he said. “That’s one lever that will happen through the year, as we evaluate the results of these wells, and if we end up outperforming, then we have that happy choice,” he said. Currently, NuVista is forecasting 2017 average daily production of 28,000 to 31,000 boe average this year. Due to expected maintenance turnarounds at gas plants, there is “some uncertainty” about production in the next couple of quarters, Wright said. “But there’s no uncertainty about the wells we’re going to drill,” he said, noting 29 wells are on this year’s agenda. “We’ll go from about 60 to over 90 wells on production this year, [which] will have a dramatic effect on production.”
FEBRUARY 17, 2017
PIPELINE NEWS NORTH •
OUTLOOK
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Alberta Climate Plan could benefit natural gas producers Alberta’s Climate Leadership Plan will be bad news for consumers, as they pay more for greener electricity from a power generation fleet free of old king coal, but the big winners will be natural gas producers. The shift away from coal to some renewables — and mostly to natural gas-based electricity — certainly won’t compensate for the loss of the export market to the U.S., which has become not only self-sufficient but a competitor in Eastern Canada. But natural gas supply and demand consultants and Alberta electricity industry experts both say it’s a market opportunity that won’t be insignificant. “We’re primarily a thermal electricity-based power market,” said Evan Bahry, executive director of the Independent Power Producers Society of Alberta (IPPSA). In Alberta’s case, the CLP means that coal, which was once responsible for almost 70 per cent of its electricity, will be a thing of the past by 2030 (Saskatchewan plans to phase out its coal-fired plants more gradually).
Bahry, citing recent statistics from the Alberta Electric System Operator (AESO), which manages the province’s power system, says that shift has already started. While the New Democratic government might like to see a shift away from coal, which is to be eliminated by 2030 under its climate plan, dominated by renewables, the chances of that happening are remote, barring a revolutionary renewable energy technology being developed between now and then. And in Alberta, where more than half of the province’s 2,773 MW of renewable power is generated by wind (the rest is hydro and biomass, with negligible solar power) “renewable” means wind. “Alberta has an awesome wind resource,” said Bahry. “We expect most of the growth in renewables in the future to be from wind.” Last May AESO produced a longterm power outlook, stretching to 2030. It’s considered the most reliable roadmap for the future, one the 90 members of IPPSA rely on and contributed to. Fifteen of those members are in the power generation business, so the forecast is a vital look at their business future in the province. The forecast was produced
during a downturn in the province’s economy (past forecasts had been somewhat more bullish about power growth), but it still envisions a growth of about 45 per cent in electricity demand by 2030. The forecast provides different scenarios, including a reference case, a high growth case, a low growth case and an “alternative policy” case. The varying scenarios take into account more oilsands growth than now envisioned by the province (presumably a new government would lift caps on greenhouse gas emissions, for one), a later phase-out for coal and other factors. The most commonly cited generation outlook, the base one Bahry refers to, sees the province having roughly 23,420 MW of power by 2030. INCREASED ROLE FOR GAS That forecast should put a smile on the faces of western Canadian natural gas producers. Wind power producers will be blown over by it too. AESO sees wind power production growing from 1,463 MW now to 5,663 MW by 2030, while hydro power would stay the same (about 894 MW ) and the rest
— 469 MW — would be comprised of “other” presumably some solar, biomass etc. All forms of natural gasgenerated power now are responsible for about 7,216 MW of electricity in the province. The biggest contribution comes from cogeneration plants, mostly in the oilsands. In fact, the oilsands is the largest single user of gas in the province, at above two bcf per day. Those are facilities designed for dual-purpose use of the steam from the plants, with most going to coax bitumen out of the ground, while the rest is used to generate electricity, much of it sold to the Alberta grid. Those plants now generate 4,504 MW. AESO says that will grow to 5,550 by 2030. That will lead to some growth in natural gas consumption. But the shift to natural gas generated power in other power plants, chiefly highly-efficient combined cycle plants, will be significant. Combined-cycle plants are only responsible for about 1,716 MW now, but AESO says that will grow to 8,541 MW by 2030. In addition, it forecasts simplecycle gas-fired plants will be producing 2,307 MW by 2030, up from 996 MW now.
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JIM BENTEIN Daily Oil Bulletin
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FEBRUARY 17, 2017
PIPELINES
$1.7B North Montney Mainline sees approval MATT PREPROST editor@ahnfsj.ca
Plans to build a new, 301-kilometre natural gas pipeline in the Peace Region have been granted environmental assessment approval by the province. Environment Minister Mary Polak and Natural Gas Minister Rich Coleman approved an environmental certificate for the North Montney Mainline Pipeline Project on Jan. 18. “The EA Certificate includes enforceable conditions and specifies the Project design parameters. These give us confidence to conclude that the Project will be constructed and operated such that no significant adverse effects are likely to occur,” the ministers wrote in a joint decision. Canada’s National Energy Board (NEB) approved the $1.7 billion pipeline in April 2015, attaching 45 conditions to the project. The province has added another 21 conditions it says will supplement the NEB’s requirements. Those conditions include developing an access management plan with First Nations and government agencies to limit pipeline right-of-way use by motorized vehicles and predators, protect riparian zones, Project map of the North Montney Mainline. and ensure the proper deactivation reclamation and restoration of roads following the pipeline’s construction. First Nation input to minimize The company must also prepare the displacement and mortality a habitat restoration plan with of caribou, as well as develop
TRANSCANADA PHOTO
a mitigation plan for the Pink Mountain area that allows for continued traditional First Nation
land use in the area, among other conditions. The North Montney Mainline— to be built by Nova Gas Transmission Ltd. (NGTL)—will be part of a network of pipelines that transports natural gas to the West Coast, where the gas would be liquefied and exported. The project would commence from an area 100 kilometres northwest of Fort St. John and travel about 300 kilometres to connect to the Nova Gas Transmission System. This would feed into the Prince Rupert Gas Transmission Line, which will deliver gas to Pacific NorthWest LNG, as well as the proposed Coastal GasLink pipeline, which would run to Kitimat. The project would also include construction and operation of associated metering facilities, valve sites and possible compression facilities. A 2013 estimate put the cost of the North Montney Mainline project at about $1.7 billion, including around $876 million of construction contracts and employment benefits. In their decision, Coleman and Polak note the project would pump more than $800 million into the provincial economy, including $8 million in property taxes to the Peace River Regional District. Construction is expected to create up to 2,500 direct jobs. Once in service, NGTL estimates five employees will be needed to carry out operation and maintenance requirements.
Keyera plans new pipeline system to transport NGLs ELSIE ROSS Daily Oil Bulletin
A new natural gas liquids gathering pipeline system in westcentral Alberta that will link eight Keyera Corp. gas plants to the Rimbey plant will provide operators with a safer and more economic alternative to trucking natural gas liquids, says the company. The estimated $147 million Keylink pipeline will use a combination of 240 kilometres of new construction and unused pipelines to connect eight Keyera gas plants, including the Brazeau River, West Pembina, and Minnehik
Buck Lake, to the Rimbey gas plant where the company can provide onsite fractionation into specification products. The Rimbey plant is pipeline connected to Keyera’s Edmonton rail terminal and Fort Saskatchewan fractionation and storage complex. Additionally, the company plans to expand the liquids handling capacity at the Simonette gas plant to meet customers’ growing needs. The project is estimated to cost $100 million and to be operational by mid-2018, based on the proposed construction schedule. Upon completion, the plant is expected to have condensate
handling operational capacity of approximately 27,000 bbls per day. Assuming progress continues on schedule, the goal is to have the new system operational in the second quarter of 2018. “We think it’s the right time to build,” said Dean Setoguchi, senior vice-president of the liquids business unit. “We have looked at it for some time and never have we had the confidence to build this pipeline system for this kind of price level anytime in the last several years.” Keyera likes the facilities it will be adding to the system and the discussions with third parties that
it thinks it can attract over time to bring volumes to the system, Lock said. “We certainly are seeing stronger volumes from this area and a stronger outlook for future volumes at this point than maybe what we would have seen three or four or five years ago,” added David Smith, president and chief executive officer. “The throughput volumes at Brazeau River and West Pembina are up considerably and the Zeta Creek plant is new and the liquid composition of the gas in the area has been increasing as well because of the zones that the producers have been focused on.”
FEBRUARY 17, 2017
PIPELINE NEWS NORTH •
On February 01, 2017, the voice of BC's construction sector became stronger. We are pleased to announce that Energy Services BC (ESBC) has merged with the Independent Contractors and Businesses Association of BC (ICBA).
TEDDY KWOK/FLICKR PHOTO
Russ Girling, TransCanada CEO and president, said Keystone XL would help the US meet its growing energy needs.
TransCanada submits new application for Keystone XL Barely two days after US President Donald Trump signed an order to move forward on the construction of the Keystone XL, blocked by former president Barack Obama in 2015, the company behind the project has submitted a new permit application to the US Department of State. In a release issued after stock markets closed on Thursday, TransCanada’s (TSX, NYSE: TRP) president and CEO Russ Girling said Keystone XL would help the US meet its growing energy needs. “Independent forecasts by the U.S. Department of State estimate that [Keystone XL] will support tens of thousands of direct and indirect jobs and associated income during construction and contribute approximately $3.4 Billion to U.S. GDP,” the company said in the statement. The project still faces challenges. To start, when Trump signed the executive order on Tuesday he said he’d negotiate the terms, including making TransCanada use only pipelines and materials produced in the US. There also are some landowners in Nebraska who have already pursued legal and procedural avenues against the pipeline. The US State Department, in turn, has 60 days to review the application and issue a decision, according to published reports earlier this week, a period during which new hurdles may arise. TransCanada first applied for a permit in 2008 seeking to build the 1,897km (1,179-mile) pipeline, which would carry 800,000 barrels of crude a day from Alberta to Steele City, in Nebraska. There it could join an existing pipeline. The company has spent at least $2.5 billion on the project, whose total cost if built would be at least $10 billion due to delays and permitting costs. If it goes ahead, Keystone XL is expected to carry more than onefifth of the oil Canada exports to the United States. —Mining.com
TOGETHER, ADVOCATING FOR GROWTH AND INVESTMENT IN NORTHEAST BC For Northeast British Columbia and our businesses, this means we will now have a much stronger voice when dealing with important issues in our area - especially in the case for jobs and investment in the region.
To learn more about this merger please visit
www.icba.ca/esbc
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LNG Petronas official confirms LNG site may relocate NELSON BENNETT nbennett@biv.com
The CEO of Malaysia’s Petronas has confirmed speculation that the company is seriously considering relocating the export terminal for its Pacific NorthWest LNG project in Prince Rupert. At the end of December, Bloomberg News cited anonymous insiders who said the company was considering moving the loading terminal, which might go some way to addressing concerns over the impact on salmon habitat off Flora Bank. On Feb. 13, Mayalsian state news agency Bernama quoted Petronas CEO Chairman Tan Sri Mohd Sidek Hassan, who confirmed that is being considered. “We have to take into account the various factors like it being poorly sited and also where it warrants,” the news agency quoted Sidek as saying during an economic forum. Bernama also suggested that the
decision to consider an alternative site may be partly in response to “Canada’s political race” – a reference to the provincial election. The story referenced NDP Leader John Horgan’s vow to find a better location for the export terminal. The biggest concern over the $11 billion LNG project is an export terminal, which would be connected to Lelu Island – where the actual liquefaction plant would be built – via a suspension bridge. The bridge would have to transit Flora Bank, where eelgrass beds provide important salmon rearing habitat. Only recently, industrial property on nearby Ridley Island became available, when Canpotex Ltd. abandoned its plans in June 2016 to build a new potash export terminal on Ridley Island. Were the export terminal to be moved to Ridley Island, it might not only address some of the environmental concerns – it might also save the company money.
The Flora Bank terminal has been contentious, dividing First Nations in the area. The Lax Kw’alaams First Nation originally opposed the project. A band council election changed the dynamics, however, with the new council expressing some support for the project. Meanwhile, a division between hereditary chiefs took an interesting turn recently in favour of the provincial government and the PNW LNG project. Hereditary Chief Don Wesley insists that his clan has the rightful claim to Lelu Island. But nine hereditary chiefs within the Tsimshian tribal organization have now thrown their support behind the project. More recently, a number of Lax Kw’alaams members have said in affidavits in Wesley’s Federal Court challenge of the PNW LNG project that Wesley does not have authority over Lelu Island. Should the company decide to relocate the terminal, a new environmental assessment would
likely be required, pushing the timeline back for the project’s construction. But a glut of new LNG now on the market means that there is not likely to be a demand for additional LNG supplies until about 2025 anyway, according to gas and LNG analysts. The PNW LNG project has been in serious question since the oil price crash. Petronas was expected to make a final investment decision on the project in 2016, but deferred. Oil and gas prices are now recovering, however, and if the company can relocate the export terminal and if the company and provincial government can get key First Nations on side - as it appears to be doing - it could remove a significant roadblock. When upstream gas assets and a new pipeline that would have to be built are factored in, the PNW LNG project is estimated to be a worth a total capital investment of $36 billion. —Business in Vancouver
Lax Kw’alaams, Metlakatla sign multi-million dollar LNG agreements NELSON BENNETT nbennett@biv.com
Premier Christy Clark chalked up something of a pre-election coup Wednesday February 15, when two key First Nations, the Lax Kw’alaams and Metlakatla, officially signed benefits agreements in support of Petronas’ $36 billion Pacific NorthWest LNG project in Prince Rupert. Although Petronas has yet to announce a final investment decision, Wan Badrul Hisham, Petronas’ chief project officer for PNW LNG, suggested that the signing of a benefits agreement with First Nations was an important step. “We at the Pacific NorthWest LNG are very encouraged by the achievement of this significant milestone in the development of the LNG project,” Hisham said at an official signing ceremony Feb. 15 in Victoria. “With this agreement in place, we can now look forward towards working on a common goal of realizing the project.” The Lax Kw’alaams originally opposed the project. In 2015, the band rejected a $1.2 billion offer of cash and land. But a change in band council leadership, which installed John Helin as the band’s mayor, eventually led to the band supporting the project. It’s not yet clear how the new benefits agreement compares to the previous one. One the surface, it appears to offer less money and land than what was originally offered. The new deal offers the Lax Kw’alaams $98 million and 1,942 hectares of Crown land –
Lax Kw’alaams Mayor John Helin: ‘The benefits that would accrue from the project... are huge for our community members.’
slightly less than 2,200 hectares originally offered. It also offers annual payments and profit sharing from the LNG plant and the Prince Rupert Gas Transmission pipeline: $590,000 annually from the LNG plant and $815,000 annually from the pipeline. There are numerous other agreements, including spending commitments worth $50 million for roads and other infrastructure. Helin said the agreement gives his people some input on how the project proceeds, and will provide his people with ongoing revenue streams and jobs. “For the first time in my lifetime…we’re really a part of what’s happening within our traditional territory as far as looking after the environment and getting benefits I think we deserve,” Helin
said. “The benefits that would accrue from the project, should it go forward – or when it goes forward – are huge for our community members,” Helin said. “It goes a long way to addressing a lot of our needs in our communities.” Metlakatla Chief Councillor Harold Leighton called the agreement “leading edge.” “It gives the Coast Tsimshian a say in how the facilities are going to be built and to make sure they’re built safely,” he said. “The revenue sharing is going to change the communities. And hopefully, one day, both communities will be self sufficient. The size and scope of the agreements that we signed are unheard of.” The LNG plant on Lelu Island would cost $11 billion to build. But when the construction of the Prince Rupert Gas Transmission line and all the upstream natural gas assets are included, PNW LNG represents a total capital investment of $36 billion. “When Pacific NorthWest LNG goes ahead, it means an investment of $36 billion,” said Premier Christy Clark. “One of the largest private sector investments – thank you Petronas – that will ever have been made in the country.” She said the project will create 3,500 construction jobs and 350 permanent jobs. Clark has been criticized for promises made in 2013 that an LNG industry would be underway by now. The only LNG project to get a final investment decision yet is the much smaller Woodfibre LNG project in Squamish. —Business in Vancouver
FEBRUARY 17, 2017
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Energy Services BC Executive Director Art Jarvis (left) and ICBA Regional Vice-President Mike Davis shake hands over a recent merger of the two organizations.
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ICBA, Energy Services BC merge Northeast B.C.’s homegrown oil and gas service sector group is merging with a provincial construction lobby in a move leaders say will increase the profile and issues facing the region’s natural resource sector. The Independent Contractors and Businesses Association of B.C. (ICBA) has acquired the Fort St. John-based Energy Services BC, the two groups announced Feb. 1 at the Premier’s Natural Resources Forum in Prince George. Being absorbed into the ICBA will give the region’s oil and gas sector a bigger voice on the provincial stage, ESBC Executive Director Art Jarvis said. “It’s a big step forward for us from just being a lobbying and advocacy group. We’ve got bigger strength now,” said Jarvis, who has helmed Energy Services BC for the last five years, and will work for the ICBA in Fort St. John. Talks between the two groups began shortly after simultaneous truck rallies in support of LNG development were held across northern B.C. last March. “That’s when I met with the (ICBA) president and we recognized that the services we advocate and lobby for parallel theirs—ours is in oil and gas, theirs is in construction,” Jarvis said. “They didn’t have the connections. It was the right marriage.” Energy Services began roughly 40 years ago as the Northern Society of Oilfield Contractors & Service Firms as a regional advocate for
industry service companies. It changed its name to Energy Services BC in 2007 and broadened its focus on the overall energy sector and to encompass a more diverse group of members. While the organization has seen success on a number of files—including a local tax inspector for Fort St. John to keep tabs on outof-province contractors that have not paid taxes and levies—it has been looking to extend its influence and profile in the province, Jarvis said. Meanwhile, the ICBA has been interested in learning more about the province’s oil and gas industry, Jarvis said. The merger will strengthen advocacy for responsible resource development. “The problem is, people down south in the Lower Mainland, they just don’t understand, they aren’t educated in what responsible resource development brings them,” Jarvis said. “This is going to turn out to be a very powerful partnership that is good for the communities and good for the province.” Current ESBC members will transition into ICBA members throughout the year, and will see greater value from their new membership, including a range of new benefits offered by the ICBA, Jarvis said. ICBA opened its first regional office in Prince George last year, and the company says acquiring ESBC furthers its regional expansion. It is seeking office space in Fort St. John and expects to be fully operational in 2018 after building out its business plan.
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OPERATIONS Analysts at Peters & Co. recently ranked the top 10 producers in the Montney, using data from the first half of 2016. Encana, which ranks number one on the list, says that after a decade of activity in the play, major strides are being achieved in unlocking its true value and potential. During the third quarter, Encana brought on several new wells on the Alberta side of the play at Pipestone. At its October investor day, Encana highlighted two wells with an average IP30 of 900 bbls/d of condensate out of a total 1,400 boe/d. Less than a month later, results had improved. Next year, the company expects the condensate-to-gas ratio of its Montney program to average at least 85 bbls/mmcf. That is more than eight times Encana’s historic Montney average of less than 10 bbls/mmcf, and it sees a 30 per cent compound annual growth rate on its Montney liquids through 2021.
AltaGas to acquire WGL Holdings in $8.4-billion deal JIM BENTEIN Daily Oil Bulletin
In what it’s calling a “transformational acquisition” Calgary-based midstream giant AltaGas Ltd. confirmed Jan. 25 — in an announcement that came as no surprise to those familiar with the company — that it will acquire Washington, D.C.-based WGL Holdings Ltd. for C$8.4 billion. The deal, announced on the same afternoon AltaGas president and CEO David Harris was to speak at a CIBC-sponsored investment conference in Whistler, B.C. (an appearance that was cancelled because of the announcement), follows the pattern recently set of Canadian energy and utility related companies increasing their presence in the U.S. For instance, last year Enbridge Inc., in a deal valued at C$42.8 billion (including debt), bought U.S.-based Spectra Energy Corp. TransCanada Corporation, in a deal worth C$12 billion, bought the Columbia Pipeline Group. Following the long-rumored transaction with WGL, AltaGas said it will have C$22 billion of “high
quality, low risk, long-lived assets” with C$7 billion of organic growth opportunities in the three business areas in which it operates. Those include gas utilities, as well as midstream and clean energy lines of business. AltaGas said it will relocate the headquarters of its U.S. power business from service regions in Dallas to Washington, D.C. In a press conference, held after the announcement, John O’Brien, president of AltaGas Services U.S., said that move will only involve about 15 employees at this point. AltaGas said WGL will continue to operate as a standalone utility headquartered in Washington, D.C., while assisting AltaGas in the management of its existing small regulated utility business in the U.S. AltaGas said the combined entity would lead to a growth of 8-10 percent in earning per share, while leading to higher growth on an absolute dollar and per share basis through to 2021. It said it will be targeting an annual growth of eight-10 per cent a year in its dividend payout through to 2021. The acquisition means AltaGas,
through ownership of WGL, will own Washington Gas Light Company, a regulated natural gas utility located in the fast-growing Washington, D.C. area. In addition, WGL owns midstream assets in the Marcellus/ Utica area, one of the fastest growing natural gas producing regions in the U.S. It also owns non-regulated contracted power and energy marketing businesses throughout the U.S. In a press release, AltaGas CEO Harris said “this acquisition provides us with a robust, complementary set of energy businesses that greatly increase our scale and diversity.” Harris did not appear at the press conference that occurred after the announcement. Terry McCallister, chairman and CEO of WGL, said, in the press release, the company’s executives “are convinced that we have found exactly the right partner in AltaGas. We are confident that, together, we will be a more diverse and stronger company that will open up new and exciting opportunities to provide value for all of our stakeholders.” Under the terms of the
transaction, WGL shareholders will receive US$88.25 in cash per WGL share, which represents an 11.8 per cent premium to WGL’s closing share price as of Tuesday. The purchase price also represents a premium of 27.9 per cent to WGL’s closing price on Nov. 28, 2016, the day there were news reports of a potential acquisition of the company by a third party. Following the closing of the transaction, which needs to be approved by regulatory agencies, AltaGas will have 3,300 employees in over 30 states and provinces. It will own eight gas utility franchises, a large midstream and energy export business, with a footprint in the Montney gas play in B.C. and the Marcellus/Utica. It also controls a large clean power and energy efficiency business in North America. AltaGas has been advancing its infrastructure in Northeast B.C, including the new Townsend gas processing facility, the North Pine natural gas liquids facility, and plans for a $180-million gas processing facility, separation train, and rail terminal. —with staff files
FEBRUARY 17, 2017
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EDUCATION TransCanada scholarships to support next gen of NRG leaders TransCanada is rolling out a series of new scholarship for students pursuing a career in the energy industry. The company’s Empower Communities Scholarship program is offering three unique scholarships to recognize students going into the trades, indigenous students, and community leaders. The TransCanada Trades Scholarship is offering up to 150 awards worth $1,000 each to students pursuing a career in trades relevant to the energy industry. The TransCanada Indigenous Legacy Scholarship is offering up to 50 awards worth $5,000 each offered to First Nations, Métis, Inuit or Native American students pursuing any post-secondary education. The TransCanada Community Leaders Scholarship is offering up to 100 awards worth $1,000 each offered to students
pursuing any post-secondary education who demonstrate a strong commitment to their communities through volunteer work, community participation, leadership or other activities. “At TransCanada, we support education and training opportunities in the communities where we do business,” the company said. “Through these efforts we aim to build community capacity, develop the next generation of community leaders, and provide a skilled workforce for our industry.” TransCanada will be accepting applications annually from January 15 to April 15. To learn more, visit www.tcscholarships. com. —Staff
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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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Increased DC municipal water use indicates Montney uptick JONNY WAKEFIELD reporter@dcdn.ca
Oil and gas workers are filling Dawson Creek hotels, eating at local restaurants and driving up water use in the city, new data suggests. According to a report to city council Jan. 23, the city has seen a 10-12 per cent uptick in water use in January over 2016. Water use is one of the best measures of the city’s “shadow” population of transient workers, many of whom are now in town for pipeline and facilities upgrading work in the Montney shale. Shawn Dahlen, the city’s director of infrastructure, said increases in water use can indicate a rise in population. “There are so many different uses for the city’s treated drinking water, so it’s one way we can take a stab at (estimating population),” he said. “But is it 100 per cent accurate? Probably not.” 2016 was the worst year of the oil and gas
downturn that began in late 2014, leading to soaring vacancy rates in the region’s hotels and apartments. However, the city appears to be rebounding thanks in part to pipeline projects in the area. In the first month of 2017, Dawson Creek’s average water use has climbed from 5,500 cubic metres a day to 6,300, Dahlen said. “We’ve definitely seen that increase from people in town through hotels and restaurants, to where we’re seeing an additional, on average, 700-800 cubic metres a day of water use,” Dahlen said. It’s a trend business groups have seen as well. In an email to members this week, the Dawson Creek Chamber of Commerce said attendees at an upcoming Junior Girls’ hockey tournament were having trouble finding rooms in the city. “According to hoteliers in town, they currently have wait lists for rooms (including hotels/motels in Pouce Coupe),” the chamber wrote. “We have some hockey families who had
to book rooms in Fort St. John.” The city draws water from the Kiskatinaw River. Water for oilfield use comes from a separate reclaimed water plant. Unlike nearby Grande Prairie, Dawson Creek does not carry out a municipal census, making water use one of the best indicators of how many people are in town. PEOPLE WHO READ NEWSPAPERS AND
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engaging Canadians, including high-income Canadians, boomers, moms and even young adults. All of which makes advertising in newspapers a very smart move.
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Fleet van or personal sedan: You are responsible for employee safety.
Whether your employees drive a company vehicle or their own, you are responsible for their safety when they drive for work. Learn more at RoadSafetyAtWork.ca.
Be a part of Road Safety At Work Week, March 6–10, 2017