Gas sniffing drones: The technology being used to help build a national GHG database / 9 OCTOBER / NOVEMBER 2017
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Encana puts new Montney midstream plants to work ahead of schedule; five upcoming developments from Canada’s major oil and gas producers; sensors could change pipeline safety performance; Canada argues its case for Trans Mountain in court; and Petronas says it remains committed to the Montney without LNG
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OCTOBER 20, 2017
ENTRY ELIGIBILITY REQUIREMENTS 1. Employees, officers or directors engaged full time in the Petroleum Industry which includes exploration, drilling development, production, refining, marketing,supportive services and supplies. These personnel must derive a minimum of 85% of their earnings from the Petroleum Industry and have been employed in the industry three (3) months immediately prior to the date of the bonspiel. 2. All Fort St. John, Fort Nelson and Dawson Creek curlers must be members in good standing of their respective Petroleum Association and are not allowed more than two associate members per team. 3. All other out of town curlers must be engaged in full time Petroleum Industry. 4. Four eligible curlers are required to validate the entry. 5. Curling starts Wednesday at 4:00 p.m. (Teams may start with 3, provided 4 are registered.) 6. Bonspiel is limited to FIRST 32 RINKS. Entries must be received by November 8th, 2017. Entry priority will be determined by postmark date and hour. 7. All entries must be mailed - attach cheque or money order $500.00, payable to Fort St. John Oilmen’s Bonspiel, and mail your entry to:
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OCTOBER 20, 2017
PIPELINE NEWS NORTH •
COMMENTARY
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End of Energy East another win for Canadian competitors
I
t’s another week in Canada when businesses and investors are taking their ideas, their people, and their capital elsewhere. On Oct. 5, it was the announcement that TransCanada has scrapped its $15.7 billion Energy East pipeline proposal, after the National Energy Board (NEB) changed the regulatory review process and after it was clear there was no way around the opposition from local and provincial politicians in Quebec. In a decade, we have gone from a country on the verge of becoming a global energy superpower to a place where, because we have so little access to international markets for our oil, we have to sell it at a discount to the United States. This is a $48 million daily gift to our neighbours, who export their own oil at the full international market price. Sadly, this is self-inflicted. Canada is now a country where it is simply becoming too difficult to build big infrastructure projects. Earlier this summer, Desjardins announced it will refuse to finance Canadian energy projects. The oil and gas sector directly employs more than 425,000 Canadians and are the largest source of private sector investment in the country. It’s hard to imagine a leading national financial institution in China, Germany, Singapore or the U.S. abandoning a major sector of their economy – it would be an unacceptable national betrayal. Yet, this announcement conjured a collective yawn from most Canadians as though it is routine and without consequences for our national economy. As federal and provincial governments across Canada have made regulatory approval and permitting process increasingly complicated, time-consuming and expensive, one could be forgiven for thinking they are doing their level best to shut down our energy economy. Well, their plan is working. Consider that TransCanada just spent $1 billion on due diligence for Energy East and has absolutely nothing to show for it. The energy sector in our country is slowly being hollowed out – talent, opportunity and family-supporting jobs are slipping away. Over the past three years, there has been an exodus of international investors from Canada’s oil and gas sector. The largest players in the world are leaving and are not coming back.
Too often in Canada, the rules change, the goal posts are moved, and companies seeking to invest billions of dollars, create jobs and provide opportunities for Canadians are unjustly vilified in the process. In British Columbia, the Site C clean energy project – which has been under construction for two years – is now being forced to undergo yet another review. This, after years of independent reviews and government approvals upheld in no less than 14 court challenges. Petronas threw in the towel on its $36 billion LNG project to export natural gas from B.C. to markets in Asia hungry for cleaner sources of energy than coal or oil. And the new provincial government in B.C. launched a last-minute challenge to the $7.4 billion Trans Mountain Pipeline project, asking the court to overturn all the National Energy Board and federal cabinet approvals. This, after a decade of effort, a 29-month independent review by the NEB, and federal and provincial government approvals. It’s easy to say it was never in the cards for Canada to become an energy super power and some do. But it does not help when every conceivable roadblock is placed in the path of companies that have the vision, capital and courage to try. The past few weeks have been dominated by conversation over changes to the small business taxes. Shockingly, some say we have too many small businesses in Canada and that not enough of them grow into larger enterprises. That’s a matter of opinion, but surely the answer is not to penalize Canadians who want to start a new venture or who are managing small businesses that are the lifeblood of our economy and to label them tax cheats. Unfortunately, we are losing sight of what it takes to attract investment, create opportunities and compete internationally. And, by this measure, Canada’s loss is the gain of its competitors – countries focused on fostering growth, attracting investment, and getting their natural resources to markets. The brash and bold character that built our great country is in danger of being read about only in the pages of history textbooks. Chris Gardner is president of the Independent Contractors and Businesses Association.
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OCTOBER 20, 2017
OUTLOOK
PNN
Top New Montney Wells: Here’s who
is leading in the Permian of the North
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SHELL PHOTO
DEBORAH JAREMKO JWN Energy
It’s been called the most important resource play in Canada, and one of the most important in North America. The Montney play that straddles the BCAlberta border has seen increasing levels of development in recent years; according to the National Energy Board, it is actually the only region in Canada where tight oil production is currently increasing. Analysts with Peters & Co. this week released a list of the top performing oil and gas wells across the Montney-Doig play from this summer. Here’s a look. Top new gas wells According to Peters, Shell had the top five highest natural gas rates for B.C. in August, with a five-well pad at Groundbirch producing about 60 million cubic feet per day (combined) and individual well rates between about 11.3 mmcf/d up to about 13.3 mmcf/d. The wells were drilled in July/August 2016, taking about one year to be completed and
brought on-stream. Murphy, at Sundown, has a high-rate well that came on-stream in August at about 6.5 mmcf/d, Peters notes. Murphy has been operating Montney wells in the area since 2011, with a significant increase to average natural gas production rates in 2017 compared to 2015. The company has brought on five new wells in 2017 with an average first-month production of about 8.0 mmcf/d, compared to the 2015 average of about 5.2 mmcf/d. The rate increases are partially attributable to longer lateral lengths. Meanwhile, Tourmaline brought three new wells on-stream at Doe (all from the same surface pad) with an average natural gas rate of about 5.7 mmcf/d per well, analysts note. Top oil wells ARC brought on five new oil wells in August, with the number one ranked well producing about 525 bbls/d on a calendar-day basis. Producing-day rates are between seven to 21 days per well, Peters says, with an average producing-day rate of 763 bbls/d and the highest rate of 1,204 bbls/d of light oil for a seven day period.
OCTOBER 20, 2017
PIPELINE NEWS NORTH •
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Five upcoming developments from Canada’s major oil and gas producers DEBORAH JAREMKO JWN Energy
Third quarter reporting season is almost upon us, with key developments anticipated from Canada’s leading oil and gas producers as well as the market’s smaller players. Here are five of the biggest announcements that may be made, according to analysts with GMP FirstEnergy. 1. Cenovus Energy is expected to announce its new CEO with its quarterly results, if not before. In June the company announced the retirement of Brian Ferguson, who has led the company since its formation in 2009. The retirement has been viewed by some as a result of negative market response to the company’s $17.9-billion buyout of ConocoPhillips from the Foster Creek-Christina Lake SAGD joint venture. Ferguson is expected to retire effective October 31, and will continue in a transition advisor role until March 31, 2018. 2. Imperial Oil is expected to discuss production improvement initiatives underway at its Kearl oilsands mine. The project, which started its first phase in 2013 and expansion in 2015, has capacity of 220,000 bbls/d but has been unable to achieve these volumes on a consistent basis. Analysts with GMP FirstEnergy note that this spring Imperial implemented some equipment modifications and improvements on one of the two ore preparation/crushing trains at Kearl, and similar work on the other train likely occurred during the third quarter. 3. Suncor Energy will provide an update on construction progress at the new Fort Hills
oilsands mine. Three months ago Fort Hills was said to be 92% complete and on budget and on track for first oil from the first of three trains by year end, with the other two trains expected to start up in early 2018. There may also be an update on a commercial dispute on the project between Suncor and Total SA: “Recall that partner Total SA was refusing to sign off on the acceleration of Fort Hills spending that Suncor announced in July, and that the total post-sanction project cost, on a 100% basis, is expected to be $16.5-$17.0 billion, while total spending by the Fort Hills partnership from inception to project completion is expected to be $20 billion,” analysts said. 4. More important than third quarter operating results at Canadian Natural Resources’ Horizon oilsands project will be an update on the status of the Horizon expansion and the timing of re-start following the September/ October turnaround, said GMP FirstEnergy. “Recall that media articles since confirmed by Canadian Natural reported that an electrical fire occurred in early September at the start of the turnaround, and Canadian Natural is not yet able to disclose whether this fire will impact the timing of the re-start of production, originally scheduled to occur by late October,” analysts said. 5. The focus for Encana is likely to be on the pace of production ramp up in the B.C. Montney through 2018, given that three large gas plants are coming online in the second half of 2017, analysts said. GMP FirstEnergy is assuming Encana to produce 194,000 boe/d average for 2018 in the play, and 216,000 boe/d in the fourth quarter of next year.
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OCTOBER 20, 2017
TRANS MOUNTAIN
Macro JV finalizes $375M Trans Mountain contract Fort St. John-based Macro Enterprises and its joint venture with Speicapag Canada Corp. has finalized a $375-million contract to build 85 kilometres of the Trans Mountain pipeline expansion. The joint venture will build a section of the expansion in the Coquihalla-Hope area. Construction also includes upgrades to one pump station. Construction is anticipated to start once regulatory requirements are met, the company says, with the contract expected to last until November 2019.
“As a British Columbia based company, we are proud to be part of this important project,” Macro President and CEO Frank Miles said. “We will continue to support Trans Mountain in their continual engagement with stakeholders, specifically working with Aboriginal and local communities ensuring positive working relationships now and in the future.” Macro began in Fort St. John in 1994. Spiecapag is part of the Entrepose Group, and has built pipelines across the world, including Angola, South Africa, Colombia, and Yemen.
The $7.4-million pipeline expansion will increase Trans Mountain capacity to 890,000 bbls per day from 300,000 bbls a day between Edmonton and Burnaby. A legal challenge against the project began in federal court on Oct. 2, while the NDP government reiterated this week it would use every available means to halt the project. Meanwhile, a recent Angus Reid poll found 47 per cent of British Columbians believe the pipeline should proceed as planned. Just 33 per cent thought the project should be scrapped.
Canada learned from mistakes, court hears NELSON BENNETT Business in Vancouver
In approving a $7.4 billion expansion to the Trans Mountain pipeline, the Government of Canada did not repeat the mistakes it made in approving the Northern Gateway pipeline, the Federal Court of Appeal heard October 12. In opening arguments, Jan Brongers, lead counsel for the Attorney General of Canada, said the consultation process for Trans Mountain differed from the Northern Gateway process in six critical ways. Two years ago, the same court that is now hearing the Trans Mountain appeal heard the Gitxaala vs. Canada case, which resulted in the court quashing Northern Gateway’s approval because of flawed First Nations consultations. Even before that ruling came down, government officials took steps to close some of those gaps in the Trans Mountain process, including granting a four-month extension to allow for “deeper and more meaningful consultation” with affected First Nations. “This additional time permitted not only deeper consultations with impacted First Nations, but also afforded time for additional information-gathering exercises,” Brongers said. Those exercises included an upstream greenhouse gas assessment report for the pipeline twinning project and a report from a special ministerial panel, which was struck to get feedback from First Nations and the general public on the National Energy Board (NEB) final report on the expansion.
The NEB confined its review to the pipeline expansion on the basis that marine traffic is not in its purview.
“Nothing similar to those initiatives had been done in Northern Gateway,” Brongers said. And whereas the Crown failed to share strength-of-claim assessments with First Nations in Northern Gateway, Brongers said those assessments were shared in Trans Mountain. These assessments offer legal opinions on the strength of the claim that a First Nation might have with respect to its rights and title, should it try to assert those rights in court. And whereas in Northern Gateway Crown officials were found to be mere note-takers who did not propose any recommendations to the governor-in-council (GIC) to address First Nations concerns,
in Trans Mountain Brongers said cabinet ministers who made up the GIC “were directly implicated in the consultation.” They received recommendations outside of the NEB certificate for additional accommodation and implemented them, including the creation of the Indigenous Advisory and Monitoring Committee and the $1.5 billion Oceans Protection Plan. Individualized appendices were also provided to the GIC for each First Nation to avoid the problem of “generic” consultations that characterized the Northern Gateway consultations. “In Trans Mountain, the direct consultation was by no means generic,” he said.
Brongers added that, in addition to the NEB’s recommendations and conditions, the GIC would have had additional government actions before them that were not available in Northern Gateway. Notably, the Trans Mountain expansion required an upstream greenhouse gas assessment. While acknowledging the Trans Mountain twinning project to be “politically controversial,” Brongers said, it was preferable to the alternatives: moving oil by rail or building a new pipeline. Court officials say the seven-day Federal Appeal Court hearing was the longest ever. Arguments were scheduled to conclude October 13.
OCTOBER 20, 2017
PIPELINE NEWS NORTH •
OPERATIONS
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Montney plants start up ahead of schedule and under budget Tower Operations at the Tower natural gas processing plant north of Dawson Creek have started ahead of schedule and under budget, Encana says. The plant’s start up began Sept. 20 and is in the process of ramping up to its 200 million cubic feet per day capacity. The plant, budgeted at $715 million, is the first of three expected to start up before the end of the year and supports the Cutbank Ridge Partnership’s condensate-focused growth plan in Northeast B.C. “The Tower plant startup, delivered ahead of schedule and under budget, is an important milestone in our strategy and five-year plan,” Encana President and CEO Doug Suttles said. “Liquids growth in the Montney is a key driver in expanding our corporate margin and delivering quality returns.” The Cutbank Ridge Partnership includes Encana and Cutbank Dawson Gas Resources Ltd., a subsidiary of Mitsubishi Corporation. Encana is building three midstream facilities in the South Peace—Tower, Sunrise, and Saturn—on behalf of Veresen Midstream, which will more than double the company’s liquids production in the Montney from the fourth quarter of 2016 to the fourth quarter of 2017. Veresen, which is providing midstream services to the partnership, funds and owns the facilities while Encana will pay to use them
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An Encana drilling rig in the Montney.
through a 30-year fee-for-service agreement. Sunrise Encana successfully started up the Sunrise processing plant on September 27, under budget and more than one month ahead of original schedule. The plant has a capacity of 400 mmcf/d. Saturn In parallel with the Sunrise and Tower facilities ramping up, the third plant, Saturn remains ahead of schedule and is on track to start up
before year-end. In addition, the Towerbirch lateral pipeline which connects all three plants to the NGTL system started up on October 1. The Saturn plant is expected to have one of its two 200 mmcf/d trains in-service by year-end, followed by its second train in the first half of 2018. Encana says its liquids and gas volumes in the Montney are expected to grow throughout 2018 as drilling programs bring the plants to full capacity. When all three plants become operation, Veresen Midstream will have 1.5 bcf/d of gas processing capacity in operation.
AltaGas commissions second Townsend gas plant AltaGas says that commercial operations have begun at its 99 mmcf-per-day shallow-cut natural gas processing facility on the existing Townsend site, adjacent to the currently operating Townsend facility in Northeast B.C. Commissioning of Townsend 2A was completed Oct. 1, 2017, with volumes expected to progressively ramp up through the fourth quarter of 2017 to the first quarter of 2018. The $125-million project was completed slightly ahead of schedule and approximately $5 million under budget. AltaGas and Painted Pony Energy have entered into 20-year take-or-pay agreements in respect of Townsend 2A and the incremental field compression equipment, subject to the satisfaction of certain conditions contained in the agreements. “By linking our significant midstream projects together — Townsend, North Pine
and the Ridley Island Propane Export Terminal (RIPET) — we are executing on our vision of offering Canadian producers a complete energy value chain,” AltaGas CEO David Harris said. The Townsend gas processing complex is at the heart of the company’s Northeast B.C. strategy and the safe commissioning of Townsend 2A marks the second stage of development at the complex, with permitting in place to increase by a further 99 mmcf per day, he said. AltaGas also has significantly advanced its other major construction projects for its northeast B.C. and energy export strategies. The 10,000 bbl-per-day North Pine NGL separation facility is tracking under budget and ahead of its previous schedule of the first quarter of 2018, with an online date now expected in early December 2017. The investment will be backstopped by long-term supply agreements
with Painted Pony for a portion of the total capacity, and will include dedication of all of Painted Pony’s NGL produced at the Townsend and Blair Creek facilities. The remaining capacity is expected to be filled with NGL produced in the area. At the Ridley Island Propane Export Terminal, construction continues to progress with the third of eight concrete pours underway and the final pour scheduled near the end of 2017. As construction progresses, AltaGas said it is seeing increased interest from western Canadian producers and aggregators looking for new access to premium Asian markets for their propane. Construction is tracking on budget and RIPET is expected to be in service by the first quarter of 2019. —Daily Oil Bulletin
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• PIPELINE NEWS NORTH
OCTOBER 20, 2017
INNOVATION
Microorganisms to convert renewable NRG to pipelineable NG MAURICE SMITH JWN Energy
Southern California Gas Co. (SoCalGas) has installed a novel bioreactor system that will be used to test power-to-gas technology at the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL) in Golden, Colorado. The project is the first of its kind in the United States converting hydrogen generated from excess renewable power into pipeline quality methane. Power-to-gas technology is a cutting-edge method of storing excess renewable energy, according to Los Angeles-based SoCalGas, the largest natural gas distribution utility in the United States. Last month, researchers at NREL’s Energy Systems Integration Facility (ESIF) in Golden, Colorado, installed a 25-foot tall bioreactor system, which will be used to produce renewable natural gas from excess renewable electricity using archaea microorganisms that consume hydrogen and carbon dioxide and
emit methane. “Power-to-gas technology can significantly increase the overall amount of renewable energy we use, by providing an economical method of storing excess solar-and wind-generated electricity,” Jeff Reed, director of business strategy and advanced technology at SoCalGas, said in a statement. “And this technology takes advantage of existing infrastructure, and can hold excess renewables for days, weeks or months to shift solar from day to night, address weather patterns and even seasonal patterns.” Subscribe to the free JWN weeklyEnergy Tech e-newsletter. SIGN ME UP “Archaea are uniquely capable of handling fluctuating levels of hydrogen produced by electrolyzers as wind and solar generation systems cycle up and down,” added Kevin Harrison, senior engineer for NREL. “That’s in part why we believe this technology could provide a superior large-scale, costeffective solution for storing excess renewable energy using our nation’s
natural gas distribution system.” According to a 2017 Lawrence Berkley National Lab study, by 2025, between 3,300 and 7,800 gigawatt-hours of excess solar and wind energy will be curtailed in California. If all that excess solar and wind energy were converted to methane through the biomethanation process and stored as renewable natural gas, it would provide enough renewable energy to heat 158,000 to 370,000 homes or provide renewable electricity to 80,000 to 187,000 homes. The pilot project will be used to help assess the commercial viability of this power-to-gas approach to energy storage and provide insights into potential megawattscale system designs. The team will combine these insights with renewable energy resource data to identify optimal locations in California and the western half of the U.S. where this grid-scale energy storage would be the most beneficial and cost-effective, said SoCalGas. Power-to-gas technology uses renewable electricity when prices
are low—including times when renewable supply exceeds demand and would otherwise be wasted— to power an electrolyzer, which splits water to produce hydrogen. The hydrogen is then combined with carbon dioxide and fed to a biomethanation reactor where it is converted into renewable natural gas, or RNG, by special micro-organisms. RNG can be used in any application currently served by natural gas, from home appliances to industrial processes, heavy duty vehicle engines and power plants. The research will also test how effectively the microbes convert hydrogen to methane and how efficiently the storable methane can be converted back to electricity. Tests will examine the potential of power-to-gas technology to store large quantities of renewable energy for up to an entire year and how it compares in performance and cost to battery storage. Initial reports are expected beginning in 2018. The study will continue for several years.
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OCTOBER 20, 2017
PIPELINE NEWS NORTH •
INNOVATION
9
Drone tech to create Canada’s first real-time GHG database
VISION EVENT PHOTOGRAPHY
Geoscience BC used sensing technology developed by NASA and the Jet Propulsion Laboratory to develop its gas sniffing drone, seen here in a demonstration on Sept. 27.
NELSON BENNETT Business in Vancouver
“What is the province doing about getting a baseline on greenhouse gases?” Asked that question at a panel on energy Sept. 27 during the Union of BC Municipalities (UBCM) convention, B.C. Energy, Mines and Petroleum Resources Minister Michelle Mungall deferred the question to Environment Minister George Heyman, who was not there to answer. Turns out Geoscience BC has the answer: It’s using drones and technology developed by NASA for its Mars missions to sniff out methane and create a real-time GHG database—the first of its kind in Canada. The new technology was demonstrated in September at the UBCM convention. Using technology developed by NASA and the Jet Propulsion Laboratory, Geoscience BC will use low-flying drones able to detect and pinpoint methane molecules to create what is being billed as Canada’s first real-time GHG database. “Independent scientific data is essential in making informed decisions relating to natural resource
development,” Carlos Salas, Geoscience BC’s vice president of energy, said in a statement. “We are demonstrating how the technology works and how it will be used to map greenhouse gas emissions in northeast British Columbia and beyond to help the resource sector, First Nations, governments and communities to make more informed resource management decisions. By bringing this technology to commercialization, GHGMap will also create new economic opportunities for western Canada.” One of the biggest concerns with the oil and gas industry in B.C. is fugitive methane leakage from gas wells. Although it is more short-lived than CO2, methane has greater heat insulation properties, so it has a much higher global warming potential. But natural gas wells aren’t the only source of methane. Cattle and decomposing organic matter also produce it, so determining just how much methane comes from natural sources or the gas industry can be challenging, especially in Northeast B.C., which has both cattle ranches and natural gas wells. “Natural and human releases of greenhouse gases, such as methane,
carbon dioxide and nitrous oxide, to the atmosphere present real concerns for climate change and air quality. Assessing and reducing these emissions requires reliable, uncomplicated measurements,” Dr. Michael Whiticar, GHGMap Project Lead, said. “Our new mini-optical instrument mounted on a small drone allows us to quickly and effectively make these measurements on regional and local scales in a completely novel approach. We believe that this
new way of doing things will make a substantial difference.” Currently, GHGs from gas fields are estimated using periodic sampling and computer modelling. The new GHGMap project will provide more accurate mapping. Geoscience BC says it will be the first real-time GHG database in Canada. It will initially be used in B.C.’s natural gas fields, but will eventually extend its use to other areas in Western Canada.
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OCTOBER 20, 2017
REGULATORY
OGC issues seven orders against Progress Energy, Conoco-Phillips Following an inspection of dams used by the oil and gas industry in Northeast B.C., the BC Oil and Gas Commission has issued seven compliance orders to ensure they are safe and pose no threat to the environment. During the spring, the commission proactively inspected 51 dams located in the Montney region and Horn River Basin. As a result of the inspections, the Commission found there were no incidents of failures or release of water or sediment from any of the dams. However, some issues were noted at seven dams, and orders were issued
to two companies. Five orders were issued to Progress Energy Canada Ltd. and subsequently, the company was required to draw down water levels to 50 per cent of live storage. The commission has carried out follow up inspections to confirm these orders are being complied with. Conoco-Phillips was issued two orders to dewater two dams. ConocoPhillips acquired responsibility for these sites when it purchased the leases from another Montney operator. The orders have been complied with and are now terminated. Some freshwater storage structures used in the oil and gas industry
Enbridge backs away from Stand.earth asset seizure NELSON BENNETT Business in Vancouver
The Vancouver office of Stand. earth (formerly ForestEthics) was raided Oct. 17 by federal court bailiffs for failing to pay a $14,559 bill owed to Enbridge Inc., following a failed court challenge of the company’s Line 9 pipeline reversal project. The unpaid bill was from a federal court challenge of the 2014 National Energy Board’s approval of a line reversal that would allow oil from Alberta to flow through its Line 9 pipeline to Eastern Canada. ForestEthics, which later became Stand.earth, was involved in a federal court appeal of the NEB decision. The appeal was dismissed but was appealed to the Supreme Court of Canada. Enbridge was an intervener in the case and was awarded costs of $14,559 when the challenge was dismissed. But Stand.earth never paid the bill, and so on Oct. 17, Enbridge received a court order for bailiffs to seize property, which will be sold to pay the bill. Stand.earth spokesperson Karen Mahon told Business in Vancouver that bailiffs had entered the office Tuesday morning, took photographs and informed the environmental organization they would be back with a truck to seize property, which will be sold. “We had assumed that Enbridge
would not be pursuing it because, since that original case, we have been proven right in many other court cases, and certainly in the court of public opinion, where the National Energy Board has admitted that their consultation policy was woefully inadequate,” Mahon said. “I don’t think this is about damages,” she added. “This is $14,000 that a company that made $4.6 billion last year is trying to collect. For us, this is clearly an act of intimidation. It’s clearly not about the money. Enbridge doesn’t need $14,000.” Just a couple of hours after bailiffs arrived, Enbridge released a terse statement, saying it has decided against seizing Stand’s property after all. “We have asked the sheriffs not to seize any assets from Stand. Earth, and will not be pursuing the matter further,” Enbridge communications adviser Jesse Semko said in an email. “This is a legal matter and Enbridge does not publicly discuss legal matters.” According to Stand.earth’s most recent financial statements from 2015, the environmental group had $2.7 million in revenue from donations, foundation grants and other revenue, had expenditures of $2.1 million, and ended the year with $1.4 million in net assets.
qualify as dams under the Dam Safety Regulation of the Water Sustainability Act. The commission was granted the authority to inspect those dams under the regulation in 2016 to ensure they are in compliance and will remain safe to the public and environment. The commission required the operators of water storage structures to submit the necessary applications, including assessments and any necessary design modifications done by qualified engineers—and those continue to come in, with the commission working to review all of them to ensure timely decisions are made in accordance with applicable
regulatory and legal requirements. The commission has taken an expanded role this year—including both designating existing staff and hiring new staff who will be designated as dam safety officers and engineers—to ensure the proper oversight of dams used for oil and gas purposes. The commission has also launched two features on its website. A compliance and enforcement page shows orders and rulings issued to oil and gas operators. A regulated dams page shows all commission-regulated dams. —BC Oil and Gas Commission
FSJ mayor talks resource development at BC Conservative AGM Fort St. John Mayor Lori Ackerman is one of a number of guests set to speak at the BC Conservatives annual general meeting on Sept. 30. Ackerman delivered a lunch hour speech on resource development at the meeting in Langley, followed by Canadian Taxpayers Federation BC Director Kris Sims, who spoke about taxation. But don’t consider it a political defection, Ackerman said ahead of the meeting, noting she remains a card-carrying BC Liberal. It’s just part of being a mayor on the public speaking circuit with a focus on energy literacy—a much-needed discussion to show the province can work together until global commodity pricing, especially oil and gas, improves, she said. “It’s important to get out there and have conversations about energy literacy that is lacking in the province,” Ackerman said. “I will take the time to go to wherever I’m being asked to speak about resource development in this province.” Major energy projects have taken centre stage in the early days of B.C.’s new NDP minority government, which has waded into legal challenges against the $7.4-billion Trans Mountain pipeline expansion and ordered an economic review of the $8.8-billion Site C dam. Billions more in proposed liquefied natural gas developments, including Pacific
NorthWest LNG and Aurora LNG near Prince Rupert, have also been shelved since the new government took office. Meanwhile, the province has lost a year’s worth of fibre supply—some 54 million cubic metres—in the Interior because of this summer’s wildfires. Ackerman believes the province has a chance to marry the technology and resource industries to lower emissions and leave a lighter footprint across the board. “With the significant contribution that our resource industries and the significant contribution our technology industry can have, marry those together so our technology industry in Vancouver is not intimidated to work on our resource industries,” she said. “I’ve heard it from them … they’ve said to me, ‘we don’t tell people we work in the oil and gas industry.’ It’s sad.” The BC Conservatives are looking to rebuild and re-establish riding associations across the province following the defeat of Christy Clark and the BC Liberal government earlier this year. The Conservatives were responsible for a handful of riding upsets for the Liberals—including the hotly-contested riding of Courtenay-Comox, which went to the NDP by 189 votes following a ballot recount. That seat put the NDP into a position to oust the Liberals in a confidence vote with the support of the BC Greens.
OCTOBER 20, 2017
PIPELINE NEWS NORTH •
LNG
LNG Canada CEO Andy Calitz: “We need the government of British Columbia specifically, but also the federal government, to take a last look at the fiscal tax competitiveness of Canada for an LNG project.”
Canada didn’t miss LNG boat NELSON BENNETT Business in Vancouver
A $40-billion liquefied natural gas plant proposed for Kitimat is still very much alive, says the CEO of LNG Canada—but senior governments may need to address tax competitiveness before Shell and its three partners can make a final investment decision. “I actually believe that B.C. will have an LNG industry, that there is societal support for an LNG industry from B.C. and … I believe specifically the LNG project can and will happen in B.C.” Andy Calitz told Business in Vancouver, following an address to the Greater Vancouver Board of Trade (GVBOT) Sept. 22. Michelle Mungall, the NDP’s new minister of energy, mines and petroleum resources, who met one-on-one with Calitz earlier in the day, seemed to share Calitz’s optimism, and said her government is considering some of the concerns the consortium—Shell, Mitsubishi, KOGAS and PetroChina—have expressed about moving forward. “Our position has always been supportive of LNG, as long as the industry meets our four conditions,” Mungall told reporters in a scrum after Calitz’s address. “And what I think is important to remember is that conditions are not roadblocks, they’re roadmaps.” A current glut of LNG on the market, much of it from new LNG plants in Australia, have whittled global LNG prices in half from what they were in 2013, when many of the big players, including Shell, were entering regulatory processes. But demand continues to grow in
Asia, and there are new LNG markets developing in India, Indonesia and Pakistan, meaning there will eventually be a demand for more LNG plants. But Shell, which has LNG projects on the drawing board in practically every time zone, has made it clear that it will only invest in projects that are competitive. “We do need to address, on a broader scale, what’s going on in terms of the global marketplace and (the question): is B.C. competitive in this global marketplace as it stands right now?” Mungall said. “And that’s a very good question and one that we’re actually answering. I’ve directed my ministry to look into that and to begin to work with First Nations, local communities, as well as the industry.” Following the announcement that two other major LNG projects proposed for Prince Rupert had been cancelled not long after the new NDP government took power—Petronas’ Pacific NorthWest LNG and Nexen’s Aurora LNG—there was considerable speculation that Canada had missed the boat on an LNG industry. “I don’t believe that Canada has missed that boat,” Calitz told GVBOT members. Unlike the Petronas and Nexen projects, both the LNG Canada plant itself and associated Coastal GasLink natural gas pipeline are fully permitted. The project has also had the support of First Nations in the Kitimat region, notably the Haisla, whereas some First Nations in Prince Rupert area were opposed to the project. Calitz said the Petronas and Nexen
decisions have both positive and negative implications for the LNG Canada project. “It strengthened the voices of both the critics and naysayers that say there will be no LNG from B.C. or there should be no LNG from B.C.,” Calitz said. Among those naysayers is Green Party Leader Andrew Weaver. On the positive side, Calitz said that 40 contractors that are bidding on contracts to build the plant now have less competition for scarce skilled labour. Calitz reiterated what is often cited as two competitive advantages that B.C. has as a potential LNG developer – proximity to Asian markets and one of the largest most productive natural gas plays in the world – the Montney in northeastern B.C. The biggest obstacle is current market conditions, although Shell executives have been more optimistic than many analysts when it comes to estimating how soon a current glut of LNG will balance out with an ever growing global demand for LNG. Earlier this year, Shell divested itself of some of its natural gas assets in B.C., which raises the question of whether LNG Canada would have enough upstream supply for the twotrain LNG plant the consortium wants to build in Kitimat. Calitz pointed out that Shell is not the only partner in the consortium with natural gas holdings in B.C. “The four partners in LNG Canada…have enough gas supply to keep the energy trains full,” he said. In addition to meeting one-on-one with Mungall last week, Calitz said he planned to meet with Premier John Horgan next month. Asked if the Green Party’s opposition to the LNG industry concerned him, Calitz said it didn’t and pointed out that the official opposition—the Liberals—are fully supportive of an LNG industry. “The combination of the NDP (MLAs) and Liberal (MLAs) who
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support an LNG project and a new mega industry for British Columbia is good enough for me to move forward in British Columbia,” Calitz said. The biggest hurdle for the project may be the question of tax competitiveness. The new NDP government plans to raise B.C.’s carbon tax from $30 per tonne to $35 per tonne, starting in the spring. Calitz made it clear that it’s not carbon taxes per se that are the big concern. Rather, it’s the full suite of taxes, from the municipal to federal level, that need to be considered. “There should be a tax on carbon,” Calitz said. “It’s not the first increment of $5 per tonne that scares me, but somehow we need an indication from the government as to where that will go. “We need the government of British Columbia specifically, but also the federal government, to take a last look at the fiscal tax competitiveness of Canada for an LNG project. “This is an important but also a sensitive matter. We do not seek any form of subsidy at all. We pay our full tax burden. One of the conditions of the new government is that there should be a fair return and benefit for British Columbians. We will do that. We need them to look at the full complexity of federal, provincial, local and other taxes that we pay to say, ‘Does this still make sense? Is this still competitive?’” One of the biggest criticisms from the industry’s standpoint of the former Liberal government’s tax and royalty regime for LNG was a special LNG tax, which companies in regions like the U.S. and Australia do not pay. Asked if that LNG tax was something LNG Canada needs addressed, Calitz indicated it was. “That is a subject we are discussing with the government,” he said. Calitz said LNG Canada will submit a “decision support package” to all four companies in the joint venture in support of a final investment decision sometime in 2018.
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• PIPELINE NEWS NORTH
OCTOBER 20, 2017
TECHNOLOGY
Straightening out the kinks in hydraulic fracturing technology MAURICE SMITH JWN Energy
The technologies that set off the shale gas and tight oil revolution, reviving the onshore industry across North America, still have some kinks that can be costly to straighten out. For example, the massive hydraulic fracturing completions required to liberate the oil and gas from the shale and extremely tight rock can pose unintended—and potentially dangerous—consequences to adjacent wells. In 2012, the blowout of a well near Innisfail, Alta., was caused by fracking in a nearby well, when frac fluid pumped under high pressure came into communication with the producing well—both targeting the same formation some 1,800 metres underground—and blew its top. Almost 500 barrels of oil and water blasted from the wellhead, impacting 4.5 hectares of surrounding area. Where sour gas might be present, a blowout presents the additional danger of exposure to toxic hydrogen sulphide (H2S). Thus, in many jurisdictions, offset wells are required to be shut in, typically with their hardware removed, while fracking takes place nearby—a potentially costly procedure. It’s a problem for which a Calgarybased start-up has a solution. Well Suspension Tools (WST) produces two deceptively simple tools that enable the temporary shutting-in of wells without the need to remove downhole pumps, sucker rod assemblies and associated hardware by allowing them to remain suspended within the well. “In the past there hasn’t been an easy way to shut in the well properly. To do a frac safely, companies would have to pull all the rods and lay them down at surface. For each of the affected offset wells, it takes about a day to pull out the rod assembly and a day to re-install them—per well. The associated costs and the lost production due to downtime can really affect the economics of an area,” says Leslie Kohnen, WST’s president. “If you use our tools, you can leave the rods in the hole, and if you want to leave them for more than a few days, you can inhibit the well so that there is no corrosion, and you could leave them for 20 years if you wanted to. “As a case in point in North Dakota, a major operator using the WST tools successfully shut in 14 wells in a day and a half. Then after the frac, got them back on production even
JWN ENERGY PHOTO
Ken Gordey, senior vice-president and technical manager, Well Suspension Tools.
faster,” Kohnen says. “Because they had 14 adjacent wells [to shut in], they saved over $500,000 on that one frac. It’s the kind of thing that saves a huge amount of money for very little cost. “Tool installation and retrieval is being done in less than one hour. The operator has re-used the tools several times, so the economic benefits of using them increases each time. The tool design also allowed the pressure to be monitored during the frac, which has been a great asset in determining their frac design and effect.” Protection of offset wells during frac operations represents about 60 per cent of WST’s business. The tools also offer effective solutions for other challenges involving rod pumped wells, such as for short- and longterm well shut-ins, well maintenance and well servicing. They have most recently been used as a solution for emergency shut-ins, such as where a weather event like a tornado requires hasty evacuation. “We had a call from a service rig operator in Oklahoma out of the blue. They wanted a tool which allowed them to quickly and safely shut in a well during the pulling or running of the rod assembly. They can now secure the rods and well safely and be off the wellsite in minutes,” says Kohnen. Ken Gordey, senior vice-president and technical manager at WST, was a consultant specializing in finding
efficiencies for oil companies. He came up with the concept for the tools after he became one of the many casualties of the 2014 oil price collapse. With his past experience on well operations, he says he challenged himself, thinking, “There has to be a better way to suspend, re-activate and workover oil wells.” Suspending an oil well leaving the polished rod and the stuffing box as a seal is not safe as it requires scheduled maintenance to work effectively. The seals dry out and start to leak, which can cause a huge liability and environmental catastrophe, he says. “Stuffing boxes were never designed as a valve.” So Gordey created the C tool and the T tool, both internal rod hangers named for the shape of the devices. They allow the rods to be hung and a wellhead valve placed on top, thus implementing a simple economic operation to suspend and re-activate the well. WST has patents pending on the tools and applications procedures. “The cylindrical C tool slides over the sucker rod and is seated at the top of the tubing, raising the rod string and pump off the bottom. The polished rod/stuffing box is removed, and a wellhead assembly is installed. With the pump unseated, fluid and inhibitors can be pumped past the C tool and down the tubing assembly easily,” Gordey explains. “The T tool threads onto the rod
string, holding it in place. Bypass slots on the side allow for fluid to be pumped into the well and for pressure to be bled off. It is the first tool to allow operators to squeeze solvents and chemicals safely using a 3,000 or 5,000 psi wellhead valve and pumping at high pressure through the tool,” he says. Two different tool designs allow for many different applications, from conventional rod wells to steam injection. The tools can be landed in the wellhead or installed in the tubing hanger. “If the rods are being put into or being pulled out of a well, and the operation needs to stop due to safety, mechanical or weather issues, simply install the tool and put on a wellhead valve and shut down the well,” Gordey says. “It can be done in less than three minutes.” With sucker rods and the bottomhole assembly left in the well—protected within an inhibited environment against degradation— well suspensions, re-activations and production optimization operations are faster and cheaper, he adds. Working on horizontal wells has also become more efficient. By unseating the bottomhole pump and hanging the rod string, fluids can be pumped and circulated to the tubing tailpipe, which is situated in the horizontal section, of the well more effectively. Alberta Oil Tool, a major rod manufacturer in Edmonton, produces the tools for WST following API standards, ISO 9001 and certified engineered drawings. In addition, C-FER Technologies has tested the tools to the highest industry standards. The tools can be used in any well environment including high H2S and CO2. WST has also recently introduced a version of the T tool adapted for cyclic steam stimulation for heavy oil, developed for a senior operator. The company expects to see more opportunities going forward as the downturn has left maintenance neglected and companies continue to focus on costs amid a modest oil price recovery. “Due to current procedures, a lot of wells haven’t been worked over or been maintained in a fairly long time, and with these tools, you can go into an existing rod well and do your stimulation or your chemical work, get rid of your issues and do a lot of the maintenance jobs that need to be done—for a lot less money than it would be if you didn’t use it,” Gordey says.
OCTOBER 20, 2017
PIPELINE NEWS NORTH •
SAFETY
13
INGU SOLUTIONS PHOTO
Sensors could change pipeline safety performance R.P. STASTNY JWN Energy
An early-stage company called Ingu Solutions has developed an affordable miniaturized technology for pipeline leak detection, geometric defects and deposits that threaten pipeline performance and safety. “Pipers” are golf-ball-sized sensors that Ingu Solutions puts into pipelines and let flow with the product stream as a cost-effective inspection tool that strengthens preventive maintenance processes. Industry estimates that about 40 per cent of the world’s pipeline assets are too difficult or expensive to inspect, representing a 1.5-million kilometer opportunity for Ingu. And then there are all the pipelines where Pipers can complement traditional maintenance procedures that use smart PIGS (Pipeline Inspection Gauges). “We’re not only reducing costs, but we’re enabling oil and gas companies to inspect pipeline assets that are currently unreachable,” says Ingu CEO John van Pol, a nuclear physicist who leads the Calgarybased company of six people. “There’s no diameter constraint in the pipeline or a flow constraint, where as a PIG always has the diameter of the pipeline.” The viability of Pipers technology is evidenced by Chevron Technology
Ventures making Ingu Solutions one of its first choices for the recently launched CTV Catalyst Program, an initiative to help early-stage companies promote technology to advance the oil and gas industry around the world. “Currently we’re running lab pilots and expect to do the first field pilot still this year,” van Pol says. From wormholes to pipes Nucleons and oil and gas sensors might seem worlds apart, but van Pol says there’s actually more commonality than people might think between nuclear physics and what Ingu is trying to do with its instruments in a pipeline. Originally from the Netherlands, van Pol started looking at sensor technology for remote and inaccessible areas in 2008 and connected with Saskatchewan’s Petroleum Technology Research Center, which wanted to map wormholes created by the reservoir process known as CHOPS (cold heavy oil production with sand). In CHOPS, sand is purposely produced in order to create these wormholes as pathways for heavy oil extraction. The idea was to see if a sensor could be made small enough to travel through a wormhole reservoir to provide more information and potentially lead to better production in CHOPS plays.
“We learned that the sensor would need to be seven millimeters or less to go through one of these wormhole reservoirs,” van Pol says. The problem was that the smallest commercially available sensor the team could make without having to invest a lot of capital to build their own chip was about 40 mm. “We developed a 40 mm version and started to test that with the Saskatchewan Research Council in Saskatoon and, even though we couldn’t use this on wormholes, it was perfectly suitable for pipelines,” van Pol says. After a project testing the sensors with Shell Canada, van Pol founded Ingu Solutions, relocated to Calgary and got picked up by Chevron for its innovation program. PIGS versus golf balls While PIGS exist in various diameters, the narrower a pipe is, the risk of a PIG getting stuck in the line increases. A golf ball-sized sensor, on the other hand, is easy to inject and extract and doesn’t get stuck. At only “a couple hundred dollars” per piece, van Pol says Ingu’s clients essentially get the sensors for free and are charged for the data analytics. That lower capital threshold opens the door for more frequent use compared to PIGS, which are typically run on a five or
10-year intervals. “You could even run them monthly or weekly. We can compare the subsequent runs and get a picture of the state of the pipeline over time, which means that the information is much more accurate.” Challenges A common challenge cited in bringing a new technology to market is that no one wants to be the first to try to prove it out — especially when pipeline safety is at stake. Ignu’s association with Chevron has helped overcome that hurdle and van Pol says the company now has “a couple of clients in Calgary that are pretty eager to run first trials on live line.” The flip side of that challenge is battling the assumption that intuitive technology for leak detection will solve all pipeline problems. “The second challenge is managing expectations, “ van Pol says. “Today we can do leak detection. A few months from now, we may be able assess wall thickness. In a year, we might be able to look at corrosion. We’re rapidly developing new technology but it takes time to get there. Smart PIGS, after all, were developed over the course of decades. So we have to make sure that we have a viable solution for today while working towards expanding those capabilities in the future.”
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• PIPELINE NEWS NORTH
OCTOBER 20, 2017
IN BRIEF
Petronas ‘committed’ to North Montney Petronas is reaffirming its commitment to the North Montney after putting a significant number of its assets in northern Alberta up for sale. The Malaysia state-owned oil and gas company has hired BMO Capital Markets to sell off its assets in the Deep Basin. It includes more than 400,000 gross acres with a 63 per cent working interest, ownership in three gas plants and pipeline network, and 32,000 acres of royalty, fee and feeleased lands in Alberta, Saskatchewan and Manitoba.
“I can say from the outset that withdrawing from Canada is not what is happening,” Progress spokeswoman Eryn Rizzoli told the Canadian Press. “The potential sale of our Deep Basin assets, which represents a small portion of Progress Energy’s resource base, would allow us to focus on our North Montney (B.C.) development, which represents significant growth opportunities in Canada.” In a mid-year earnings update, Petronas reported earnings of CA$13.4 billion, up 35 per cent increase from the CA$9.9 billion recorded in the same period last year. Progress had been producing 540 million cubic feet of gas per day to the domestic market and generated CA$261 million in the first two quarters of 2017, Petronas said. “Despite the decision not to
proceed with (Pacific NorthWest LNG), Petronas remains committed to monetise the natural gas resources in the North Montney area in Canada,” the update reads. “At 22.3 trillion cubic feet of proven resources, Canada holds the second largest gas resources in Petronas’ portfolio after Malaysia.”all commission-regulated dams. —PNN
Daily Oil Bulletin launches new assets portal Daily Oil Bulletin (DOB) has announced the launch of its new Assets for Sale portal on Sept. 19.
The data can be accessed via the Bulletin’s website, which is a subscription-based service. The map displays oil and gas assets—royalty, production, land— available for acquisition or trade. Advisors and sellers are listed with each property. Asset data for this new initiative is supplied by CanOils, which is owned by JuneWarren-Nickle’s Energy Group, which also publishes the DOB. JWN, DOB, Rig Locator, and Pipeline News North are all owned by Glacier Media. The tool provides unique view of energy assets for sale across Canada, presented in a map format similar to Rig Locator. In Northeast B.C., users can find 15 production assets for sale and three parcels of land for sale. —Pipeline News
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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.
OCTOBER 20, 2017
PIPELINE NEWS NORTH •
IN BRIEF Plastics building up Since the early 1950s, when large-scale production of synthetic materials first began, humans have created 8.3 billion tonnes of plastics, most of which has since been discarded. A study published in the journal Science Advances was the first of its kind: a global analysis of the production, use and fate of all plastics ever made. The researchers found that by 2015, humans had generated 8.3 billion tonnes of plastics and already thrown out 6.3 billion tonnes of it. Of the waste total, only nine per cent was recycled, 12 per cent
was incinerated and a whopping 79 per cent was left to accumulate in landfills or the natural environment. If this trend continues, approximately 12 billion tonnes— approximately 35,000 times the weight of the Empire State Building—of plastic waste will find its way into landfills or the natural environment by 2050. “Most plastics don’t biodegrade in any meaningful sense, so the plastic waste humans have generated could be with us for hundreds or even thousands of years,” says Jenna Jambeck, a study co-author and associate professor of engineering at the University of Georgia. “Our estimates underscore the need to think critically about the materials we use and our waste-management practices.” The pace of plastic production
has outgrown most other humanmade materials, increasing from two million tonnes in 1950 by approximately 20,000 per cent to more than 400 million tonnes in 2015. Materials growing at a faster rate are used extensively in the construction sector, such as steel and cement. While those materials are meant to last, plastics’ largest market is in packaging, most of which is used once and discarded. “Roughly half of all the steel we make goes into construction, so it will have decades of use—plastic is the opposite,” says Roland Geyer, lead co-author of the report and assistant professor of environmental science at the University of California, Santa Barbara. “Half of all plastics become waste after four or fewer years of use.”
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And the pace of plastic production shows no sign of slowing. Of the total amount of plastic produced in 1950-2015, roughly half of that was just in the last 13 years. “What we are trying to do is to create the foundation for sustainable materials management,” says Geyer. “Put simply, you can’t manage what you don’t measure, and so we think policy discussions will be more informed and fact-based now that we have these numbers.” “There are people alive today who remember a world without plastics,” says Jambeck. “But [plastics] have become so ubiquitous that you can’t go anywhere without finding plastic waste in our environment, including our oceans.” —JWN Energy
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• PIPELINE NEWS NORTH
OCTOBER 20, 2017
LAST WORD
Waiting for the LNG Key Word: Consolidation
W
ith the recent cancellation of the Pacific NorthWest LNG and Aurora LNG projects in Prince Rupert, the list of B.C. LNG projects being cancelled or delayed continues to grow ever longer. A look in our rear view mirror had a Liberal government in 2013 projecting three projects by 2020 in conjunction with a series of claims that have not come to fruition. Given the current situation, it leaves many people wondering where LNG export plans in British Columbia are headed. Recent global developments leave me scratching my head wondering how viable any BC LNG project is, given current global market conditions. Woodfibre LNG in Squamish seems to be advancing at such a slow pace it makes one wonder if the approval was nothing but a publicity stunt for a premier on the eve of a party convention last fall. Tilbury LNG, located on the banks of the Fraser River in the Lower Mainland, is so small it’s not even worth mentioning. The current state of the B.C. LNG export industry is like being served a plate of Tic Tacs while having been promised a full course Christmas dinner. A look towards our major competitor, Australia, shows us a project no company would ever want to replicate, and is certainly one that all proponents have factored into their decision making and risk analysis for future developments: Gorgon LNG. Located on the north coast of Australia, Gorgon was completed with final costs around the $54 billion mark, approximately $20 billion over budget. Budget overruns, production delays, cost overruns, labour unrest, and, most recently, renegotiated supply contracts with a major buyer have plagued Chevron’s project. Nobody wants a Gorgon. Nobody wants to take on that kind of risk. Some energy analysts have changed their tune
CHEVRON PHOTO
Gorgon LNG in Australia.
and have predicted a change in global LNG supply and market dynamics, even going as far to say the window for LNG exports from Canada is opening as excess supply is reduced and demand forecast to increase. With buyers wanting to purchase LNG on the spot market instead of oil-indexed contracts, the financial risk for projects is still a very live issue. A solution to address the high-risk game of building LNG projects in British Columbia is spreading risk around by increasing the number of partners on a project and consolidating project components. This is something that should
have happened a long time ago as the number of proposed projects rose to double digits in numbers. Moving forward if you hear news about companies consolidating their interests and working together on a B.C. LNG project, that’s the moment when we all should be paying close attention. Jeff Richert lives in Taylor, B.C., and ran as an independent candidate in Peace River North in the 2017 B.C. election.
CAPP’s plan for Canada to become a global oil & gas supplier of choice Canada can both share its energy prosperity with the world and drive to a lower-carbon economy at home — but only if governments choose to develop the country’s oil and natural gas with competitive policies that attract investment and spur innovation, according to the Canadian Association of Petroleum Producers (CAPP). Global population growth is estimated to grow to 9.2 billion people by 2040, putting energy rates higher than today and increasing demand in all forms by 30 per cent, CAPP said in a statement. Canada has the world’s third largest reserves of crude oil and vast resources of natural gas, but the country continues to be without broad access to the global market for either commodity. Companies are also pulling out on plans to develop said access including Trans Canada’s decision last week to abandon its proposed
$15.7-billion Energy East oil export pipeline, and the cancellation of two major Canadian LNG export projects in the last four months representing combined capital investment of $64 billion. CAPP laid out a six-point action plan to improve market dynamics for Canadian oil and gas. Here it is. 1. A national vision for oil and gas development — CAPP says the federal government must take a leadership role working with governments, industry,communities and citizens to define Canada’s vision in global oil and natural gas markets. 2. A national clean energy task force that includes oil and natural gas — “The federal government needs to work with industry, innovation agencies and provinces to adopt a national clean-energy task force that includes the oil and natural gas sector,” CAPP says. “The approach should include a commitment to research and
development, as well as an attractive fiscal framework to encourage investment for Canadian oil and natural gas innovation.” 3. A competitive, equivalent climate leadership plan — Climate leadership is critical for Canada’s oil and natural gas industry to become a global supplier of choice, CAPP says. “Such policies should be developed with a balanced approach to attract investment, grow jobs and the industry while reducing greenhouse gas emissions. The federal government should work with provinces to establish an equivalency basis including Alberta, British Columbia, Quebec and Ontario, where there is a price on carbon.” 4. A competitive international trade policy — Canada’s oil and natural gas sector is vulnerable to competitiveness challenges from exposure to international trade,” CAPP says. “As such, governments should recognize the sector’s energy-
intensive, trade- exposed nature to prevent carbon leakage and ensure Canadian producers are globally competitive.” 5. An effective and efficient outcomes-based approach to regulations — “Market dynamics and mounting regulatory costs are creating barriers in an increasingly competitive market, reducing investment in Canada’s oil and natural gas sector,” CAPP says. “An efficient and predictable regulatory system and improved access to new customers will encourage investment.” 6. Improved market access to ensure Canadian oil and natural gas production can reach more customers — CAPP recommends that the federal government continue to support proposed projects that enhance market access for Canada’s resources, “in a manner that adds predictability, consistency and efficiency to investment decisions.”