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Enbridge crew members at the Gretna Terminal stand by the final tie-in point of the Line 3 Replacement pipeline in Canada. The Line 3 pipeline replacement is complete and shipped its first oil on Dec. 1. The new pipe meets the old pipe at the international border at Gretna, Manitoba. And the old pipe in the U.S. continues to be in use until it is replaced. Read more about the project on page 4. | Enbridge Photo
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WHAT IS THE FORT ST. JOHN PETROLEUM SOCIETY? The purposes of the society “Fort St John Petroleum Association” is to create a nonprofit fraternal organization for educational benevolent and social purposes.
• To create a medium through which the society members may express themselves in Social activities, Educational pursuits and Athletic endeavours. • To contribute to the community in supporting worthwhile projects as decided upon from time to time by the society. • To provide entertainment that is enjoyable, instructive and beneficial to its members and families. • To encourage a spirit of good fellowship among the society members VISIT http://fsjpetroleumassociation.com FOR MORE DETAILS
DECEMBER 20, 2019
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Why we must get Canadian energy to global markets
C
anada is known around the world as a country of inclusiveness, tolerance and respect for human rights. Our energy industry also holds world class standards – among the best anywhere when it comes to innovation, environmental protection and responsible resource development. According to Statistics Canada, nearly half of all money spent by Canadian businesses on environmental protection was contributed by the oil and natural gas extraction industry. It’s time for Canadian energy to play a vastly more significant role on the world stage. The world’s energy needs are growing significantly. By 2040, the International Energy Agency’s World Energy Outlook 2019 projects global energy demand will have increased by 24 per cent. Even taking into account increased use of renewables, oil and natural gas will make up 53 per cent of the total energy used around the world. More than one billion people don’t have access to electricity. As the globe’s population increases and people strive for a better standard of living, energy demand will increase every year over the next couple of decades. Developing economies are depending on affordable and reliable energy to reduce energy poverty and provide things Canadians take for granted, like clean cooking facilities, lighting, and transportation. Africa, for example, is expected to increase its oil use by a whopping 72 per cent. At December’s COP25 (Conference of the Parties summit)
in Madrid, Spain, nations around the world faced the challenges of balancing economic stability with their greenhouse gas (GHG) reduction commitments – targets set under the Paris Agreement to reduce emissions and manage global warming. Canada is among them, yet our position is unique, in that we can offer a solution to help bring people out of energy poverty, while reducing net global GHGs. We have an opportunity to do just that, and work with China and India, who account for more than 20 per cent of the world’s emissions. So what’s the Canadian energy solution? Getting Canadian LNG (liquefied natural gas) to global markets that need it. The International Energy Agency (IEA) projects by 2040 global demand for natural gas will increase nearly 36 per cent, replacing coal as the world’s second-largest energy source. In the year-over-year period from 2017 to 2018, China’s natural gas consumption increased a staggering 33 per cent. Canada has an abundant natural gas resource that’s estimated to be 1,220 trillion cubic feet; enough to serve current markets for 300 years, and positioning us well to meet emerging demand worldwide. Canadian LNG would create up to 65 per cent fewer greenhouse gases than coal when used in Asia to generate electricity, as Canadian LNG facilities will have lower emissions intensity than LNG produced anywhere else. According to the Institute for Energy Economics and Financial
Analysis, China alone is adding one large new coal-fired power plant to the grid every two weeks. The window for Canada is open right now. Canada’s significant natural gas resources can help meet global demand and reduce global GHG emissions by displacing coal-fired electricity generation in China, India and southeast Asia. With the total net global GHG reduction from each Canadian LNG plant estimated to be about 100 MtCO2e per year, we can achieve the equivalent of removing 22 million cars from the roads. It means Canada can make a much bigger difference outside of our borders in lowering global GHG emissions than we could ever achieve by focusing only on ourselves. In turn, these emissions reductions must be recognized both domestically and internationally and contribute to our commitment under the Paris Agreement. For this to happen, Article 6 of the Paris Agreement must enable countries to share offset credits – called Internationally Transferable Mitigation Outcomes (ITMOs) – from another country. If Canada, as the supplier of this cleaner burning fuel, is able to receive credit for a portion of these carbon offsets, Canada will be better positioned to meet its Paris climate accord targets while allowing additional LNG facility development to take place at home. If Canada can take this opportunity to grow an industry around LNG to meet global demand, it will also create economic and other benefits across Canada. The Canadian oil
and natural gas industry contributes billions to government revenues every year, which supports our social fabric and standard of living by helping to fund schools, nurses, teachers and infrastructure, and making life more affordable for all Canadians. In addition, all Canadians deserve opportunities for prosperity, which the energy industry helps to support across the country. The industry remains positive as we look at the opportunity ahead. For Canada, a strong oil and natural gas industry keeps our communities strong. This includes providing opportunities for Indigenous communities and businesses to play an active role in resource development. For many Indigenous communities, involvement with the energy industry provides a path toward defeating poverty and in turn leads the country further along our road to reconciliation with Indigenous peoples. It’s essential that we build upon our energy industry with innovation and thoughtful foresight so that we can all benefit socially, economically and environmentally, here in Canada and beyond our borders. With market access, and a framework that enables Canadian LNG and oil to get to global markets, Canada can help fill world energy demand, playing a role in bringing populations out of energy poverty and reducing net global greenhouse gas emissions at the same time. Tim McMillan is president and CEO of the Canadian Association of Petroleum Producers.
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• PIPELINE NEWS NORTH DECEMBER 20, 2019
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Stephen Baker with Off The Rock Trucking heads out for a day of hauling, Nov. 27, 2019. | Dillon Giancola Photo
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Enbridge’s Line 3 pipeline replacement is complete and shipped its first oil on Dec. 1. In Canada, that is. The replacement of the pipeline through Minnesota has not been built due to delays. But that doesn’t mean Line 3 is not in operation, nor is the Canadian Line 3 replacement a pipeline to nowhere. The new pipe meets the old pipe at the international border at Gretna, Manitoba. And the old pipe, in the U.S., continues to be in use until it is replaced. As a result, the new pipeline, one of five pipes that makes up Enbridge Mainline system, will soon be in operation. The mainline system runs from Hardisty, Alberta, east-southeast through southern Saskatchewan and Manitoba. It crosses into North Dakota at its very northeast corner before going on through Minnesota to Superior, Wisconsin. From there the mainline system splits, going through Wisconsin and Michigan to Sarnia, Ontario, and south to Chicago, around Lake Michigan, and again to Sarnia. While there are other export pipelines, the Enbridge mainline system is the primary conduit of Canadian oil exports from Canada to the United States. As the old Line 3 in the United States is operating at a reduced capacity, the new line in Canada is, for now, going to run at about half its rated capacity. The Line 3 Replacement will continue to transport light and medium grades
of crude oil as it does today. The new pipeline will run at approximately half of its rated capacity, some 400,000 barrels per day, until such time as the Minnesota portion receives final approval, is constructed and brought onstream. “First and foremost, the Line 3 project was about enhancing the safety and integrity of infrastructure that is critical to the functioning of our society, much like a highway, a bridge, or an airport,” Leo Golden, Vice Presiden Line 3 Project Execution, said. “Today, Line 3 is one of more than 80 oil and gas pipelines and 30 major electric transmission lines that cross the Canada-U.S. border, operating as part of a single, integrated North American energy market. Access to this continental energy market is critical for consumers, industry, and governments.” The new pipeline stretches approximately 1,070 kilometres from Hardisty, Alberta to Gretna, Manitoba. At an estimated cost of $5.3 billion, it represents the largest capital expenditure in its 70-year history in western Canada. “We are truly grateful and humbled by the tremendous support we’ve received across Alberta, Saskatchewan and Manitoba for this project over these past six years,” said Golden. “Without that support and collaborative mindset, we wouldn’t be where we are today.” — Pipeline News
DECEMBER 20, 2019
New geoscience research projects to study induced seismicity in NEBC Geoscience BC will be supporting a series of four new research projects to generate new public science about the relationship between earthquakes and natural gas development. Additional research related to earthquakes caused by natural gas development — induced seismicity —was one of four research focus areas recommended in a March 2019 Scientific Review of Hydraulic Fracturing in British Columbia by the Ministry Of Energy, Mines and Petroleum Resources. “Geoscience BC has been creating new public data and information about the relationship between natural gas well completions and induced seismicity in northeast B.C. since 2012,” Carlos Salas, Geoscience BC executive vice-president and chief scientific officer, said in a statement. “The Scientific Review of Hydraulic Fracturing in British Columbia and a Geoscience BC open request for research proposals process have helped us to prioritize the new research that is needed.” The four new projects are:
McGill University project in B.C.’s Northeast Region. Geoscience BC funding maintains the network, allows additional research and will make data available in real-time, to all researchers.
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• Statistical Assessment of Operational Risks for Induced Seismicity from Hydraulic Fracturing in the Montney, Northeast BC (Enlighten Geoscience) This project aims to determine some of the factors that can influence induced seismicity in the Montney play in the northeast region of B.C. It uses statistical methods to analyze public data from natural gas completion activities with information about the geology to predict earthquakes resulting from natural gas development based on previous events. • Development of an Induced Seismicity Susceptibility Framework and Map for NEBC using an Integrated Machine Learning and Mechanistic Validation Approach (E. Eberhardt, UBC)
• Understanding and Mitigating Induced Seismicity Risk in the The project combines multiple Kiskatinaw Area, B.C. (D. Eaton, datasets in a machine learning University of Calgary) setting, together with laboratory experiments and numerical The project installs and simulations, to model the monitors a closely spaced network relationship between natural gas of seismographs in the Kiskatinaw operations, geology and seismic area of B.C.’s northeast region activity in the Montney play in to provide higher quality data B.C.’s northeast region. about the location of induced seismic events, to better detect The four new projects are the smaller events and to improve result of an open request for understanding of how faults proposals issued by Geoscience BC respond to hydraulic fracturing. in June 2019. Each of the projects was reviewed by a committee • Comprehensive Investigation of independent subject matter of Injection-Induced Earthquakes experts and recommended by in Northeastern British Columbia Geoscience BC’s volunteer oil and (H. Kao, University of Victoria) gas technical advisory committee before being approved by the The project manages a network Geoscience BC board of directors. of nine seismographs that monitor ground motion which was previously installed for a — Daily Oil Bulletin
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• PIPELINE NEWS NORTH DECEMBER 20, 2019
FortisBC’s Tilbury LNG facility.
Enbridge updates on regional projects in Northeast B.C. matt preprost Enbridge officials were in Fort St. John and Taylor last month to give councillors an update on the company’s regional projects. Enbridge sold its Alberta and B.C. gathering and processing assets to Brookfield Infrastructure in a $4.3-billion deal announced in 2018. The second phase of the deal, which includes the McMahon gas plant in Taylor, is expected to close by the end of 2020. “Even though there’s been lots of changes… I’m here to say we’re still committed to the communities,” Michaela Bjorseth, engagement manager for Enbridge, said. Here’s an overview of Enbridge projects in the queue and what the company is looking to do about caribou: Spruce Ridge This project involves two loop segments to build capacity in the system. Construction includes 25 kilometres of 36-inch pipeline near Chetwynd, and 13 kilometres of 24inch pipeline near Aitken Creek. The project also includes the installation of two additional compressor units. The project has received approval from the National Energy Board,
now called the Canada Energy Regulator, as well as permitting approvals from the BC Oil and Gas Commission. Construction is planned to start in 2020. The project is planned to be in service in 2021. The project is estimated at $565 million. Compressor Station 1 Segregation This project includes upgrades to Compressor Station 1 to be able to operate independently from the McMahon plant, now operated by NorthRiver Midstream. Work includes would involve replacing the existing 2,000-horsepower compressor with an 1,850-horsepower compressor, along with installation of a new meter skid, and other associated equipment. Enbridge plans to submit a project application to the Canada Energy Regulator in December. Pending approval, construction could begin in the winter or spring of 2020, with an in-service date targeted for 2021. T-South Reliability and Expansion This project will add capacity on the T-South system, which runs from south of Taylor to the U.S. border, Bjorseth said.
Work includes installation of new compressor units and gas coolers at five existing compressor stations, and upgrades to compressors at two other stations and one meter station. The most northern work will take place near Azouzetta Lake. Frontier Project This project is still at a high level, Bjorseth said, and the company is exploring opportunities to separate natural gas liquids from its transmission gas. A straddle plant is being considered west of Chetwynd that would extract the liquids and ship them via a new pipeline to a fractionator and rail facility. Enbridge is still refining the scope of the project with its customers, Bjorseth said. A project description has been submitted to environmental assessors. Pending the regulatory process and approvals, construction could begin as soon as 2022, with an in-service date in 2024. The project is estimated at $2.5 billion. Caribou Habitat Enbridge must offset caribou habitat losses as part of approval conditions for four recent projects,
and is currently looking at locations to carry out that work, Bjorseth said. “We are going to be offsetting up to potentially 400 to 600 hectares of caribou habitat, so it’s quite a large footprint,” Bjorseth told Fort St. John council on Nov. 25. “We’re really interested in working with local governments, local communities, indigenous communities, on where those should be. This could be replanting, it could be access controls.” October 2018 pipeline explosion Enbridge has inspected its entire transmission system with the latest state-of-the-art tools after an explosion north of Prince George in October 2018. The tool has double the number of sensors and is “more accurate at assessing a potential problem such as stress corrosion cracking,” Bjorseth said. Enbridge will be increasing the frequency of inspections with the tool, and has also nearly doubled the amount of integrity digs across its system, Bjorseth said. “This is where we go in, excavate around the pipeline and physically inspect it, and take any ne cessary repairs,” Bjorseth said. —Pipeline News North
DECEMBER 20, 2019
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B.C. carbon tax fueling new clean industry fund
Harmac Pacific in Nanaimo plans to invest $1.7 million in dewatering technology to turn sludge into fuel.
Harmac Pacific in Nanaimo will receive more than $800,000 in provincial funding for a new sludge treatment system that the company says will reduce greenhouse gas emissions by reducing the amount of natural gas it needs to burn for its boilers. Harmac is the first company to be approved for grants under the new CleanBC Industry Fund, which is being funding through carbon tax revenue. The B.C. government expects to approve $12.5 million under the new fund for 16 projects proposed by various industries to help them adopt technology that reduces their carbon emissions. The government expects the funding to help leverage more than $30 million in private sector investments in things like energy efficiency. Harmac plans to invest $1.7 million in a new ionization treatment process to dewater sludge, which can then be burned in its boilers, reducing the amount of natural gas it has to burn. The CleanBC industry fund will cover about half that of the cost – $862,500. After wood waste is turned into pulp, the sludge that is left over is
currently filtered through a screw press to wring out the moisture. It is then incinerated in Harmac’s boilers, which produce steam, both for the pulp mill’s processing and to drive turbines to generate electricity. But the filtering process doesn’t get all of the moisture out of the sludge. The ionization technology Harmac plans to install helps reduce the moisture content of the sludge to the point where it will burn, which is expected to reduce the amount of natural gas that the company uses to fire its boilers. “We can only get to about 25% solids content right now, so we’re more incinerating it than burning it,” said Ryan Prontack, Harmac’s engineering superintendent. “So what we’re trying to get to, with this project, is to the point where we can get it dry enough that it does burn on its own. By using the drier sludge as a fuel, the company will use less natural gas. Harmac calculates that will reduce CO2 emissions by about 4,800 tonnes per year. In total, the government hopes that the 16 projects it plans to fund with the CleanBC industry fund will reduce GHGs by 2.5 million tonnes by 2030.
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• PIPELINE NEWS NORTH DECEMBER 20, 2019
Artist’s rendering Chevron-Woodside Kitimat LNG | FLUOR Photo
If Chevron sells stake in Kitimat LNG, it wouldn’t be the first time it changed hands nelson bennett Chevron Corp. is taking a US$10 billion to US$11 billion write-down and considering selling some of its assets, including its 50% stake in the Kitimat LNG project. The company has revised its revenue projections in the light of an oil and gas glut in the U.S. and depressed natural gas prices and is tightening its belt. The company attributes about half of the tax impairment to its Appalachia shale assets. The company says it is considering selling some of its shale assets in the U.S. and its 50% share in Kitimat LNG, which just recently received a new 40year LNG export licence from the Canada Energy Regulator. “As a result of Chevron’s disciplined approach to capital allocation and a downward revision in its longer-term commodity
price outlook, the company will reduce funding to various gasrelated opportunities including Appalachia shale, Kitimat LNG and other international projects,” the company said in a press release December 10. “Chevron is evaluating its strategic alternatives for these assets, including divestment.” The other partner in the Kitimat LNG project is Australia’s Woodside Energy. The Kitimat LNG project was the first major LNG project to be proposed in B.C. and has changed hands before. Originally proposed as an import terminal, the project was sold by LNG pioneer Alfred Sorensen to Apache Corp. and EOG Resources. Later, Encana Corp. bought a 30% share. None of those companies still own stakes in the project. Apache sold its stake to Woodside Resources, and Chevron later bought out Encana and EOG.
In a recent analysis for the Oxford Institute of energy Studies, Peter Findlay of Criterium Group in Calgary predicted that Western Canada “is likely to offer one of the lowest-priced sources of global gas for decades to come,” but said Canada has fumbled the ball, allowing the U.S. to beat Canada in the race towards becoming a major LNG exporter. He notes superior natural gas assets in the Western Canadian Sedimentary Basin compared with the U.S., but says an “incoherent and ineffectual approach to regulating it” is largely to blame for Canada losing ground to the U.S. “I think it’s important to note that ownership changes are not unusual in projects like this – large capital energy projects,” said Bryan Cox, CEO of the BC LNG Alliance. “I think what’s really important to note is that Chevron very clearly stated in its remarks that they view
this project as globally competitive. Chevron and Woodside recently sought an amendment to its environmental certificate to allow a change in both scale and design. The proponents want to increase production and use all electric drive, which would dramatically shrink its the project’s carbon emissions intensity. “It’s a very attractive project,” Cox said. “And we’re confident, as an industry, that, should they divest, the next owner can move this over to a final investment decision.” In his analysis, Findlay said a final investment decision on Kitimat LNG is not expected until around 2022 or 2023, with completion and commissioning timed for 2029. — Business in Vancouver
DECEMBER 20, 2019
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Inter Pipeline to spend $935M on new Alberta petrochem plant Deborah Jaremko Nearly 80% of Inter Pipeline’s planned 2020 capital program will be directed toward construction of the Heartland Petrochemical Complex, the company said on Thursday. The facility, under construction near Fort Saskatchewan, will be Canada’s first integrated propane dehydrogenation (PDH) and polypropylene (PP) plant, converting Alberta propane into pellets for plastic products. It carries a $3.5-billion capital cost, of which Inter Pipeline has spent approximately $1.9 billion, as of the end of September 2019. In 2020 the company said it will invest approximately $935 million is expected to be invested in the project, with a focus on advancing mechanical construction of the PP plant and completing the final stages of construction of the PDH facility. Construction began in early 2018 and is scheduled for completion in late 2021. Inter Pipeline announced $1.195 billion in capital spending for next year, which includes $80 million for sustaining capital, $45 million in its conventional oil pipelines business (primarily for the expansion of its Central Alberta pipeline system), $30 million for oilsands transportation (focused on improving operating efficiencies), $40 million on European bulk liquids storage (if the sales process underway is unsuccessful), and $20 million for corporate activities.
Inter Pipeline CEO Christian Bayle speaks at the Heartland Petrochemical Complex construction site in September 2019. | JOEY PODLUBNY Photo
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Enbridge Westcoast expansions expected to continue elsie ross Enbridge Inc. has more than doubled its investment in Westcoast’s T-North and T-South over the last several years and expects expansions to continue for years to come, a senior company official said Tuesday. “Our T-North and T-South pipelines are playing a really significant role already by providing upstream transportation for LNG Canada and Woodfibre Squamish,” Bill Yardley, executive vice-president and president of natural gas and midstream, told the company’s investor day. “A world class gas supply and proximity to Asia makes Western Canada ideal for LNG export projects.”
Enbridge recently received Canada Energy Regulator approval for the $1 billion T-South reliability and expansion project. The project is expected to come into service in 2021, about the same time as its $500 million Spruce Ridge project in T-North which provides needed access for Montney producers trying to reach export markets, said Yardley. “This is a great investment on T-South to serve both growing demand of domestic needs in Vancouver and the Pacific Northwest but also an LNG export market, all under a cost-ofservice framework,” he said. Another area of focus is the Westcoast Gas Transmission Connector pipeline which has been on the books for some time, analysts heard. “It’s got a nicely-developed route to
Prince Rupert, it’s scalable and cost-effective,” he said. “Any of the next phase LNG projects that have Prince Rupert in their sights are talking to us with regard to the West Coast Connector.” Enbridge also is exploring the development of natural gas liquids infrastructure in Canada so that its customers can fully monetize the liquids that currently are entrained in the gas stream and don’t have an outlet, said Yardley. It has filed a project description with the B.C. Environmental Assessment Office for Project Frontier which would involve building an NGL extraction facility, a pipeline and associated facilities in northeastern British Columbia, possibly as early as 2024. — Daily Oil Bulletin
New gas-fired power plant proposed near Grande Prairie Deborah Jaremko The regulatory process is underway for a proposed new natural gas-fired electrical generating station in northwest Alberta. The Canadian Impact Assessment Agency is accepting public comment on the Prairie Lights Power Project, a 360-megawatt facility that would be located about 35 kilometres south of Grande Prairie. The project would also include 6-inch, 2,200-metre natural gas pipeline to connect the plant to the Nova Gas Transmission system,
as well as a single double circuit 144 kV, 24-kilometre transmission line to connect to the existing Big Mountain 845S substation. The capital cost of thed project has not been disclosed, but the Prairie Lights Power says that the construction phase will generate $400 million in value-added for the local economy, and support 300 jobs. Operating activities would generate $30 million in value added annually, supporting 75 jobs annually in addition to provincial and municipal government revenues, the company said.
Between 2018-2019, approximately $1.5 million was spent on project design, it said. The project “will generate electricity from natural gas to provide a reliable source of electricity to help meet the growing demand of electricity in Alberta, and support the transition from coal power plants, which are nearing retirement in Alberta,” Prairie Lights said. The company envisions site access and construction mobilization in May 2020, followed by operations in October 2022. — JWN Energy
DECEMBER 20, 2019
recision says automated drilling P systems operating commercially One of North America’s biggest drilling companies reported it has “achieved commercial acceptance” of its suite of automation systems. Technologies deployed across Precision Drilling’s Super Triple rig fleet in various basins in the U.S. and Canada are currently contracted at commercial rates, earning expected returns and achieving over 90% utilization, the company said in a statement. Precision has also packaged its automated drilling technologies under a new brand called “AlphaAutomation,” which it said includes 32 systems that provide enhanced drilling efficiency, wellcost savings and consistency gains. The company said it intends to
continue deployment across its Super Triple fleet, including 24 additional systems over the next 12 months. “Achieving this milestone is a result of three years of field-hardening the software, extensively training our crews and closely collaborating with our customers in order to overcome field acceptance hurdles and fully demonstrate the value our technology delivers,” said CEO Kevin Neveu. “We have drilled over 1,000 wells with AlphaAutomation and have successfully deployed this highly scalable technology throughout North America.” — JWN Energy
Cando begins construction on new rail car storage Cando Rail Services says it has started construction on a new terminal in Sturgeon County that will use a loop-track system to enable staging and storage of up to 1,900 rail cars. In a statement, the company noted the proximity of the Cando Sturgeon Terminal to the $4.5-billion petrochemical plant under construction by Canada Kuwait Petrochemical Corporation, and to Pembina Pipeline’s Redwater Fractionator, which will supply propane to the new facility. The Cando terminal will be unit-train capable and serviced by the CN mainline. In a statement Wednesday, CEO Brian Cornick called the decision to proceed “a defining moment” for the company. In a project description filed with federal environmental assessors in February 2019, Cando said that the petrochemical industry located in Sturgeon County and adjacent Strathcona County largely uses rail - predominantly tank and hopper
cars – to transport products to customers. “Tank cars are privately owned and require rail facilities to keep cars when they are not actively in use at either a production facility or a user’s facility,” the company said. “The project will facilitate the storage and grouping of rail cars from various industries to consolidate rail staging operations in one area; thereby, removing the need for each individual industry to provide its own staging facility.” Sturgeon County Mayor Alanna Hnatiw said that “access to costadvantaged feedstock, worldclass transportation and logistics infrastructure and readily available labour are allowing the Heartland to capitalize on the current petrochemical investment cycle.” Early works and site mobilization have begun with completion expected in 2020, Cando said. A capital cost estimate has not been released. — JWN Energy
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• PIPELINE NEWS NORTH DECEMBER 20, 2019
Rendering of the proposed Goldboro LNG project. | PIERIDAE ENERGY
Western Canadian gas, European demand key for LNG projects in eastern Canada Jim Bentein Liquefied natural gas projects planned for eastern Canada represent a significant opportunity for Alberta’s gas producers to reach tidewater and access markets in western Europe. Three key LNG projects located in Eastern Canada — Pieridae Energy Ltd.’s Goldboro project in Nova Scotia; LNG Limited’s Bear Head project, also in Nova Scotia; along with GNL Quebec’s Énergie Saguenay project — all plan to access gas from Western Canada. That’s good news for struggling producers in Alberta and British Columbia, as increased demand for gas from Western Canada would lead to improved pricing. In addition, these projects — especially the two in N.S. — are about half the shipping distance to major European markets compared to U.S. Gulf ports, a major advantage for the Canadian proposals. Several steps taken by Pieridae
Pieridae has taken several recent steps to move its Goldboro LNG project forward. In late June it announced it would spend C$190 million to buy Shell Canada Energy’s midstream and upstream assets in the southern Alberta Foothills, which recently closed. That followed the announcement in August 2018 that it would acquire Ikkuma Resources Corp. in an allstock deal (no dollar amount was revealed). That Alberta Foothillsfocused junior produced about 101 mmcf/d. “Closing the Shell asset acquisition means we have secured the majority of the gas needed to supply the first train at our Goldboro LNG facility for at least 20 years,” said Alfred Sorensen, Pieridae’s chief executive officer. “Now, we can focus on completing negotiations with Kellogg Brown & Root Limited for a fixed price contract to build the Goldboro LNG facility in order to complete the project financing and make the final investment decision
in 2020.” Sorensen doesn’t see the access to western Canadian gas as a huge barrier to the development of his Goldboro LNG project, which would have a capacity of 10 million tonnes per annum (mtpa) and cost up to US$10 billion to develop. “We have spoken to TC [Energy Corporation] and Enbridge [Inc.] and we think, given the volumes we would need, it’s possible with the existing infrastructure,” he said. It would involve “some looping,” but the gas could move from the TC Mainline to the Maritimes & Northeast Pipeline, with it traveling to Nova Scotia. M&NP was originally built to transport gas from developments offshore N.S. to markets in Atlantic Canada and the Northeast U.S. Goldboro LNG is located adjacent to the Maritimes & Northeast Pipeline, and is why the site was chosen, said Sorensen. Diversifying supply for Europe
In July 2019, Pieridae negotiated extensions of the key deadlines under its 20-year agreement with Germany’s largest utility Uniper. These included expected commercial deliveries of gas to Uniper to start between Nov. 30, 2024, and May 31, 2025, and the extension to Sept. 30, 2020, of the deadline to make a positive financial investment decision for moving ahead with the Goldboro LNG project. The 20-year agreement with Uniper is for all of Train 1 at Goldboro or five mtpa. Uniper is the largest distributor of natural gas in Germany, and one of the largest distributors of natural gas in all of Europe. At the Canadian LNG Conference held in London, U.K., at the end of November, Sorensen said: “Uniper, for us, ended up being a one-stop shop. Not only can we sell gas to the Germans … they [also] deliver into the United Kingdom, into Spain, into Italy, and in the summer we could even sell into Brazil.”
DECEMBER 20, 2019
The deal with a German utility unfolded “because they don’t want to be reliant on Russian gas,” Sorensen said. And shipping time from Nova Scotia to Germany and other parts of Europe is six days, far less than the 10 or more days from the U.S. Gulf Coast, a competitive advantage for projects on Canada’s East Coast. “Our entire project is about geopolitical issues,” Sorensen said at the London event. “It’s about diversifying western European gas away from Russia. And it’s why the German government is as supportive as they are.” (The German government has confirmed support of the project, declaring it eligible in principle for up to US$4.5 billion in loan guarantees, including US$1.5 billion for upstream development.) European demand Demand for natural gas and LNG will increase in Europe as France, Italy, Spain, the Netherlands and — most likely — Germany phase out coal, as Germany moves away from nuclear energy, and as the Netherlands gradually phases out of production from its oil and gas fields, according to the former executive director of the International Energy Agency. “All this will increase the need for gas imports in Europe, and I highly expect Europe’s import needs will increase by 50 bcm in the next five years,” Marie van der Hoeven said at a recent PETRONAS Speaker Series event. “While Russian gas might satisfy quite a lot of these additional import needs, there are limiting factors.” For example, noted van der Hoeven, pipeline transportation bottlenecks to western Europe from Russia persist. There is also much political resistance in Europe to importing Russian gas, she said. These two issues coalesce with concerns regarding the Russianled Nord Stream 2 and TurkStream pipeline projects. “The pipelines are almost
operational despite strong opposition by the European commission and some eastern European countries,” she said, adding these pipelines enable Russia to minimize use of Ukraine’s transit complex — the object of “very difficult negotiations” between the EU, Russia and Ukraine as current contracts expire. “And so, given the political reluctance to significantly increase gas imports [from Russia], LNG will need to fill the European supplydemand gap. At the same time, European consumers will have to compete with Asian buyers who’ve traditionally been more ready to pay premium prices.” Bear Head project Another N.S. project — the Bear Head LNG export plant at Point Tupper — also touts its closeness to the European market, being about half the distance to Europe compared to U.S. export facilities in the Gulf of Mexico. In addition, the site is closer than its North American competitors, including those in B.C., to other major LNG markets including burgeoning natural gas markets in India and Argentina. Bear Head initially was designed around accessing gas from offshore N.S., but that source no longer exists. It then looked at accessing U.S. gas and had approvals in place to import it, but the current Trump administration wants U.S. gas to be exported from U.S. LNG export plants. Originally designed as an LNG import facility by then-owner Anadarko Petroleum Corporation, the 200-acre-plus site had roads and other infrastructure already in place when Australian-based LNG Limited (LNGL) bought it in 2014 for US$11 million. Anadarko had spent US$100 million on the site. LNGL has added about 100 acres of land to the site since then. The company is also proposing to build its Magnolia export project in Louisiana, for about US$4.62 billion, with Bear Head costing
about the same, said John Baguley, chief operating officer of LNGL. The Bear Head LNG export terminal also plans to use gas from Western Canada. The project, which would ultimately export about eight mtpa, would need to access 1.75 bcf/d from TC Energy’s Mainline, which moves gas from Western Canada to North Bay, Ont. That would require the development of a 1,600-1,700-kilometre pipeline from North Bay to Nova Scotia, which Baguley said would cost “billions” of dollars. “We’re too small to do it,” he said. Baguely suggested it might be a good idea to partner with competitor Pieridae on a pipeline to move gas to N.S., noting there are potential synergies between the two projects, but he “has never really talked to Pieridae about that.” Meanwhile, Sorensen said a new pipeline would likely be needed from North Bay to access enough gas for both Bear Head and Goldboro. And he agrees that “between the two of us [LNGL and Pieridae] we could likely finance a [new] pipeline.” Sorenson estimates it would cost LNGL about $100 million to build the 60 kilometres of pipeline from Goldboro to Bear Head. Recently, TC Energy’s newly appointed executive vice-president and president of Canadian Natural Gas Pipelines, Tracy Robinson, said she sees growing interest among its customers in the prospect of access to global LNG markets off the East Coast. There’s “lots of interest” among producers of piecing together transportation to reach any number of markets — Eastern Canada, northeast United States and across TransCanada’s U.S. system, she said. Robinson said eastern LNG projects continue to make progress and that TransCanada is in discussions with all of them. “They are all, I would say, at various stages of development, supply, getting pipe capacity,
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positioning an LNG facility and finding markets,” she said. “We are watching that carefully. We have not yet signed any agreements with any of them but we are in dialogue with all of them.” Energie Saguenay GNL Quebec’s Énergie Saguenay project, which involves the construction of a natural gas liquefaction complex at Port Saguenay, Que., plans to export 11 million tonnes of LNG per year, with gas sourced from Western Canada. The project includes liquefaction equipment, storage facilities, and marine shipping infrastructure. The project is worth an estimated US$7.2 billion and is slated to start operations in 2025. Gazoduq Inc. is proposing the construction and operation of a natural gas pipeline approximately 780 kilometres long between northeastern Ontario and Saguenay. This proposed project would connect TC Energy’s existing main natural gas transmission system in northeastern Ontario to the Énergie Saguenay project. In a pre-application project description filed earlier this year with the Canada Energy Regulator, Gazoduq said the 1.8 bcf/d pipeline will provide the necessary link between surplus natural gas supplies in Western Canada and the LNG facility’s international markets such as Asia and Europe, as well as potentially providing transportation services to local distribution companies in northern Ontario and Quebec. The 42-inch pipeline is scheduled to be in service by the fourth quarter of 2024 with the LNG facility expected to launch operations in 2025. “Project success rests on the natural gas transmission line being in-service by the fourth quarter of 2024,” said Gazoduq. “This will require tightly controlled, but achievable project execution and approval timing.” — JWN Energy
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Christmas in The Patch W
hile oil and gas had been discovered in the Peace area in the 1940s, it was not until the early 1950s that exploration and production was feasible. Up until this time farming, trapping and logging were the main industries. With the coming of oil and gas also came the people, literally from all over Western Canada. The majority of these people had worked in the oil business and followed their drilling rigs wherever there was work. While some had families and brought them with them, some were single. They were far from home and in those days you couldn’t just hop a plane or even drive home as the distance was often far too great to get home and back to the Peace country to work in a reasonable amount of time. When my father’s rig came here in the early ‘50s, most of his hands had been with the same rig for years. My family was lucky as we always were together at Christmas time. For the guys on the rigs without families or with families far away, Christmas was sometimes very hard as they had no place to celebrate Christmas other than the camp at the rig. If they worked on Christmas Day the camp cooks always made sure that a full Christmas dinner was served. Those that didn’t work over Christmas were left to find their own forms of celebration. This is when the people who had homes and families nearby began to invite these people for Christmas Eve and Christmas Day celebrations. I can remember, as a child my family, Mom mostly, would be sure to have enough food and drink on hand for anyone who was alone and wanted to join us. These people were usually rig hands and I can remember as many as 30 people at our house for Christmas Eve and again for Christmas Day. Depending on how well things were going in the patch dictated what meals were served. My dad was a “Tool Push” in those days and about two weeks before Christmas the presents from various service companies would start to show up at our house. Sometimes the people from the companies would bring them and of course would be invited in for some Christmas cheer. The presents were usually either turkeys or hams but I remember one
A group of men unloading Christmas trees from the back of a truck. | FORT ST. JOHN NORTH PEACE MUSEUM / I984.49.81
larry evans Christmas, when I was young, a box of yellow apples were delivered to our house in a taxi. My sisters and I enjoyed those apples very much as we had never seen this kind of apple before and that alone made it a very memorable Christmas. Another gift I will always remember was a Tom-Tom or native drum that was brought to our house by a First Nations person who worked on the rigs. This was my first encounter with First
Nations people and they seemed no different than anybody else. The people I met were usually quiet and a bit shy. Over the years I came to know many of them as more began to work in The Patch. My father treated everyone equally as long as they pulled their load, so I know that the First Nations people I met were hard workers. When they came to the house they always brought a gift but I remember the Tom-Tom as one of the best ever. My friends were beside themselves with envy and I would let them play with it for a while but always made sure it came home with me. It eventually wore out and went the way of most things but every Christmas it comes to mind. As time went on our close family friends came to include such interesting people as Marie Jobin, Alice Hanke and Darlene Shular, making the First Nations culture more familiar to our family. These people were often part of our family and
joined in the Christmas celebrations at our house. My mother would gather the gifts of food and plan her menu for Christmas Eve. Everyone who was not working over Christmas would be invited to out house Christmas Eve. In the good times the men would include sliced turkey, ham, oyster stew, clam chowder, fresh buns, baking and all the fixings...the table would be full! This would be repeated Christmas Day for anyone who showed up. Needless to say there were always repeats from the night before. It was always an exciting time for me but it wasn’t until I was older that I began to appreciate what it had meant to the people who came to our house for Christmas. Even today, I sometimes run across someone who had celebrated Christmas at my parents home many years ago and they always express their appreciation for a Christmas remembered.
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