A pipe yard servicing government-owned oil pipeline operator Trans Mountain is seen in Kamloops, British Columbia, Canada June 7, 2021. REUTERS/Jennifer Gauthier CALGARY, Alberta (Reuters) – Canadian regulators on Monday kicked off a two-day hearing to weigh up a controversial route change request from the Trans Mountain expansion (TMX) project that…
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CALGARY, Alberta (Reuters) – Canadian regulators on Monday kicked off a two-day hearing to weigh up a controversial route change request from the Trans Mountain expansion (TMX) project that has sparked Indigenous opposition and may lead to further delays for the key oil pipeline.
After years of environmental opposition, regulatory hold-ups and ballooning costs, Canadian government-owned TMX is nearing completion and due to start shipping an extra 590,000 barrels per day of crude from Alberta to Canada’s Pacific coast in the first quarter of 2024.
Canadian producers are eagerly awaiting the increased export capacity that will open up access to markets in Asia and the U.S. West Coast and help support heavy oil prices.
But last month Tran Mountain Corp (TMC), the crown corporation building the expansion, asked the Canada Energy Regulator (CER) to change the approved route on a 1.3-kilometre (0.8 mile) section of pipeline near Kamloops, British Columbia, to avoid planned micro-tunneling construction that it now says is unfeasible.
TMC’s proposal to instead lay the pipeline through a different area nearby, using horizontal directional drilling and a conventional open trench, is being opposed by the Stk’emlupsemc te Secwepemc Nation (SSN) First Nation, whose territory the pipeline crosses.
Last week, TMC said being forced to continue with the micro-tunneling option could mean that segment of the pipeline is not completed until December 2024, versus a January completion date if the route adjustment is granted. Building the micro-tunnel could cost as much C$86 million ($63.64 million), the corporation added.
Earlier this year, TMC estimated the entire expansion project would cost C$30.9 billion, more than four times its original budget, and warned the price tag could rise further.
Concerns about TMX being delayed have already started weighing on Canadian crude prices, as traders worry rising oil sands production could get bottlenecked in Canada.
The dispute will also likely complicate the Canadian government’s plan to sell the pipeline once construction is finished. Trans Mountain was bought by Prime Minister Justin Trudeau’s Liberal government from Kinder Morgan Inc in 2018 to ensure it got built.
“It truly is a nightmare come true for the Canadian government,” said Morningstar analyst Stephen Ellis. “The response of the SSN First Nation seems quite compelling and detailed, and lays out Trans Mountain’s shortfalls in a very clear fashion.”
In letters already filed with regulators, the Indigenous group says altering the route would disturb lands that hold “profound spiritual and cultural significance”, and it only agreed to allow TMX to cross its territory in the first place because of assurances the micro-tunneling would work.
“Any support or consent that SSN has provided for the Project has been based on conditions that explicitly protect the Pípsell (Jacko Lake) Corridor from disturbance or harm,” the SSN said in an August filing.
Ellis said it seemed likely the expansion project would be delayed even if regulators grant TMC’s request, echoing a letter filed last week by Canadian Natural Resources Ltd, a major shipper on the pipeline.
The CER will hear arguments and cross-examinations from both the SSN First Nation and TMC over two days in Calgary, and extend the hearing to a third day if required.
A CER spokeswoman said regulators will issue a decision as soon as possible after considering all the evidence, and recognized the time sensitivities associated with hearing.
($1 = 1.3548 Canadian dollars)
(Reporting by Nia Williams; Editing by Aurora Ellis)
FILE PHOTO: A TORC Oil & Gas pump jack is seen near Granum, Alberta, Canada May 6, 2020. Picture taken May 6, 2020. REUTERS/Todd Korol/File Photo (Reuters) – Alberta, Canada’s largest oil-producing province, will finalize an investment incentive program for emissions-cutting technologies like carbon capture and storage in “coming months,” the…
(Reuters) – Alberta, Canada’s largest oil-producing province, will finalize an investment incentive program for emissions-cutting technologies like carbon capture and storage in “coming months,” the province’s energy minister, Brian Jean, said on Tuesday.
Carbon capture and storage (CCS) is seen as a key tool in helping Canada’s high-polluting oil and gas industry slash emissions without cutting back on production, but companies are holding back on final investment decisions because of the high costs involved and have been lobbying for more government support.
An Alberta incentive program, which would work alongside a federal government investment tax credit first announced last year, would be a key step forward for Canada’s nascent CCS industry and could spur projects forward.
Jean said the incentives, which will be similar to the existing Alberta Petrochemical Incentives Program, should be designed properly, and he is having conversations with stakeholders.
“We’re going to make sure we do a robust consultation to get it right,” Jean told Reuters in an interview. “If we get it right, that means that we’re going see another economic boom here in Alberta.”
Liberal Prime Minister Justin Trudeau’s federal government is aiming for net-zero emissions by 2050. But oil producers in Canada, the world’s fourth largest producer, are also the country’s biggest polluters.
A number of companies including Enbridge Inc, TC Energy and a group known as the Pathways Alliance, consisting of Canada’s six largest oil sands producers, are proposing to build major CCS storage hubs.
Alberta Premier Danielle Smith instructed Jean in a mandate letter in July to develop an incentive program for technologies including CCS, lithium for batteries and geothermal development.
However Alberta, which also has a net-zero 2050 target, has repeatedly clashed with Ottawa over interim targets and a promised cap on oil and gas emissions that is supposed to be announced later this year.
Since last year, Ottawa and the Alberta government have been urging each other to contribute more public funding to support CCS technology.
(Reporting by Nia Williams, editing by Timothy Gardner)
FILE PHOTO: Crude oil storage tanks are seen at the Kinder Morgan terminal in Sherwood Park, near Edmonton, Alberta, Canada November 14, 2016. Picture taken November 14, 2016. REUTERS/Chris Helgren/File Photo (Reuters) – A busy oil sands maintenance season and early summer wildfires put a dent in Canadian crude production in…
(Reuters) – A busy oil sands maintenance season and early summer wildfires put a dent in Canadian crude production in the second quarter, but oil companies are ramping up growth over the next two years and will add nearly 8% to Canada’s total output, analysts estimate.
The roughly 375,000 barrel per day (bpd) increase in two years would be more than Canada, the world’s fourth-largest oil producer, has managed to add over the last five years combined, even after promising European allies it would boost crude output in the wake of Russia’s invasion of Ukraine in early 2022.
According to Canada Energy Regulator data, Canadian oil production averaged 4.86 million bpd in 2022, up from 4.61 million bpd in 2018.
Much of the growth will come from oil sands producers like Cenovus Energy and Canadian Natural Resources Ltd (CNRL) tweaking operations to boost efficiency.
Companies are also moving forward on so-called “step-out” or “tie-back” oil sands thermal projects, where instead of building an entirely new facility to steam bitumen deposits, they are linking new areas with existing plants to speed up development and lower costs.
The move to boost output – while continuing to funnel free cash to shareholders – shows producers are confident prices will stay firm, analysts said.
“Companies can finally say things have recovered enough in the industry that we can maintain returns to shareholders and put some money into production growth,” said RBN Energy analyst Martin King.
Benchmark North American crude has averaged $75.64 a barrel year-to-date, declining from 2022 highs, but above the five-year average of $65.89 a barrel.
Increasing production would be at odds with the Canadian government’s effort to meet its goal of cutting carbon emissions by 40-45% by 2030, given oil and gas is the country’s highest-emitting sector.
RBN expects total Canadian crude output to increase 175,000 bpd this year and another 200,000 bpd in 2024, while S&P Global Commodity Insights analyst Kevin Birn said annual oil sands production alone will rise around 350,000 bpd by 2025.
Two-thirds of Canada’s crude comes from northern Alberta’s oil sands.
STEP-OUTS AND TIE-BACKS
Following a lacklustre second quarter, Cenovus downgraded its full-year production forecast due to wildfires, while Suncor Energy, CNRL and MEG Energy warned that output would come in at the lower end of their 2022 guidance after big maintenance turnarounds.
Output is expected to pick up in the second half of the year, and companies are making progress on tie-in projects.
Cenovus is building a 17-km (11-mile) pipeline connecting its Narrows Lake site to its Christina Lake processing facility that will add up to 30,000 bpd in 2025 , while CNRL is planning to develop the Pike project, purchased from BP in 2022, by stepping out from its Jackfish and Kirby facilities.
“It’s a great opportunity and quite innovative. Rather than building a central processing facility all way up at the site, we’ve been able to tie it back to our existing plant,” Norrie Ramsay, Cenovus’s executive vice-president upstream, told an earnings call this month.
The new volumes will coincide with the planned start-up of the 600,000 bpd Trans Mountain expansion (TMX) pipeline project in the first quarter of 2024. However, delays to TMX could result in pipeline congestion and force producers to ship crude by rail, adding costs.
“It’ll have to be done by the middle of next year or we’ll have to have more rail,” said Eight Capital analyst Phil Skolnick.
(Reporting by Nia Williams; Editing by Denny Thomas and Sephen Coates)
FILE PHOTO: A wind farm generates electricity near bales of hay in the foothills of the Rocky Mountains near the town of Pincher Creek, Alberta September 27, 2010. REUTERS/Todd Korol/File Photo WINNIPEG, Manitoba (Reuters) – Alberta’s seven-month pause on approving new renewable power projects in the Canadian province has caused four…
WINNIPEG, Manitoba (Reuters) – Alberta’s seven-month pause on approving new renewable power projects in the Canadian province has caused four major international companies at various development stages to stop work on their plans, an industry official said.
Alberta’s surprise move this month has also prompted some domestic companies to consider whether to refocus investment on other provinces and the U.S.
Wind and solar energy producers have criticized Premier Danielle Smith for creating business uncertainty and jeopardizing billions in potential investments.
Alberta, the country’s main oil and gas producing province, paused approvals on Aug. 3 of new renewable electricity generation projects over one megawatt until Feb. 29, chilling investment in the fast-growing industry. The pause is necessary to address concerns about renewables’ reliability and land use, said a spokesperson for Alberta’s utilities minister.
The move has increased tensions between Smith and Prime Minister Justin Trudeau’s Liberal government, which is drafting regulations to force provinces to eliminate greenhouse gas emissions from their grids on a net basis by 2035.
One of the international companies that has paused its work had applied to build a renewable power project in the province, said Jorden Dye, acting director of the Business Renewables Centre, a Calgary-based organization that matches renewable developers and buyers.
A second company has paused design work on its first Alberta project, Dye added.
A third company delayed plans to secure Calgary office space, while a fourth was making preliminary inquiries about investing in Alberta before deciding to wait, he added.
“Those investment decisions … are not going to move forward until the government clears this up,” Dye said.
He said he could not name the companies because plans are confidential.
THE ALBERTA WAY
Alberta has led the country in building renewable capacity and is on track to eliminating combustion of coal for power next year, six years ahead of plan.
Along with domestic firms, foreign companies like Berkshire Hathaway’s BHE Canada, EDF Renewables and Enel Green Power generate renewable power in Alberta. Companies have invested nearly C$5 billion ($3.7 billion) since 2019, according to the Pembina Institute.
The pause directly affects 15 projects in the approvals queue, the government spokesperson said. But Pembina said the freeze puts at risk a total of 91 projects at early development stages.
Calgary-based BluEarth Renewables is reviewing the 400 megawatts’ worth of early-stage wind and solar projects it was considering for the province, although it has no projects currently in Alberta’s approval queue, said CEO Grant Arnold.
“Without certainty as to what the outcome of this pause will be, we will prioritize investment into other jurisdictions,” Arnold said. BluEarth also operates in three other provinces and the U.S.
Alberta Utilities Commission is deliberating whether to stop receiving applications during the pause period, rather than just halting approvals, a move that would suggest it may freeze development even longer, Dye said.
“You could see a scenario where an investor says, ‘Alberta is now a risky place to invest so I need a higher return to justify the political risk,'” said Dan Balaban, CEO of Greengate Power, which built Canada’s biggest solar farm in southern Alberta with fund manager Copenhagen Infrastructure Partners, producing power for Amazon.com.
“We need to get back to the Alberta way, which is very pro-business.”
($1 = 1.3550 Canadian dollars)
(Reporting by Rod Nickel in Winnipeg, Manitoba; additional reporting by Steve Scherer in Ottawa; Editing by Denny Thomas and Marguerita Choy)