Canadian Energy Centre
Completing Trans Mountain, Indigenous LNG: What to watch in Canadian energy in 2024
Workers lay pipe during construction of the Trans Mountain pipeline expansion on farmland in Abbotsford, B.C., on May 3, 2023. CP Images photo
From the Canadian Energy Centre
By Deborah JaremkoActivity promises to highlight Canada’s position as a world supplier of choice
It’s going to be a big year for Canadian energy, with major milestones anticipated that will transform Canada from a supplier with a single customer (the United States) to a global player.
Global demand for oil and gas is expected to stay strong in the decades ahead as the world works to reduce emissions, still supplying nearly half of energy needs in 2050, according to the International Energy Agency.
Activity in 2024 promises to highlight Canada’s position as a supplier of choice with a leading approach to reducing emissions and engaging Indigenous communities.
Here are five things to watch.
5. Start-Up Activities for LNG Canada
Construction of the LNG Canada export terminal is now more than 90 per cent complete. Photo courtesy LNG Canada
Against the backdrop of surging liquefied natural gas (LNG) demand – Asia’s consumption hit a record 26.6 million tonnes in December – Canada’s first LNG export terminal is preparing for start-up.
LNG Canada will have among the world’s lowest emissions for LNG supply, at 0.15 tonnes of CO2 equivalent per tonne of LNG, less than half the global average.
This year, the terminal at Kitimat, B.C. will test and fine-tune equipment and the process of producing LNG will begin, the company says.
The start-up program will take more than one year to complete.
Moving into the final stages at LNG Canada follows the recent completion of the Coastal GasLink Pipeline, connecting natural gas supply from northeast B.C.
4. Progress Toward Oil Sands Net Zero
The Pathways Alliance has extensive work underway on the environmental program for its proposed CCS project, involving 135 experts ranging from aquatic and wildlife biologists to archeologists and paleontologists who have spent more than 1,600 hours in the field working to minimize environmental disturbance. Photo courtesy Pathways Alliance
Major regulatory applications are expected in 2024 for one of the world’s largest proposed carbon capture and storage (CCS) networks, located in Canada’s oil sands.
The project would connect CO2 captured at an initial 14 oil sands facilities by pipeline to a shared hub for storage deep underground.
It is the foundation of the plan by the Pathways Alliance – companies representing 95 per cent of oil sands production – to reduce emissions from operations by nearly one third by 2030 on the way to net zero by 2050.
Pathways has said that after regulatory approvals are complete, CO2 injection and storage could begin by late 2026.
3. Growth in Indigenous Ownership
Eva Clayton, back left, President of the Nisga’a Lisims Government (joint venture owner of the proposed Ksi Lisims LNG project), Crystal Smith, back right, Haisla Nation Chief Councillor (joint venture owner of proposed Cedar LNG project), and Karen Ogen, front right, CEO of the First Nations LNG Alliance pose for a photograph on the HaiSea Wamis zero-emission tugboat outside the LNG2023 conference, in Vancouver, B.C., Monday, July 10, 2023. CP Images photo
The rising tide of Indigenous ownership in Canadian energy is likely to continue growing in 2024.
From LNG terminals to oil and gas pipelines, natural gas-fired power plants and CCS projects to reduce emissions, more Indigenous communities are taking on a leadership role.
Since 2022, more than 75 First Nations and Métis communities in Alberta and British Columbia have agreed to ownership stakes in energy projects including the Coastal GasLink pipeline and major oil sands transportation networks.
Indigenous loan guarantee programs like those offered by the Alberta Indigenous Opportunities Corporation (AIOC) are helping communities invest.
So far, the AIOC has underwritten more than $500 million in loan guarantees. This year it has $3 billion of support available, up from $2 billion in 2023.
Details of a proposed national loan guarantee program to help facilitate Indigenous equity ownership in major resource projects are also expected in the federal budget this spring.
2. Green Light for Cedar LNG
Rendering courtesy Cedar LNG
Owners of the world’s first Indigenous-led LNG project – a floating terminal at Kitimat, B.C. –plan to make the final decision to proceed within the next three months.
Cedar LNG, owned jointly by the Haisla Nation and Pembina Pipeline Corporation, would have capacity to export three million tonnes of LNG per year, primarily to Asian markets.
With emissions intensity of 0.08 tonnes of CO2 equivalent per tonne of LNG, it would be one of the lowest carbon footprint LNG projects in the world.
In early January, the partners reached the critical milestone of selecting the primary contractors to engineer, build and deliver the floating LNG unit.
A final investment decision is now expected in the first quarter of 2024.
1. Completion of the Trans Mountain Pipeline Expansion
Worker at Trans Mountain’s Edmonton terminal. Photo courtesy Trans Mountain Corporation
After more than 12 years in the making, Canada’s first large-scale access to growing global oil markets is now weeks away from completion.
The existing Trans Mountain pipeline system from Edmonton, Alberta to Burnaby, B.C. runs consistently at maximum capacity with producers seeking more export space than is available.
The expansion will increase service by about 600,000 barrels per day, bringing more Canadian oil to customers around the world, primarily on the U.S. west coast and Asia.
After the recent resolution of a regulatory delay, Trans Mountain can now proceed with the last two per cent of construction.
The company anticipates oil will flow on the expanded line before the end of March.
Cenovus Energy’s Sunrise oil sands project in northern Alberta
From the Canadian Energy Centre
By Will Gibson
‘Canada continues to be resource-rich and competes very well against major U.S. resource bases’
From the Canadian Energy Centre
Horizontal drilling technology and more investment in oil production have fundamentally changed the industry
There’s extensive discussion today about energy transition and transformation. Its primary focus is a transition from fossil fuels to lower-carbon energy sources.
But in Alberta, a fundamental but different energy transition has already taken place, and its ripple effects stretch into businesses and communities across the province.
The shift has affected the full spectrum of oil and gas activity: where production happens, how it’s done, who does it and what type of energy is produced.
Oil and gas development in Alberta today largely happens in different places and uses different technologies than 20 years ago. As a result, the companies that support activity and the communities where operations happen have had to change.
Regional Shift
For the first decade of this century, in terms of numbers of wells, most drilling activity happened in central and southeast Alberta, with companies primarily using vertical wells to target conventional shallow natural gas deposits.
In 2005, producers drilled more than 8,000 natural gas wells in these areas, according to Alberta Energy Regulator (AER) records.
But then, three things happened. The price of natural gas declined, the price of oil went up and new horizontal drilling technology unlocked vast energy resources that were previously uneconomic to produce.
By 2015, the amount of natural gas wells companies drilled in central and southeast Alberta was just 256. In 2023, the number dropped to only 50. Over approximately 20 years, activity dropped by 99 per cent.
Where did the investment capital go? The oil sands and heavy oil reserves of Alberta’s northeast and shale plays, including the Montney and Duvernay, in the province’s foothills and northwest.
Nearly 60 per cent of activity outside of the oil-rich northeast occurred in central and southeast Alberta in 2005. By 2023, overall oil and gas drilling in those regions had dropped by 30 per cent, while at the same time increasing by 159 per cent in the foothills and northwest.
“The migration of activity from central and southern Alberta to other regions of the province has been significant,” says David Yager, a longtime oil and gas service company executive who now works as a special advisor to Alberta Premier Danielle Smith.
“For decades there were vibrant oil service communities in places like Medicine Hat, Taber, Brooks, Drumheller and Red Deer,” he says.
“These [oil service communities] have contracted materially with the new service centres growing in places like Lloydminster, Bonnyville, Rocky Mountain House, Edson, Whitecourt, Fox Creek and Grande Prairie.”
Fewer Wells and Fewer Rigs
Extended-reach horizontal drilling compared to shallow, vertical drilling enables more oil and gas production from fewer wells.
Outside the oil sands, in 2005, producers in Alberta drilled 17,300 wells. In 2023, that dropped to just 3,700 wells, according to AER data.
Despite that massive nearly 80 per cent decrease in wells drilled, total production of oil, natural gas and natural gas liquids outside of the oil sands is essentially the same today as it was in 2005.
Last year, non-oil sands production was 3.1 million barrels of oil equivalent (boe) per day, compared to 3.4 million boe per day in 2005–but from about 13,600 fewer new wells.
Innovation from drilling and energy services companies has been a major factor in achieving these impressive results, says Mark Scholz, CEO of the Canadian Association of Energy Contractors. But there’s been a downside.
Yager notes that much of the drilling and service equipment employed on conventional oil and gas development is not suited for unconventional resource exploitation.
Scholz says the productivity improvements resulted in an oversupply of rigs, especially rigs with limited depth ratings and limited capability for “pad” drilling, where multiple wells are drilled the same area on the surface.
Rigs have been required to drill significantly deeper wellbores than in the traditional shallow gas market, he says.
“This has resulted in rig decommissioning or relocations and a tactical effort to upgrade engines, mud pumps, walking systems and pipe-handling technology to meet evolving customer demands,” he says.
“You need not go beyond the reductions in Canada’s drilling rig fleet to understand the impact of these operational innovations. Twenty years ago, there were 950 drilling rigs; today, we have 350, a 65 per cent reduction. [And] further contractions are likely in the near term.”
Scholz says, “collaboration and partnerships between producers and contractors were necessary to make this transition successful, but the rig fleet has evolved into a much deeper, technologically advanced fleet.”
A Higher Cost of Entry
Yager says that along with growth in the oil sands, replacing thousands of new vertical shallow gas wells with fewer, high-volume extended-reach horizontal wells has made it more challenging for smaller companies to participate.
“The barriers to entry in terms of capital required have changed tremendously. At one time a new shallow gas well could be drilled and put on stream for $150,000. Today’s wells in unconventional plays cost from $3 million to $8 million each,” he says.
“This has materially changed the exploration and production companies developing the resource, and the type of oilfield services equipment employed. An industry that was once dominated by multiple smaller players is increasingly consolidating into fewer, larger entities. This has unintended consequences that are not well understood by the public.”
More Oil (Sands), Less Gas
Higher oil prices and horizontal drilling helped change Alberta from a natural gas hotbed to a global oil powerhouse.
In the oil sands, horizontal wells enabled a key technology called steam assisted gravity drainage (SAGD), which went into commercial service in 2001 to allow for a massive expansion of what is referred to as in situ oil sands production.
In 2005, mining dominated oil sands production, at about 625,000 barrels per day compared to 440,000 barrels per day from in situ projects. In situ oil sands production exceeded mining for the first time in 2013, at 1.1 million barrels per day compared to 975,000 barrels per day from mining.
Today the oil sands production split is nearly half and half. Last year, in situ projects–primarily SAGD–produced approximately 1.8 million barrels per day, compared to about 1.7 million barrels per day from mining.
Natural gas used to exceed oil production in Alberta. In 2005, natural gas provided 54 per cent of the province’s total oil and gas supply. Nearly two decades later, oil accounts for 60 per cent compared to 29 per cent from natural gas. The remaining approximately 11 per cent of production is natural gas liquids like propane, butane and ethane.
Alberta’s non-renewable resource revenue reflects the shift in activity to more oil sands and less natural gas.
In 2005, Alberta received $8.4 billion in natural gas royalties and $950 million from the oil sands. In 2023, the oil sands led by a wide margin, providing $16.9 billion in royalties compared to $3.6 billion from natural gas.
Innovation and Emerging Resources
As Alberta’s oil and gas industry continues to evolve, another shift is happening as investments increase into emissions reduction technologies like carbon capture and storage (CCS) and emerging resources.
Since 2015, CCS projects in Alberta have safely stored more than 14 million tonnes of CO2 that would have otherwise been emitted to the atmosphere. And more CCS capacity is being developed.
Construction is underway on an $8.9-billion new net-zero plant producing polyethylene, the world’s most widely used plastic, that will capture and store CO2 emissions using the Alberta Carbon Trunk Line hub. Two additional CCS projects got the green light to proceed this summer.
Meanwhile, in 2023, producers spent $700 million on emerging resources including hydrogen, geothermal energy, helium and lithium. That’s more than double the $230 million invested in 2020, the first year the AER collected the data.
“Energy service contractors are on the frontlines of Canada’s energy evolution, helping develop new subsurface commodities such as lithium, heat from geothermal and helium,” Scholz says.
“The next level of innovation will be on the emission reduction front, and we see breakthroughs in electrification, batteries, bi-fuel engines and fuel-switching,” he says.
“The same level of collaboration between service providers and operators that we saw in our productivity improvement is required to achieve similar results with emission reduction technologies.”
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