The coming year could mark a turning point for the expansion of Canada’s oil and gas sector as governments look to harness its resources to drive economic independence and prosperity.

Against a backdrop of steady drilling activity and continued production growth, new major export projects are expected to take significant steps forward. 

Here are five key developments to watch. 

5. Modest growth in drilling activity

Oil and gas drilling in central Alberta, fall 2025. Photo supplied to the Canadian Energy Centre

Oil and gas drilling in Western Canada is set for modest increases in 2026 amid flat oil price forecasts and softer natural gas prices, according to the Canadian Association of Energy Contractors (CAOEC).

CAOEC projects an average of 213 active drilling rigs, up from 201 in 2025. A total of 5,709 wells are expected to be drilled, an increase of just under three per cent.

This will be accompanied by an average of 458 active service rigs, up from 447 in 2025. 

The activity is expected to support 85,000 direct and indirect jobs over the year. 

“These aren’t abstract figures; they’re the heartbeat of Canada, the proof that our work isn’t just about extracting resources — it’s about giving Canadians a hopeful future,” said CAOEC CEO Mark Scholz.

4. New investment spurred by Alberta-Canada agreement

Oil sands workers in northern Alberta. Photo courtesy Pathways Alliance

The recent wide-ranging energy agreement between the Alberta and federal governments could unlock new investment in data centres, emissions-reduction technology and oil sands growth in 2026.

The deal is “formidable,” Edmonton-based Capital Power CEO Avik Dey told investors in December. 

“It allows us a pathway to building new natural gas-fired power generation in Alberta,” he said.

The company announced it is now negotiating an electricity supply agreement with an unnamed data centre developer in the province.

Policy think tank Clean Prosperity estimates the $130-per-tonne carbon credit price agreed to by Alberta and Ottawa could unlock more than $90 billion in low-carbon investment including carbon capture and storage (CCS).

And as details of Alberta’s proposed pipeline to the northwest coast become clearer, oil sands producers could begin dusting off expansion plans.

According to BMO Capital Markets, producers have already submitted project proposals with combined capacity of 4.1 million barrels per day — enough to more than double current oil sands production.

This total includes both approved projects and proposals that are currently on hold or delayed.

3. Data centres taking flight

Alberta’s goal of attracting $100 billion in data centre investment is expected to advance in 2026 as key policy measures take shape and new projects receive approval.

Interest is strong, with proposed data centres now requesting more than 20 gigawatts of power, according to the Alberta Electric System Operator. 

The province passed legislation in 2025 that encourages data centres to bring their own generation to support their connection to the power grid. This is designed to enhance reliability of the grid while accelerating the approval process for data centre projects.

In December, two European companies announced a $1.26 billion plan to build four new AI-ready data centres in Alberta. 

Portugal-based Technologies New Energy will supply 80 per cent of the power for the new data centres for Data District Inc., a division of Swiss asset management firm Alcral AG. 

“Alberta offers the energy resources, industrial base and investment momentum to support this growth,” TNE said in a statement.

Initial operations are targeted for 2026.

2. Go-ahead for Ksi Lisims LNG

Rendering of the proposed Ksi Lisims LNG project. Image courtesy Ksi Lisims LNG

An Indigenous-led floating LNG terminal on B.C.’s northern coast near Alaska is “not far off” from a final decision to proceed. 

That milestone is expected in 2026, spokeswoman Rebecca Scott said in November. 

Ksi Lisims (pronounced “s’lisims”) is a partnership between the Nisga’a Nation, a consortium of Canadian natural gas producers called Rockies LNG, and a subsidiary of Houston-based Western LNG. 

The 12-million-tonne-per-year project would help significantly expand Canada’s LNG export capacity, which is currently about 14 million tonnes per year. 

In November, Ksi Lisims was referred for fast-tracking by Canada’s new Major Projects Office (MPO). 

Start-up is targeted for 2029.   

1. Advancing a new northwest coast oil pipeline

Pipe in storage for the Trans Mountain expansion near Hope, B.C. in August 2019. CP Images photo

Alberta’s application to the MPO for a new oil pipeline to the northwest coast is expected by July 1, 2026. 

It’s a project that’s been designated in the national interest as a key measure to establish Canada as an energy superpower.

The pipeline application is expected to target a deep-water port for oil exports to Asian markets, while creating opportunities for Indigenous ownership. 

If a proposal is approved, the federal government has committed to enabling bitumen exports, including an “appropriate adjustment” of the tanker moratorium on B.C.’s north coast if necessary. 

The governments have also agreed to a maximum two-year timeframe for permitting and approvals.

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Canada’s energy landscape changed significantly in 2025, with mounting U.S. economic pressures reinforcing the central role oil and gas can play in safeguarding the country’s independence.

Here are the Canadian Energy Centre’s top five most-viewed stories of the year.

5. Alberta’s massive oil and gas reserves keep growing – here’s why

The Northern Lights, aurora borealis, make an appearance over pumpjacks near Cremona, Alta., Thursday, Oct. 10, 2024. CP Images photo

Analysis commissioned this spring by the Alberta Energy Regulator increased the province’s natural gas reserves by more than 400 per cent, bumping Canada into the global top 10.

Even with record production, Alberta’s oil reserves – already fourth in the world – also increased by seven billion barrels.

According to McDaniel & Associates, which conducted the report, these reserves are likely to become increasingly important as global demand continues to rise and there is limited production growth from other sources, including the United States.

4. Canada’s pipeline builders ready to get to work

Photo courtesy Coastal GasLink

Canada could be on the cusp of a “golden age” for building major energy projects, said Kevin O’Donnell, executive director of the Mississauga, Ont.-based Pipe Line Contractors Association of Canada.

That eagerness is shared by the Edmonton-based Progressive Contractors Association of Canada (PCA), which launched a “Let’s Get Building” advocacy campaign urging all Canadian politicians to focus on getting major projects built.

“The sooner these nation-building projects get underway, the sooner Canadians reap the rewards through new trading partnerships, good jobs and a more stable economy,” said PCA chief executive Paul de Jong. 

3. New Canadian oil and gas pipelines a $38 billion missed opportunity, says Montreal Economic Institute

Steel pipe in storage for the Trans Mountain Pipeline expansion in 2022. Photo courtesy Trans Mountain Corporation

In March, a report by the Montreal Economic Institute (MEI) underscored the economic opportunity of Canada building new pipeline export capacity.

MEI found that if the proposed Energy East and Gazoduq/GNL Quebec projects had been built, Canada would have been able to export $38 billion worth of oil and gas to non-U.S. destinations in 2024.

“We would be able to have more prosperity for Canada, more revenue for governments because they collect royalties that go to government programs,” said MEI senior policy analyst Gabriel Giguère. 

“I believe everybody’s winning with these kinds of infrastructure projects.”

2. Keyera ‘Canadianizes’ natural gas liquids with $5.15 billion acquisition

Keyera Corp.’s natural gas liquids facilities in Fort Saskatchewan, Alta. Photo courtesy Keyera Corp.

In June, Keyera Corp. announced a $5.15 billion deal to acquire the majority of Plains American Pipelines LLP’s Canadian natural gas liquids (NGL) business, creating a cross-Canada NGL corridor that includes a storage hub in Sarnia, Ontario. 

The acquisition will connect NGLs from the growing Montney and Duvernay plays in Alberta and B.C. to markets in central Canada and the eastern U.S. seaboard.

“Having a Canadian source for natural gas would be our preference,” said Sarnia mayor Mike Bradley. 

“We see Keyera’s acquisition as strengthening our region as an energy hub.” 

1. Explained: Why Canadian oil is so important to the United States

Enbridge’s Cheecham Terminal near Fort McMurray, Alberta is a key oil storage hub that moves light and heavy crude along the Enbridge network. Photo courtesy Enbridge

The United States has become the world’s largest oil producer, but its reliance on oil imports from Canada has never been higher.

Many refineries in the United States are specifically designed to process heavy oil, primarily in the U.S. Midwest and U.S. Gulf Coast.

According to the Alberta Petroleum Marketing Commission, the top five U.S. refineries running the most Alberta crude are:

• Marathon Petroleum, Robinson, Illinois (100% Alberta crude)
• Exxon Mobil, Joliet, Illinois (96% Alberta crude)
• CHS Inc., Laurel, Montana (95% Alberta crude)
• Phillips 66, Billings, Montana (92% Alberta crude)
• Citgo, Lemont, Illinois (78% Alberta crude)

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Indigenous communities across British Columbia are playing a critical role in building the foundation for LNG—from natural gas supply to pipeline corridors and export terminals—helping drive momentum as Canada’s LNG export sector takes its first steps.

A growing role for McLeod Lake Indian Band

One of these communities is the McLeod Lake Indian Band. Part of the Tse’khene group of Aboriginal peoples, McLeod Lake is located about 150 kilometres north of Prince George in the Montney natural gas region.

“McLeod Lake Indian Band wants to create a business environment within its traditional territory that is conducive to the responsible development of the area’s natural resources,” said Jacob Albertson, CEO of the Duz Cho Group of Companies, which is 100 per cent owned by the band.

Jacob Albertson, CEO of Duz Cho Group of Companies.

Since 2018, the bustling business has seen revenues surge nearly tenfold, from $14.5 million to $134 million annually.

‘Canadian gas is Indigenous gas’

Albertson recently joined the board of the First Nations Natural Gas Alliance (formerly the First Nations LNG Alliance), which has member organizations from B.C., Alberta and Newfoundland and Labrador.

“Canadian natural gas is Indigenous natural gas,” said Alliance CEO Karen Ogen, who served as elected Chief of the Wet’suwet’en First Nation from 2010 to 2016.

Ogen’s goal is to inspire and support more First Nations engaging in discussions with industry and government about potential resource opportunities.

Karen Ogen, CEO of the First Nations Natural Gas Alliance.

“We can show the world that Canada’s natural gas can be developed responsibly and advance economic reconciliation for the benefit of our citizens and those around the world who need an alternative to coal,” she said.

The Alliance’s work helped advance the Coastal GasLink pipeline, which is now delivering natural gas from northeast B.C. to the LNG Canada terminal at Kitimat, in the traditional territory of the Haisla Nation. 

“Attitudes have changed as knowledge has improved,” Albertson said. 

“That’s why I’m excited about the future and how the people of this region can benefit from it.”

A bigger voice for First Nations in B.C.’s interior

McLeod Lake was one of 20 Indigenous bands along the route whose elected leadership signed agreements with the pipeline project. 

Albertson sees joining the Alliance’s board as a chance to amplify the voice of B.C.’s interior Nations like McLeod Lake, whose traditional territories host much of the natural gas that feeds coastal LNG exports.

It’s important for community members to understand both the impacts and benefits of development, he said.

Business transparency helps builds support

To keep members better informed about local projects, Albertson began sharing Duz Cho’s monthly reports with the band’s 550 members, along with quarterly meetings in Prince George, Vancouver and Calgary.

“That transparency is very important,” Albertson said. 

“We’ve really focused on reporting about the benefits of these projects as well as the impacts. It’s helped the membership realize these projects are good for the community.”

Duz Cho now seeks job creation opportunities and equity partnerships rather than simply collecting royalties from industry.

“We restructured some of the agreements so members would have those opportunities,” says Albertson.

“There is a real value to hiring community members, who have firsthand knowledge of the projects they work on and can share that within the community.”

Duz Cho sign in Chetwynd, B.C. Photograph for Canadian Energy Centre

Education key to energy expansion in B.C. 

Improving understanding of resource projects is critical as Canada looks to expand its energy exports through B.C., Ogen said. 

“Those types of education and awareness need to happen, not only for LNG, but for oil,” she said. 

“I think that the process that we did helped us inform a lot of people.”

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As a lifelong farmer, entrepreneur and community leader, Alanna Hnatiw knows first-hand the crucial role energy plays in a strong and diverse economy. 

The mayor of Sturgeon County, a sprawling rural municipality northeast of Edmonton, Hnatiw has spent much of the last decade working to protect its agricultural roots while building new industries that support the jobs and services families and businesses rely on every day.

Hnatiw says there is widespread appreciation among the county’s 20,000 residents for the opportunities afforded by the province’s oil and gas resources. That’s why she joined other leaders in Alberta’s Industrial Heartland region to applaud a major new natural gas pipeline planned for the area.

“Natural gas is an integral to all the industrial operations in Sturgeon County and the surrounding area. It goes beyond just burning it to turn turbines, it is the feedstock for all kinds of value-added processing. From fertilizer and plastics to petrochemicals and hydrogen, natural gas is the lynchpin for us into the future,” she said.

Filling growing demand

Hnatiw is one of more than a dozen community and industry leaders who sent letters of support to the Alberta Utilities Commission (AUC) last year endorsing ATCO Energy Systems’ proposed Yellowhead Pipeline project. 

The project achieved a significant milestone in August when the AUC approved ATCO’s application determining the pipeline is needed. 

The largest infrastructure investment in the company’s history, the 230-kilometre pipeline from Peers to Fort Saskatchewan will transport more than 1.1 billion cubic feet of natural gas per day when operational in late 2027.

For context, Alberta produced about 11 billion cubic feet per day of natural gas in 2024, according to the Alberta Energy Regulator. 

Proposed route map of the Yellowhead Pipeline. Map courtesy ATCO

The Yellowhead Pipeline will boost deliveries to the greater Edmonton area as demand continues to grow for power generation, manufacturing, petrochemical processing and residential use. 

Industrial customers have reserved 90 per cent of the pipeline’s capacity to meet their future needs. 

This includes Dow Chemical, which plans to build an $8.9-billion net-zero ethylene processing facility in Fort Saskatchewan, Heidelberg Materials’ Edmonton facility that aims to be the world’s first full-scale cement plant equipped with carbon capture and storage (CCS), and McCain Foods, which requires more natural gas for a planned expansion of its French fry factory in Coaldale.

Prosperity driver

Edmonton Global CEO Malcolm Bruce described the Yellowhead Pipeline as a “visionary” infrastructure project in his letter of support to the AUC. 

“The [project] will create jobs, enable billions in new investment and drive Alberta’s hydrogen roadmap and natural gas vision and strategy.”

ATCO’s projections show the pipeline will generate substantial economic benefits. The company estimates that during construction, it will support 12,000 jobs and contribute $1.6 billion per year to Alberta’s economy. 

Once in operation, the pipeline is expected to support 23,700 jobs per year and add $3.9 billion annually to Alberta’s GDP.

For Sturgeon County, the project also provides much-needed certainty that natural gas will be available for the $30 billion in new industrial investments the region is hoping to attract in the coming years. 

Future plans

The municipality is already home to major operations including the NWR Sturgeon Refinery and Nutrien fertilizer plant, both of which capture carbon dioxide emissions that are transported through the Alberta Carbon Trunk Line for deep underground storage near Clive, Alberta. 

Hnatiw said future development may include hydrogen production with CCS, petrochemical processing, gas-fired power plants and large-scale data centres.

“With our operations running near capacity right now, this new pipeline helps alleviate the uncertainty around gas supplies for industrial developers,” Hnatiw said.

The county’s industrial goals are inextricably tied to ensuring its farming sector continues to flourish, she said.

“Eighty per cent of our land base is agricultural, but it only accounts for one per cent of our budget as far as taxes go, so we need our industrial residents to support our rural way of life,” she said. 

“We don’t want people to have to leave our community to make a living. We want a future that is full of opportunity, and one that is also sustainable for the families that produce our food, our fuel, and all the other value-added products we can provide.”

ATCO’s next step is to file for AUC approval to build the pipeline later this year. The company expects construction to begin in 2026. 

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Greg Kist has seen plenty of change during more than three decades working in the energy industry. But the former executive with Petronas and Progress Energy has rarely experienced a history-making moment.

That happened in July 2024, when the B.C. government awarded the Halfway River First Nation what’s known as oil and gas tenure in the heart of the Montney play.  

It’s an agreement that grants the Nation decision-making authority over the exploration and development of petroleum and natural gas resources on more than 34,000 hectares of Crown land in its traditional territory, located approximately 1,000 kilometres northeast of downtown Vancouver.

That agreement is now moving further into action with a deal between Halfway River-owned Tsaa Dunne Za Energy (TDZE) and ARC Resources. 

Members of the Halfway River First Nation participate in a field tour with the BC Energy Regulator in June 2025. Photo courtesy BCER

The agreement, signed earlier this year, will see TDZE work with Calgary-based ARC to develop about 25 per cent of the tenured land. 

The region is adjacent to ARC’s existing Attachie natural gas operations, which are rich in high-value natural gas liquids. 

The company describes Attachie as one of its most profitable assets, which can be expanded thanks to the TDZE agreement. 

“This land was deferred from development for more than two decades while sitting in the premier natural gas play in North America,” says Kist, one of TDZE’s managing executives. 

“Unlocking it will generate all kinds of economic activity and royalties for the B.C. government that help pay for schools and health care. But it will also generate the same benefits for the Halfway River First Nation.”

ARC plans to integrate the new areas using existing roads, pipelines and other infrastructure from Attachie.

Developing the land will still require consultation with the Halfway River First Nation. 

Drilling in the Montney play straddles the border between northeast B.C. and northwest Alberta. Photo courtesy ARC Resources

“This is very much about Tsaa Dunne Za Energy delivering the best return on this particular asset for its shareholders, which are the members of the Halfway River First Nation,” Kist says. 

In addition to granting tenure to develop oil and gas on the land, the B.C. government and Halfway River have implemented a landscape planning pilot to mitigate the impacts of development on the Nation’s Treaty 8 rights and manage potential cumulative effects of new development.

“The tenure award and landscape planning pilot will help to ensure that oil and gas development in these areas is sustainable and managed in accordance with the values of the Halfway River First Nation,” Chief Darlene Hunter said in a statement.  

Kist sees the agreement as a template for other governments, energy companies and First Nations to follow.

“This has the potential to be the model for cooperative development so that we can develop resources in the right way that benefits governments, First Nations and industry. I’m proud to be a part of this because everybody involved wins from this.”

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More than a century after its founding, the former ghost town of Nordegg, Alta. is getting natural gas service, promising lower costs and more reliable energy for homes and businesses.

“Natural gas will be a huge game changer, especially for commercial use,” said Clearwater County Reeve Michelle Swanson.

The former coal mining town is no stranger to cold winters. During Alberta’s cold snap in January 2024, the hamlet broke its cold weather record reaching a bone chilling -45.8 degrees Celsius.

In the 1920s, Nordegg — tucked into the foothills of the Rockies about two hours west of Red Deer — was home to Alberta’s most productive coal mine, a fuel supply primarily for steam locomotives.

But demand declined following the Leduc No. 1 oil discovery in 1947, and the mine closed in 1955.   

The population dwindled from a peak of nearly 3,000 people to as few as 27 at one point, said Swanson.

Today, about 90 people call the hamlet home, and the future is looking brighter.

“We’re slowly building up. We have more full time residents. We have businesses that are looking to locate there, a couple hotels. Tourism is the area’s primary industry,” Swanson said. 

By adding access to natural gas and installing new fibre optic internet, Nordegg will be able to sustain new growth and attract development, she said.

In July, the Alberta government announced $2.5 million in funding to help build an 11-kilometre pipeline connecting the hamlet to a nearby gas plant. The $8-million project is also funded by the county and the Rocky Gas Co-Op. 

With the new gas connection, residents could save up to 25 per cent on their utility bills, according to the province.

Swanson said that right now people in Nordegg get their energy from electricity, wood and propane. 

“Electricity is the primary heat source, and your secondary is wood stoves and most of the businesses are also running off propane, because of the costs of electricity,” she said. 

The biggest benefit of connecting to natural gas is reliability, she said. 

“Number one is having the predictability that gas provides. It is going to be there on time. Propane, I mean, you can run out,” Swanson said.

Safety is another big factor in a region that can be prone to wildfires.

“I know our firefighters were worried that a wildfire could set off a lot of propane explosions, and that’s not helpful,” she said. 

“At the end of the day to me, it’s all about the fact that you’re creating a safer community, and you’re having a more predictable fuel source.”

Pipeline construction began in February and is targeted for completion this fall.

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The head of the National Coalition of Chiefs (NCC) is calling for the repeal of the oil tanker ban on B.C.’s north coast as Canada seeks “nation-building” projects to strengthen economic independence.

With short shipping times to hungry Asian markets, ports like Prince Rupert or Kitimat offer a strong business case – but only if the tankers can dock. 

“No proponent is going to look at investing in a pipeline to the north coast with that kind of legislation in place,” says NCC founder and CEO Dale Swampy.

Formed in 2016, the NCC is a group of pro-development First Nation leaders including some who were equity partners in the cancelled Northern Gateway pipeline from Edmonton to Kitimat.

Canada’s Indigenous communities need projects, not lawsuits that hold them up, he says.

Original map of the proposed Northern Gateway Pipeline, submitted to regulators as part of a preliminary information package in October 2005. Map courtesy Canada Energy Regulator

Northern Gateway and the tanker ban

The tanker ban and Northern Gateway are intrinsically linked. 

The moratorium contributed to the loss of Indigenous ownership stakes and an estimated $2 billion in economic opportunity for First Nations and Métis communities.

“We have consistently spoken up against this legislation, which directly affects the ability of our communities to participate in developing resources,” Swampy says.

With the aim to diversify markets for Canadian oil by reaching customers in Asia, Enbridge announced Northern Gateway in 2004. 

The project’s 7,800-page regulatory application to the National Energy Board (NEB) – including more than 1,600 pages specific to marine safety – followed in May 2010. 

In December 2013, after extensive assessment and public hearings, including with Indigenous communities, a three-member Joint Review Panel from the NEB and the Canadian Environmental Assessment Agency recommended the project to go ahead. 

In June 2014, the federal government approved Northern Gateway with 209 conditions, including a requirement to fulfill over 400 voluntary commitments, many tied to marine safety.

After receiving approval, Northern Gateway’s management team and the project’s Aboriginal Equity Partners proposed an increase in Indigenous ownership from 10 per cent to 33 per cent. 

They also created a joint governance structure where the communities and the company would have an equal voice. 

The modified project would also incorporate First Nations and Métis environmental stewardship and monitoring using traditional science. 

Meanwhile, legal actions were underway by environmental groups and Indigenous communities outside the equity partners. 

By December 2014, the Federal Court of Appeal had consolidated multiple cases challenging the project’s approval. 

Blocking the Northern Gateway pipeline and enacting a moratorium on oil tanker traffic on B.C.’s north coast became cornerstones of the Liberal Party’s 2015 election platform.

Oil Tanker Moratorium Act legislated moratorium area, 2017. Map courtesy Transport Canada

In November 2015, just a week after being sworn in, former Prime Minister Justin Trudeau instructed his transport minister to “formalize” the ban, a major setback for Northern Gateway. 

Five months later, in June 2016 the Federal Court of Appeal overturned the government’s approval for the project, ruling that Canada had failed to fulfill its constitutional duty to consult Indigenous communities. 

In November 2016, Trudeau officially rejected Northern Gateway, devastating hopes for the bands that would have become equity partners.

“Thirty-one of the 40 First Nations and Métis communities who were located on Northern Gateway’s right-of-way supported the pipeline, but a couple of communities backed by environmental groups were able to stop the entire project,” Swampy says. 

“That’s not fair or democratic.”

In May 2017, Bill C-48, also known as the Oil Tanker Moratorium Act, was formally introduced in the House of Commons.

Indigenous communities stripped of opportunity

At the time, Swampy told the Financial Post that the communities saw the decision to reject Northern Gateway as political and not acting in the best interests of Canadians.

“They weren’t asked about the financial effect, the lost employment,” he said. 

The implications of the tanker ban go far beyond the West Coast, Indian Resources Council CEO Stephen Buffalo told the Standing Senate Committee on Transport and Communications in March 2019. 

Buffalo joined Swampy and other Indigenous leaders to speak to the committee as part of its consideration of Bill C-48. 

Representing more than 130 First Nations that produce or have the potential to produce oil and gas, he said community prosperity is closely tied to the sector. 

“The industry is suffering greatly from the lack of pipeline access…We need access to new markets to obtain fair value for our oil resources,” Buffalo said.

“We are struggling with addictions and depression, and people are losing hope. If we are ever going to make faster progress on these issues, our First Nations communities need more own-source revenues to fund cultural programs, sports programs or health activities for our young people,” he said.

“We need more jobs available for our people. We need them to earn good wages — wages that can support their families. Right now, Bill C-48 and other policies threaten all of that for us.”

Buffalo questioned the necessity of the tanker ban.

“I think all First Nations would support development of strict regulations that protect the environment, but that’s different from arbitrarily stopping just Canadian oil tanker activity,” he said.

The Senate approved the tanker ban and it became law upon Royal Assent on June 21, 2019. 

Shifting times and new pipelines

Six years and the threat of U.S. tariffs later, the view on Canadian oil pipelines — and, potentially, the tanker ban itself — is shifting. 

Growing public support for pipelines in recent opinion polls has encouraged Swampy. 

So, too, has the change in attitudes towards development by coastal First Nations that have experienced the benefits of working with industry.

“Many of the coastal First Nations in northwestern B.C. are either building or looking at building LNG facilities. They appreciate the fact prosperity can be gained by partnering on these projects,” he says.

The NCC wants to see that same opportunity for the communities that would have benefited from Northern Gateway, through a new oil pipeline proposal to either Kitimat or Prince Rupert. 

“We are hoping providing some certainty with Indigenous consultation and participation will give proponents some certainty they have a willing partner,” Swampy says. 

To avoid lawsuits that delay or cancel projects and drive developers out of Canada, Swampy says agreements must, from the outset, unite leadership from proponents, governments and affected First Nations.

“We hope governments hear our message: we want projects, not lawsuits,” he says.

“Communities don’t need a cheque or a handout. They need the opportunity to participate in a meaningful way.”

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Alberta has a new set of recommendations to address the growing number of oil and gas production and infrastructure assets in the province that are nearing or have passed the end of their commercial lifespan.

Following a monthslong engagement process with nearly 100 stakeholders including representatives from provincial and municipal governments, technical experts, producing companies and the service sector,  the province released its Mature Asset Strategy (MAS) report earlier this year. 

Led by industry veteran David Yager, a special advisor to the Premier, the report presents a suite of 21 major recommendations aimed at driving economic growth while protecting the environment and ensuring long-term sustainability. 

The recommendations have not yet been formally accepted by the Alberta government. 

Broadly, they aim to address the growing issue of non-payment of municipal taxes and surface leases, ensure production facilities keep operating as long as it makes economic sense, repurpose aging oil and gas assets and infrastructure where possible to generate wealth, and accelerate closure activities. 

What is a mature asset? 

The MAS defines a mature asset as an oil and gas reservoir, field or well that has been producing for an extended period and rates are declining, making it uneconomic to continue operation now or in the near future. 

This includes associated surface equipment and pipelines.

According to the Alberta Energy Regulator (AER), the province has approximately 262,000 “non-reclaimed” wells that fit into the mature asset designation.  

This includes about 94,000 wells that are “decommissioned” (wellbore cut and capped, surface equipment removed but site reclamation incomplete), about 78,000 that are “inactive” (not on production but not decommissioned), and about 91,000 that are “marginal” (producing 10 barrels of oil equivalent or less per day). 

There are also approximately 23,000 surface production facilities that are either inactive or have been decommissioned but not reclaimed, and about 174,000 kilometres of flowlines and pipelines that are decommissioned or non-operating. 

How did we get here? 

Collapsed natural gas prices are a major driver of many of the challenges facing Alberta’s mature assets, the MAS says. 

In the first nine years of this century, a total of 84,635 new gas wells were drilled in Alberta, primarily shallow gas wells in central and southeast Alberta. In 2005 alone, the figure in this region exceeded 8,000.

Alberta’s AECO-C natural gas reference price during this period averaged $5.83 per gigajoule (GJ).

Then the North American shale gas revolution happened, natural gas prices plummeted and activity changed dramatically.

As the price of oil remained stable, new horizontal drilling and reservoir completion technology unlocked vast new unconventional energy resources in the U.S. and in Alberta. 

From 2016 to 2020, the AECO-C reference price averaged only $1.68/GJ, a 71 per cent decline.

In this seven-year period only 3,790 new gas wells were drilled, reflecting the dramatically deteriorating economics.

While there was some relief in gas prices following the outbreak of the war in Ukraine in 2022, the impact on gas prices was short-lived. Alberta’s natural gas reference price last year averaged only $1.17/GJ.

On a year-over-year basis from 2005 to 2023, gas drilling in central and southeast Alberta plunged by 99 per cent.

Today more than half of Alberta’s “marginal” wells – primarily producing natural gas – are located in the province’s southeast in Cypress County, Special Areas, Newell County, Wheatland County and Kneehill County.

“Many recent insolvencies have been linked to operators holding large amounts of these types of assets,” the MAS says. 

“The producers generating attractive returns on invested capital today are generally not the same producers that own many of the mature assets.” 

Although the oil and gas industry as a whole has returned to profitability, this is only true for certain segments, the report says.  

Alberta’s oil sands, conventional oil and “wet” natural gas plays that contain high value liquids like ethane, butane and propane are now profitable. 

Dry natural gas production, on the other hand, has struggled for years to remain profitable, falling short of covering all financial obligations for many producers. 

This includes unavoidable costs like municipal taxes and surface leases, rising expenses such as carbon taxes, AER and Orphan Well Association levies, and, ultimately, the cost of shutting down and reclaiming operations.

These economic considerations are key to consider before drawing conclusions about mature assets and liabilities in Alberta, the report says. 

Resolving unpaid municipal taxes

The MAS says that during consultations, representatives of rural municipalities and private surface lease owners repeatedly asserted that “trust has been broken.” 

This sentiment stems from unpaid or reduced payments for surface lease rental fees and municipal property taxes.

“Despite record oil and gas production, significant royalty and tax contributions and substantial job creation, some producers have struggled to meet financial obligations,” the report says. 

While recognizing the need to address this challenge, the MAS emphasizes the overall value that has flowed from oil and gas operators to Albertans.   

“While several hundred million dollars in unpaid municipal taxes over the past four years has made headlines, in 2022 alone the total municipal taxation levied on oil and gas assets in Alberta was $1.6 billion,” it says. 

In 2023, Alberta’s seven largest oil and gas producers contributed approximately $24 billion to various levels of government in taxes, royalties and fees. 

In addition to low natural gas prices, limited access to capital and increasing costs have complicated the issue, the report says. 

“These challenges forced many companies into bankruptcy or financial distress, prompting cost-saving measures including non-payment of surface leases and municipal taxes.”

The MAS recommends that the province, municipalities, the Rural Municipalities of Alberta and the AER work together to establish a rapid and transparent process for addressing late or non-payment of municipal taxes.  

It also recommends re-establishing a separate quasi-judicial and independent Surface Rights Board to address the complex concerns raised by rural municipalities and private surface lease owners.

Extending production

The MAS seeks to ensure Alberta’s mature oil and gas fields remain producing for as long as economically viable because it is ultimately beneficial for all stakeholders.  

“The continued operation of all producing assets supports the economy through taxes, royalties, wages, local support businesses, and maintenance contractors,” the report says. 

Economic adjustments to existing government programs could potentially extend the productive life of mature assets and sustain these benefits. 

The MAS cites several opportunities including changes to the Enhanced Hydrocarbon Recovery Program for deploying CO2-enhanced oil recovery projects, examining waterflood techniques in shale reservoirs, and pursuing elemental carbon recovery instead of carbon capture, utilization and storage (CCUS) from existing gas plants. 

New methods for conventional oil and bitumen extraction could also increase recovery and extend the life of mature assets, it says. 

New opportunities

High transportation costs and limited market access have long kept Alberta’s oil and gas prices low.

The MAS aims to reverse this by finding ways to bring the markets closer to the source.

Natural gas, in particular, is seen as a significant opportunity.

“Repurposing central and southeast Alberta’s legacy natural gas base could materially improve the outlook for tens of thousands of assets and multiple stakeholders,” the report says. 

“Given the current surplus of natural gas in North America, the most compelling opportunity is to add value…by utilizing more of it within Alberta, particularly by converting it into electricity.” 

This can sustain and stimulate local economies, reduce waste, finance future closure activities, and provide a reliable energy source for Alberta’s grid, it says.

Opportunities for stranded or undervalued natural gas include AI data centres, local power generation to support renewables, LNG for regional use, bitcoin mining, small-scale manufacturing, agricultural operations and Indigenous enterprises. 

Existing oil and gas assets can also be repurposed for new uses including subsurface heat for geothermal power, lithium extraction from brine water, and using surface locations for solar power generation instead of undergoing full reclamation.

Accelerating closure

While many mature assets in Alberta offer opportunities for value creation through life extension, others are nearing or at the point where closure and reclamation are the most appropriate steps.

The MAS says there is a clear need to make closure operations more efficient through better planning and collaboration. 

For example, it notes that by 2024 nearly 95,000 well sites had been decommissioned but their surface locations remain unreclaimed, mainly due to cost uncertainties and often delayed timelines between completing remediation and receiving a final reclamation certificate.

“Improved coordination with expert vendors and multi-level field operations cooperation could significantly reduce unit costs without compromising compliance,” the MAS says.

It highlights the opportunity to use spring breakup (the winter melting period between late March and late May, when traditional drilling operations are paused) to focus on closure work. 

This would serve the dual benefit of keeping workers employed while making closure activities happen faster.

Because time is money, the key to cost-effective closure operations is retaining skilled and experienced field service personnel, the report says.

The MAS also envisions enabling so-called “ClosureCo” and “HarvestCo” business models. 

For a fixed sum, a ClosureCo would assume responsibility for well closure and future liabilities from the current asset licensee, while a HarvestCo would use revenue from mature assets to fund its own closure activities.

“Special purpose, multi-discipline closure service entities in the U.S. provide a business model that could be replicated in Canada,” the report says.  

Innovative financial solutions

The MAS engagement process has underscored the need to develop flexible financial instruments that manage closure costs, it says. 

The report highlights proposals including legacy asset insurance funds and asset-attached closure financial products. 

“A new post-reclamation future environmental liability insurance fund – financed by contributions from licensees but managed by the province – could provide dedicated capital for managing liabilities tied to closed assets,” the MAS says. 

“This fund would offer certainty for surface rights owners and show licensees a path to remove closure obligations from balance sheets, which could provide another justification for accelerated closure activity.”

Meanwhile, asset-attached closure funding mechanisms on wells drilled in the future are envisioned as value tied to the individual wells or infrastructure, not the licensee. 

Dedicating a small portion of future cash flow from production to closure funds would ensure costs are planned for and covered throughout an asset’s lifecycle, the report says.

This would improve the balance sheets of licensees and enable smoother asset transfers to a greater number of potential buyers that would take on the well and its attached closure fund. 

A focus on collaboration

The MAS stresses that renewed commitment to collaborative efforts among all stakeholders is essential to address the scale of closure liabilities effectively. 

It highlights examples of successful collaboration including the AER’s Area-Based Closure (ABC) program.

This approach involves grouping well sites by location to concentrate closure efforts, allowing companies to utilize workers and equipment more efficiently to reduce costs.

From 2019 to 2023, the ABC program saved an estimated $1.7 billion through regulatory improvements and coordinated closure activities, the MAS says. 

“By leveraging innovation, collaboration, and tailored financial mechanisms, Alberta can reduce the burden of closure liabilities, enhance environmental stewardship, enhance economic growth, attract capital, and foster a resilient and competitive energy sector,” the MAS says. 

“These measures will not only address the challenges of today but also position Alberta as a leader in sustainable resource management for the future.”

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As construction gets underway on Cedar LNG, the world’s first Indigenous majority-owned LNG export terminal, a report from RBC highlights the project as a model of successful energy development in Canada.

“We broke a pattern that had existed for over a century,” said Karen Ogen, CEO of the First Nations Natural Gas Alliance.

“First Nations have been at the heart of the LNG opportunity, not on the sidelines or just on the job sites but in the boardrooms helping to make it happen.”

RBC said the Cedar LNG project in Kitimat, B.C. – a partnership between the Haisla Nation (50.1 per cent) and Pembina Pipeline Corporation (49.9 per cent) – is a model for Indigenous economic reconciliation in action.

“Canada’s future growth and prosperity depends heavily on getting Indigenous economic reconciliation right,” said report co-author Varun Srivatsan, RBC’s director of policy and strategic engagement.

“If not, the country’s ability to diversify our resource exports, enjoy independence and resiliency in strategic sectors, and improve productivity, which has lagged that of other countries for years, are all at risk.”

RBC outlined the enormous potential of Indigenous-led energy projects to drive economic growth.

Almost three-quarters of the 504 major resource and energy projects planned or underway in Canada run through or are within 20 kilometres of Indigenous territories.

The value of Indigenous equity opportunity from these projects is estimated at $98 billion over the next 10 years, with oil and gas projects dominating the list at $57.6 billion.

“It’s clear that First Nations are critical to LNG in Canada. It’s First Nations territory from where the gas is extracted in Treaty 8 territory, it’s First Nations territory across which gas is transported via pipeline, it’s First Nations territory where LNG terminals are located, and it’s First Nations waters through which carriers take LNG to market. This is why we say Canadian LNG is Indigenous LNG. And we are going to make history,” Ogen said.

Cedar LNG reached a final investment decision last June, following a permitting process that saw the Haisla Nation directly involved in planning the facilities and operations.

This includes a floating LNG terminal with emissions among the world’s lowest, at 0.08 per cent CO2 equivalent per tonne of LNG compared to the global average of 0.35 per cent. Operations are slated to start in late 2028.

“Our community felt it was important that our values of being Haisla, being Indigenous, were felt through every decision that was being made. That is what makes this project unique,” said Crystal Smith, the Haisla Nation’s elected chief councillor.

Central to the Haisla’s involvement in Cedar LNG are the jobs and ongoing revenues that benefit the nation and neighbouring communities.

This has included support for education and cultural programs and building a state-of-the-art health facility and a new housing development.

“Cedar LNG shows what is achievable when you have a shared vision,” Smith said.

“It is going to mean that my kids and grandkids have a different future from what I or anybody in my generation have experienced in our community. It is going to revive our culture, revive our language, and make us stronger going forward.”

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As the utilities and hydroprocessing technical lead for Imperial Oil’s Strathcona Refinery near Edmonton, 32-year-old Marjorie Mallare and her team help ensure operations run smoothly and safely at one of Canada’s largest industrial facilities.

The exciting part, she says, is that all four engineers she leads are female.

It’s part of the reason Mallare was named one of ten Young Women in Energy award winners for 2025.

“I hope they realize how important the work that they do is, inspiring and empowering women, connecting women and recognizing women in our industry,” she says.

“That can be very pivotal for young women, or really any young professional that is starting off their career.”

Born and raised in the Philippines, Mallare and her family moved to Edmonton near the end of junior high school.

Living in the industrial heartland of Alberta, it was hard not to see the opportunity present in the oil and gas industry.

When she started post-secondary studies at the University of Alberta in the early 2010s, the industry was booming.

“The amount of opportunities, at least when I started university, which was around 2011, was one of the high periods in our industry at the time. So, it was definitely very attractive,” Mallare says.

When choosing a discipline, engineering stood out.

“At the time, chemical engineering had the most number of females, so that was a contributing factor,” she says.

“Just looking at what’s available within the province, within the city, chemical engineering just seemed to offer a lot more opportunities, a lot more companies that I could potentially work for.”

Through work co-ops in oil and gas, her interest in a career in the industry continued to grow.

“It just kind of naturally happened. That drew my interest more and more, and it made it easier to find future opportunities,” Mallare says.

Following a work practicum with Imperial Oil and graduation, she started working with the company full time.

On the side, Mallare has also driven STEM outreach programs, encouraging young women to pursue careers in engineering.

In addition to supporting the Strathcona Refinery’s operations department, Mallare and her team work on sustainability-focused projects and reducing the refinery’s carbon footprint.

The 200,000 barrel per day facility represents about 30 per cent of Western Canada’s refining capacity.

“Eventually, our group will also be responsible for running the new renewable diesel unit that we’re planning to commission later this year,” says Mallare.

Once completed, the $720 million project will be the largest renewable diesel facility in Canada, producing more than one billion litres of biofuel annually.

Projects like these are why Mallare believes Canada will continue to be a global energy leader.

“We’re leading others already with regards to pursuing more sustainable alternatives and reducing our carbon footprints overall. That’s not something we should lose sight of.”

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