Summary

• With demand for electricity rising fast, BC Hydro says it needs natural gas power plants to keep operating to ensure the province has enough power.
• Island Generation, a natural gas plant in Campbell River, B.C., was supposed to be decommissioned but BC Hydro is now seeking to renew its contract as the province needs the power. 
• Energy Minister Adrian Dix said Island Generation is facing supply issues due to the Squamish-based Woodfibre LNG project. As the project is not yet operational, Dix’s comments have confused and surprised some politicians and experts.

When a heat wave hits Vancouver Island, residents turn up their air conditioning, flick on fans or adjust their heat pumps. Demand for electricity spikes. That’s also true during cold snaps and long, dark winter nights when more electricity is needed to keep homes lit and warm.

It’s on those days of extreme electricity demand that a Campbell River power plant fuelled by natural gas is most likely to fire up. Island Generation, owned by Capital Power, is one of a handful of facilities in B.C. that use natural gas to produce electricity. It’s what is known as a peaker plant, mostly called on to generate power at times of peak demand.

With a capacity of 275 megawatts, Island Generation can create enough electricity to power about 125,000 homes. It accounts for about one-quarter of all the electricity that can be produced on Vancouver Island. Only about 40 per cent of the electricity used on the island is generated locally. The rest comes from the mainland, transmitted via cables laid across the bed of the Salish Sea.

Over the past five years, Island Generation has operated an average of 15 days per year, according to Adrian Dix, B.C.’s minister of energy and climate solutions.

But, the facility has been having trouble getting the gas it needs to generate electricity at critical times, Dix told members of the B.C. Conservative caucus on April 23. He said the supposed natural gas supply issue is connected to liquefied natural gas (LNG) production. 

“The reason why the supply of gas is affected is that gas is going to a project called Woodfibre LNG in Squamish. That has been the issue between ourselves and Capital Power,” he said. 

Dix’s statement surprised and puzzled the politicians and experts The Narwhal spoke to. Woodfibre LNG is still under construction until at least next year. Until then, there’s no obvious reason the Squamish facility would be using gas that would otherwise go to Island Generation. 

But questions to the Energy Ministry, Island Generation and Woodfibre LNG mostly went unanswered. None provided information needed to clarify the situation with Island Generation’s gas supply.

“Woodfibre LNG will be purchasing gas in the future once the facility is operational,” a spokesperson for the facility said in response to multiple emails and questions, an answer that does not directly address whether the facility is currently buying natural gas, as the minister implied.

The Energy Ministry did not respond to The Narwhal’s request for an interview with Dix or to specific questions about the ministry’s knowledge about Island Generation’s gas supply or its efforts to ensure the facility will be able to get the gas it needs to operate.

Green Party MLA Jeremy Valeriote, who represents the Vancouver-Sea to Sky riding where Woodfibre LNG is located, told The Narwhal he has not been able to clarify Dix’s comments.

“I’m just flagging for the public that it’s been hard for either of us to get any public information on this,” Valeriote said.

‘Where would that extra energy come from?’

BC Hydro’s contract with Capital Power was set to end in October 2026, but it recently applied to the BC Utilities Commission for a new agreement. The application mentions both Island Generation and the McMahon Cogeneration facility in Taylor, B.C., near the heart of the province’s oil and gas industry. The two gas-fired plants could help BC Hydro meet about 80 per cent of a 500-megawatt electricity shortfall it forecasts will materialize by 2030.

Demand for electricity has been rising rapidly in B.C., driven partly by large industrial customers such as LNG terminals and mining operations. BC Hydro has been under pressure to find efficiencies in its system and bring on new generating capacity with an emphasis on renewable sources such as wind and solar.

Meanwhile, the provincial government has been working to usher in an LNG boom, which could put pressure on the electrical grid and increase competition for natural gas.

Valeriote noted BC Hydro is supposed to be phasing out fossil fuel electricity generation, not seeking new contracts with gas-fired plants.

“It’s pretty concerning when we talk about firing up what should have been a decommissioned gas plant on the island that may not even have gas … in those critical, peak times,” he said.

BC Hydro’s submission to the utilities commission argues the Clean Energy Act, which requires it to generate and purchase enough energy to meet demand, trumps the regulations regarding phasing out fossil fuels. 

B.C. Conservative MLA Larry Neufeld wants to know what would happen if Island Generation were unable to operate during a demand peak.

“Where would that extra energy come from?” Neufeld, who serves as his party’s critic for oil, gas and LNG, said. 

“Would that be siphoned off of the Lower Mainland? Would it be imported? Those are excellent questions that the minister would be responsible to answer.”

B.C.’s LNG push and electricity demand

By 2030, there could be three LNG facilities operating in B.C. and a huge increase in demand for natural gas. In May, the Canadian government celebrated an agreement that could see one of them, Ksi Lisims LNG, sell one million tonnes of liquefied natural gas (LNG) per year to Germany, starting sometime in the 2030s.

Another is LNG Canada, located on B.C.’s coast, the first large-scale LNG export facility in the country. 

It is already using up a huge amount of gas to operate: last year, LNG Canada received more than 3.6 billion cubic metres of natural gas. Nearly 10 per cent of what it burned off was because of an issue with one of the flare stacks, as The Narwhal previously reported.

And, it might eventually use much more. Earlier this month, B.C. Premier David Eby, federal Natural Resources Minister Tim Hodgson and LNG Canada CEO Chris Cooper held a press conference about a potential second phase of the project.

The newsiness of this announcement — trumpeting another small step toward a final commitment to proceed — was so thin one reporter asked why a press conference had been called at all. But Phase 2 could make a big difference to the province’s energy supply, as LNG Canada’s demand for natural gas could double as its production capacity rises to 28 million tonnes of LNG per year.

Woodfibre LNG will have a much smaller production capacity. It is expected to produce 2.1 million tonnes of LNG per year and will need about 7.7 million cubic metres of natural gas to do so. That gas will be supplied via a new pipeline branch off the Eagle Mountain pipeline, which currently supplies Vancouver Island, including the Island Generation station.

FortisBC is in the process of building that new section of Eagle Mountain as well as upgrading the section of the pipeline that leads into Squamish. A spokesperson for the company said in a statement that Fortis “regularly assesses system capacity and plans for growth and changing regional needs.”

“FortisBC can meet the needs of existing customers on Vancouver Island and we are continuing to deliver natural gas service in line with our contractual agreements,” the spokesperson said.

The Narwhal also asked Capital Power for an interview to discuss the minister’s comments. In response, a company spokesperson sent a two-sentence statement.

“Capital Power and BC Hydro are engaged in discussions around the future of the Island Generation facility in Campbell River,” the statement said. “Our focus is always to ensure we support the reliable, safe delivery of the power needs of British Columbians.”

A follow-up email with the same questions The Narwhal sent to the Energy Ministry went unanswered.

Conservative MLA Neufeld said British Columbians should not have to worry about a shortage of natural gas, even with a large increase in demand.

“Having spent over 30 years in the industry in northeast British Columbia, I will state that it is my opinion that that is a non-issue,” Neufeld told The Narwhal.

“There is far more than enough natural gas in the ground … we don’t have to be concerned about a supply crunch. Whether that is taken advantage of properly by government and by regulation is another question for the minister.”

But as British Columbians brace for a summer of heat waves and rising electricity demands, the province’s ability to keep power flowing becomes an increasingly important question.

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Summary

• B.C. is preparing to overhaul its natural gas royalty system, which determines how much revenue the government earns from the industry, by 2027.
• The government is promising a better return for taxpayers while industry warns higher rates could drive investment to Alberta.
• The debate comes as some advocates argue B.C. should collect more from gas companies who are using public lands for profit.

As B.C. readies to change what it charges fossil fuel companies extracting natural gas from public lands, industry supporters are pushing back.

B.C. has been eyeing changes to its natural gas royalty structure since 2021 when an independent assessment found the existing system needed a complete overhaul. The old system was “contributing to or possibly overcompensating” for the costs of developing oil and gas in B.C., the assessment concluded, which hugely reduced royalties returned to the public.

Details on how the new framework will increase royalties have yet to be released.

According to BC Conservative Labour critic Kiel Giddens, it risks “chasing away investment potential.” He raised the issue in the legislature on the final day of the spring sitting, saying if B.C.’s new royalties are too high, gas producers could move their operations to Alberta.

“There is a real risk that we could actually lose revenue if we’re not competitive,” Giddens told reporters.

Green Party MLA Jeremy Valeriote had a different take. 

“If Alberta wants to sell off their public resources for a song, then we should let them,” he told reporters at the legislature. “We should be standing up for competitiveness in terms of getting the most out of our resources.”

Energy and Climate Solutions Minister Adrian Dix is confident the new royalty system will strike a better balance for both the industry and British Columbians.

“To ensure a fair return … but also a situation where the industry can prosper and invest — those are my two goals in the process,” Dix said.

The new royalty system is emerging alongside B.C.’s burgeoning liquefied natural gas (LNG) industry. LNG Canada, the first production facility to begin operating in B.C., began shipping its product to Asian markets last year — although the facility has experienced equipment issues that have reduced its production capacity. The B.C. and Canadian governments are eagerly anticipating a final investment decision on Phase 2 of the facility, which will double its capacity to 14 million tonnes of LNG per year.

Meanwhile, three other B.C.-based LNG projects are moving toward being operational before 2030. Together, these LNG production facilities will create a significant boom in gas demand, one the industry is keen to capitalize on.

On April 9, Dix sent a letter to industry stakeholders, as originally reported by DOB Energy. The letter, obtained by The Narwhal after Dix’s ministry refused to provide a copy, acknowledged the feedback included several key themes, such as “the need for reliable B.C. gas supply to underpin existing and future LNG projects.”

Dix also emphasized the government’s commitment to “the growth of LNG as a cornerstone of B.C.’s economic strategy.” 

“A strong, investable upstream sector is essential to realizing this opportunity,” he wrote.

How much revenue does B.C. earn from royalties? Probably less than you think

The new royalty system is set to take effect on Jan. 1, 2027, following years of consultations with the industry and First Nations, as well as members of the public.

Royalties are supposed to give British Columbians a share of the profits that private companies earn by pumping oil and gas from public lands. B.C.’s previous royalty regime was criticized on that front because it offered companies a generous suite of credits that could reduce their royalty payments.

In 2022, B.C. announced the end of several of those credits, including the deep well credit, which former Premier John Horgan described as “the largest fossil-fuel subsidy in British Columbia.” 

At that point, the province had given away more than $7 billion in credits to oil and gas producers, with $3.75 billion of those still on the books. Companies are able to use those credits to reduce the royalties they would otherwise pay; money that would have gone into the provincial budget to fund other initiatives. (As of last month, companies had yet to claim about $600 million in credits, according to Dix.)The billions in credits contrast with the revenue B.C. actually collects from natural gas producers. Budget documents show B.C. has collected $5 billion in royalty revenue from gas producers since 2019, nearly half of that in 2022. This year, the province expects to collect $942 million in royalty revenue — less than it projects the BC Lottery Corporation will earn. Next year, royalty revenue is expected to hit $1.6 billion, driven by higher natural gas production.

“I think the dirty little secret of oil and gas is that they don’t contribute a ton in taxes,” Sven Biggs, Stand.earth’s Canadian oil and gas programs director, said. “There is not tons of economic activity actually connected to this [industry].”

The majority of B.C.’s oil and gas operations are concentrated in the northeast, where agricultural fields are criss-crossed by pipelines and studded with well pads. Oil and gas is a way of life for many Peace Region residents but it also comes with downsides. Fracking operations use huge amounts of water to extract gas from the ground, a process that can also leak gas and chemicals into the air and water. The Canadian Association of Physicians for the Environment has called for the B.C. and federal governments to fund a health impact assessment of the LNG sector to assess links between the industry’s activities and “asthma, heart disease, birth defects, childhood leukemia, neurodevelopmental and neurodegenerative diseases like autism and Alzheimer’s.”

Beyond royalties, Biggs argues B.C. should also be seeking to recoup the cost of the industry’s environmental and potential health impacts.

“All of those costs get passed on to us if they are not paying,” he said. “Technically this gas belongs to British Columbia — it’s a Crown resource and we are licensing it to these extraction companies.”

Complaints about competitiveness ‘a smokescreen,’ advocate says

The new system the province is proposing would take into account the money companies invest in their B.C. operations, as well as the money those operations make, called a revenue minus cost system. This approach is “globally recognized for maximizing economic values,” according to a B.C. government website.

Adopting a revenue minus cost system would bring B.C. into alignment with other gas-producing places, including Alberta, notes Werner Antweiler, an economics professor at the University of British Columbia’s Sauder School of Business.

When the province began reviewing the royalty regime, the plan was to capture “50 per cent of profits after production costs are accounted for” — a pretty standard split in other jurisdictions, according to Antweiler.

“When you calculate revenue minus cost, revenue is pretty simple [because] you can see what the market pays,” Antweiler said. “The cost, that’s a different thing. … Anything that’s increasing costs will reduce profits and will lower the royalty. So one of the key questions that I have is to what extent are we calculating costs the same way as other jurisdictions?”

Depending on how costs are calculated, companies may pay only 30 or 40 per cent of their profits to governments in royalties, Antweiler said.

As for BC Conservative Labour critic Giddens’ warning about companies moving to Alberta, Biggs said those warnings are “a smoke screen from the industry.” He noted gas companies have been investing in B.C. for years — a trend partly sparked when Alberta implemented a new royalty regime in 2016.

“I don’t see a way that they can walk away from those at this point,” he said. “It would be a huge write-down. Alberta could produce more gas — hypothetically, but not really enough to meet the kind of demand we’re talking about.”

However, Biggs worries that governments remain susceptible to threats that an entire industry will “pack up and leave town and blame the administration for the lack of investment.”

“It works very well on them every time,” he said.

Years ago, when B.C. was working to lure gas companies to set up shop in the province, offering competitive royalty rates was a key advantage, Antweiler said.

“As the industry has matured, there’s really no reason to continue treating them better than their peers in Alberta.”

‘No decision has been made yet’ on B.C.’s new natural gas royalty regime

Industry priorities have already prompted the government to back down on a couple of proposed royalty scenarios, as Dix’s April letter shows.

“The province will not be advancing the Transition-Plus or Enhanced Return royalty curve scenarios further,” Dix wrote in the letter. “We acknowledge the concerns raised about the magnitude of change associated with those scenarios and the uncertainty they could introduce at this stage. Any further scenarios will consider your feedback as we work to align with the objectives of the new royalty framework.”

The Energy Ministry did not respond to The Narwhal’s questions about the letter, including a request for a description of the Transition-Plus and Enhanced Return scenarios.

Antweiler noted the two scenarios are similar to interim royalty rates outlined in 2022 under which companies pay higher royalties when gas prices are high and lower rates kick in when prices drop. The revenue minus cost system is simpler, he said, and could still give B.C. a good rate of return, depending on how it is designed

“It makes sense to me to move away from just an update of the existing system and to something that’s really robust and economically cohesive,” he said. “That’s exactly what other jurisdictions — like Alberta — are doing.”

Antweiler hasn’t seen the specific rate scenarios the province has been discussing with industry stakeholders. Those are covered by non-disclosure agreements, as Giddens pointed out to reporters.

Dix said non-disclosure agreements, known as NDAs, are a standard part of government consultations with both First Nations and industry stakeholders.

“The energy companies provide information to us about the impact of different possible royalty regimes and differences that are obviously commercially sensitive, so that’s done under NDA,” Dix said. “We put forward different proposals and asked them to comment on different potential proposals, just to see what the impact is on different companies.”

“I think that’s really irresponsible,” the Green Party’s Valeriote said of the government’s apparent concession on the two royalty scenarios. “I think we should be extracting the most value for the B.C. public out of these public resources, and caving into lobbyists and others who want to make it easier to make big profits, it’s just not good public policy.”

“No decision has been made,” Dix said when asked about the letter in the legislature on May 28.

“A lot of work has gone into the process and now we’re in the consultation stage,” he added. “This included extensive consultation with Treaty 8 First Nations and with energy companies.”

The minister told reporters he hopes to have a final decision on the new natural gas royalties later in June.

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Construction on the North Coast transmission line is not expected to start until later this year, but last week BC Hydro took “a key step toward securing a major customer” for its electricity: Ksi Lisims LNG.BC Hydro and Ksi Lisims LNG have signed a memorandum of understanding that “provides clarity on how and when BC Hydro will deliver as much as 600 megawatts of clean electricity to the proposed floating LNG facility,” according to the government’s press release. Energy Minister Adrian Dix hailed the agreement as a key step toward Ksi Lisims’ final investment decision, which is expected later this year.The details of the agreement will not be made public, a BC Hydro spokesperson told The Narwhal in an email, because it contains confidential information about Ksi Lisims.

The Ksi Lisims LNG project is expected to consume as much electricity as 250,000 B.C. homes use in a year. How BC Hydro plans to supply that power — and what it means for the broader grid — has not been disclosed. But a key piece is building the multibillion-dollar transmission line. In December, Dix signed a cabinet order outlining many of the terms BC Hydro and North Coast transmission line customers will operate under, including that the costs for the project be recouped via hydro rates.The most recent cost estimate for the first two phases of the North Coast transmission line is $6 billion, double BC Hydro’s initial $3-billion estimate. The third phase of the project, which will run high-voltage transmission lines north from Terrace, B.C., to Bob Quinn Lake near the Alaska border, has not yet been costed. B.C. is currently negotiating with the Canadian government to secure federal funding for the project.

The B.C. government estimates the projects served by the new transmission line could yield $950 million per year in revenue for the provincial and local governments and boost B.C.’s gross domestic product by “nearly $10 billion per year.” Ksi Lisims is “expected to attract nearly $30 billion in investment,” according to the province.

But in order to lock in those economic benefits, BC Hydro has to provide “cost certainty” to those potential new customers. If that means reducing the amount of money private companies would otherwise be expected to pay, BC Hydro will have to find other ways of recovering those costs.

“Rate payers are going to pay in the end because [these projects] are going to need so much electricity that supply is not going to be able to meet demand and prices are going to have to go up,” explained Andy Hira, a political science professor and director of the Clean Energy Research Group at Simon Fraser University. 

New contracts could let big projects off the hook for connection costs

The North Coast transmission line will primarily serve industrial customers, including mining projects and the Port of Prince Rupert. The B.C. government has not been shy about promoting the project as a boon for private companies it hopes will invest in the province.“This is the reliability companies can count on, every hour of every day,” Premier David Eby told a crowd at the Natural Resources Forum in Prince George, B.C., on Jan. 20. “Certainty that power will be there when companies need it. Certainty that it will be available at a predictable cost. That certainty is what turns proposals into final investment decisions.”

But here’s why that cost certainty could mean higher hydro costs for British Columbians. A cabinet order Dix signed in December could spare large North Coast power users from paying millions to hook into the power grid.

The order includes new contracts specifically for North Coast transmission line customers. One of those contracts deletes a handful of words from a decades-old contract called tariff supplement 6, which requires new industrial customers seeking more than 150 megawatts to pay the costs of generating and transmitting the power beyond that threshold.

“This was an important protection for other customers and was put in place in the 1990s after a negotiation overseen by the BC Utilities Commission,” Richard Mason, a former BC Utilities Commission member, told The Narwhal. “New large loads using the North Coast transmission line will almost certainly require BC Hydro to add new generation, raising the average cost for everyone.”The tweak in the new contracts seems to let large projects, like Ksi Lisims, seeking to connect to the North Coast transmission line off the hook for extra generation and transmission costs they would otherwise be required to pay.“In other words, new customers with large loads won’t have to contribute to any extra transmission or generation cost,” Mason said. “These costs will now be socialized across all BC Hydro’s customers.”

The Energy Ministry did not directly address detailed questions from The Narwhal about the changes. An emailed, unattributed statement from the ministry confirmed “those costs do not apply to new large projects in specific industrial sectors connecting to the BC Hydro system in the North Coast region” under a new contract created by Dix’s order.

The implications of that change are concerning to Hira.

“The fact that they’re doing this behind closed doors, without any public discussion — that they’re passing on potentially huge costs to taxpayers and not providing any justification — is really alarming,” he said. 

The Narwhal asked both the Energy Ministry and BC Hydro how any additional generation or transmission costs would be recouped and whether the government has estimated how much those costs could be for North Coast transmission line customers. 

In its statement, the energy ministry confirmed those costs “will be recovered from all BC Hydro ratepayers, including those industrial customers.”

The statement did not include any mention of a cost estimate but did note that large industrial customers connected to the North Coast transmission line will pay BC Hydro for the electricity they use, as all BC Hydro customers do. North Coast transmission line customers will also have to pay a security deposit to BC Hydro and cover the cost of power lines to their connection point.

The B.C. government has considered making changes to tariff supplement 6 since at least 2024. A briefing note prepared for Eby in March 2024 outlined the potential for an unprecedented increase in industrial electricity demand, driven mainly by large industrial customers. Requiring LNG, mining and other companies to pay the costs required under tariff supplement 6 “could be prohibitive,” the document stated.

But companies that expect to reap huge profits from B.C.’s natural resources are well positioned to pay their own costs, Hira argued.“The government can’t state that companies that are prepared to invest millions in an LNG pipeline and port facilities can’t afford to pay an electricity connection fee — it simply doesn’t make sense,” he said.

Costs for connecting North Coast transmission line customers could be significant

In addition to Ksi Lisims, the North Coast transmission line could serve “half a dozen private mining projects worth $50 billion in investment,” according to Mining and Critical Minerals Minister Jagrup Brar. 

Under the new contracts in Dix’s December order, none will be required to pay the extra generation and transmission costs required under tariff supplement 6. The Energy Ministry did not respond when asked how much the change could save eligible projects.

However, another LNG project on the north coast provides a hint. Cedar LNG, near Kitimat, B.C., was subject to tariff supplement 6, seemingly for the first time in the transmission contract’s 30-year history. 

To get Cedar LNG connected to the power grid, the provincial government opted to contribute $200 million to help build a new 287-kilovolt transmission line and other electrical infrastructure in July 2025. The floating liquefaction and export terminal could produce three million tonnes of LNG per year for export to Asian markets, using 214 megawatts of electricity.Neither the province nor Cedar LNG replied to questions about how much the company may have contributed toward the transmission infrastructure.If all of the anticipated North Coast transmission line projects come with similar transmission costs, the cost to BC Hydro could be substantial, even before considering the cost of any new electricity-generating capacity that might be needed to meet the new power demand.If electricity prices in B.C. do increase significantly, Hira pointed out B.C. could miss out on attracting other industries to invest in the province. Instead, he said, the province seems to be doubling down on natural resource extraction.

“You’re mortgaging the possibility of diversifying the province’s economy.”

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The Government of Ontario began accepting applications for commercial-scale geologic carbon storage projects on Feb. 2, 2026.

Ontario’s associate minister of energy-intensive industries, Sam Oosterhoff, is impressed by Suncor Energy. The oil and gas company is producing about 100,000 barrels of oil products per day at its Sarnia, Ont., refinery, Oosterhoff told his colleagues at the legislature after visiting the plant in what’s known as Chemical Valley.

They aren’t “cowboys” who don’t care about climate change, he said on Nov. 4, adding that while they produce all that oil they still “care deeply about reducing emissions.” And Oosterhoff, along with the Government of Ontario, believes they should do it through a process known as carbon capture and storage — with the storage location being Ontario’s bedrock.

That’s why, Oosterhoff said, Ontario should pass new legislation that would enable this process across the province, for high-emitting industries like cement and steel, non-renewable power generation and for oil and gas refiners, like Suncor. 

The proposed Geologic Carbon Storage Act, folded into Bill 27, the Resource Management and Safety Act, was debated after second reading the day Oosterhoff spoke. It could move to third reading shortly.

Carbon capture and storage involves containing the carbon dioxide released when fossil fuels are burned and injecting it deep underground to prevent it from entering the atmosphere and increasing global warming. Advocates say doing so could limit some of the most severe effects of climate change, like hotter and more widespread wildfires, floods and drought, as the province and country have experienced in the past few years. But critics argue carbon storage allows for the continued burning of fossil fuels, rather than transitioning away from them.  

Oosterhoff said in debate that the need for storage is crucial because the oil and gas industry plays a key role in the life of everyday Canadians, an argument also familiar in the House of Commons — despite oil and gas being non-renewable resources. “A solar panel is not going to provide the case covering that I have on this phone,” Oosterhoff told his colleagues, though non-plastic — as well as recycled plastic — phone cases are on the market. Some people even go without phone cases, a consumer category that is only about two decades old.

While carbon storage can lower emissions from industrial processes, like Suncor’s oil refinery in Sarnia, the greenhouse gases released into the atmosphere when that refined oil is burned by customers down the line, continues to warm the climate. Some academics and activists also point out carbon storage is extremely expensive and edges out investment in solutions that could limit the production of carbon dioxide in the first place.

When it comes to Ontario’s readiness for carbon storage, there are other pressing concerns — like an unknown number of gas wells that some critics argue could heighten the risk of leaks of poisonous hydrogen sulfide and planet-warming methane. But as The Narwhal reported in September, Ontario can’t afford to properly plug these wells, located mostly in southwestern Ontario — the same region where carbon storage is proposed.

“There’s a real concern about what’s going to happen to those abandoned oil and gas wells once this new industry starts up,” Ontario NDP MPP Peggy Sattler said, in response to Oosterhoff.

Dave Sawyer, an environmental economist with the Canadian Climate Institute, a climate policy research organization, said carbon storage has been framed as a “silver bullet” to dealing with the ballooning emissions from the oil and gas sector.

“There’s a broader innovation agenda there that could have been driven,” he said. “And the silver bullet notion takes all the oxygen out of the room.”

So what would Bill 27’s passage, and the start of carbon storage in Ontario actually look like? Read on.

What is carbon capture and storage and how does it work?

Bill 27 introduces a framework for commercial-scale geologic carbon storage, as it’s never been done before in Ontario.

In order to divert and store the carbon dioxide generated by industrial processes such as oil and gas refining, the British Geological Survey explains, it is converted to a liquid-like form and injected into the pores of sedimentary rock. This is called geologic carbon storage. 

Those rocks are contained using naturally occurring storage caps and human-made ones to stop carbon dioxide from escaping. A “caprock” is a thick, impenetrable type of rock, such as shale, that sits above more porous rock, like a lid on Tupperware. Human-engineered barriers are made up of steel and other corrosion-proof materials to keep the carbon dioxide secured underground. 

Materials published by the Government of Ontario in May 2025 explain that carbon dioxide has most commonly been stored in formations like saline aquifers or depleted oil and gas reservoirs. “Previous research has suggested the most suitable storage formations in Ontario may be found beneath the beds of Lake Huron and Lake Erie and surrounding onshore areas,” the government notes.

Ontario’s Ministry of Natural Resources did not respond to questions about its carbon storage plans by publication time. Its published information sheet continues that, after carbon is injected, wells are plugged and the site is then monitored to “mitigate any potential safety risks to the public or the environment.”

The Intergovernmental Panel on Climate Change, which provides scientific assessments on climate change for policymakers, says that if the carbon dioxide is stored properly on well-managed geologic storage sites, the CO2 could be trapped for millions of years.

Geologic storage is currently the most popular form of carbon storage, though other methods are being researched, said Bo Zhang, an assistant professor of civil and environmental engineering at the University of Alberta.

Zhang said he believes carbon capture and storage is really the best way for Canada to reach net-zero goals by 2050 — given how reliant the country currently is on fossil fuels.

Maurice Dusseault, a professor emeritus of engineering geology at the University of Waterloo, said through thinking about these processes, it’s important to remember the goal in the first place: to stop carbon dioxide from entering the Earth’s atmosphere and contributing to extreme weather events, disaster and death.

And Dusseault said that while renewable energy use has increased globally, that hasn’t meant a reduction in fossil fuels. In fact, the Intergovernmental Panel on Climate Change reports that globally the amount of carbon dioxide produced per unit of energy only decreased by 0.3 per cent from 2010 to 2019. 

But moving away from fossil fuels has been challenging — as Canada’s entire infrastructure has been built with fossil fuels in mind, Dusseault said. 

In Ontario, the increased use of natural gas for power generation in recent years has seen the province’s grid go from 94 per cent emissions-free, down to 87 per cent.

Is carbon capture safe in Ontario?

Bruce Hart, an adjunct professor in earth sciences at Western University, said he’s optimistic about Ontario’s carbon storage plans, given the types of rock available in the southwestern part of the province.

Hart said rocks from the Cambrian Age are nestled about a kilometre underground along the north shore of Lake Erie. This is likely the best place for carbon storage, he said, due to the depth and the 500-metre layer of “very impermeable rock” overlying the Cambrian rock zone, offering containment.

This is critical because carbon dioxide is an asphyxiant and, the British Geological Survey explains, leaks at such a concentration “could cause suffocation,” as well as negating climate change mitigation. 

Going back to the issue of old oil and gas wells in Ontario, the instability of those reservoirs has already been displayed. On Aug. 26, 2021, hydrogen sulfide gas leaking from a crudely buried gas well ignited, causing an explosion in the town of Wheatley, Ont. 

Twenty people were injured and about 60 households and 30 businesses were evacuated.

Across the province, research has suggested the number of old wells is likely in the tens of thousands, with many dug prior to regulations around properly plugging them and many in unknown locations.

Ontario has mentioned in its public documents that saline aquifers and depleted oil and gas reservoirs have been used to store carbon dioxide in other jurisdictions. 

But Hart said the only aged wells that would be used are ones dug deep enough into the Cambrian layer. Many of the more shallow derelict wells that were abandoned are only hundreds of metres deep at most, far above that. Ontario describes its plans for carbon storage as taking place 800 metres or more below the surface — one and a half times the height of the CN Tower.

In terms of these wells increasing the risk of leaks, he said modern drilling methods are highly sophisticated, and the integrity of any kind of borehole is “monitored nearly continuously.” 

“There is a vanishingly small possibility there could somehow be leakage from the borehole, but even if that were to occur, the [measuring, monitoring verification] program would instantaneously detect that leak and the operation would be shut down,” he said. 

Carson Fong, a program manager specializing in carbon dioxide removal at the Pembina Institute, a Calgary-based climate think tank, said if the new regulations ensure that sufficient engineering studies are completed to guarantee the carbon dioxide is secure, storage in Ontario can be done safely.

But he adds there isn’t enough information in Bill 27 to determine if project-specific studies will be sufficient. 

“The legislation notes it’ll be up to the minister to determine that … so we might need to wait for more detailed regulations to really evaluate this,” he said. 

Another concern brought forward to the Ministry of Natural Resources and Forestry regards consent and consultation with landowners and communities, specifically First Nations. “Indigenous communities are seeking meaningful engagement and consultation throughout the development of the framework and individual projects,” reads the province’s summary of comments from summer 2024 on the discussion paper for regulating geologic carbon storage.

The Chippewas of Kettle and Stony Point First Nation noted in comments that Traditional Knowledge must be incorporated into any environmental risk assessments on carbon storage. 

The Ontario Federation of Agriculture also outlined concerns in comments it submitted to the province on Oct. 2, requesting impact assessments on agricultural lands to ensure carbon capture would not have negative effects. It recommended the government look at whether reducing carbon-intensive industries is a better option — considering the cost of establishing, operating and policing geologic carbon storage. 

Is carbon capture and storage already happening in Canada?

According to the federal government, as of 2023 there were five carbon dioxide capture, transport, storage and utilization projects operating in Canada. As of 2025, those projects capture about four megatonnes of carbon dioxide a year and are limited to Alberta and Saskatchewan.

In Alberta they are the Alberta Carbon Trunk Line, the Glacier Gas Plant and Quest Carbon Capture and Storage. In Saskatchewan, the operational projects are the Weyburn Midale CO2 storage facility and the Boundary Dam. 

According to the International Energy Agency, a Paris-based intergovernmental organization, another 63 projects are being planned, and seven are under construction. By 2030, the International Energy Agency projects Canada’s capacity to be about 31.3 megatonnes per year of carbon storage — a significant increase, but still only around five per cent of the nearly 600 megatonnes of carbon dioxide equivalent Canada is projected to emit annually by then.

Carbon capture and storage has played a starring role in Prime Minister Mark Carney’s vision for Canada’s climate change policies. 

Carney has touted the practice as a critical investment need for Canada in order to reduce emissions in the oil and gas sector — while maintaining continued resource extraction. He has described an opportunity for the country to establish itself internationally as a leader in carbon storage. 

That fervor became more apparent in the federal government’s climate plan, unveiled as part of the Carney government’s first budget on Nov. 4, the same day Oosterhoff spoke to his colleagues in provincial parliament. The plan indicates that Canada’s proposed cap on emissions from the oil and gas sector, which isn’t yet in place, could be thrown out by the Carney government in favour of further investments in carbon capture and storage technology. 

The federal government is also considering fast-tracking a $16-billion carbon capture and storage project proposed by the Pathways Alliance, an organization of major oilsands producers. 

So, should we be going all-in on carbon storage?

Some environmental economists, like Sawyer, warn that carbon storage and capture “seizes the mind” because when applied to modelling, it seems like an ideal solution. But he warns that the dream of carbon capture and storage could actually be a mirage, distracting from innovative thinking around climate change that reduces dependency on fossil fuels. 

Aly Hyder Ali, a program manager at climate advocacy group Environmental Defence, is vehement in the organization’s rejection of carbon capture and storage. He characterizes it as a tactic that allows emitters to expand fossil fuel production, not a meaningful solution to climate change.

“This technology is an extremely costly disruption that ultimately only lets oil companies continue to increase their production,” he said. All it “captures” are subsidies for the oil and gas industry, he said. 

Zhang disagrees: “I wouldn’t say it’s a band-aid solution,” he said. “Because there is no complete replacement for fossil fuels right now.”

In Ontario, the provincial government sees carbon storage as a means to “support the transition to a low-carbon economy.”

Ultimately, in the battle against climate change, Sawyer sees the increased push around carbon capture and storage as playing only the goalie on a hockey team — the last resort — instead of all the other possible players.

Updated on Feb. 2, 2026, at 11:14 a.m. ET: This story was updated to note when the province started accepting applications for geologic carbon storage.

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In a world grappling with a building climate crisis, electrification has become a buzzword. Securing a reliable supply of clean — or at least relatively low-emission — and plentiful power to displace fossil fuels is regularly proffered by policymakers as the way forward.

But electrifying large swaths of society — from heavy industry to transportation — isn’t as simple as putting a plug in a socket. New power generation projects, such as wind and solar farms, need to be connected to the grid, which must have the capacity to carry and ferry that power. Transmission lines, substations and all kinds of electrical infrastructure must be built or upgraded to allow that to happen. None of it is cheap, especially when some of your biggest customers — such as mining operations or oil and gas facilities — could be located hundreds of kilometres away from the nearest power line.

So what happens when energy-hungry industries want to connect to the grid, but worry the cost of that access will hurt their bottom lines? B.C. may be about to find out.

Last week, the B.C. government approved the environmental assessment certificate for the Ksi Lisims liquefied natural gas (LNG) project. It will be built on an island near the mouth of the Nass River in northern B.C., close to the Alaska border. Once operational in 2028, Ksi Lisims could produce up to 12 million tonnes of LNG per year.

Natural gas — which is extracted in B.C. primarily through hydraulic fracturing, or fracking — is mostly methane, a powerful greenhouse gas responsible for around 30 per cent of the current rise in global temperatures, according to the International Energy Agency.Electrifying Ksi Lisims would allow the facility to “produce some of the cleanest, low-carbon LNG anywhere in the world,” according to B.C. Premier David Eby.

To go electric, Ksi Lisims estimates needing to draw about 600 megawatts from B.C.’s power grid, according to internal government documents obtained by The Narwhal in February. The project’s remote location means building the required electrification infrastructure won’t be quick, cheap or easy and the project’s environmental certificate notes Ksi Lisims will likely be powered by natural gas when it begins operations. 

Ksi Lisims is one of eight major industrial projects — including LNG facilities, mines and oil and gas operations — that have expressed interest in connecting to B.C.’s grid. Together, they could require more than 3,000 megawatts of electricity. For context, the Site C dam is capable of producing up to 1,230 megawatts of power.

Every one of the projects listed in the internal documents was seeking more than 150 megawatts, and this number is important. It’s the threshold that should trigger a BC Hydro rule created in the early 1990s known as tariff supplement 6. It requires new industrial customers seeking more than 150 megawatts to pay the costs of generating and transmitting the power beyond that threshold.

The 150-megawatt threshold is meant to protect other BC Hydro customers, including residential users and small businesses, from being hit with higher electricity prices as a result of investments in new infrastructure to serve large industrial customers. However, requiring LNG, mining and other companies to pay those costs “could be prohibitive,” the documents note.

Despite being on the books for more than 30 years, tariff supplement 6 had never been applied because “no projects above 150 megawatts have been built in B.C.,” according to a briefing note prepared for Eby in March 2024. 

But, with multiple large industrial projects exploring their options for connecting to BC Hydro’s grid, that will not be the case for long. 

B.C. government opted to pay for part of Cedar LNG’s connection costs

At 214 megawatts required, Cedar LNG was one of the first projects to trigger tariff supplement 6’s threshold. The facility, a floating liquefaction and export terminal in Kitimat, could produce three million tonnes of LNG per year for export to Asian markets. The company was spared additional generating costs for clean power because BC Hydro was forecasting a power surplus when Cedar LNG’s connection to the provincial grid was being assessed.

As for the transmission infrastructure needed to electrify Cedar LNG, the provincial government opted to contribute $200 million to help build a new 287-kilovolt transmission line, a new substation, new distribution lines and nearshore electrification for the project.

Access to BC Hydro’s electrical grid will allow Cedar LNG to produce “the lowest emission LNG in the world,” according to B.C. Energy Minister Adrian Dix.

“This is the best LNG in the world,” Dix said during the July announcement. “Our market position, our proximity to the Asian market, makes it the best LNG in the world and it’s the lowest emission LNG in the world.”

So how much did Cedar LNG pay for the infrastructure that will allow it to market its product as the cleanest in the world? The Energy Ministry referred The Narwhal’s questions about Cedar LNG’s contribution to the transmission infrastructure to the company, which did not respond by publication time.

The Narwhal also asked the Energy Ministry whether other major projects — such as Ksi Lisims — can also expect the province to pay for a portion of any transmission infrastructure required to go electric, but did not receive a response.

The government has been eyeing changes to tariff supplement 6 for more than a year in a bid to find ways “to balance industrial competitiveness with electrification in other sectors of the economy, all while keeping rates affordable,” according to the 2024 briefing note to the premier.

Earlier this year, the BC Utilities Commission, an independent regulator that oversees energy utilities, ordered BC Hydro to review the rule, noting its age and lack of nuance in assigning costs. The commission set a Sept. 30 deadline for the review to begin but has since granted BC Hydro an extension until April 30.

In pleading its case, BC Hydro told the commission it needed more time to develop alternatives to tariff supplement 6 — something the Energy Ministry was already mulling over in March 2024. BC Hydro also noted that some economic development policies the provincial government is considering “could impact the scope and objectives of any review.”

The details of what those policies are and how they could impact the review of tariff supplement 6 are considered confidential and have not been made public.

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The federal government celebrated B.C.’s newly approved Ksi Lisims liquefied natural gas (LNG) export facility this week, touting Canada’s environmental standards. But the project will be heavily reliant on natural gas in its initial stage, according to the approval released Monday. 

This will result in “significant adverse effects on greenhouse gas (GHG) emissions,” according to the B.C. government. It would also be at odds with the provincial government’s stated plans for new LNG facilities to be net zero by 2030.

Nevertheless, the project is lauded by the federal government as “responsible resource development” subject to “some of the most environmentally rigorous standards in the world,” according to a Sept. 15 statement posted to social media by Energy Minister Tim Hodgson.

Eventually, the idea is the massive liquefaction and export project, which will ship supercooled methane to countries in Asia starting around 2028, will be powered by hydroelectricity. But the project approval, which was granted on Sept. 15, permits the LNG plant to start operations before hydroelectric power is in place, noting: “no significant adverse effects are expected from Ksi Lisims LNG, with the exception of significant adverse effects on greenhouse gas (GHG) emissions from the use of natural gas-fired power barges used to electrify the project prior to connection to the BC Hydro electrical grid.”

Natural gas — which is extracted in B.C. primarily through hydraulic fracturing, or fracking — is mostly methane, a powerful greenhouse gas responsible for around 30 per cent of the current rise in global temperatures, according to the International Energy Agency. That spike in temperatures is causing increasing climate disasters worldwide, including uncontrollable wildfires, devastating floods and protracted droughts. These extreme events, in turn, are responsible for hundreds of thousands of deaths and trillions of dollars in damage to cities and infrastructure.  

The Ksi Lisims LNG plant — a project co-developed by the Nisg̱a’a Lisims Government — will be built in northern B.C. on an island near the mouth of the Nass River, known as Ḵ’alii Aksim Lisims to the Nisg̱a’a, close to the Alaska border. Access to the nearest village, Ging̱olx, is via a cracked and rutted winding road subject to extreme weather conditions. It is unclear how or when a hydro transmission line capable of carrying enough high-voltage electricity to meet the needs of the energy-intensive liquefaction operation will be built. Western LNG, one of the Nisg̱a’a government’s industry partners, referred The Narwhal to publicly available documents about proposed transmission lines, which would not be completed until 2032 at the earliest.

“Ksi Lisims LNG represents a transformational opportunity for all participating B.C. nations, and it will be developed in line with our nation’s high environmental standards,” Eva Clayton, Nisg̱a’a Lisims Government president, said in a statement emailed to The Narwhal.

While announcing the Ksi Lisims LNG approval, B.C. Premier David Eby said the project will help “diversify our economy and reduce reliance on the U.S.” Both Eby and Hodgson celebrated the involvement of the Nisg̱a’a nation in the export project and associated Prince Rupert Gas Transmission pipeline. The Nisg̱a’a Lisims Government has a stake in both projects, but documents filed with the B.C. government show the primary owner and operator of Ksi Lisims is Texas-based Western LNG. Employees of Western LNG, which has offices in Houston and Vancouver, met with senior provincial government officials 69 times since the beginning of 2024, according to B.C. lobbying records. Both Ksi Lisims and the Prince Rupert Gas Transmission pipeline are backed by Blackstone Inc., a U.S. investment company.

“When the premier says that LNG projects make us all better off, he’s either not being honest or he’s delusional,” Shannon McPhail, a director with Skeena Watershed Conservation Coalition, said in an emailed statement to The Narwhal. “This LNG expansion will benefit American corporations but it is going to cost everyday people through higher domestic energy costs, healthcare costs, local infrastructure costs and loss of revenue for the economies and businesses in this region that are dependent on an intact ecosystem.” 

Natural gas allowed in ‘circumstances beyond the control of the proponent’: new rules

Earlier this year, B.C. sent its first shipments of LNG overseas from the LNG Canada liquefaction and export facility in Kitimat. Powered by burning some of the gas it receives from the Coastal GasLink pipeline, LNG Canada’s first phase can produce up to 14 million tonnes of the liquefied gas annually. Ksi Lisims LNG will be able to ship 12 million tonnes.

In March 2023, immediately after approving a smaller gas liquefaction and export project, Cedar LNG, B.C. Premier David Eby announced new regulations for the province’s oil and gas sector, including requiring new LNG facilities to make a “credible plan” to reach net-zero emissions by 2030. Practically, the new rule means any future LNG projects would have to be powered by electricity, rather than running on natural gas as LNG Canada primarily does.

Ksi Lisims proposed “using renewable hydropower from the B.C. grid” to power its operations — about 600 megawatts (MW), according to internal government documents obtained by The Narwhal in February. If electrified, the second phase of the LNG Canada project (which would see it double its output of LNG to around 28 million tonnes per year) would need an additional 585 megawatts, the documents show. Together, the two LNG facilities could soak up enough electricity to power more than 500,000 average homes, based on calculations from the B.C. government.

But delivering that much power to the remote Ksi Lisims LNG project site will not be a quick or easy endeavour. Earlier this year, the B.C. government announced plans to fast-track the North Coast transmission line, a 450-kilometre high-voltage line to serve industrial customers in northwest B.C., including mining and LNG projects. 

But the North Coast transmission line may not be complete by 2030. That would leave Ksi Lisims in a difficult situation, out of compliance with provincial regulations. Dix issued “a clarification” of the 2023 net-zero policy in March, advising the environmental assessment agency that new LNG facilities need to be ready to become net zero by 2030 but can use natural gas if clean electricity is not available “due to circumstances beyond the control of the proponent.”

‘Another LNG project means more pollution’ either way: climate advocate

Even if B.C. is able to provide Ksi Lisims LNG with hydroelectric power for the energy-intensive liquefaction process, that doesn’t mean the project will not contribute to global climate change and domestic emissions. Upstream emissions, produced during the extraction process and in transport via the PRGT pipeline, as well as regasification and combustion emissions are all part of the bigger picture of LNG exported from B.C. 

“Approving another LNG project means more pollution, higher climate risks and greater harm to our health,” Thomas Green, senior climate policy advisor with the David Suzuki Foundation, said in a statement. “We don’t need more fossil fuel infrastructure when clean energy and electric technologies can power our lives, cut costs and create better jobs here in B.C.”

The approval of Ksi Lisims follows a June decision by the B.C. government to secure the Prince Rupert Gas Transmission pipeline’s approval indefinitely. The 800-kilometre pipeline project has faced opposition since it was first proposed in 2014 and Indigenous and non-Indigenous community members along the route and on the coast have been organizing resistance as construction gets underway.

As The Narwhal previously reported, the Ksi Lisims LNG project did not receive consent from all of the First Nations it consulted. Gitanyow Hereditary Chiefs and the Haida Nation expressly told the province they did not consent. Sleydo’ Molly Wickham, a Wet’suwet’en land defender who fought for years against another natural gas pipeline, Coastal GasLink, which feeds gas to LNG Canada, said the new approval sets the stage for conflict.

“Forcing projects through unceded Indigenous lands without free, prior and informed consent has proven to cost industry and government billions of extra dollars,” she said in an emailed statement. “Due to the blatant disregard for traditional governance systems, private industry, like Coastal Gaslink and the PRGT pipeline, have and will be forced to use militarized police and private security forces to complete their projects.”

— With files from Shannon Waters

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The B.C. government has just approved the Ksi Lisims liquefied natural gas (LNG) export facility, which will produce up to 12 million tonnes of LNG annually by 2028. 

Ksi Lisims LNG — pronounced s’lisims, meaning “from the Nass River” in the Nisg̱a’a language — is a joint venture involving the Nisga’a Lisims Government, Canadian natural gas consortium Rockies LNG and Western LNG, a U.S.-based LNG project developer. 

Located at the north end of Pearse Island, close to the Alaska border, the facility will be the second largest LNG producer in B.C., nearly matching the 14-million-tonne production capacity of the first phase of the LNG Canada export terminal, which began shipping LNG to Asia this year. 

In their reasons for decision, posted publicly on Sept. 15, B.C. ministers of environment and energy, Tamara Davidson and Adrian Dix, said they were approving the new LNG project despite not receiving consent from nearly half of the First Nations who participated in the environmental assessment process.

“We recognize that LNG facilities, along with natural gas pipelines, electrical transmission lines … and other development in the area has deeply affected Indigenous communities and ways of life, and that Ksi Lisims LNG will contribute to the cumulative effects on ecosystems and communities in the region,” they wrote.

However, they concluded the Ksi Lisims project would “constitute economic reconciliation and an exercise of self-determination for Nisga’a Nation” and provide “direct and indirect economic opportunities for First Nations in the region and for British Columbia.”

LNG exported from Ksi Lisims will primarily be sent overseas to countries like Japan and South Korea, where the gas will be burned to produce heat and electricity.

In approving the project, the ministers noted Ksi Lisims will be bound to 23 conditions, including a greenhouse gas emissions plan in line with B.C.’s net-zero policy. However, they noted the project is expected to have “significant adverse effects on greenhouse gas (GHG) emissions from the use of natural gas-fired power barges used to electrify the project prior to connection to the BC Hydro electrical grid.” It is unclear how or when the project would be electrified.

Western LNG and the Nisga’a government also own Prince Rupert Gas Transmission (PRGT), an 800-kilometre natural gas pipeline that will cross more than 1,000 waterways on its route to supply Ksi Lisims LNG. The pipeline was greenlit by the province’s environmental assessment office in June, paving the way for construction to continue this summer, more than a decade after the project was first proposed. 

“Ksi Lisims LNG represents a transformational opportunity for all participating B.C. nations, and it will be developed in line with our nation’s high environmental standards,” Eva Clayton, president of the Nisga’a government said in a statement. “This is what reconciliation looks like: a modern Treaty Nation once on the sidelines of our economy, now leading a project that will help write the next chapter of a stronger, more resilient Canada.”

Some First Nations consulted on Ksi Lisims LNG did not give consent

For the Nisg̱a’a, Ksi Lisims is a development opportunity that will benefit Nisga’a communities, the province and the Canadian economy, but other First Nations oppose the project. 

The Lax Kw’alaams band, for example, says the LNG facility would negatively affect its traditional territory and has expressed concerns about the project’s potential impact on B.C.’s ability to meet its climate targets. Lax Kw’alaams is southwest of the newly approved LNG facility and tankers filled with the liquefied gas will pass by the village regularly.

The environmental assessment office announced earlier this month that it had concluded dispute resolution processes initiated by Lax Kw’alaams and the Metlakatla First Nation as part of Ksi Lisims’ environmental assessment — despite failing to address the First Nations’ concerns about the project’s potential impacts on their communities.

The project also faced a legal challenge filed by the Gitanyow Hereditary Chiefs in October 2024. The chiefs submitted an application for judicial review to the B.C. Supreme Court, alleging B.C.’s environmental assessment office failed in its duty to consult and is negligent in its obligations to protect fish species when it concluded the project does not pose a threat to Nass River salmon populations.

“This project threatens our food security and government has denied Gitanyow a role in decision making,” Simogyet (Hereditary Chief) Malii Glen Williams said in a statement at the time.

The challenge was rejected by the court in early September. 

Naxginkw Tara Marsden, Wilp Sustainability director with the Gitanyow Hereditary Chiefs, said the approval puts B.C. on a dangerous path. 

“It’s hard to believe that we’re moving ahead in B.C. with climate-destroying LNG projects in the midst of a climate crisis,” Naxginkw said in a statement provided to The Narwhal. “Greenlighting LNG projects is part of a trend in the wrong direction.”

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Energy giant Enbridge’s emissions-conscious entity, Sustain, has stopped offering clean energy options to commercial developers, leading several industry sources to question the company’s commitment to helping its customers move away from fossil fuels.

In 2022, the Calgary-based energy company, primarily known in Ontario for the delivery of natural gas through its subsidiary Enbridge Gas, created a separate entity called Enbridge Sustain. It was established to offer “dependable and convenient energy solutions to help homeowners, developers and commercial customers in Ontario reduce their greenhouse gas emissions and energy costs,” according to a company press release at the time. These products included geothermal heating systems, solar panels, hybrid heating and electric vehicle chargers for high-rise condominiums and large commercial construction projects.

Those offerings have been scrubbed from the Sustain website, which now focuses solely on providing heating and cooling solutions to residential homeowners. 

Sean Mason, the founder of the energy-efficient building company SEAN, told The Narwhal that Sustain has said it will honour its existing contracts, including for a project his company is working on in Barrie, Ont., a 73-unit townhome and condo community with geothermal heating and cooling systems. But going forward, SEAN will have to look for other low-emissions suppliers.

It “was a good partnership with sean.ca and I’m sad it’s gone [to be honest],” Mason said in an email. 

Along with Mason, The Narwhal spoke to eight other sources across industries and organizations, including one other that, like Mason, works directly with Sustain. All of them shared their names and connection to the energy industry with The Narwhal but requested public confidentiality, citing fear of professional retribution. The confidential sources told The Narwhal some developers who have contracts with Sustain have not had their queries to the company answered for several weeks. 

They also said that since October 2024, nearly two dozen employees responsible for bringing clean energy solutions to developers have been laid off or reassigned to the parent company. The changes have significantly reduced the Sustain team from approximately 40 employees to under 20, sources said. Some of those let go had been with the parent company for decades or were seasoned experts in clean energy solutions, according to sources as well as public profiles. 

In an emailed statement, Kendra Black, spokesperson for Enbridge Gas, confirmed that Sustain will honour existing contracts but did not confirm any layoffs. She called the changes “a recalibration to ensure our efforts are directed where they can have the greatest impact.” 

“Enbridge Sustain remains a platform in Enbridge’s decarbonization efforts and Ontario’s energy future,” Black wrote. “We have made a strategic decision to streamline operations and focus on areas with stronger, more immediate demand. While we are pausing some commercial offerings, this is not an exit from low-carbon initiatives.” 

Black did not answer questions about how many employees Sustain has today, why the restructuring was needed or how this restructuring will change Sustain’s impact on emissions and clean energy adoption. She also didn’t specify where Enbridge, and Sustain, sees “stronger, more immediate demand.” 

The onset of the climate emergency — and the need to move away from fossil fuels — has posed an existential threat to Enbridge. Public urgency around finding lower-emissions solutions has grown, while improved battery technology and the decreasing costs of energy from wind and sun threaten to replace methane-heavy natural gas and other fossil fuels that create greenhouse gas emissions and exacerbate global heating. In recent years, Enbridge has argued in public hearings at the Ontario Energy Board, in letters to politicians and in public advertisements that its business remains vital because it is facilitating the energy transition by offering cleaner sources of energy, including hydrogen fuel.

Enbridge Sustain was an innovative venture into the energy transition, which several sources said had the potential for a huge impact on the way construction is done in Ontario — where buildings account for 24 per cent of the province’s greenhouse gas emissions. In a December 2022 interview, a senior Sustain executive told industry publication Sustainable Biz Canada Enbridge considers itself “an energy company, rather than just a gas utility that delivers one form of energy to customers,” that is “trying to figure out what role … can we play with customers to navigate and figure out energy transition?”

Ontario construction slowdown a likely cause of changes to Enbridge Sustain, sources say

Public information about Sustain is sparse because, unlike its parent company, it was created as an unregulated business that is strictly separate from natural gas operations. That means it doesn’t have to publicly report its financial health. The company has received $200 million in federal financing through the Canada Infrastructure Bank for retrofits across colleges, universities, multi-residential buildings and hospitals. Enbridge Gas is also the main provider of home energy retrofit funding in Ontario, supported by both the provincial and federal governments; both Enbridge Gas and Sustain offer home energy retrofits.

Sustain does not appear in Enbridge’s annual shareholder circular or financial outlook over the last three years. The company did tout Sustain in two corporate sustainability reports, which are published publicly every year. In 2022, it included a short line on a timeline detailing the company’s “emissions leadership.” The one released this May includes what appear to be early signs of change in the commercial offerings by Sustain: while solar, hybrid heating and electric vehicle charging are mentioned, references to geothermal have disappeared. 

Sources told The Narwhal the changes started last October. They say geothermal and hybrid heating were the first to be cut from commercial sales, followed by electric vehicle chargers. Sources suggested several possible reasons for these decisions. Market conditions have changed drastically since Sustain was set up three years ago, with construction across Ontario significantly slowing down, which sources said limited developer interest in clean energy investments. Plus, the federal industrial carbon price further complicated things, simultaneously creating incentives for adopting clean technology while also increasing the cost of construction for large developers in the short-term.

Collectively, sources said that both Enbridge and the construction industry have withstood economic changes before, and they believe a strong commitment would make the commercial arm of Sustain viable, though perhaps on a longer timeline than Enbridge had planned.

“They had opportunity to rule that market given their relationship with developers [but the] market turned against them,” Mason’s email said. 

The decision to wind down Sustain for new builds comes after a battle last year with the Ontario Energy Board, which Enbridge won. Last year, the board ordered Enbridge to stop charging homeowners for new natural gas hookups — its choices were to foot the bill itself or charge developers. At the time, the board noted that natural gas and its infrastructure would likely cost residents more in the long run than clean energy solutions like heat pumps, which Sustain offers. The Ontario government overruled the board in that case, meaning Enbridge is still able to pass down its new infrastructure costs.

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By early September, B.C. politicians will decide the fate of the province’s next big LNG venture. 

According to an announcement quietly posted on a provincial government website last week, the Ksi Lisims LNG environmental assessment was completed on Aug. 7 and referred to B.C.’s ministers of environment and energy for a final decision. The ministers — Tamara Davidson and Adrian Dix, respectively — were given 30 days to decide whether or not to approve the major fossil fuel development.

Ksi Lisims LNG is a proposed floating liquefied natural gas (LNG) export facility, which would be built on the B.C.-Alaska border about 100 kilometres north of Prince Rupert. Backed by the Nisg̱a’a government and Texas-based Western LNG, it would be supplied by the contested Prince Rupert Gas Transmission pipeline, an 800-kilometre project that will cross more than 1,000 waterways and dozens of First Nations’ territories.

B.C.’s natural gas export industry kicked off this summer when LNG Canada started operations in Kitimat. That facility, supplied by the controversial Coastal GasLink pipeline, is the first major liquefaction and export project built in Canada. If built, Ksi Lisims LNG would be capable of producing 12 million tonnes of LNG annually, nearly as much as LNG Canada will produce initially.

The announcement noted the federal government will also review the assessment and “a package of materials to support the federal decision” that have been sent to the impact agency, which reviews major projects for compliance with Canada’s Impact Assessment Act. 

On the same day it referred the Ksi Lisims LNG project for a decision, the environmental assessment office declined requests from Metlakatla and Lax Kw’alaams First Nations for dispute resolution processes. Both nations had previously entered into dispute resolution with the province but neither were able to reach agreement. (Another First Nation, Gitga’at, had also entered into the process but withdrew before completing.)

In near-identical letters sent to each nation on Aug. 7, Julie Chace, a senior official with the environmental assessment office, noted the office would not facilitate additional dispute resolution.

“I do not consider it necessary or reasonable for the [Environmental Assessment Office] and Metlakatla to participate in another facilitated [dispute resolution] process,” she wrote in one of the two letters. “Dispute resolution is a tool to help resolve substantial disagreements as a next step to reach consensus if parties are unable to reach consensus on their own.”

Chace added she took under consideration a request from Ksi Lisims LNG that the office refer the project for decision “without further delay.” 

That request, which was submitted in a letter dated July 29, was written by the Texas company’s president and CEO, Davis Thames. In it, he urged the office to reject the requests and wrote “there is no prospect of achieving consensus in a further facilitated dispute resolution over matters that have already been addressed.” Thames added the nations “will have an opportunity to raise their outstanding concerns in a meeting with the ministers during the 30-day decision-making phase.”

Chace’s letters echoed the wording used by the industry executive. 

“Metlakatla’s outstanding concerns and lack of consent regarding the project and sustainability recommendation may be presented directly to the ministers at this meeting, following referral and prior to their decision,” she wrote.

Neither Metlakatla nor Lax Kw’alaams were able to provide comment prior to publication. The B.C. government did not comment prior to publication.

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Flames as high as a 30-storey building, ships nearly as long as the Eiffel Tower is tall, $40 billion dollars. Everything about LNG Canada is big — including its promises. 

Often referred to as the largest private investment in Canadian history, the megaproject connects B.C. shale gas reserves near the Alberta border to marine shipping routes on the northwest coast. More than a decade after the project was first approved, Canada’s liquefied natural gas (LNG) sector is finally up and running: LNG Canada sent its first shipment to Asia on June 30.

As exports start flowing overseas from the Kitimat, B.C., facility, two more liquefaction plants are under construction — Woodfibre LNG and Cedar LNG. Another, Ksi Lisims LNG, could be approved any day. The promise around all this industrial buildout has always been prosperity, but whether the industry can deliver, and for how long, is up for debate.

“An oversupply of LNG is widely expected, potentially starting as early as next year, with a massive wave of new projects coming online around the world, especially in the U.S. and Qatar,” Steven Haig, a policy advisor with the International Institute for Sustainable Development, told The Narwhal. “When it comes to the economic benefits of LNG, Canada is really late to the party — and that party is almost over.”

Haig and his colleagues recently penned a deep dive into the risks of locking in more LNG infrastructure, reporting that Canadian exports are unlikely to achieve “energy security for importers or economic resilience for exporters.”

“What we explain in our analysis is that we are very likely moving into a period of oversupply with lower prices — and those lower prices may well be below what projects need to break even,” Haig told The Narwhal. “If they run at a loss for too long, then they can become stranded assets, with economic implications for the people who work for these facilities or for communities that might become economically associated with them.”

‘Higher domestic prices for Canadian consumers’ are a possibility

As Canadian LNG — the liquid form of natural gas, which is mostly composed of methane and in B.C. is extracted primarily through fracking — starts making its way into international markets, British Columbians and Albertans could also see a spike in their heating bills, according to Deloitte Canada. As the Financial Post recently reported, domestic natural gas prices could jump up by 60 per cent this year, and climb even higher next year. 

Haig said if the price a company can get from exporting LNG is higher than it can get selling natural gas domestically, prices in places like B.C. and Alberta will go up. This happened in Australia, where domestic prices tripled as Russia’s 2022 invasion of Ukraine sent shockwaves through the supply chain.

“LNG links regional gas markets together in the global LNG market,” Haig explained. “So a local supply disruption in one place can lead to skyrocketing LNG prices elsewhere.” 

“When those high prices are in effect, then it can become more profitable for a gas producer in Canada, for example, to export that gas to the international LNG market than to use that gas in Canada’s domestic gas market.” That, he said, can lead to higher domestic prices for Canadian consumers.

LNG Canada is now operating its first phase, which will produce up to 14 million tonnes of supercooled gas per year. It’s already approved and permitted to double production.

Teresa Waddington, LNG Canada’s vice-president of corporate relations, told The Narwhal earlier this month that talks are underway about whether or not to go ahead with the expansion. She said a final decision depends on a number of factors including “overall competitiveness [and] affordability.” LNG Canada did not respond to new questions from The Narwhal by publication time.

When the international consortium of oil and gas companies behind LNG Canada (Shell, Petronas, Korea Gas, PetroChina and Mitsubishi) first started courting Canada to develop an LNG export industry in B.C. in the early 2010s, they said it would boost the economy locally, provincially and federally. With recent trade threats from the U.S. government, that narrative is gaining traction again and politicians like B.C. Premier David Eby and Prime Minister Mark Carney are celebrating the sector as an economic saviour. 

Haig cautioned the narrative should be taken with a grain of salt.

“We’re seeing this big push towards LNG expansion to diversify Canada’s exports beyond the United States, but these are multi-billion dollar and multi-decade projects,” he explained. “Their long-term viability is a serious concern as global markets shift towards cleaner and more reliable energy sources, like renewables. Investing in LNG as a supposed transition fuel in the meantime would be a long, costly detour.”

‘It’s not too late’: Canada can reduce economic and climate risks by putting the brakes on LNG exports, expert says

Alongside promises of prosperity, LNG Canada and other proponents of the sector maintain the gas is a so-called “bridge” or transition fuel — a climate solution. The argument goes like this: burning gas to generate power is less harmful than burning coal, and B.C. exports will help countries like China substantially reduce their reliance on the “dirtier” fossil fuel. The first part is the subject of much debate, especially when the entire lifecycle of LNG is taken into consideration. The second — that Canadian LNG will displace coal — Haig said simply isn’t true. 

“Coal is cheap, renewables are cheap and LNG is not,” he said. “If we look at China’s power sector, for example, it’s renewables — not LNG imports — that are eating into coal’s market share. This is mostly because renewables are cheaper than LNG and because LNG requires expensive new infrastructure, such as re-gasification plants and pipelines, to connect consumers with supply.” 

China, while still responsible for about one third of the world’s greenhouse gas emissions, is outpacing the rest of the world by leaps and bounds in building renewables. In May this year, the country added the equivalent of 100 solar panels per second. As the Guardian reported in June, “China’s installed solar photovoltaic capacity has now surpassed 1,000 gigawatts for the first time, equivalent to half of the world’s total installed solar capacity.” 

Haig said Canada is at a crossroads as it decides whether or not to approve more LNG projects, but added, “it’s not too late.” 

“LNG exports can delay investments in renewables and generally increase global fossil fuel use, increasing global greenhouse gas emissions,” he said. “Doubling down on LNG projects would likely expose Canadians to more risk and volatility, not less.”

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In early October 2023, a senior bureaucrat in the Ontario Energy Ministry emailed an Enbridge official with a “sort of urgent” request. 

Newly released internal documents show that Premier Doug Ford had called the natural gas giant that month to discuss delays in obtaining a natural gas connection for a facility whose name is redacted in the documents. The issue was so important, Ford made the call on a weekend. The following day, per the emails, the premier was set to meet with the president and CEO of Enbridge and the executive vice-president of Enbridge Gas in Etobicoke, Ont., where Ford resides. 

“I really need to know what this is and what the status is and what the next steps are,” the government official said in their email to Enbridge Gas. 

The communication is just the latest example of the close relationship between Ford’s government and Enbridge, at a time when the government is setting out its long-term energy plans. Those plans include expanding natural gas infrastructure and codifying Ontario’s dependency on the fossil fuel, which is largely made up of methane, a greenhouse gas that causes global heating.

It’s part of a 3,532-page document package containing hundreds of government briefings and emails from 2021 to 2023. They reveal provincial officials acted as liaisons between Enbridge and the public, with one bureaucrat in contact with the company on a daily basis. They also show elected officials, including Ford himself, in talks with the company’s top leadership.

The documents were obtained via freedom of information legislation and shared with The Narwhal by an energy expert. Enbridge Gas, the Ministry of Energy and the premier’s office did not respond to The Narwhal’s requests for comment.

“Natural gas is fundamental as an insurance policy to keep the lights on,” Energy Minister Stephen Lecce told reporters when he announced the province’s new long-term energy plan on June 12. Without natural gas, he said, Ontarians will experience “liability issues, blackouts and higher energy costs.”

Time and again, the Ford government has come out in support of projects proposed by Enbridge Gas, the $50-billion, Calgary-based private company with a near-monopoly on gas distribution in Ontario. Most notably, the government overturned a decision by an independent regulator that would have forced Enbridge to stop passing down the costs of new gas hookups to Ontarians — all to protect the company’s bottom line, according to internal documents The Narwhal reported on last year. 

Enbridge and natural gas already run deep in Ontario. The fossil fuel is the primary source of heating for three-quarters of homes in the province. But the onset of the climate emergency — and the need to move away from heat-trapping greenhouse gases such as methane — is absent from the Ford government’s actions or long-term energy plans.

The grid is already dirtier as a result: in 2021, the electricity system was 94 per cent emissions-free, but has now dropped to about 84 per cent. The Ford government has promised a near-emissions free grid by 2050, but is veering in the opposite direction. 

Here’s what you need to know about the Ontario government’s long-term future — and past —  with natural gas. 

Internal documents illustrate close relationship between Ontario officials and Enbridge Gas

Internal documents in the newly released package show Enbridge Gas regularly emailing officials in the Energy Ministry to inform them of project proposals in different communities. This included battery projects and pipeline expansions, as well as any opposition to either. 

These emails show that in 2023, the Energy Ministry told someone wanting a connection that it would put them in touch with a staff member “who talks to Enbridge every day.” This was just one example of the ministry’s involvement in guiding the expansion of natural gas, from offering homeowners suggestions on how to get hookups, to relaying detailed constituent complaints about delays in Enbridge providing natural gas connections. The ministry also relayed residents’ questions about subsidies for switching to heat pumps, a government-funded program Enbridge administers. 

In several instances, senior government officials in the Energy Ministry, including the minister’s chief of staff, asked Enbridge staff to show support for proposed energy laws. “Continued support for this legislation is critical to success, it would be great to see Enbridge at committee as well, and a supportive letter to legislators would also be helpful!” a senior official wrote to company representatives in November 2023. In response, the company created one-page documents detailing why it felt that various laws would increase access to reliable power across the province. 

“As a responsible gas supplier, Enbridge Gas maintains transparent communication with all levels of government in the regions where we operate,” Enbridge Gas spokesperson Leanne McNaughton told The Narwhal in April 2024. “This helps us ensure that our residential, commercial and industrial customers continue to have access to a resilient energy source of their choice.” 

Enbridge staff also took the opportunity in these back-and-forths to offer advice to the government about the future of the province’s grid. In one such note, the company said, “Achieving the goals of a coordinated energy system in Ontario will be difficult, if not impossible, unless Enbridge Gas has an equivalent seat at the system planning table.” 

Ontario’s energy plan keeps natural gas in the mix until 2050 — 10 years longer than experts say is necessary

The long-term provincial energy plan released June 12 is a 152-page document titled “Energy for Generations.” It’s a compilation of promises already made to deal with the energy supply crisis ahead: a lot more nuclear (which will take years to get up and running), a lot more energy efficiency programs (to replace those the Progressive Conservative Party scrapped when it came to power) and a lot more natural gas — one of Ontario’s cheapest and last remaining fossil fuel-based sources of energy. 

One slightly new aspect of this plan is Ontario’s first official natural gas policy, which codifies what this government has been arguing for many years: that the methane-heavy fossil fuel is “vital” and “critical.” 

“There is no alternative,” Energy Minister Lecce said repeatedly as he unveiled the plan, especially in this time of rising demand for power. That demand is spurred by the electrification of transportation and buildings, as well as the push for more power-hungry data centres to facilitate artificial intelligence. The government is also attempting to integrate electricity and heating in its new “coordinated energy planning” approach, and proposes that both be increasingly generated by natural gas.

The province has been weighing its use of natural gas for several years. In a government-commissioned report The Narwhal reported on in December — which was withheld from the public until now — experts urged the province to phase out natural gas and drastically increase nuclear and wind energy to reduce emissions.

The Independent Electricity System Operator, the Crown agency in charge of balancing energy supply and demand, has projected that natural gas could be phased out by 2040 without causing much disruption. 

Ontario’s new long-term energy plan deviates from the operator. The government projects the fossil fuel will be used until at least 2050 and then sparingly, as various nuclear facilities in refurbishment come back online. About this two-decade-plus stretch, the plan says, “This will result in a short-term increase in electricity system emissions.” 

When asked about the discrepancy between experts’ climate caution and his government’s plan, Lecce said, in order to maintain reliability, the government will not phase out natural gas.  

Ontario directs independent energy board to enable ‘continued rational expansion of the natural gas system’

Part of the government’s new natural gas policy is a directive to the Ontario Energy Board that its decisions weigh “allowing gas utilities an opportunity to earn a fair return on investment, and enabling the continued rational expansion of the natural gas system.”

The Ontario Energy Board is the independent regulator for electricity and natural gas in the province, tasked with approving and denying plans set out by energy companies. Its job is to implement policy set by the provincial government and to keep industry accountable, ensuring decisions are financially responsible and in the public interest. 

The province’s new order comes just over a year after the Ford government made the unprecedented move to overturn the energy board ruling that would have forced Enbridge or developers to pay for natural gas hookups in new homes, instead of passing the cost on to homeowners. At the time, the board justified its ruling — which came after a year-long deliberation involving tens of thousands of pages of documents, public hearings and dozens of interviews across the energy industry — as being more economical for ratepayers and in line with transition to renewable energy. The board found that the energy transition will likely make natural gas “a stranded asset,” financially unviable or socially unacceptable as lower emissions energy sources, like electric heat pumps, increase and improve.

The internal emails recently shared with The Narwhal show that in the lead-up to that decision, officials with Enbridge Gas were communicating with bureaucrats about how various board proceedings were delaying the company’s ability to build pipelines and other natural gas infrastructure. 

Company officials shared briefings with the province that said certain environmental advocacy groups had delayed Enbridge’s board approvals. The briefings said over the course of 2023, the company had faced “several outstanding issues” with the board, “including weighing into policy decisions, regulatory approval delays and determining based on their views of climate change if ‘gas is good.’ ” 

In the documents, the company stated delays it attributed to the board had increased project costs and forced it to pause construction. 

“If the government would like to see these [natural gas expansion] projects proceed, they must work with the [Ontario Energy Board] to create the regulatory certainty needed,” company officials wrote repeatedly to officials in the Energy Ministry and to various MPPs. Enbridge representatives also asked the government how the company could earn back investments as they wait for board decisions. 

“These ongoing delays for residential, business and Indigenous communities waiting for access to reliable, affordable natural gas … are unacceptable.”

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