Read by reporter Drew Anderson

Assar Grinde is the kind of man whose calm is infectious, even as he rattles off an encyclopedic knowledge of facts about drought, water and the impacts of fracking on the region he calls home. A cattle rancher by trade who studied geology at the University of Alberta, you get the sense he’d rather be tending his herd than fighting with regulators and oil and gas companies.

But on a Sunday in early July after a morning on the ranch, he sits in the back of his friend Daniel Iseli-Otto’s truck, sporting a sweater knit by Iseli-Otto’s mom, and talks about the reasons he can’t just walk away.

It started three years ago when Lloyd Creek — a tributary of the Blindman River, which runs through the land Grinde’s family has ranched for generations — dried up. It was something he’d never seen before and he says the oil and gas companies were still pulling water from the river.

“We wanted to make sure that the river didn’t dry up because we thought that was crazy,” Grinde says.

He and Iseli-Otto helped found the Blindman River Watershed Society and dove into the labyrinth of data used by the Alberta Energy Regulator and the equally bewildering bureaucratic divisions of the provincial government.

It’s a funny time to be talking about the stress on the Blindman River watershed and the concerns he and Iseli-Otto have when it comes to the vast quantities of fresh water being used by oil and gas companies for hydraulic fracturing, or fracking.

The fields around Rimbey, Alta., about 200 kilometres north of Calgary, are saturated in surreal hues of green, stark against the grey skies of an abnormally wet July that has brought much-needed rain.

It’s a far cry from the drought-like conditions of May and June, conditions that have become all too common in a region suffering through a decade-long dry spell.

But the sudden rush of water isn’t enough to quell the concerns of area ranchers and residents who watched that creek run dry and their drinking wells drop. They say the rain isn’t enough to make up for how much has been lost from the aquifers — the deep underground natural reservoirs that feed those wells.

And then there’s the issue of oil and gas companies using billions of litres of water to crack open the earth beneath those green fields and exploit one of the hottest gas fields going, the Duvernay. They take surface water when there isn’t any to spare, and a fleeting moment of plenty might only make it worse, according to landowners who met with The Narwhal.

Grinde says promises were made by those companies, but rarely kept.

“ ‘We’re going to be taking the water at high flows when there’s too much of it, and we’ll store it and then use it when we need it.’ That was the industry’s sales pitch,” he says, driving through the region southwest of Edmonton along with Iseli-Otto. “But then we’ve been in a drought eight of the last 10 years, and they are still pulling water down.”

Dana Kreil, the chair of the nearby Medicine River Watershed Society, and a councillor for Lacombe County, says there’s no trust in the province to monitor the water and to intervene. Her society has bought its own monitoring equipment and is pressuring the government for solutions.

“You can’t fool the locals,” she says, making it clear she’s speaking for the watershed society and not the county. “There are people telling me the top of their runners wouldn’t get wet in that river. So you can’t tell me that those are acceptable levels for pumping from there.”

‘You only get conflict when there’s scarcity’

The Blindman River, as well as the Medicine, aren’t among the great waterways of the world. With enough momentum, it wouldn’t be hard to leap from one bank to the other. They are slow and meandering, but they are critical to ranchers and farmers.

They are also tenuous.

Neither river is fed by the mountain glaciers to the west. They rely instead on spring runoff and underground aquifers to keep water flowing. This year’s early-summer drenching is an indication of the feast and famine cycles expected to be the norm as the climate shifts — droughts with sudden onslaughts of rain. Grinde says his ranch received almost as much rain in June as it did the entire year previous.

For decades, fracking companies here have been injecting water deep into the ground to break up rock holding gaseous wealth in tight crevasses. That water, vast quantities of it, is almost entirely permanently lost to the water cycle as it remains trapped in the reservoirs that previously held gas. The practice was largely accepted by area landowners, but then water became scarce and drilling activity increased.

“We haven’t had to care about fresh water because we never had this issue before,” Grinde says. “You only get conflict when there’s scarcity, and you have that imbalance between supply and demand, and that’s really what’s happened in the last few years.”

Once Grinde and others started paying attention, they discovered a system of what they say is weak oversight, weak data and regulatory capitulation.

Water use is overseen by both Alberta’s Environment Ministry and the energy regulator — depending on who’s using the resource — and Grinde says it leads to a lot of plausible deniability. Water monitoring in the area is based on a federal government sensor 50 kilometres away in Blackfalds, Alta., but Grinde says it doesn’t actually measure the flow of the river, just the water pressure. Even if it did, Grinde thinks the minimum flows established by the province to determine when a company can pull river water for fracking are too low.

The Alberta Energy Regulator did not answer a question about the monitoring situation on Blindman River, but said monitoring is used to inform when a company can divert water. It noted that monitoring can be seen on the Alberta Rivers site.

The regulator says companies are responsible for measuring flow if there is no station nearby.

“So then that kind of led us down this path of trying to figure out: ‘Do you guys have rules around it?’ ” asked Grinde.

For some in the area, the answer is more uncertain than they’re comfortable with.

Company wants to pull billions of litres from critical freshwater aquifer

In March, Spartan Delta, a fracking company operating in the area, applied for a water licence to pump a maximum of 475 million litres of water per year — about 2.4 million bathtubs’ worth — from the Paskapoo Formation, a vast underground freshwater reservoir that stretches south past Calgary and north past the Athabasca River near Fox Creek.

That raised red flags for those in the region already worried about a strained system.

Grinde wants the government to prevent oil and gas companies from accessing shallow fresh groundwater for fracking, implementing a ban now so that it doesn’t have to draft new rules in the midst of a full-blown crisis.

“Right now [the companies] say, ‘Well, we don’t have any more surface water available to get licensed, we’re just going to start drilling shallow groundwater wells,’ which is really concerning because we don’t know enough about the groundwater, and it’s so vital to everybody who’s living here,” he says.

Tens of thousands of wells tap into the aquifer for drinking water, as do towns across Alberta. According to a report by the federal government, the Paskapoo “supports more groundwater wells than any other aquifer system in the Canadian Prairies,” making it “the most significant supply of groundwater” in the whole region.

That same federal report — published almost 20 years ago — also cautioned the aquifer is slow to recharge and the amount of water that can be pulled from the aquifer might be limited and may have already been exceeded in 2008.

Spartan Delta already pumps water from the Medicine River, with hoses stretching along ditches and culverts throughout the region pulling water into massive reservoirs. It also uses recycled water from its operations, but that only accounts for approximately 10 per cent of its use.

In 2024, the latest year of data from the Alberta Energy Regulator, Spartan Delta used approximately 171 million litres of fresh water for fracking. Its latest application shows the company estimates it will need much more than this, around 1.5 billion litres per year for the next 10 years.

The company did not answer emailed questions but sent a statement instead, saying it is focused on “responsible, sustainable development of oil and gas.”

Spartan Delta said it adheres to all rules and regulations set out by the regulator, Alberta’s Environment Ministry and local bylaws.

“All of our water use is determined by Alberta Environment,” reads a portion of its statement. “The company receives temporary diversion approvals, term licences and has undergone several audits to validate we are in compliance with all of the terms of the water approvals. All resident concerns are evaluated by the appropriate regulating body of our activities during the approval process.”

The regulator also did not directly answer questions emailed by The Narwhal, but did provide information on water use. An unidentified spokesperson said the regulator reviews all water licence applications and considers risks to individuals and the environment. The spokesperson added there are restrictions on water use if levels drop below prescribed thresholds and that restrictions can also be implemented in response to “landowner concerns.”

Analysis on aquifers is conducted by hydrogeology experts, the email said.

Though landowners are concerned about Spartan Delta’s water use, the company is a small player compared to others.

Parallax Energy Operations used almost one billion litres in 2024, while Canadian Natural Resources Ltd., one of the largest oil and gas companies in Canada, used 2.9 billion litres of fresh water for operations across the province. Overall, fracking consumed 20 billion litres of fresh water in 2024, up sharply from the seven billion litres consumed in 2013.

Grinde’s goal is to prove to the province and the regulator that the aquifer is dropping, realizing that officials could just turn around and say, well, it’s a drought.

“But even if it is a drought, the volume of water that the companies are using for fracking is accelerating that,” he says. “It could be that if there’s only a certain amount of water, you have to justify the use for certain things, right? So maybe you have to talk about hierarchy of use.”

Time and again, Grinde, Kreil and Iseli-Otto talk about the amount of work required to collect information, to get in touch with provincial officials, to make someone listen. Without decades of data, the response from officials and companies is: prove it.

“It’s the province’s job,” Kreil says. “It’s not the watershed society’s job. We’re volunteers.”

The provincial government did not respond to questions emailed by The Narwhal.

Alberta ranchers say their bison herd collapsed when a fracking company moved in

It’s easy to look out across the fields and patches of trees and imagine the landscape in central Alberta is largely unchanged, but Iseli-Otto, who works as a carpenter and has lived here his whole life, looks out his truck window and remembers bush where fields now stretch — a child’s wilderness transformed into cropland. It’s a reminder of how quickly things can change. How the immutable becomes a memory.

The change can be slow, or it can come on in a relative blink.

Tucked into a secluded corner of the countryside, is the home of Butch and Nicole Smith, two bison ranchers who have lived and worked in the area for decades, with the dream — shared by one of their daughters — of passing their ranch to the next generation.

Inside the home, a stuffed cougar looks down from its final perch above the kitchen, and the walls are covered in framed rodeo photos showing the victories of the family’s horses. Tail Light was the “team roping heading horse of the year.” Hickory, the “2011 pole bending horse of the year.” Their daughters have won an astonishing number of championship rodeo belts and saddles, all of which are on display.

A hint of the Smiths’ directness, and their frustration, comes in the form of a small sign by the kitchen table: “What (and I can’t stress this enough) the f*ck,” it reads.

Over bison burgers and sausages, the Smiths talk about how Spartan Delta cleared the land across from their feedlot and built two massive reservoirs two years ago to store the vast quantities of water the company pumps. They talk about how construction and pumping for the reservoirs, which bisect a wetland, led to startling changes in their bison herd.

“We started seeing the wildest behaviour from them,” Nicole says. “They’re very habitual animals.”

The herd was refusing to move to the areas they usually feed, and there was a sudden drop in their herd.

Nicole says they had 240 pregnant cows in the fall of 2024, but only 194 live births.

“We had many dead calves, aborted calves and calves that starved as stressed mothers produce not enough milk,” she says.

The Smiths blame the stress of the industrial activity and the disruption to stubborn routines.

The Smiths, however, aren’t the types to sit back and watch. They say they’ve spoken with their MLA, Jason Nixon, with the premier, with two environment ministers — Rebecca Schulz and RJ Sigurdson — and Energy Minister Brian Jean. They are working with Ecojustice, an environmental legal outfit, and were invited by the Alberta NDP to sit in the legislature last spring after speaking with MLA Nagwan Al-Guneid.

Now, after two years of fighting, they’re losing faith and plan to move.

“Neither one of us is a — how do I say it — a sitter arounder. I’m not gonna sit here and be miserable. I can’t even walk anymore because both ways just reminds you of all of it,” Nicole says.

“I’m raging when I hit the end of my driveway — every single time.”

‘There’s very little oversight right now’

Tensions are high in the region where fracking butts up against homes and ranches. In early July, a rumour spread that some of the hoses that pump water from ponds and rivers were shot at, but the Alberta RCMP said there were no reports of an incident on that day. Perhaps most telling was that none of the people who spoke with The Narwhal seemed surprised, although no one supported the idea and warned of the danger of puncturing the high-pressure lines.

There is a real sense that landowners have been abandoned in favour of oil and gas.

Kreil, whose society includes representatives from eight municipalities, including Red Deer, Lacombe County and Sylvan Lake, said the group recently met with the minister of Environment and Protected Areas and the CEO of the Alberta Energy Regulator to talk about the stress on the watershed. In its presentation, the society noted more than half of all fresh water in their watershed is allocated for oil and gas. Temporary water licences are almost entirely for fracking.

She says the minister told them to write a resolution calling for policy changes through the Rural Municipalities of Alberta — an organization which represents towns and districts across the province.

“I think he felt that he had dealt with us enough to say: ‘Write a resolution,’ ” she says.

Kreil stresses she’s not opposed to oil and gas, or to fracking in particular, but there has to be a balance.

“When we went to the minister, we said we want some solutions,” she says. “We’re not just coming here to bellyache and complain.”

Her organization wants to see more wastewater treated and reused, including municipal wastewater, to reduce or eliminate fresh water use. It wants better data on the state of the watersheds and a better understanding of drought and its impacts. And it wants new regulations governing use by agriculture, oil and gas and municipalities.

But those critical of the way fracking companies are operating all point their finger at the regulator when asked what the biggest problem is. The rules are weak and out of touch, responsibility is passed on and there’s no enforcement, they say.

“The problem with the Alberta Energy Regulator is there’s very little oversight right now,” Kreil says.

Iseli-Otto says he tried alerting a contact at the regulator about companies pumping from the Blindman River in May when the water levels were worryingly low, but nothing came of it.

Two days later, he was driving home and the pumps were running.

“So I texted him and I said, ‘Hey man, pumps are running, what’s going on? Why is this happening?,’ ” he says. In screenshots of the text messages shared with The Narwhal, Iseli-Otto then asks if someone from the regulator had checked to see if the pumps had stopped.

“That’s the point at which I got the automated text message saying this number is not monitored.”

Alberta pushes to double production, build pipelines

The regulator is an arms-length government body, but that doesn’t mean it’s entirely independent. The government sets the overall policy direction for the regulator to follow, for example, and the government appoints the regulator’s board of directors.

Recently, it appointed David Yager to the board, a long-time friend of Premier Danielle Smith who also acts as one of her special advisors, and tasked him with overseeing a revamp of the organization.

There have also been revelations of direct intervention from the provincial government into regulatory decisions.

And the direction from the government is clear: it wants to double oil and gas production and it’s willing to incentivize companies to do so, even as it helps finance a new pipeline to the West Coast.

With the push for more production and without more stringent rules on water use, the problems in the area are likely to continue, or increase.

“We’ve had companies tell us ‘We’re not doing anything differently until the government tells us to,’ because it’s a competitive industry,” Grinde says.

“We said to the minister, as long as this is free, they will never change,” Kreil adds.

But in the end, something has to give, she says.

“You can’t be running the people out of water for oil.”

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

One of British Columbia’s government agencies is poised to get a lot more power. 

Premier David Eby’s NDP government has just introduced legislation to give new responsibilities to the BC Energy Regulator (BCER), which oversees the province’s growing oil and gas sector and other energy projects. 

The changes will put the regulator — largely funded by the oil and gas industry — in charge of fast-tracking renewable energy projects like wind and solar, along with the $3-billion North Coast transmission line that will power liquefied natural gas (LNG), mining and other industrial projects.

Through a suite of agreements with various B.C. ministries, the regulator has long had special powers to make decisions related to ecosystem health, wildlife, cultural heritage sites, climate, Indigenous and non-Indigenous communities and more.

Regulator officials can issue tickets, fines and warnings, and order companies to stop working if they are breaking the law. The agency is also responsible for issuing permits for energy projects — everything from pumping water from a stream and laying a pipeline under a river to setting allowable levels of greenhouse gas emissions at natural gas wells.

In announcing the regulator’s new powers earlier this year, the B.C. government touted the agency’s transparency and its adeptness in working with First Nations and energy companies. A recent investigation by The Narwhal and Investigative Journalism Foundation found the regulator’s inspectors don’t always enforce laws and regulations designed to protect the environment and human health. 

So what exactly is the BC Energy Regulator? Read on.

What is the BC Energy Regulator, or BCER?

The regulator is a Crown corporation, like BC Hydro and BC Transit. It answers to the B.C. Ministry of Energy and Climate Solutions, headed by Adrian Dix. 

When the regulator was formed in the 1990s, it was called the BC Oil and Gas Commission.

“The original purpose of the BC Energy Regulator was very much to facilitate the development of the oil and gas industry in the province,” Deborah Curran, executive director of the Environmental Law Centre at the University of Victoria, previously told The Narwhal.

At the time, the B.C. government was courting fossil fuel companies to set up shop in the province, and it established dedicated ministries — such as the Ministry of Natural Gas Development — to help the sector get up and running. To support oil and gas development, the regulator was given special powers that superseded decisions normally made by other ministries. 

What kind of decisions can the regulator make?

The regulator has broad decision-making powers. For example, the regulator can make decisions and issue permits to clear an archaeological site or cut down old-growth forests to clear land for fossil fuel projects. The regulator also has primary responsibility for overseeing major projects like the controversial Coastal GasLink pipeline.

Former premier John Horgan’s NDP government renamed the commission in 2023, and expanded its responsibilities to include hydrogen, ammonia, methanol and carbon storage projects.

In an emailed statement, the regulator said its role is to provide “sound regulatory oversight of the energy industry” and ensure companies comply with their permit conditions and B.C.’s laws. “We do not advocate for industry nor solicit economic development,” the regulator said.

Why will the regulator be overseeing more natural gas projects? 

The majority of B.C.’s fossil fuel production is natural gas. Mostly composed of methane, the fuel, which is used for heating and energy generation, is a powerful greenhouse gas with 80 times more warming potential over a 20-year period than carbon dioxide. 

Companies have been extracting natural gas in B.C. for decades, but activity has ramped up over the past dozen or so years. It’s projected to reach record highs in the next few years as new LNG export projects come online. That means the regulator will be overseeing far more natural gas projects. 

The majority of natural gas extraction in B.C. takes place through hydraulic fracturing, commonly known as fracking. Fracking involves drilling into shale rock formations and injecting a mix of fresh water and chemicals to fracture the rock and release the gas.

Canada’s first LNG exports will be shipped this year, when the first phase of LNG Canada’s facility in Kitimat, B.C., starts operations. LNG Canada will receive gas from Coastal GasLink. The consortium of foreign-owned companies behind the project, including Shell, plans a second phase, doubling production, if it can secure investment. 

More LNG developments are underway or proposed, and all fall under the purview of the energy regulator. Construction has started on Woodfibre LNG in Squamish, B.C., and Cedar LNG in Kitimat. The government is expected to decide whether to green-light the proposed Ksi Lisims LNG plant northwest of Terrace, B.C., near the Alaska border, and its feeder pipeline, the Prince Rupert Gas Transmission line, sometime in the next few months.

Do BCER inspectors always enforce regulations?

The BC Energy Regulator oversees all activity associated with fracking and LNG development, including construction of pipelines like the Prince Rupert Gas Transmission (PRGT) line. Yet the agency’s compliance and enforcement division includes just 17 inspectors, who report to seven supervisors.  

The Narwhal, in collaboration with the Investigative Journalism Foundation, recently published five reports about the energy regulator’s compliance and enforcement department. In at least 1,000 instances, inspectors documented apparent environmental infractions but did not penalize the companies for breaking the rules. 

The investigation into the regulator’s sometimes secretive approach to monitoring the fossil fuel industry in B.C. found the agency often notes when companies are breaking regulations or laws in hidden records but does not issue any official citations. Instead, it chooses to employ what it calls a “graduated enforcement model.” Critics call the method inadequate, suggesting the energy regulator has become “captured” by the industry it oversees.

The investigation also uncovered a regulator database of “serious leaks” at gas wells and an exemption granted to one of Canada’s biggest oil companies for more than 4,000 pipelines not compliant with regulations. Thousands of records describing problems at wells and pipelines — including dangerous levels of leaking gases and chemical spills affecting wildlife and livestock — were brought to light.

During the five-year period when the Coastal GasLink pipeline was being built by Calgary-based TC Energy, the regulator levied just $3,680 against the pipeline company for infractions. Meanwhile, the Environmental Assessment Office — the agency’s regulatory counterpart in the Ministry of Environment — fined Coastal GasLink more than $1 million for causing impacts to land, fish and wildlife during construction.

Why should British Columbians care about the BC Energy Regulator?

As the BC Energy Regulator takes on new responsibilities, it will continue to be the primary government agency in charge of all fossil fuel infrastructure. Fossil fuels are the largest contributor to global climate change, accounting for more than 75 per cent of global greenhouse gas emissions and nearly 90 per cent of all carbon dioxide emissions, according to the United Nations.

Climate change will directly cause an additional 250,000 deaths annually between 2030 and 2050, according to conservative predictions by the World Health Organization. It will disproportionately impact marginalized communities, meaning the brunt of it — including deaths — will be experienced by those least able to access support. 

Oil and gas development such as fracking, pipelines and LNG export facilities also impact ecosystems and present risks to public health and safety. Studies have found fracking is linked to earthquakes, reproductive issues and groundwater contamination.

In northeast B.C., where most of the province’s natural gas comes from, Treaty 8 First Nations have witnessed the steady degradation of their lands for decades. In one instance a B.C. Supreme Court judge found the provincial government — including the regulator — guilty of infringing on Blueberry River First Nations’ treaty rights by permitting and encouraging so much resource development that community members were no longer able to hunt and fish.

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This investigation is a collaboration between The Narwhal and the Investigative Journalism Foundation.

Oil and gas companies operating in British Columbia have reported 44 “serious” leaks at wellsites over the past year, according to publicly available BC Energy Regulator records. 

The leaks are all from surface casing vents, which are “an integral part of the safety system of a natural gas well,” the regulator said in an emailed statement.

A leak is designated serious if it releases more than 300 cubic metres per day of methane or includes hydrogen sulphide — a gas that can cause symptoms like headaches, nausea and dizziness at relatively low concentrations. A leak is also considered serious if it leaches contaminated water or oil into the surrounding environment, according to the regulator’s oil and gas operations manual.

Leaks of methane and other gases were among those reported. At seven sites, hydrogen sulfide leaks were also recorded, including at one well emitting the gas at a concentration of 5,000 parts per million. Hydrogen sulfide emissions can be deadly. At levels above 1,000 parts per million, they can result in “unconsciousness, cessation of respiration and death in a few minutes,” according to the U.S. Center for Disease Control.

Amanda Bryant, a senior oil and gas analyst at the Pembina Institute, said the conditions that qualify a leak as serious “mean a significant risk to environment and health could be present.” 

“Groundwater contamination is also clearly a serious concern,” she explained in an emailed response to questions. “When it comes to potential emissions, based on average Canadian residential gas consumption, 300 cubic metres of gas per day … could power 43 Canadian homes per day.”

The documented leaks highlight some of the potential environmental risks of B.C.’s burgeoning oil and gas sector, which is poised to expand significantly to supply new liquefied natural gas (LNG) export projects. The majority of B.C.’s gas is extracted through hydraulic fracturing, known as fracking.

All the wells reporting serious leaks since March 2024 “have mitigations in place to control the identified hazards,” according to the regulator. In its emailed statement, the regulator said the numbers in the database “do not necessarily indicate an ongoing release, but rather capability of flow.” The regulator did not specify which, if any, of the reported leaks are ongoing.

Over the past three years, oil and gas companies reported 160 serious leaks, while 252 were reported over the past five years. The BC Energy Regulator database, which includes a handful of reports from the late 1990s and early 2000s, records 659 leaks deemed serious. Of those, 340 were from active wells, 55 from suspended wells and 127 from abandoned (the industry term for permanently sealing a well.)

Of 252 ‘serious’ leaks reported in five years, BC Energy Regulator issued four orders and one fine

The regulator has a variety of enforcement tools it can use to bring companies into compliance, including issuing safety orders and imposing financial penalties. In an emailed response to follow-up questions, the regulator said it had issued four enforcement orders and one administrative penalty related to surface casing leaks at two wells in the past five years. 

A $10,000 penalty was issued to Petronas In October 2024 after the regulator determined the company’s history of non-compliance and the seriousness of the issue — gas emissions exceeding the allowable amount — warranted the fine. The other leaking well, owned by Pavilion Energy, within one kilometre of a private residence, was found in 2020 to be leaking at a rate of more than 4,700 cubic metres of gas per day. After numerous problems with the well, a connected pipeline and related infrastructure, the regulator issued three orders in 2024. Pavilion “complied with the provisions” of each order and is currently in compliance, according to the regulator.

According to the database, companies also reported nearly 7,000 smaller leaks over the same time period the regulator deemed “non serious,” as well as 164 leaks whose severity was listed as “unknown.”

“Leaks like this underline the importance of good regulation and enforcement of that regulation that prompts operators to fix these leaks as quickly as possible,” Bryant said.The regulator estimates B.C.’s oil and gas production has grown nearly 29 per cent in the past five years. In 2023 — the last year for which the regulator provides public data — 524 new well applications were approved, compared to 378 the previous year. 

“Each data entry is a point in time and may not reflect the current state of emissions, if any, from the well,” the regulator said, adding companies are required to check for evidence of leaks as part of routine maintenance and submit the results.

An investigation by The Narwhal and the Investigative Journalism Foundation revealed the regulator’s inspectors frequently spotted infractions at oil and gas sites but did not take enforcement action. In its emailed responses, the regulator said it is striving to be more transparent and recently made new data public.

Close to 290 oil and gas companies currently operate 6,596 facilities in B.C. Those companies produced nearly 15 billion cubic metres of gas between December 2024 and February 2025, according to regulator records. When Canada’s first major LNG export facility, LNG Canada, starts production this year, gas extraction in the northeast is expected to skyrocket.

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In mid-February, B.C.’s northeast was shaken by a series of earthquakes that both the province’s energy regulator and Natural Resources Canada say were linked to hydraulic fracturing, or fracking, for natural gas. 

To release oil or gas from rock formations deep underground, companies blast a mix of water, chemicals and sand into the earth, a process that can sometimes trigger earthquakes.

Honn Kao is a seismologist, or earthquake scientist, who leads a Natural Resources Canada research project on “induced seismicity,” which refers to earthquakes caused by human activities. He says the whole point of hydraulic fracturing is to cause very, very small earthquakes, known as microseismicity, to fracture rock and release gas. “That is totally normal, because that’s the purpose of it.” 

“It is not a particular surprise to see induced earthquakes that happened in the area where you have a lot of hydraulic fracturing operations or wastewater disposal injections,” Kao says in an interview. The two, he says, “usually go hand in hand.”

Naturally occurring earthquakes happen when underground rock suddenly breaks and there is motion along a fault. The sudden release of energy causes seismic waves that shake the ground. 

When fracking fluids are injected into the earth’s subsurface at high pressure, they sometimes cause faults to slip earlier than they would naturally, inducing an earthquake, Kao explains. “So quite often [when] you have an increased level of hydraulic fracturing operation in the region, then the level of seismicity becomes larger, higher as well.” 

But that doesn’t necessarily mean bigger earthquakes will occur. The vast majority, Kao says, are “small events that can be located or detected by seismometres, but not necessarily felt by local residents.” 

The issue, Kao says, is when earthquakes are large enough to be felt in nearby communities. “That means the energy released by the earthquake is way bigger than the energy that we input through fluids.” The implication, he says, is that it must have triggered a fault where energy is already building up for an earthquake … “and you just simply make it happen earlier.” 

And that has long concerned local residents, from ranchers to people worried about their well-being and drinking water. Some northeast B.C. residents affected by fracking can no longer get earthquake insurance. 

How do experts determine if an earthquake was caused by fracking?

Determining if an earthquake is induced by fracking requires investigation and research that includes examining the rock properties where the earthquake occurred and the injection history for nearby fracking operations, Kao explains. An earthquake is generally deemed to be induced if it occurs near an active fracking injection operation, he says.

Injection operations take place at relatively shallow depths, while many natural earthquakes occur at deeper depths. “Generally speaking, most of the induced earthquakes occur at or slightly above the injection depths.” But sometimes they are deeper, so seismologists have to examine different factors to infer whether a quake is caused by industrial activity. 

Induced earthquakes usually occur in clusters, like the February earthquakes in B.C.’s northeast, Kao adds. “Once the hydraulic fracturing operations finish, they die down very quickly.”

The BC Energy Regulator requires any fracking operations that trigger an earthquake with a magnitude of 4.0 or greater to immediately suspend operations. In an emailed response to questions, the regulator said the operations may continue with written permission “once the well permit holder has submitted operational changes satisfactory to the BC Energy Regulator to reduce or eliminate the initiation of additional induced seismic events.”

Do fracking earthquakes cause damage?

Kao says B.C. hasn’t experienced induced earthquakes large enough to cause significant damage to buildings or infrastructure. Most earthquakes causing damage to buildings and infrastructure have a magnitude of 5.5 on the Richter scale or higher, Kao explains. 

That doesn’t mean smaller earthquakes can’t have impacts. A B.C. family says a 4.3 earthquake on Feb. 11 precipitated a rush of calf births on its ranch, including premature twins, and the loss of most of their main water supply. While the quake may not have caused damage to buildings and infrastructure, Kao says “it certainly is a warning sign.” 

He says it’s important to make sure a robust regulatory framework is in place that will prevent fracking-induced earthquakes from becoming large enough to cause significant damage in the community. “I think that is really the ultimate balance we want to achieve between public [safety and concerns] and the economic benefit of the industrial activity.”

The regulatory framework appeared to be working in the case of the February earthquakes he says, because they died down once the fracking operations responsible ceased.

Can fracking companies prevent earthquakes from happening?

Fracking companies can take steps to prevent earthquakes by controlling the number of injection wells or the volume of injected fluids. If an earthquake occurs, Kao says the operator can immediately change the injection pattern by reducing the injection rate, “or even completely shut down their injection operation.” 

Kao and other researchers are studying the spate of February earthquakes in northeast B.C. 

“We want to figure out why it happened, what we have missed, what kind of sign can we actually see beforehand? And hopefully we’ll build that into the regulatory framework, so that we can prevent these kinds of things … in the future.”

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Rancher Matt Hedges was trying to catch a few hours of sleep during calving season in mid February when an earthquake rattled his home on Dead Horse Creek Ranch in northeast British Columbia.

“The whole house just started to shake, the pictures, windows, the mirrors and everything,” he says. It felt like a large truck was rumbling past, even though the Alaska Highway is nine kilometres away from the ranch where his parents Marilyn and Bill have lived for more than 40 years, and where Matt grew up and also works. 

The ranch’s 300 cattle were “all in a dither” after the quake struck at eight minutes to midnight. Matt stayed on his feet most of the night as cows went into labour and the temperature dropped below -30 C. “That night, we got a whole pile of calves, and some were premature.” 

The Feb. 11 earthquake was 4.3 on the Richter scale, according to Natural Resources Canada, and felt across a wide area. It was followed by another quake less than two hours later, with a magnitude of 3.8. Matt was so busy hauling damp newborn calves into the barn to keep them warm, taking extra care not to upset their “riled up” mothers, that he didn’t even feel the second one.

In the hours following the earthquakes, the spring that supplies drinking water for the cows and the main ranch house slowed to less than a quarter of its regular flow. 

“We’ll see whether this water comes back,” Matt says in an interview with The Narwhal. “We might need a new water spring there. If suddenly we’re out of water, then we’ve got to spend a bunch of money developing it again, right? … Personally, I’m really fed up with basically the whole oil patch, everything to do with it.”

According to an email from the BC Energy Regulator, the two earthquakes in the Peace Region were caused by hydraulic fracturing, commonly known as fracking, for natural gas by Tourmaline Oil, Canada’s largest gas producer. To release the gas from rock formations deep underground, fracking companies blast a mix of water, chemicals and sand into the earth, a process that can sometimes trigger earthquakes.

The two earthquakes were bookended over a five-day period by four other earthquakes in the region, each measuring 3.0 or higher on the Richter scale, as well as nine smaller quakes. All are “suspected industry-related” events, according to Natural Resources Canada’s earthquake database.

As northeast B.C. gears up for a fracking boom to supply new liquefied natural gas (LNG) export facilities, Hedges and his family have unwittingly found themselves at the epicentre of growing friction between the ranching and oil and gas industries. Some northeast B.C. residents affected by fracking can no longer get earthquake insurance, while others worry about potential health impacts, contaminated water supplies and incursions on their land. February’s spate of earthquakes has escalated their worries and underlying stress. 

Ranchers across western Canada also worry about the health of their cattle, and potentially losing their livelihoods. Alberta farmers told a University of Alberta researcher that fracking-induced earthquakes have led to “sick and dying cattle, stillborn calf births and reduced reproduction rates.

Animal behaviour experts also say earthquakes can cause stress and premature births — as they seemingly did on the Hedges’ ranch.

Forty calves were born on the ranch in the two days following the Feb. 11 earthquake, as two other earthquakes struck, up to double the number expected during that time. 

One cow delivered twins born approximately two weeks early. “They’re just tiny little things but they seem to be doing alright,” Matt’s brother Bo says in an interview. “But it does take more time when you have little, little premature calves that need a bit more attention. And then when you have everything else going on with the herd at this moment in time, it just strains everything that much more.”

Ranchers and animal experts say oil and gas operations put cattle at risk 

The BC Energy Regulator, which oversees oil and gas operations in the province, orders fracking companies to suspend operations if they are known to have triggered an earthquake with a magnitude of 4.0 or greater. In an email, the energy regulator confirmed Tourmaline Oil, the company the regulator said was responsible for the two earthquakes that preceded the Hedges’ water woes, suspended the fracking operations in question. Tourmaline did not respond to an interview request sent via email, or a voicemail message left at the company’s regional office in Fort St. John, B.C., about an hour’s drive from the Hedges’ ranch.

The regulator also said it is working closely with researchers, including at Natural Resources Canada, to enhance induced seismicity regulations for the fracking industry.

But that’s cold comfort for the Hedges, who say they have spent $50,000 in time and other expenses over the past several years trying to protect their cattle from the impacts of nearby oil and gas operations carried out by different companies.

Late last year, the family’s fears about the future of the Dead Horse Creek Cattle Company escalated when Bill and Marilyn, who are in their 80s, received notice from Calgary-based oil and gas company Yoho Resources that fracking will soon take place immediately adjacent to their ranch. The main fracking well pad will be about two kilometres away from the ranch houses, next to the property. Because private property owners in B.C. don’t own the rights to minerals and oil and gas under their land, drilling could occur beneath the Hedges’ ranch. 

This past week, with their water supply still affected by the quakes, the Hedges had no option but to put up with Yoho’s preparatory drilling. (Yoho did not respond to an email from The Narwhal.)

Matt worries the cattle, which number about 600 in the summer, will be unsettled by the nearby drilling and fracking, affecting their fertility. “If it’s during our breeding season, I don’t know what’s going to happen.”

He says a different fracking company induced an earthquake last spring, “and it really screwed up our breeding program with the heifers. It stirred them up so bad. I’ve never seen anything like it.” 

Ronaldo Cerri, a professor in animal reproduction at the University of British Columbia, says the correlation between stress in cows and calving is documented. “Even the physiological process by which cows deliver the baby starts with an internal stress, a stress from the baby that communicates with the mother and the calving process starts,” Cerri says in an interview. “So if you do start having things around that causes stress, you can actually have premature deliveries.” 

He says it makes sense for animals to be stressed by earthquakes. “If there are earthquakes around, they will be stressed. They will be more restless. …. That’s not normal for them. These are routine animals. So anything that gets them away from that state, that will cause stress to them, and then that could possibly trigger calvings.”

The earthquakes are only part of the Hedge family’s mounting issues with the fracking industry. About three years ago, fracking started on and around the Crown grazing lands the family has leased from the province for the past 40 years. Companies built pipelines and access roads across a swampland and creek that had functioned as a natural barrier for the family’s cattle. 

Cows will be cows, and the Dead Horse Creek Ranch bovines wandered away from their grazing lands. Bo says the family has experienced “a ton of stress” over it. Last summer, the Hedges found about 100 cows and calves less than 1.6 kilometres from the former natural barrier. The summer before, cattle were found grazing on the verge of the busy Alaska Highway multiple times, where they posed a threat to motorists and traffic made it dangerous to round them up on horseback, Matt says. 

While fracking operations on the Crown grazing range are fenced, Bo says, the loss of the natural barrier means cows can also access unfenced fracking operations on nearby land. 

“Our cattle get in there and they can drink whatever crap has been left around,” Bo says. In recent years, he says, calves have occasionally been born with deformities — the brothers say this year’s calves included a dwarf, who lived only a few days, and others born with genitalia “oddities.”

After the Hedges complained to the BC Energy Regulator about the loss of the natural barrier, Bo says they were drawn into a frustrating and time-consuming process that’s already lasted more than a year without resolving the issue.

The energy regulator ordered the three fracking companies involved to each build part of a 2.8-kilometre fence — with gaps between each company’s section. But the Hedges say they need an unbroken 6.4-kilometre fence to protect cattle from the highway and unfenced fracking operations.

The shorter fence was finally built last August, but Bo says it won’t help. “The cattle will hit those lines, walk along, come to the end of the fence and just walk around those fence lines to the end of the fence and continue on. It doesn’t really do anything.” 

In late August 2024, almost a year after the Hedges first asked the regulator for help with the fence, the brothers expressed their frustration in a letter, recently seen by the Narwhal. 

“We are tired of subsidizing the BC Energy Regulator and oil and gas companies involved with our time, money and resources to try to solve a problem that falls under the job description of the BC Energy Regulator and is the responsibility of the companies involved,” Matt and Bo wrote, restating that the shorter fence with gaps would not keep cattle away from either the highway or nearby unprotected oil and gas facilities. 

In response to the family’s frustrations, Patrick Smook, vice-president of compliance and operations for the regulator, told Matt to stop emailing and phoning regulator staff in a November letter reviewed by The Narwhal. Smook told Matt to instead send an email to a general community engagement address, and to call the regulator’s emergency line to report incidents or complaints.

That doesn’t sit well with the Hedges.

Bo doesn’t dispute that his family has called and emailed the regulator a lot. But their repeated attempts to make contact were because they were “worried about the public, worried about our safety, worried about our animals,” he says, and kept waiting for updates on whether companies would be directed to build a sufficient fence. 

“They may feel that they were being badgered by us, but if they had only picked up the phone or only answered the email and given us an update of what was going on, then we would have known where they were at with things,” Bo says. “It’s really hard for us to understand how a government agency that’s supposed to be regulating the oil and gas companies can not engage with the public.” 

The only options the Hedges have now, he says, are to spend about $60,000 to build the rest of the fence, or to fight deep-pocketed oil and gas companies in the courts, an option Bo says could end up being even more expensive.

The family’s herd of reddish Simmental and Simmental cross cattle are normally “pretty quiet animals,” Bo says. But they’ve been “a little worked up” since this month’s earthquakes.

“Some of the cows that you would never think would be a little ‘heads up’ are pretty restless right now,” he says. People working with them “have to be that much more wary and cautious.” 

Researchers studying how to mitigate fracking-induced earthquakes 

Bo, who felt the biggest earthquake in his apartment in Fort St. John, says he was surprised to hear on a local radio station that the recent earthquakes hadn’t caused any damage. “I have no idea why the BC Energy Regulator would downplay the effect and the potential impact that it would have.” 

In an emailed response to questions from The Narwhal, the BC Energy Regulator said it is “committed to reviewing and following up on complaints and concerns.” The regulator also said it can’t comment “on the issue of liability in the unlikely event of damages caused by an induced seismicity event.” The regulator, a government agency largely funded by the oil and gas industry, said such questions “are best directed to the province” — but the B.C. Energy Ministry didn’t respond to The Narwhal’s questions.

Responding to a question about potential future earthquakes from increased fracking in the region, the regulator’s email said it requires companies to suspend injection activities if they cause an earthquake of 4.0 magnitude or greater. Operations can resume, however, the regulator noted in a separate email, with written permission — “once the well permit holder has submitted operational changes satisfactory to the BC Energy Regulator to reduce or eliminate the initiation of additional induced seismic events.”

The regulator also said approval orders are required for each fracking disposal well, “all of which operate under strict pressure and reporting conditions.” 

The regulator said it maintains a seismic monitoring network of 35 stations positioned near energy resource activities and has collaborated with seismologists to define a local magnitude calculation for northeast B.C. that reflects the region’s geology (as a result, the regulator’s calculation of earthquake magnitudes frequently differs from Natural Resources Canada’s). It also pointed to its partnership with Geoscience BC and the BC Oil and Gas Research and Innovation Society to research induced earthquakes and provide analysis used to regulate fracking activities.

With fracking operations poised to begin adjacent to the Hedges’ ranch, the family is more worried than ever about earthquakes and other impacts on their cattle. Bo says it shouldn’t be up to affected ranchers and others to “have to negotiate and fight and go through the court system to get the oil patch to fix [what’s wrong].” 

The Hedges’ most immediate worry is their greatly diminished water supply. When Marilyn and Bill bought the land for their ranch almost 50 years ago, they built their log house and cattle corralls near a naturally occurring spring that runs out of a nearby hillside. 

The spring fills the water tank that supplies the house, while the overflow goes into a trough for cattle to drink. The trough overflow is channeled into a dugout where it’s kept for emergencies, like a fire. From the dugout, the spring water flows into Dead Horse Creek, ebbing and flowing at different times of the year. 

Since the earthquakes, “there’s barely enough water for the house,” Bo says. And the Hedges have had to move their cattle from a corrall whose drinking trough relied on the spring “because there’s not enough water … whether that water system comes back to where it was or not remains to be seen.” 

He says the family is in discussions with Tourmaline Oil to see “how they can help us mitigate some of the impact,” adding, “We will see what comes of that.”

Bo says it’s often possible to work something out with oil and gas companies for small things. “But when you’re starting to talk about a water source that allows a ranch to function and that sort of thing,” he believes oil and gas companies are going to question how much money they’re willing to spend. “They try to keep you a little bit happy and throw you some breadcrumbs here and there, but they’re in to make money for themselves.” 

“And I get that that’s business, right? But when their business starts to drastically affect and change the livelihood of other businesses and people in the community, that’s where it starts to cross the line.”

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As construction of the Woodfibre LNG project gets underway in Squamish, B.C., locals are worried about potential air pollution and health impacts from flaring — the process of burning off excess gas, mostly in the form of methane. 

Woodfibre has estimated flaring will occur during about three per cent of the plant’s operations, or on about 11 days per year. Tracy Saxby, co-founder of the local environmental group My Sea to Sky, says that’s too many. 

“That exceeds the definition of a high amount of flaring, based on this new research that shows that being exposed to flaring at fossil fuel facilities for more than 10 days a year can have significant impacts for human health,” Saxby told The Narwhal. She said chronic exposure to flaring can increase rates of asthma, heart disease, lung disease, premature death and mortality.

After hearing Squamish-area residents’ Woodfibre-related worries, University of Victoria researcher Laura Minet decided to launch the first Canadian study on the potential health impacts of flaring from the Woodfibre liquefied natural gas (LNG) export facility. 

Minet agreed studies indicate oil and gas development can impact the health of local communities, but said it’s difficult to draw comparisons with LNG export facilities “because it’s [a] different context.” 

“I think it’s all a question of magnitude and how much flaring is happening,” she said. “What we can for sure say is … there are very high chances that it’s going to have impacts on the health of the community.”

But according to Minet, an assistant professor in civil engineering, her attempts to get modelling data for Woodfibre flaring have hit a wall.

In October 2023, Minet filed a freedom of information request with the B.C. Ministry of Environment and the B.C. Environmental Assessment Office, hoping to get access to details about how Woodfibre LNG modelled the potential impacts of any flaring for its environmental assessment. 

Two significant concerns are Woodfibre’s proximity to residential areas in Squamish, with a population of 24,000, and local geography. Howe Sound is a long, narrow ocean inlet. Its steep sides, formed by glaciers, make the inlet susceptible to inversions, where a layer of warm air traps cooler air in the space below.

“That means that if there’s excess air pollution, air pollution could be also trapped close to the ground under certain meteorological conditions,” such as during heat waves, Minet, who heads the university’s clean air lab, said in an interview.

Minet requested a copy of emission dispersion modelling files referenced in a 2015 memo from Golder Associates, the consulting firm that compiled Woodfibre’s environmental impact assessment submissions. In the memo, a Golder employee promises to provide the files to the Ministry of Environment on an external hard drive.

“The response I got from them was that they couldn’t find a hard drive and they couldn’t actually find any proof that they had received it from Golder Associates,” Minet said. 

The Narwhal also filed a freedom of information request seeking the modelling files referenced in the Golder memo. In response, the B.C. Environmental Assessment Office said the files were publicly posted on its website. But after reviewing the data cited by the office, Minet disagreed.

“These memos are responses to [questions] asked by the Ministry of Environment on the modelling done by Golder Associates, and provide some information on the modelling assumptions, but they are not modelling files.”

Woodfibre LNG is majority owned by Indonesian billionaire Sukanto Tanoto’s Pacific Energy Corporation. The gas export project is under construction on the site of an old pulp and paper mill on the shore of Howe Sound. It’s one of three approved LNG projects in B.C. including the LNG Canada facility in Kitimat, B.C., which will be Canada’s first LNG facility to ship compressed gas overseas. Four other LNG projects are proposed in the province.

In an emailed response to questions from The Narwhal, Woodfibre spokesperson Sean Beardow did not directly answer a question about the amount of flaring that will take place. “There will be flaring associated with initial start up and we’re exploring different avenues on how to reduce it as much as possible,” he said.

Woodfibre aims to minimize flaring by redirecting gas that evaporates from LNG storage tanks to the liquefaction facility instead of flaring it, according to Beardow. He said Woodfibre LNG — unlike the larger LNG Canada project — will use electric compressors, which can help reduce flaring because they require maintenance less frequently than gas-powered compressors and don’t need to flare gas when restarting after maintenance.

When Woodfibre LNG plans to flare gas, it is required to notify the District of Squamish, Squamish Nation, Musqueam Indian Band and Tsleil-Waututh Nation at least 24 hours in advance, Beardow said. In the event of unplanned flaring, the company is required to advise local governments within 24 hours of the start of flaring if the quantity of gas exceeds a specific volume — 10,000 cubic metres per event — or flaring occurs for more than four hours in a row.

Beardow did not directly answer a question about the impact flaring may have on air quality and human health, saying only that B.C. has “a world-class regulatory framework that protects both the environment and human health alike.”

“Woodfibre LNG trusts in the province’s regulatory system and will operate within its established limits in all aspects of its operations, including flaring,” Beardow added in an email.

Environmental assessments often rely on vague and optimistic flaring estimates provided by project proponents: Minet

The missing modelling files aren’t the only data issues observed by Minet and her team. Tim Takaro, a professor emeritus at Simon Fraser University’s Faculty of Health Sciences who is involved in the Woodfibre LNG study, said there are “many, many problems” with flaring estimates for the project. 

“One of the big obvious ones is that the largest release period is during the startup — generally one to two years, sometimes longer — and during maintenance. But in the environmental assessment, they leave out that they start their calculations during the running phase where the emissions are the lowest.”

The Narwhal asked the B.C. environment ministry if ​​flaring during the plant’s startup was included in Woodfibre’s environmental assessment, but did not receive a direct answer. Instead, the ministry cited a supplemental report that states “flaring will occur under controlled conditions during introduction of hydrocarbons” while the plant is starting up and systems are tested. Woodfibre anticipates flaring will occur less than three per cent of the time, the report says.

Woodfibre also estimates the project’s start-up and system testing will last one month and involve “intermittent flaring periods lasting up to three or four days at any one time,” according to the supplemental report.

In Kitimat, residents have been advised the LNG Canada gas liquefaction facility could be flaring continuously for up to three months as the facility tests equipment in preparation to launch its first shipments to Asia next year.

Minet said potential human health impacts of flaring haven’t been extensively researched, partly due to the relatively small number of LNG export facilities — which cool and compress natural gas for easier transport — around the world. Currently, about 40 plants are operating worldwide and about half of them have opened in the past 15 years.

The Woodfibre study, which involves a team of scientists from University of Victoria, Simon Fraser University, University of Toronto and Texas A&M University, as well as officials from Vancouver Coastal Health and the Canadian Association of Physicians for the Environment, will add to a growing body of research about the burgeoning industry.

“My hope is to be able to provide information on what is happening around the world at LNG export facilities,” Minet said. “This information could be a good basis for future environmental impact assessments. We can rely partly on what the proponents are saying and how much flaring is going to occur in those facilities, but it’s good to compare this with what has been observed at other facilities and also build worst-case scenarios.” 

Most environmental impact assessment documents compiled by LNG proponents are “based on best case scenarios,” according to Minet. 

“They never model a case when they’re going to have to flare a lot because there are maintenance issues or because the facility has to close for a certain period of time,” she said, adding estimates about flaring frequency are often quite vague.

“Looking at environmental impact assessments from other LNG export facilities around the world, the information that’s communicated to the public is always very generic — ‘We’re expecting to flare a bit, but not too much’ — and we have no idea what this is based on.” 

“There’s been a lot of flaring happening at some energy export facilities in the U.S. and notably in Australia — and some reports of journalists saying that the communities around them have been affected and have reported potential health issues associated with this excess flaring,” Minet said.

Government agencies, including B.C.’s Ministry of Environment and Climate Change Strategy, use estimates provided by project proponents when deciding whether to approve projects like Woodfibre LNG. 

In the U.S., Saxby pointed out, some liquefied natural gas (LNG) facilities have underestimated the frequency and duration of flaring. “Those frontline communities disproportionately shoulder the burden of pollution and there are significant health risks.”

She said if flaring is underestimated, “it means that the local air quality impacts and the associated health impacts are also being underestimated — and that’s a really big problem.” 

B.C. government can’t locate files mentioned in Woodfibre LNG environmental assessment 

The Narwhal’s freedom of information request for the emissions modelling files was closed by the government, which said there were “no records.” Minet is still waiting for her request to be fulfilled.

“They said, ‘We have other files that we can provide you, other documents,’ which I assume would be the emails between Golder and the [ministry] just to understand the assumptions. But we’re a year later, and I haven’t received them yet.”

The environment ministry has not responded to questions The Narwhal emailed in August, asking if the hard drive and modelling files have been located and if any efforts have been made to obtain them.

When The Narwhal asked Woodfibre about the files, Beardow directed us to the assessment office website.

Saxby is deeply concerned that Woodfibre LNG may have received its environmental assessment certificate without providing the data on which its estimates about flaring and potential health impacts are based.

“From our perspective, that completely invalidates Woodfibre LNG’s environmental assessment certificate,” she said. “There’s a lot of concerns about this project and the fact that it hasn’t been properly assessed … Everybody that lives in the community and in Howe Sound are being put at risk. Our health is being put at risk.”

Takaro shares Saxby’s concern that Woodfibre LNG’s environmental assessment certificate may have been issued despite a lack of modelling data about flaring from the project.

“How is it possible that a company … can operate in a space that protects them from scrutiny of people who know about the health effects of those emissions?”

Minet hopes study findings will help challenge environmental impact assessment standards

Without the modelling for Woodfibre’s flaring emissions, Minet and her colleagues have turned to other data sources to assess in the study.

“What we’re doing now is reviewing data that is publicly available on all LNG export facilities that are open around the world already, [and] that includes looking at satellite data,” she said. 

Understanding how often other LNG plants are flaring and how local conditions, like weather and geography, influence the dispersal of those emissions will enable Minet’s team to assemble a range of projections for flaring at Woodfibre, from best-case to worst-case scenarios.

Once the study is published, Minet hopes it will be a resource for the other LNG projects making their way through the environmental assessment process. Those include the Ksi Lisims LNG project, which would be the province’s second-largest LNG export project if approved. The proposed projects could collectively produce 30 million tonnes of LNG per year on top of about 19 million tonnes per year from Woodfibre, LNG Canada and Cedar LNG.

“My hope is to question those environmental impact assessments … and see if we could better define them to include more worst-case scenarios, to have a better picture of what could happen to the community, rather than relying on best-case scenarios.”

Woodfibre LNG was approved by the B.C. government in 2015 and the Squamish Nation in 2018. The company expects to ship about 2.1 million tonnes of LNG overseas each year, starting in 2027.

Updated Dec. 2, 2024, at TK:TK p.m. MT. This story has been updated to remove a reference to Howe Sound being the world’s most southerly fjord.Updated Dec. 2, 2024, at 9:40 a.m. PT. This story has been updated to remove a reference to Howe Sound being the world’s most southerly fjord.

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When you think of B.C.’s central interior forests, you probably picture swaths of trees stretching over hills and up mountains, punctuated by rivers and the occasional lake. 

You probably don’t think of sand.

But if a proposal working its way through the B.C. environmental assessment process is approved, a special type of sand used in hydraulic fracturing for gas — commonly known as fracking — will be extracted from a forest near Bear Lake, north of Prince George. The sand would be trucked to B.C.’s northeast, where a fracking boom is poised to begin to supply the province’s new liquefied natural gas (LNG) export industry. 

Vitreo Minerals, a sand and gravel supplier based in Golden, B.C., proposes to build an open-pit mine and two processing facilities that could produce two million tonnes of frac sand per year for up to 20 years. The Angus mine, which has the potential to supply up to 400 fracking wells per year, would be B.C.’s only operating frac sand mine. 

The project will involve building new access roads through the forest, clearing land for the mine and its crushing and drying facilities and constructing a new transmission line and natural gas pipeline to power the operation, according to a project description submitted to the B.C. Environmental Assessment Office. 

“We propose to essentially mine — by drilling and blasting in a very conventional-looking quarry — a rock known as quartz arenite, a very high-purity silica-rich rock,” Vitreo Minerals CEO Scott Broughton explained during a recent project information session hosted by the assessment office. “It actually has the perfect-size sand grains that we’re looking for to produce proppant [frac sand] for the oil and gas industry.”

But environmental groups say the mine, which would be located in the Fraser River watershed, poses risks to nearby communities, water, local wildlife and the environment.

Sven Biggs, the Canadian oil and gas programs director for Stand.Earth, said the non-profit group will be keeping tabs on any long-term expansion plans for the frac sand industry in B.C. “If the plan really is to produce enough silica in British Columbia to support the LNG industry here in B.C. and Alberta, those would be very large operations and could have a much larger footprint than this initial project,” he told The Narwhal.

What is frac sand, exactly? And what’s the big deal with the Angus project? 

Why does the LNG industry need silica sand?

B.C.’s fracking operations will soon greatly expand as Canada’s first LNG export project, the LNG Canada plant in Kitimat, prepares to produce 14 million tonnes of LNG annually starting in 2025. The nearby Cedar LNG plant, which expects to begin operations in 2028, will produce another three million tonnes of LNG per year. And the proposed Ksi Lisims LNG project, near the Alaska border, would add another 12 million tonnes to B.C.’s total LNG production.

To extract gas to ship to LNG plants, fracking operations need silica sand — lots of it. Exact figures are difficult to obtain but each fracked well uses an estimated 5,000 tonnes to 9,000 tonnes of frac sand, known in the industry as proppant. The Wilderness Committee estimates LNG Canada alone will require 18,000 additional fracking wells to supply gas that will be liquefied for transport to overseas markets.

Frac sand is mixed with fracking fluid — a blend of water and chemicals — and pumped into the shale deposits that hold the gas. After the fluid fractures the rock, the sand helps hold the fractures open, freeing the gas.

The best frac sand is unweathered silica, produced by crushing and processing quartz rock. Sand created through this process is jagged, allowing it to grip the rock and hold it open. Most frac sand currently used in B.C. is imported by rail from the United States, where Wisconsin is a major producer.

Are there benefits to producing silica sand in B.C.?

Vitreo Minerals sees an opportunity to produce high-quality frac sand much closer to the B.C. fracking operations where it will be used. 

If approved, the Angus project will be the first mining operation in Western Canada to produce top-quality silica sand close to the Montney formation in northeast B.C. and Alberta, which contains vast natural gas reserves. 

“The Montney shale deposit is the largest carbon bomb in Canada, the sixth largest in the world,” Biggs said. “If the plans to build LNG and extract all of that gas go ahead, we are going to pass the threshold of a safe climate … and that’s why this mine is being proposed, to help facilitate a huge expansion in fracking to supply LNG terminals.”

Producing frac sand in B.C. will bring economic benefits for the province, the company states in its project description.

According to Vitreo Minerals, 150 people would be employed during the project’s construction phase while the mine would support 140 permanent jobs once operational. The positions would all be filled by local workers, the company states.

However, a technical advisor with the environmental assessment office has raised concerns about Vitreo’s estimates as well as its commitment to local hiring, suggesting the project could require specialized workers from elsewhere in B.C. or Canada. That might require the company to build a work camp for the project.

“The introduction of work camps and an influx of temporary labourers can disproportionately affect specific demographic groups, notably women and First Nations peoples,” a summary of the technical advisor’s comments states. 

During the recent information session, Broughton said he was confident the project would employ local workers, contractors and First Nations.

“We clearly prefer that this project — and we feel confident that we can do this — hire local workers and First Nations workers to operate this mine.”

Vitreo Minerals did not respond to an interview request from The Narwhal.

Is acid-rock drainage a concern? 

Creating a new mine and processing infrastructure will add to the upstream — and often overlooked — impacts of B.C.’s new LNG export industry. 

During a presentation to the local government of the Fraser Fort George regional district last November, Broughton described the activities at the proposed Angus project as “simple processing.”

“There’s no chemistry. There’s no heat. There is nothing nasty,” he said. “This is just a physical process, and it will look a lot like a conventional sand and gravel operation to many people.”

But Wilderness Committee climate campaigner Peter McCartney disagrees. 

“There’s absolutely nasty stuff buried underground that you are disturbing anytime you do mining,” McCartney told The Narwhal. “I think what he’s implying is that they’re not chemically extracting minerals, which is true, but there are still lots of nasty things like heavy metals and that acidity that’s under there. There’s all sorts of stuff that you don’t want coming from underground into the environment that isn’t necessarily a chemical additive — it’s just naturally occurring.”

When naturally occuring materials in rocks, including sulphur-bearing materials, are exposed to oxygen, moisture and bacteria, they can create acid-rock leaching, which poses a significant threat to groundwater. The company says its geochemistry studies at the Angus site suggest the rock that would be mined and processed are “not potentially acid generating and have limited potential for metal leaching.”

Is silica dust from frac sand harmful? 

During an early engagement process, communities and First Nations near the proposed mine site raised concerns about silica dust, a known carcinogen that can cause a variety of respiratory problems, including silicosis, a lung disease. 

Vitreo states the proposed sand plant and finishing plant will not produce any silica dust and says a dust mitigation and monitoring plan will be developed for the mine and surrounding site. 

Once the mine is operational, approximately six trucks every hour — more than 50,000 trucks annually — will travel along Highway 97 transporting proppant to markets in northeast B.C., according to the company. 

McCartney said each truckload creates an opportunity for silica dust to escape. 

“Anytime a big wind picks up, it’s going to be blowing silica sand out of that mine and onto anybody in the vicinity,” he said. “They can mitigate that, but if you’ve ever tried to put up a tarp in the middle of a windstorm, it’s not easy … the number one concern that we hear from communities that are in proximity to these frac sand mines is ‘how is this going to affect my health [and] the air quality in our community?’ ”

Nearby surface water would be used to suppress dust and process the mined material into sand, according to the recent information session. The company says it may also use groundwater at the Angus sand plant. It began studying potential groundwater impacts in 2022.

Would the silica sand mine affect wildlife?

The Angus project could affect up to 76 species of concern, including 15 listed on the federal Species At Risk Act or B.C.’s red list, which includes species considered threatened, endangered or extirpated. 

Surveys conducted by the company in 2022 confirmed the presence of eight provincially or federally listed species, including the olive-sided flycatcher, common nighthawk, rusty blackbird, barn swallow, horned grebe, western toad, grizzly bear and wolverine. 

The project is located within the range of a grizzly bear population of moderate conservation concern.

What about greenhouse gas emissions? 

Creating a new mine and processing infrastructure will add to the upstream — and often overlooked — impacts of B.C.’s new LNG export industry. 

Vitreo says the project will help offset emissions from transporting frac sand from the U.S. 

However, the company’s project description says building the mine will create 9,900 tonnes of carbon emissions. Once it’s operating, the mine will emit 60,860 tonnes of carbon per year, most from natural gas to power the facility that finishes drying the frac sand. Annual operating emissions from the Angus project would equal the yearly emissions of 14,485 passenger vehicles.

The project’s other major emissions will come from haul trucks and other traffic, the description says. Fugitive dust, sulphur dioxide, nitrogen dioxide and carbon monoxide will also be produced as a result of mining operations.

The finishing plant’s emission intensity means it will be subject to B.C.’s greenhouse gas emission reporting regulation.

The project’s impact on B.C.’s ability to meet its emission-reduction targets will be part of the company’s environmental assessment application, the document states.

How does the project affect First Nations?

The Angus project is located on the traditional territories of the McLeod Lake Indian Band and West Moberly First Nations. Both are taking part in the environmental assessment process and have participated in some preliminary fieldwork, according to the company. 

The environmental assessment office also notified three nearby First Nations — Lheidli T’enneh First Nation, Nak’azdli Whut’en and Nazko First Nation — about the project. According to the detailed project description, Nak’azdli Whut’en told the company by phone before the start of the engagement process they “do not support fracking and therefore will not support the project.” Of the three, only the Lheidli T’enneh First Nation is officially participating in the environmental assessment process.

Under B.C.’s Environmental Assessment Act, companies proposing major projects are required to reach “consensus” with participating First Nations at key stages of the process. It’s a relatively new requirement that has so far been applied to about 20 projects, according to the Environment Ministry.

If consensus can’t be reached, participating First Nations can provide a “notice of consent or lack of consent” at the end of the assessment process, according to the assessment office. 

McLeod Lake Indian Band declined to comment on the project. Lheidli T’enneh First Nation, Nak’azdli Whut’en and West Moberly First Nations did not respond to interview requests before publication time.

What happens next with the frac sand mine project?

The Angus project is “one of the first, if not the first, silica sand mine to ever go through the environmental assessment process” in B.C., according to an email from the Ministry of Environment and Climate Change Strategy.

The environmental assessment office is seeking public feedback on its draft environmental assessment plan for the Angus project until June 27. The office expects to issue an order in August that will allow Vitreo Minerals to begin developing its formal application for an environmental assessment certificate.

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Go here to read our latest coverage of the Prince Rupert Gas Transmission pipeline.

Four years after the Coastal GasLink pipeline sparked nation-wide protests, construction of another major pipeline in British Columbia is poised to begin this summer. 

The Prince Rupert Gas Transmission pipeline, owned by TC Energy, the same company that built the Coastal GasLink pipeline, will carry natural gas from the province’s northeast to Ksi Lisims, a proposed liquefied natural gas (LNG) export facility on Nisga’a territory near the Nass River estuary in northwest B.C. 

The gas, commonly extracted from underground deposits through a process called hydraulic fracturing, or fracking, is mostly composed of methane, which is 80 times more powerful than carbon dioxide over a 20-year period when it comes to heating the planet.

The Nisga’a-led Ksi Lisims facility would be capable of producing up to 12 million tonnes of LNG annually, which would be shipped across the Pacific Ocean to countries like Japan and South Korea. Ksi Lisims — currently undergoing an environmental assessment — would be the second-largest LNG export project in the province after the LNG Canada project in Kitimat, which the Coastal GasLink pipeline will supply.

The B.C. government approved the Prince Rupert gas pipeline in 2014 to supply the proposed Pacific NorthWest LNG facility on Lelu Island, near Prince Rupert. That project was cancelled in 2017, leaving the transmission line in limbo. Then, in 2019, TC Energy obtained a five-year extension to its environmental certificate. The extension came with several conditions the company must meet, including completing a cumulative effects study for the project in consultation with First Nations.

In March, Nisg̱a’a Nation and Texas-based Western LNG announced a deal to buy the pipeline from TC Energy. In late May, TC Energy submitted a letter to B.C.’s Environmental Assessment Office, notifying the provincial government pipeline construction will start Aug. 24.

The start date is contingent on “the successful closing of the sale … to Western LNG and Nisg̱a’a Lisims Government,” Allison Denby, with Calgary-based TC Energy, wrote to the environmental assessment office. “Construction activities will be initiated within Nisg̱a’a Lands.”

Here’s what you need to know about B.C.’s newest pipeline project.

What do First Nations think of the Prince Rupert Gas Transmission pipeline?

Like the Coastal GasLink pipeline, completed last fall, the new 800-kilometre pipeline will cross numerous First Nations territories. Coastal GasLink famously faced strong opposition during its five years of construction and was slapped with extensive financial penalties for breaking multiple environmental laws. 

Not all communities in the north are happy about the prospect of another pipeline cutting through northern B.C. Gitanyow Nation agreed to the Prince Rupert gas pipeline project in principle — and on paper — in 2014 but now opposes the project, saying much has changed in the past decade.

“In terms of climate change, the advance of the [United Nations] Declaration on the Rights of Indigenous Peoples, the advance of Gitanyow policies and laws that we’ve developed around water, around protected areas — there is so much change,” Tara Marsden, Wilp sustainability director for Gitanyow Hereditary Chiefs, told The Narwhal in May. “At the time, the project was not what it could be today. It was still a big risk, but in a 2014 context it was not the extreme risk that we view it as today.”

Gitanyow has expressed concerns about the environmental and climate impacts the pipeline and associated liquefaction and export facility will have on salmon populations, wildlife and “implications for increasing drought, wildfire and glacial recession within our territories.” 

Marsden said enforcement actions related to Coastal GasLink opposition against Indigenous land defenders by the RCMP’s Critical Response Unit (formerly known as the Community-Industry Response Group, or C-IRG) have also changed the way the Gitanyow community thinks about the pipeline.

Neighbouring Gitxsan Hereditary Chiefs are also concerned about the project’s implications, including potential police intervention if community members oppose the pipeline. Simogyat (Chief) Molaxan Norman Moore previously told The Narwhal he feels the government isn’t acting in good faith.

“They’re treating us as wards of the government. They’re treating us as minions,” he said in March. “We say things and it just goes past and they’re just sitting there, nonchalant. They’re brushing us off. The government is brushing us off.”

For the Nisg̱a’a, it’s a different story. 

“The Nisg̱a’a Nation has long tried to establish an economic base in the Nass Valley … in a way that agrees with our principles and our values, as we live in harmony with our lands and we move forward to building that economic base,” Nisg̱a’a Nation president Eva Clayton told attendees at the BC Natural Resources Forum in Prince George in January. “LNG will be a transformational opportunity for us to build our economy.”

TC Energy’s plan to begin constructing the pipeline on Nisga’a lands would likely postpone any potential conflict with opposing parties while achieving a substantially started designation from the environmental assessment office. Such a designation would secure government approval for the pipeline indefinitely. 

Getting to that point is a race against time; the project’s environmental assessment certificate will expire in November unless the B.C. government says sufficient work has been accomplished to warrant the designation. To make the determination, the environmental assessment office will examine how much work has been done on the project, with a focus on land-based physical activities that affect the environment, according to an email from the B.C. environment ministry.

How will the Prince Rupert Gas Transmission pipeline affect the environment?

The Prince Rupert Gas Transmission project was first approved as a 900-kilometre pipeline. Moving its terminus from Lelu Island to Nisg̱a’a territory would shorten its length by about 100 kilometres. By comparison, the Coastal GasLink pipeline is 670-kilometres long.

The new pipeline will span more than 1,000 waterways, including major salmon-bearing rivers, destroy habitat for at-risk species such as caribou and cross through old-growth management areas and sensitive wetland ecosystems, according to the 2013 project description submitted to the B.C. environmental assessment office. The description said more than 200 plant species along the project route are considered by the province to be of special concern, including four that are threatened or endangered. 

Of hundreds of wildlife species potentially impacted by the project, the description noted 76 are recognized as species of management concern. They include 34 species listed under the federal Species At Risk Act, 40 species listed by the Committee on the Status of Endangered Wildlife in Canada — an independent body which makes recommendations for federal listings —  and 72 species listed as endangered, threatened or of special concern by the province of British Columbia.”

The Coastal GasLink pipeline’s environmental transgressions have set a worrying precedent for communities along the route of the new pipeline. Construction activities repeatedly failed to protect the environment from impacts and B.C. officials rebuked workers — not always consistently — for failing to meet conditions outlined in the project’s environmental assessment certificate. — Shannon McPhail lives in New Hazelton and is the executive director of the Skeena Watershed Conservation Coalition. Her family has lived in the Kispiox Valley for generations. She said the B.C. government should re-examine its approval of the new pipeline project in light of the climate and biodiversity crises. 

“Everyone agrees we are in a climate crisis,” she told The Narwhal earlier this year. “People’s wells in the Kispiox Valley are drying up — they can’t water their livestock and they haven’t had enough snow for livestock to eat or drink. There’s no way we can balance the Prince Rupert Gas Transmission pipeline project to be built through all of this forest when we’re predicted to have a wildfire season worse than last year.”

In December 2023, a spokesperson for the B.C. Ministry of Energy, Mines and Low Carbon Innovation the told The Narwhal the BC Energy Regulator had directed TC Energy to engage Treaty 8 First Nations “on a number of key concerns,” primarily “regarding routing through areas of cultural or ecological significance and cumulative effects.”

TC Energy has not submitted any proposed pipeline route amendments to the environmental assessment office.

What’s next for B.C.’s newest pipeline project?

The environmental assessment process for the Ksi Lisims project aims to address any concerns, including from First Nations with differing views.

“Resolving disputes between any segments of society is complicated,” B.C. Environment Minister George Heyman told The Narwhal in May. “Resolving differences between First Nations over the impacts of a project is just as complicated.” 

“I know the environmental assessment office takes that challenge very, very seriously and it is a difficult challenge,” Heyman said. “Like anything in society, not everybody agrees.”

Marsden said she’s baffled the pipeline project and the Ksi Lisims LNG project are treated as separate projects in the environmental assessment process, even though they are closely intertwined. She said the splintered process — in which the impacts of building supply pipelines are not factored into environmental assessments for LNG facilities — allows proponents to leave out potential downsides of their projects while emphasizing far-reaching benefits.

“They don’t apply the same splitting principle to the benefits,” Marsden said, noting Ksi Lisims emphasizes its LNG will offer cleaner fuel to Asian markets. “They want to talk about the benefits of replacing coal in Asia, that’s their bottom line … so they want to look at something way beyond the scope of anything the B.C. government can control. But they don’t want to look at the impacts associated with the project that are right here in B.C.”

These impacts include putting strain on B.C.’s climate ambitions. The Ksi Lisims LNG facility and associated activities, including pipeline construction and gas extraction, will produce carbon and methane — increasing emissions despite the province’s legislated reductions targets. 

Documents previously obtained by The Narwhal indicate the B.C. government hopes to provide electricity for Ksi Lisims with a new taxpayer-funded $3 billion transmission line. And while Ksi Lisims proponents say electrification will significantly lower emissions, it’s unclear if the province, facing widespread drought and reduced hydro capacity, will have enough electricity to meet escalating demand from the LNG sector.

Other documents obtained by The Narwhal reveal BC Hydro wants to skip an environmental assessment for the new transmission line.

The environmental assessment office is unlikely to complete its review of the Ksi Lisims project before B.C.’s October election, in which the impacts of climate change and the future of resource development are likely to be prominent issues. 

Following the end of a public comment period in December 2023, the assessment office requested additional information from the Nisg̱a’a Nation and its partners to address concerns identified during the public engagement period. Concerns included the facility’s carbon emissions, power requirements and potential environmental and wildlife impacts.

The proponents have up to one year to submit a revised application.

— With files from Shannon Waters

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Early on Mother’s Day, Fort Nelson First Nation Chief Sharleen Gale headed out to make sure everyone in her community was packing an emergency bag and preparing to immediately evacuate their homes in northeast B.C. It was a cool, dry morning and the skies were filled with smoke. 

A few kilometres away, the out-of-control Parker Lake wildfire was closing in on Fort Nelson, an oil, gas and forestry town known as the gateway to the northern Rockies. It was no longer safe to stay. The fire had grown from 50 hectares to 1,700 hectares in the two days since it was first detected. Winds were expected to push the flames within striking distance of the two communities and emergency officials urged all residents to head south.

Hoping to spread the word to as many people as possible, Chief Gale texted The Narwhal information about the evacuation and the unfolding situation. 

“Need support with this while I go door-to-door getting the rest of my community to evacuate,” she wrote. 

A screenshot of the declaration she’d sent out to her community was attached.

“We understand that the decision to evacuate is disruptive and unsettling,” the declaration said, noting in bold by noon that day there would “no longer be any assistance offered to remaining members.”

In the thickening smoke, residents piled into cars, trucks and buses and drove more than four hours to Fort St. John or nearly nine hours to Prince George. By the following day, the Parker Lake blaze had displaced more than 4,000 people from their homes and scorched more than 5,200 hectares, a grim harbinger of what is shaping up to be another devastating and stressful wildfire season for B.C. and beyond.

Holdover fires from last year, extreme drought conditions across most of the province and the driest winter in half a century have set the stage for an early and aggressive start to the fire season. 

In a region where vast quantities of water are allocated annually to the oil and gas sector, the prolonged and severe drought has already prompted the B.C. government to bring in some restrictions on the industry’s water use. Meanwhile, intense and widespread wildfires will put the industry’s production plans and disaster protocols to the test.

‘Extremely concerned’: communities brace for the worst

Last year was the province’s worst fire season on record, with more than 2.84 million hectares burning up. But even after immediate wildfire threats subsided last fall, dry conditions persisted as temperatures dropped through the winter and little rain fell during the spring to dampen the fire-ready understory. 

Chief Gale wasn’t available for an interview, texting from the evacuation centre in Fort St. John to say she needed to focus on making sure community members were safe and had all they needed.

Cliff Chapman, BC Wildfire Service’s director of provincial operations, said crews on the ground and in the air are focused on protecting buildings and infrastructure. He noted dozens of structure protection personnel, predominantly from municipal fire departments in the province’s northeast, are working to protect the two communities.

“Those individuals are deploying sprinklers, doing structural protection [and] defending the structures in Fort Nelson from the potential of fire entering the community,” he explained at a May 13 press conference in response to questions from The Narwhal. “That includes the use of heavy equipment on the ground, putting in fire guards.” The goal, he added, was “to slow the spread of that fire.”

“Everything is focused on the protection of the communities of Fort Nelson and Fort Nelson First Nation,” Chapman emphasized. “That is where all of our resources are assigned.” 

B.C. Minister of Emergency Management and Climate Readiness Bowinn Ma told reporters she and her colleagues are worried about what might happen over the next few days. 

“With no precipitation, no major precipitation in the forecast ahead, and winds that can pick up at any time … let’s just say we are extremely concerned,” she said at the press conference.

At the time of publication, the situation remained extremely volatile. BC Wildfire Service said the Parker Lake fire had grown further, burning more than 8,000 hectares in total, and noted conditions in and around the communities “are still very receptive to wildfire and we will continue to see substantial growth of our fires today.”

Climate change is the underlying cause of extreme and early wildfires

While early fires have popped up across the province, the drought-stricken northeast is B.C.’s hotspot. 

Numerous fires have started burning across the region over the past several weeks, while dozens of holdover fires — the remnants of last year’s fires that smouldered in the ground throughout the winter, including under the snow — are flaring up. 

Holdover fires are a particular concern because northeast drought conditions remain the worst in the province. The region’s 2023 fires, such as the Donnie Creek fire, which burned an area larger than Prince Edward Island, were the biggest B.C. has ever seen. In the forests around Fort Nelson, two substantial holdover fires to the north and east of the evacuated communities now span nearly 100,000 hectares, adding to worries about the Parker Lake blaze.

“In the past, the winter conditions are what put out a lot of holdover fires,” Ma told reporters at the press conference. “In this case, what we’ve seen is that due to higher temperatures and persistent drought … from last year, many of these holdover fires were not put out the way that they normally are.”

Chapman said it’s often not clear how widespread and potentially volatile a smouldering fire might be until the spring, even though some can be tracked to a certain extent through the winter.  

“That’s a big reason why we sent an incident management team up to Fort Nelson ahead of this Parker Lake fire, knowing that this cold front would likely expose where the holdover fires were still carrying heat,” he said. “And that’s exactly what happened.”

The Parker Lake fire itself is not a holdover — it’s listed as human-caused and is still under investigation. That doesn’t mean it was set intentionally. A human-caused fire can include fire accidentally lit by a number of causes, such as a spark from an off-road vehicle or gunshot, industrial activity or a cigarette ember. Most fires in B.C. are caused by lightning, but earlier in the season wildfires are more likely to be sparked due to human carelessness or human activity on the landscape.

Around the world, the size and intensity of wildfires are increasing as the impacts of climate change deepen. 

As Juliette Biao Koudenoukpo, with the United Nations forum on forests, wrote last year, “climate change exacerbates wildfire risk through increased drought, high air temperatures, low relative humidity, dry lightning and strong winds.”

The conditions in northeast B.C. are consistent with research connecting climate change-related events like the 2021 heat dome that settled over the west to bigger, faster-moving and more destructive fires on the landscape. At higher latitudes, overall warming is more pronounced, stacking the odds against a mild fire season. When temperatures rise and less rain and snow falls, forests become drier year after year. In such conditions, all it takes is one spark.  

BC Energy Regulator issues early water use suspensions for oil and gas industry 

As northeast B.C. fires spread — including near communities like Hudson’s Hope, Doig River and Fort St. John — B.C.’s growing oil and gas industry is also impacted. The northeast is home to most of the province’s oil and gas activity, including extensive fracking operations and related infrastructure. Fracking operations are poised to increase significantly to supply LNG Canada’s new export project via the Coastal GasLink pipeline. 

Extracting gas from underground deposits uses vast amounts of freshwater — between five and 30 million litres per well, according to the Canadian Association of Petroleum Producers. Last year, oil and gas producers in B.C. faced early and prolonged water-use restrictions due to drought conditions. Because snowpack was so low this winter, dry conditions persist. Reduced flow in streams and creeks also directly impacts wildland firefighting operations as water resources needed to suppress fire and protect structures become scarcer.

Three oil and gas companies have reported wildfire-related impacts so far this year, according to the BC Energy Regulator, the B.C. government’s regulatory body in charge of permitting oil and gas and other energy-related activities. 

In an emailed statement in response to questions from The Narwhal, the regulator said it works closely with the BC Wildfire Service “to help ensure safe pipeline crossings and support the redeployment of equipment to sites deemed to be most at risk.” 

“We can also act as a liaison between the [wildfire service] and companies to help [firefighters] access permit holders’ fresh water storage sites for fire suppression activities,” a spokesperson said in the email.

The spokesperson did not name the affected companies prior to publication nor provide any details.

B.C. Energy Minister Josie Osborne said the regulator “is very much on top of things” when it comes to drought and fire. In a telephone interview with The Narwhal, Osborne said the regulator monitors industry water usage and has already issued suspensions in the northeast this year. 

“We are facing a drought and we know that snowpack conditions are lower, especially up in the Peace River,” she said. “They have the ability to limit and suspend water use and they have done so under Section 10 of the Water Sustainability Act.”

The BC Energy Regulator warned industry of potential water shortages in January but, at the time of publication, it had not yet published any directives on its website.

Speaking about the impacts of fire on industrial operations, Osborne said the province’s priority is safety and noted companies keep a close eye on the spread of wildfire. 

“People — workers — might need to be evacuated,” she explained. “They take it very seriously. I know that [from] talking with them and understanding when different parts of their operations need to cease to keep people safe and to keep equipment safe and keep the environment safe.”

The BC Energy Regulator spokesperson said companies are required to have plans for emergencies, including wildfires, and directed The Narwhal to its interactive map supporting oil and gas permit holders. 

“Site preparedness such as clean pads, prompt removal of vegetation and debris provides a robust level of preventative protection from wildfires finding a source of ignition on a site,” the spokesperson wrote. “Pipelines are buried at a significant depth below ground and are not directly affected by wildfires. Above ground piping is typically insulated and then reinforced by a metal jacket. Risks to exposed piping are minimized due to both the insulation and proper site management.”

While companies can generally protect facilities from wildfire, the risk of industry causing a fire, through a gas leak or other activity, is higher when forests are bone-dry. In mid-April, a TC Energy pipeline in Alberta ruptured, setting fire to the surrounding forest. The fire was contained fairly quickly and the cause of the rupture remains unknown.

B.C. officials tell people to ‘take extra, extra care’

Every night since people were forced to evacuate, a group of drummers has gathered outside the North Peace arena in Fort St. John to drum and sing for healing and to offer prayers for the community and to those fighting the fires. 

While the fires in the northeast continue to burn, the forests are dry across the province. Emergency Management Minister Ma stressed the public needs to be especially careful when going out into fire-prone areas this coming long weekend.

“Even if there are no fire bans in place, folks who are going out into the wilderness to go camping, we need people to take extra, extra care,” she said.

Chapman added he hopes people do still go out to enjoy the backcountry and urged people to pay attention to their surroundings. 

“You also become our eyes and ears in some of the remote areas of B.C. and you’re able to call in these fires,” he said. “If you see something, please call it in — even if you think it’s already been called in, please call it in so that we can continue to respond as quickly as we can.”

Follow @BCGovFireInfo on X and connect with your local municipality or regional district on Facebook. Download the BC Wildfire Service app on Apple or GooglePlay for information about evacuation alerts or orders. Make a plan using B.C.’s emergency ready service and prepare a grab-and-go bag. If you see a wildfire, please call 1-800-663-5555 or *5555 on a cell phone to report.

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Last week, the Alberta government released a draft map outlining new buffer zones prohibiting new wind energy developments, saying “wind projects are no longer permitted in the buffer zones due to the impact of their vertical footprint.” 

Speaking to the media in late February, Alberta’s Affordability and Utilities Minister Nathan Neudorf had announced the government’s plan to establish 35-kilometre buffer zones around protected areas and other “pristine viewscapes.” Neudorf added there is no universal definition of what constitutes a pristine viewscape, but generally refers to “areas that are unobstructed, natural landscapes.”

The buffer zones in the draft map encompass much of the eastern slopes of the Rocky Mountains, extending as far east as Calgary. It’s an area dotted with oil and gas facilities and coal mines. Much of the area has been farmed or logged.

In other areas not totally off-limits, the government said renewable energy projects will have to pass through increased regulatory scrutiny in the form of “visual impact assessments.”

As Evan Wilson of the Canadian Renewable Energy Association has pointed out, the Alberta government’s new rules — from pristine viewscapes and beyond — apply only to the renewables industry. “Why is this something that is just impacting wind and solar?” he asked, speaking to CBC. 

Wind turbines have been getting larger, with towers double the average height compared to 20 years ago, and some new turbines stretching upwards of 200 metres tall. Other permitted activities are not as tall as a turbine, but that doesn’t mean they should be treated differently, according to the Alberta Utilities Commission. 

The commission, the regulator of power development in the province which conducted the government-ordered inquiry into renewable energy development, said in its first report any prohibition to “achieve viewscape protection” should be “industry agnostic” and “apply to all forms of development within the restricted zone.”

A spokesperson for Neudorf confirmed only new wind energy projects would be barred from the buffer zones, but said all forms of generation, including natural gas plants, would be subject to visual impact assessments in other specified areas.

Geoff Scotton, a spokesperson for the Alberta Utilities Commission, said the organization has no information on when areas off-limits to wind development will be more clearly defined and that it is “up to the Government of Alberta.”

With wind energy likely off the table in large swaths of the province — and new restrictions on solar farms in others — here’s a look at some of the things Albertans can still do in those “unobstructed, natural landscapes.”

1. Urban sprawl is continuing in Alberta’s draft ‘pristine viewscape’ regions

As the Alberta government seeks to create buffer zones around many of the Rocky Mountain national parks — extending as far east as Calgary — there has been no indication that construction would be stopped on new developments and urban sprawl. 

In Canmore — approximately five kilometres from the boundary of Banff National Park — plans have forged ahead for a massive new development that would take up almost all of its remaining developable land, nearly double the population and eat into critical wildlife habitat.

In Calgary, numerous new communities have been approved on the city’s outskirts extending west towards Bragg Creek. Cochrane too has seen rapid population growth — a 23 per cent increase in five years and much faster than officials had predicted — and now predicts “increased demand for land to support this growth.”

All of this means urban boundaries are likely to sprawl farther, into land that is part of the government’s buffer around pristine viewscapes and protected areas. 

2. Logging applications are ongoing in Kananaskis Country — now off limits to new wind energy projects

Kananaskis Country is something of an iconic outdoor destination for Calgarians and tourists alike — more than four million people visited in 2023. In Kananaskis, provincial parks are knitted together with public lands and recreation areas with varying levels of protection: some are off limits to most activities while others are open to industry. Just 60 per cent of the region is fully protected.

That means logging continues in the area — with cutblocks often earmarked smackdab in the middle of wilderness destinations. According to the Alberta government’s new map of buffer zones, no wind turbines will be allowed in Kananaskis Country, but the government has made no similar move to create a blanket ban on logging. Plans to log areas like West Bragg Creek, for example, are moving ahead. Canadian forestry company West Fraser Timber, which recently bought Alberta-based Spray Lake Sawmills, is allowed to log approximately 800 hectares in the area in 2026.

3. Investments in pulp mill is being celebrated by the government just outside of Jasper National Park

Farther north, West Fraser Timber also has rights to log a wide area along the border with Jasper National Park, and just days after the buffer zone map was released, the government celebrated investment in an existing pulp mill in Hinton, within the no-go zone for wind turbines.

“Our investment-friendly policies, competitive corporate tax rate and highly educated workforce continue to draw in world-class companies that can feel confident about spending their money here,” a government statement said as the new investments in the pulp mill were announced.

4. Coal mining is not explicitly prohibited under Alberta’s new draft ‘pristine viewscape’ plans

The eastern slopes of the Rocky Mountains were the focus of much outrage when the previous United Conservative Party government tried to open up large swaths of them to coal mining in 2020. That decision was ultimately reversed, but a number of projects — essentially grandfathered in — were allowed to carry on. Coal mines are currently operating in communities from Grande Cache to Hinton, which are areas that overlap with the Alberta government’s new draft map of buffer zones around protected areas, with a large focus on the eastern slopes of the Rocky Mountains. 

In March 2022, the Government of Alberta decided four “advanced” coal mine proposals would be allowed to proceed despite a moratorium on coal development in Alberta’s eastern slopes. 

Those advanced proposals include Summit Coal Mine 14. That new project will be four kilometres northeast of Grande Cache on Grande Mountain, a forested peak popular with hikers, horseback riders and snowmobilers, that is within the new no-go zone for wind turbines. The mine would create a footprint of 53.5 hectares on the mountain and would involve 91 drill holes, creating an underground footprint of 512 hectares.

The Northback Grassy Mountain open-pit coal mine is currently being considered by the provincial regulator even after it was rejected twice in previous years, and new mining activities are underway at the Vista Mine near Hinton — both of which fall into the buffer zones on the government’s draft map.

5. There are no blanket bans on what landowners can do with their land, from RV storage fields to mega mansions

The Alberta government’s ban on wind turbines in buffer zones around protected areas and pristine viewscapes includes large swaths of private land. Landowners will no longer be permitted to agree to lease their land to a renewable energy company to build wind turbines — but they can’t say no to leasing it to an oil and gas company. 

The government has also made no moves to restrict other uses of private land: from building mega mansions to starting RV storage lots, both of which can be a common site along some stretches. Landowners must apply for the necessary development permits but face no blanket ban based on their impacts on the viewscapes or protected areas.

6. Drilling for oil and gas continues across much of the province, including in wind energy no-go zones

Oil and gas wells are a common sight on Alberta’s landscape, stretching from the mountains all the way into Saskatchewan to the east. 

In 2024, there were 328,436 wells in Alberta that had not yet been reclaimed. Approximately 157,000 of them are currently active and producing fossil fuels. 

The Alberta government has not announced any new restrictions on oil and gas development in the buffer zones now off limits to wind turbines.

7. Fracking is using increasing amounts of water in areas off-limits to new wind energy projects

The buffer zone is a hotbed of hydraulic fracturing, or fracking, in Alberta.

The major formations where oil and gas is held in tight, rocky spaces far underground all kiss the edge of the western buffer zone. This includes the Cardium formation, which extends the length of the zone from Grande Prairie in the north down to the U.S. border.

Fracking activity is sparse in the south, picks up west of Calgary and then intensifies dramatically moving north adjacent to Jasper.

As drought threatens the province, new drilling continues to be approved by the Alberta Energy Regulator — though some areas are facing the possibility of such an intense water shortage that fossil fuel companies have been warned they might be forced to cut back. 

Overall water use for fracking saw a 252 per cent increase between 2013 and 2022. Intensity of water use has increased even more, a 260 per cent change, according to the regulator. 

In 2022 producers used 25.4 billion litres of water for fracking.

Updated on April 4, 2024, at 2:44 p.m. MT: This story was updated to say the pulp mill near Hinton is not new, as previously stated, but will receive significant investments under a new owner.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Last year was the hottest in recorded history and British Columbia’s worst-ever wildfire season, with so-called “zombie fires” still smouldering this winter. Much of the province remains in extreme drought conditions, with farmers facing another year of crop losses and the prospect of having to cull livestock. Wild salmon populations across the province continue to decline, sending ripple effects through coastal and interior ecosystems. 

The United Nations is unequivocal about the cause.

“Fossil fuels — coal, oil and gas — are by far the largest contributor to global climate change, accounting for over 75 per cent of global greenhouse gas emissions and nearly 90 per cent of all carbon dioxide emissions,” the international body notes on its website. 

B.C. is on the cusp of exponentially increasing its methane and carbon emissions as liquefied natural gas (LNG) projects get underway. The gas, commonly extracted from underground deposits through a process called hydraulic fracturing, or fracking, is then cooled to -160 C to take a denser liquid form that’s easier to transport. It is mostly composed of methane, which is 80 times more powerful than carbon dioxide over a 20 year period in terms of heating the planet. 

At the end of the Douglas Channel, a 100-kilometre inlet on B.C.’s north coast, a massive change is taking shape. Soon, the first gas liquefaction and export facility to be built in Canada will light up the night sky as it starts operations with a dramatic flare of burning gas. LNG Canada is poised to bring its processing plant online in Kitimat, B.C., receiving gas from the province’s northeast via the Coastal GasLink pipeline and readying it for shipping across the Pacific Ocean. To the north, the proposed Ksi Lisims floating LNG plant is currently undergoing environmental assessment. The Nisg̱a’a-led project would receive gas from Prince Rupert Gas Transmission, an approved pipeline TC Energy sold to the Nisg̱a’a Nation and its Texas-based partner, Western LNG, on March 14.

As it does, B.C. will enter a new chapter of industrial development, kicking off a long-promised boom and potentially paving the way for further expansion of the province’s fossil fuel sector. 

Here’s what you need to know about five projects underway and proposed in the northwest. 

1. LNG Canada: climate questions remain as B.C.’s first major LNG export facility gets ready to ship mid-decade

LNG Canada is owned by a consortium of foreign corporations: Shell, Petronas, PetroChina, Mitsubishi and Korea Gas. 

Malaysia’s state-owned Petronas is gearing up to exploit its tenures in what’s known as the Montney Formation, a vast underground shale complex about the size of New Brunswick and Nova Scotia combined. The Montney lies under Treaty 8 First Nations’ territories in both B.C. and Alberta. Petronas will supply LNG Canada with most of the gas and the Chinese, Japanese and South Korean companies are ready to receive shipments. Shell Canada, a subsidiary of Royal Dutch Shell, is stickhandling the rest, navigating government policies and regulations and negotiating what has amounted to billions of dollars in provincial and federal subsidies.

Teresa Waddington, a senior executive with LNG Canada, said the project is playing a major role in providing jobs and economic benefits to British Columbians.

“I’ve seen the signatures in Sharpies on the underside of pipes, inside the vessels and all the other places where these Canadians are demonstrating their pride in being part of the building and bringing an entirely new industry to Canada,” she said at the BC Natural Resources Forum in Prince George in January. “The time is now and we are almost there. It is remarkable.” 

Waddington added the project will produce LNG “at one of the lowest greenhouse gas [intensities] in the world today,” comparing it to similar facilities in operation in the U.S. and other countries.

LNG Canada was approved by B.C. to power its plant by burning gas and holds a 40-year export licence issued by the Canada Energy Regulator. The project, if it proceeds at full capacity as approved for the next four decades, will add more than 500 megatonnes of equivalent carbon emissions to the Earth’s atmosphere, according to analysis by the Canadian Centre for Policy Alternatives. That’s more than the entire remaining carbon budget allocated to Switzerland for the rest of the century. 

When factoring in the extraction, pipeline transportation and cooling of the liquefied natural gas that LNG Canada will ship, B.C.’s reductions targets — to lower emissions by 40 per cent below 2007 levels by 2030 and reach net-zero by 2050 — are virtually impossible to achieve. Those targets, part of the province’s CleanBC plan, came into effect after the project was approved by former premier Christy Clark’s government. 

LNG proponents often point to how the gas can help countries like China, Japan and Korea reduce reliance on other fossil fuels, such as coal, leading to a reduction in global emissions. That argument is contested by climate scientists who maintain methane emitted during the extraction, processing and transport of the fossil fuel, including leaks at every step of the process, make LNG worse for the climate than coal. Critics also argue there’s no proof that gas exported from B.C. will be used to displace coal.

The consortium of companies behind LNG Canada is eyeing electrification, which would significantly reduce its greenhouse gas emissions. But powering the facility with clean energy would divert much-needed power away from other sectors.

“If they were going to try to reduce their emissions using electricity, and they did that upstream, along the pipeline and at the plant, they would need about two Site C [dams] worth of electricity,” Merran Smith, executive director of Clean Energy Canada, told The Narwhal in a previous interview.

BC Hydro recently put out a call for new power proposals, which could include reviving long-languishing wind and solar projects. B.C. Premier David Eby announced in January the province was giving the public utility $36 billion to build out community and regional infrastructure over the next decade.

“We must expand our electrical system like never before, to power industrial development, to power our homes and businesses, to power our future,” Eby said.

The liquefaction and export facility will begin its “commissioning” activities this year to ready the plant for full-scale operations. A spokesperson with LNG Canada told The Narwhal some of those activities have already started.

“At this time, we don’t have a hard date for start-up activities, but they are expected to begin this year,” the spokesperson wrote in an email. “Start-up activities (testing of systems and sub-systems where natural gas is introduced) will include flaring. Local residents and stakeholders will be advised prior to the commencement of activities such as flaring.”

2. Coastal GasLink: mechanically completed, the controversial pipeline is poised to start shipping gas across northern B.C., including through Wet’suwet’en territory

Before the gas can be shipped from the liquefaction facility, it needs to be transported across the province via the Coastal GasLink pipeline. Coastal GasLink will transport 2.1 billion cubic feet of gas to LNG Canada daily to start, doubling that amount if the liquefaction facility goes ahead with its approved plans for a second phase. 

In November, Coastal GasLink announced it had finished building its pipeline, the first to connect underground shale formations in B.C.’s northeast to marine shipping routes on the Pacific coast in decades. Under the terms of its environmental assessment certificate, the pipeline company will now conduct reclamation activities along the 670-kilometre project.

During construction, the pipeline project, built by Alberta-based TC Energy, was marred by controversy, delays and cost overruns. Coastal GasLink has cost more than double its original estimate, with a final price tag of around $14.5 billion. TC Energy is a minority shareholder, after selling most of its shares in 2020 to U.S.-based KKR Investments and the Alberta Investment Management Corporation (AIMCo), a Crown corporation that manages $160 billion of the province’s public pension, endowment and government funds. TC Energy also inked an agreement with 16 elected First Nations governments in 2022, giving them the option to collectively buy a 10 per-cent equity share of the pipeline. 

Since starting construction in 2019, the project has repeatedly failed to meet environmental regulations, earning the company more than $800,000 in fines levied by the B.C. government, to date. Those failures have resulted in impacts to wild salmon habitat, endangered whitebark pine and sensitive wetlands that support innumerable species.

As TC Energy navigated challenges and criticism, the pipeline company regularly maintained its work was permitted and regulated by provincial and federal authorities. 

“Coastal GasLink is a complex project and is subject to some of the most stringent regulatory requirements in the world,” the company told The Narwhal last year. “Coastal GasLink respects the role our regulators have in upholding the high regulatory standards we are committed to meeting. Those high standards matter to Indigenous and local communities, to the people of British Columbia and they matter to us.”

The pipeline has faced strong opposition from Wet’suwet’en Hereditary Chiefs and their supporters since its approval in 2014. Despite the province and the pipeline company signing deals with five of six elected band councils, neither received consent from the Hereditary Chiefs, whose authority and jurisdiction over the 22,000-square-kilometre territory was affirmed in a landmark Supreme Court of Canada ruling in 1997. 

When the Hereditary Chiefs and their supporters tried to prevent the pipeline from being built across the territory, the company successfully petitioned the B.C. Supreme Court for an injunction against anyone interfering with construction. The ensuing conflicts led to more than 80 arrests of Wet’suwet’en land defenders and their supporters, allegations of RCMP misconduct and international scrutiny. Court proceedings are ongoing.

3. Prince Rupert Gas Transmission: once a ‘pipeline to nowhere’, construction on TC Energy’s approved 900-kilometre project could be getting underway this year

As work on Coastal GasLink winds down, TC Energy could be getting ready to start building another gas pipeline across the north. 

The Prince Rupert Gas Transmission project would connect Montney gas to Ksi Lisims, a proposed liquefaction and export facility on Nisg̱a’a territory. Approved by the B.C. government around the same time as Coastal GasLink, the pipeline would span around 900 kilometres and cross the Kispiox and Skeena rivers and traverse Nilkitkwa Lake at the headwaters of the Babine River. The project was originally approved to supply Pacific NorthWest LNG, a Petronas liquefaction facility that was to be built on Lelu Island, near Prince Rupert, B.C. The Malaysian-owned company pulled the plug on its project in 2017, stranding the pipeline — until now. If all goes ahead, TC Energy would shorten its approved route by around 100 kilometres.

TC Energy has until the end of 2024 to put enough work into the project to receive a “substantially started” designation, which would secure its environmental assessment certificate indefinitely.

“At this preliminary stage, we are focused on evaluating regulatory and future options, which would be subject to further agreements being entered into,” TC Energy told Natural Gas World in October. “No final investment decisions have been made.”

On March 14, the pipeline company announced it was selling its interests in the project to the Nisg̱a’a Nation and Western LNG, a Texas-based fossil fuel company.

Shannon McPhail, executive director of the Skeena Watershed Conservation Coalition, said the B.C. government should reexamine its approval of the project in light of climate and biodiversity. 

“Everyone agrees we are in a climate crisis,” she told The Narwhal in an interview. “Everyone agrees that we are at risk of biodiversity loss and we will likely experience ecosystem collapse. And all of that is being perpetuated by things that are lawfully and legally permitted by our governments.”

McPhail continually called on provincial and federal regulators to hold TC Energy accountable during the construction of Coastal GasLink and alleges the various government agencies failed their mandates to protect ecosystems, including fish habitat. 

As The Narwhal recently reported, the B.C. Energy Regulator signed off on numerous alleged environmental infractions and Fisheries and Oceans Canada withheld related information from the public and media on multiple occasions. McPhail said northern watersheds are at a tipping point and any more pressures could send ecosystems into an irreversible spiral, impacting communities throughout the region. 

“We’re in a drought province-wide,” she said. “People’s wells in the Kispiox Valley are drying up — they can’t water their livestock and they haven’t had enough snow for livestock to eat or drink. There’s no way we can balance the Prince Rupert Gas Transmission pipeline project to be built through all of this forest when we’re predicted to have a wildfire season worse than last year.”

4. Ksi Lisims: the Nisg̱a’a-led liquefaction and export facility continues through B.C.’s environmental assessment process as neighbouring First Nations and communities raise concerns 

According to Nisg̱a’a Nation President Eva Clayton, Ksi Lisims offers a “transformational opportunity” for the nation to build its economy. The proposed project, a floating gas liquefaction and export facility that would be built near the village of Gingolx, is led by the Nisg̱a’a Nation in partnership with a consortium of B.C. and Alberta gas producers and a Texas-based LNG company.

“The Nisg̱a’a Nation has long tried to establish an economic base in the Nass Valley,” Clayton said at the natural resources forum in Prince George. “And [Ksi Lisims] is one that we want to do in a way that agrees with our principles and our values, as we live in harmony with our lands and we move forward with building that economic base.”

Last year, Nisg̱a’a and its partners signed an agreement with TC Energy for the pipeline supply and in early January, Ksi Lisims signed a 20-year agreement with Shell to sell two million tonnes of LNG annually to the fossil fuel giant. If approved, the liquefaction facility would process and ship 12 million tonnes per year. It plans to use electricity supplied by BC Hydro to cool the gas, though it is unclear how the public utility would generate enough power to meet the project’s needs and continue providing electricity to other sectors. 

The proposed project is currently undergoing environmental assessment. During a recent public comment period on Ksi Lisims’ application to the government, the province’s Environmental Assessment Office received 536 submissions, many expressing concerns about the project’s potential impacts to climate, species like salmon, other ecological impacts and the Indigenous Rights of interior and coastal First Nations. Even the City of Terrace — no stranger to industrial development; long a hub for mining and forestry activities — weighed in with concerns that the influx of activity associated with LNG Canada put considerable strain on communities without providing any substantial economic benefits, noting that pattern would likely repeat if Ksi Lisims is built.

The proponent will now revise its application for government review and the public will have one more opportunity to weigh in before a decision is made.

5. Cedar LNG: Haisla chief councillor says the Kitimat-based floating LNG plant represents a ‘path to achieve healing’

Last March, the B.C. government approved Cedar LNG, a partnership between the Haisla Nation and Pembina Pipeline Corporation. Touted as the first Indigenous-majority-owned LNG facility (Ksi Lisims could be the second), the floating liquefaction and export terminal would be built on the Douglas Channel across from the Haisla village of Kitamaat, a few kilometres from LNG Canada. 

Cedar LNG will also receive gas from Coastal GasLink and plans to export three million tonnes annually, about 30 per cent of what its larger neighbour LNG Canada plans to ship during its first phase. 

Crystal Smith, Haisla’s elected chief councillor, got emotional as she addressed attendees at the Prince George conference. She said collaborating with LNG Canada, and advancing the nation’s own project, is starting to address an economic imbalance between settlers and Indigenous peoples.

“Something I’m profoundly impacted by is our ability to fund the programs that really connect our people to their culture and our language, a language that has virtually disappeared in my generation,” she said. “We are reigniting our potential through culture and language and that is perhaps the most powerful thing of all. When I think of my daughter speaking Haisla with my grandchildren, that is what drives me each and every day.”

Cedar LNG, to Smith, represents a shift away from a long history of exploitation of resources by colonizers towards a more equitable and collaborative approach. 

This was a common thread throughout the conference. While the gathering was awash with land acknowledgements and talk of partnerships and collaboration with First Nations, an undercurrent of leveraging social license to support industrial development buoyed discussions. Gaining that social license and creating those partnerships could result in channelling much-needed benefits to First Nations, long left out of the resource sector and forced into poverty by colonial genocide. 

Smith said Haisla’s role as owner of the project represents the beginning of a new chapter for First Nations.

“While our focus right now is advancing Cedar LNG, that is not the end of our journey,” she said. “It is the start of how we want to work together to advance reconciliation and achieve equality for Indigenous Peoples everywhere.”

“I am as unapologetic today as I was when I say that economic development and reconciliation is the path to achieve healing for our people.”

Updated on March 14, 2024, at 2:57 p.m. PST: This story has been updated to include news that TC Energy is selling its Prince Rupert Gas Transmission pipeline to the Nisg̱a’a Nation and Western LNG.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.