The oil and gas industry has a track record of running roughshod over the science of climate change in pursuit of massive profits, while financially backing organizations that spread doubt and misinformation about the dangers of fossil fuels.

What might surprise Canadians, however, is that arguably some of the most consequential examples of climate denial in history happened back in the 1950s and 1960s, long before climate science went mainstream, and involved a key project in Alberta.

The details have been gathered into a forthcoming book by Canadian investigative journalist Geoff Dembicki called The Petroleum Papers: Inside The Far Right Conspiracy To Cover Up Climate Change, due to be published Sept. 20 by Greystone Books.

Dembicki’s book highlights decades of effort by oil companies and the organizations that lobby for them to distract from the environmental destruction their products create by building, in his words, “an edifice of lies,” meant to anticipate and blunt public anger over climate change and its causes.

In an interview, he said the book’s central message is that, far from being a bit player, Canada’s oilsands industry has played a “profound role” in how Americans deal with the climate emergency, due to the enormous amounts of money, time and expertise that U.S. companies have sunk into making high-carbon oilsands projects profitable.

“A lot of the companies that had the biggest financial stakes in the oilsands, such as Exxon, were really key to leading disinformation campaigns in the 1990s and 2000s. That had a huge role in blocking solutions to climate change, when we really could have gotten good control of the emergency,” Dembicki told The Narwhal.

“The point I really want to drive home is that Canada has played a huge, underexplored role in the ability of one of the world’s largest emitters to deal with this problem.”

The birth of Alberta’s oilsands and the first climate warnings to industry

Dembicki’s book takes a close look at Philadelphia-based Sun Oil, a company that would eventually spawn Suncor.

These days, Suncor is one of Canada’s multibillion-dollar oilsands producers, pumping out over 600,000 barrels per day of petroleum products from its oilsands holdings, while producing tens of millions of tonnes of carbon pollution in the process.

Sun Oil had been present in Canada since the 1920s, selling gasoline imported from the United States branded as “Sunoco,” a condensation of SUN Oil COmpany. (After corporate acquisitions, Sunoco-branded gas stations in Canada were converted to Petro-Canada branding, while in the U.S. they are now controlled by a Dallas-based energy firm.)

In 1949, Sun Oil began examining oilsands development and established a division in Calgary, and by 1950 the company had launched a drilling program and acquired “Lease 86,” where Suncor’s current oilsands operation would eventually be located.

Two years later, Sun Oil committed $250 million to create the Great Canadian Oil Sands company, which at the time was the largest single private investment in Canada. In 1967, the company and its subsidiaries would launch the first commercialized heavy oil megaproject in the oilsands, opening the door to exploiting the third largest proven oil reserve in the world.

The project’s success ushered in an era of explosive growth in oil production and carbon pollution in Canada. Federal figures show that between 1990 and 2020, oilsands production jumped more than 725 per cent, while emissions soared by over 430 per cent. As of 2020, the oilsands represented the largest portion of oil and gas emissions in Canada, at 81 million tonnes, a figure that represents more carbon pollution than the economies of B.C. or Quebec.

The Great Canadian Oil Sands plant is now considered a “landmark” by the Alberta government. It calls the company a “pioneer” that slogged through years of operational mishaps, like jammed crushers and frozen conveyor belts, to eventually turn a profit in 1975. Suncor describes its early efforts in Alberta as resulting from “perseverance, dedication and innovation” that proved the skeptics wrong.

But as Dembicki argues, Sun Oil followed through with this massive project in the 1960s even as the firm was exposed to clear scientific warnings about the dangers of unchecked greenhouse gas emissions.

The climate warnings came in two distinct moments. The first was a November 1959 symposium in New York City called Energy and Man, organized by Columbia University and the lobby group the American Petroleum Institute. That event featured “one of the earliest known climate change warnings to the oil and gas industry,” Dembicki wrote.

Speaking at the event was Robert Dunlop, then president of Sun Oil and also a director at the petroleum institute at the time. He promised during his speech to “listen with the keenest attention” to another speaker, Edward Teller, a nuclear weapons physicist.

Teller would inform the influential crowd that burning fuel creates carbon dioxide that ends up in the atmosphere, causing a “greenhouse effect” that is heating up the Earth.

“It has been calculated that a temperature rise corresponding to a 10 per cent increase in carbon dioxide will be sufficient to melt the icecap and submerge New York,” he said.

“All the coastal cities would be covered, and since a considerable percentage of the human race lives in coastal regions, I think that this chemical contamination is more serious than most people tend to believe.”

Dunlop would later argue in 1967 in front of the U.S. Congress, as chair of the petroleum institute, that toxic fumes from internal-combustion engines, like carbon monoxide, nitrous oxide and unburned hydrocarbons would eventually be “controlled.”

Although this prediction would come to pass, as most gas-powered vehicles in the United States began to be fitted with catalytic converters by the mid-1970s to comply with tighter exhaust regulations, the technology doesn’t eliminate emissions of carbon dioxide, the main greenhouse gas.

Dunlop didn’t raise the issue of carbon dioxide in his comments to Congress either. One of Dunlop’s top priorities at the company following the “Energy and Man” conference would be to figure out how to develop Alberta’s oilsands, Dembicki wrote.

As Great Canadian Oil Sands was just starting operations, Dunlop would again be exposed to a clear warning, this time from a report commissioned by the petroleum institute. The group had asked scientists at the Stanford Research Institute to study the link between the oil and gas industry and the Earth’s temperature rise.

Their 1968 report was clear: concentrations of carbon dioxide in the atmosphere were climbing fast, and the only explanation that made scientific sense was that it was the unrelenting burning of fossil fuels. “There seems to be no doubt that the potential damage to our environment could be severe,” they wrote.

The report, excerpts of which are available online, found that carbon emissions were overcoming the natural process of carbon dioxide removal, and that the temperature increase would eventually melt icecaps, leading to sea level rise and consequential environmental damage. They then concluded that research needed to be urgently directed towards technologies to control emissions.

By that time, Sun Oil was already sending oilsands oil down a pipeline from Fort McMurray to a refinery in Sarnia, Ont., and heading into Alberta’s history books as achieving a “certain level of glory.” Suncor itself would officially form in 1979, when the Canadian operations of Sun Oil merged with the Great Canadian Oil Sands company.

The company has made some effort in recent years to soften concerns over its climate impact. It has supported carbon pricing, said it intends to offer more “low- carbon fuels” and promised to cut its emissions and reach “net zero” emissions by 2050, although this pledge doesn’t include the majority of its carbon pollution, which comes from the burning of its products.

Suncor, however, has recently lobbied against climate transparency measures. The company’s former chief executive Mark Little recently stepped down following news reports of a string of worker deaths at company facilities. The death of a 26-year-old contractor near Fort McMurray in July was the fifth such workplace fatality since 2021.

Prosperity in the oilsands has played a huge role in wealth generation for companies in Alberta, as well as the provincial government, and to a certain extent, Albertans themselves. The royalties from bitumen, the tar-like petroleum substance derived from the oilsands, have poured billions of dollars into provincial coffers. The International Energy Agency estimates that over five per cent of workers in Alberta are employed in the oil and gas industry. Many more indirect jobs exist to supply industry needs as well as support the daily activity of industry workers.

At the same time, Sun Oil’s first oilsands megaproject, and a second megaproject that would come in the 1970s, both received significant levels of public funding to help them succeed. And there have been persistent questions about whether the riches generated from the oilsands have been fairly distributed to Albertans.

The Narwhal asked Suncor for its response to the book’s arguments and to comment on the company’s history when it came to heeding the many scientific warnings about climate change, but has not heard back.

The religious connection that greased the oilsands wheels

Dembicki outlines in his book how the wheels for Sun Oil’s oilsands megaproject were greased by the religious worldviews of Dunlop’s predecessor, former Sun Oil president J. Howard Pew, as well as then-Alberta premier Ernest Manning. Both men felt that North American oil needed to be urgently exploited.

The Pew name is associated these days with the Pew Charitable Trusts and the Pew Research Center it established, but in the early 1960s, Pew, a Christian libertarian, was able to get Manning’s approval to get an oilsands operation started in Alberta, after the two exchanged letters riddled with Biblical references.

Dembicki’s book quotes extensive research done by Darren Dochuk, a history professor at the University of Notre Dame, who has studied the links between religion and petroleum in the United States, including in his own book, Anointed With Oil: How Christianity and Crude Made Modern America.

Through archival documents, Dochuk has shown how Pew became bent on using the oil in northern Alberta to loosen North America’s dependence on overseas oil. Pew enthusiastically showed off a file marked “Athabasca Tar Sands” in his Philadelphia office, Dochuk wrote, to anyone who would indulge him.

He talked about “America’s Christian heritage,” and gave rousing speeches on the virtues of “freedom” and “friendly competition.” He railed against the 1930s New Deal package of economic stimulus, unemployment relief and public works projects, calling it a government attempt to dominate the private sector. He defended the right for employers to lower employee wages on a whim.

Manning, meanwhile, held conservative evangelical beliefs and was a radio preacher. He wanted Alberta to generate wealth from its resources, but as a “premillennialist,” Dochuk wrote, he also believed Christ’s return was near, and that Christians needed to “extract expeditiously whatever oil was left under their soil before their dispensation expired.”

“Here is a really profound connection that is ultimately going to be instrumental in starting one of the most important, and one of the most expensive experiments in oil production in the 20th century,” said Dochuk in an interview about his research on Pew and Manning’s relationship.

Pew, who was no longer officially the head of Sun Oil by the early 1960s but was still a dominating figure in the company, began exchanging letters with Manning that referenced the Bible, discussed Presbyterian and evangelical conferences, and had religious book recommendations.

Pew asked Manning if he could cite his sermons in his public talks, Dochuk wrote, while Manning told Pew that Christians like them needed to “take an uncompromising stand for the faith” in their work.

“They saw each other as kind of brethren, if you will, within the church, sharing a similar conservative evangelical gospel,” said Dochuk.

The two became close friends. They met in person at a ceremonial unveiling of the Great Canadian Oil Sands project in 1964, and again in Jasper, Alta., in the Rockies. The friendship helped overcome a level of skepticism on Manning’s part of an American company extracting riches from Alberta’s natural resources.

Dochuk said it wasn’t an easy negotiation when it came to business and government, as Manning was a populist at heart, while Pew was a libertarian conservative.

“Nevertheless I would say that the relationship between the two men, based on their shared values, was instrumental in getting that project off the ground and running,” he said about Great Canadian Oil Sands.

While there was a possibility that climate change was a topic of concern between Pew and Manning, Dochuk added, nothing he came across in his research pointed to proof that it was.

“There was just an assumption that this was an anthropocentric project of Christian stewardship, of using the land, that this is a God-given resource,” he said.

“I don’t think (climate) was on the radar, certainly in the way that we might imagine it to be today.”

Pew’s views, and Manning’s views, don’t represent the entirety of Christian ideology when it comes to climate change today.

In fact, dozens of Christian organizations and institutions around the world divested from fossil fuels in 2021. The Vatican itself has asked Catholics to divest from the oil and gas industry.

The World Council of Churches, which has declared its support for climate justice, issued a statement at the outcome of the last United Nations Climate Change Conference that expressed “disappointment and dismay” at the extent of progress by governments to commit to addressing the climate crisis.

Human beings are “dependent on the divinely created web of life for our well-being” and “carry the responsibility to care for God’s creation,” the council’s statement read, adding “sisters and brothers in poor, vulnerable and marginalized communities are facing the worst impacts of climate change while those responsible for the crisis continue to resist the demands of solidarity and justice.”

More warnings on emissions at the dawn of the Syncrude oilsands megaproject

Dembicki’s book shows how Sun Oil’s success in the oilsands was soon followed by a second megaproject backed by the American oil behemoth, Exxon, which by 1970 had grown to become the second largest corporation in the United States.

By this time, Exxon had long been the majority owner of Canadian oil company Imperial Oil, and that ownership structure continues to this day. Similar to Sun Oil’s experience, officials at Imperial Oil were also exposed to early warnings about climate change, even as the company was setting up its own oilsands megaproject, Dembicki wrote.

At first, Imperial Oil, through a partnership with Los Angeles-based Richfield Oil, pitched a plan to unleash a nuclear explosion in the oilsands, with the theory that it would melt the heavy oil and allow for easy pumping to the surface.

After that disastrous idea was put on ice in the late 1950s, Imperial Oil and its partners launched Syncrude, a joint effort that was first established in 1965, with preparations at a site at Mildred Lake beginning in 1973 and production starting in 1978.

The Syncrude megaproject, which grew to produce over three billion barrels of oil by 2019, was put into motion after the company was warned by internal scientists on three separate occasions in the 1970s about the dangers of fossil fuel use.

The first warning came in 1970 from an Imperial Oil chemical engineer working in Sarnia, Ont. The scientist’s report, “Pollution Is Everybody’s Business,” included a description of “air pollutants,” one of which was carbon dioxide, which he noted came from “oxidation of plant and animal matter” and “combustion.”

“Since pollution means disaster to the affected species, the only satisfactory course of action is to prevent it — to maintain the addition of foreign matter at such levels that it can be diluted, assimilated or destroyed by natural processes — to protect man’s environment from man,” reads a line from the report.

The report also argued that pollution “cannot be dealt with on a voluntary basis” and so the “protection of the interests of society as a whole requires the establishment of legal controls on pollution, as on other anti-social acts.”

Then in 1977, a senior Exxon scientist and top expert in the company’s research and engineering arm, gave a dire presentation to the company’s management committee warning that carbon dioxide from burning fossil fuels will put humanity in danger by heating up the planet.

The scientist made it clear that “there is general scientific agreement that the most likely manner in which mankind is influencing the global climate is through carbon dioxide release from the burning of fossil fuels,” according to an investigation by InsideClimate News.

The following year he informed Exxon managers and other company scientists about research showing how average global temperatures could climb by two or three degrees Celsius as carbon dioxide became more concentrated in the atmosphere, leading to floods and droughts, and jeopardizing agriculture.

“Man has a time window of five to 10 years before the need for hard decisions regarding changes in energy strategies might become critical,” he wrote in a summary to Exxon in 1978.

At first, Exxon responded rapidly, launching an internal research body that sampled carbon dioxide and engaged in climate modelling, but by the late 1980s the company would begin scaling back the work, according to the InsideClimate News investigation, and directing its resources toward climate denial instead.

“It put its muscle behind efforts to manufacture doubt about the reality of global warming its own scientists had once confirmed. It lobbied to block federal and international action to control greenhouse gas emissions. It helped to erect a vast edifice of misinformation that stands to this day,” wrote the journalists.

Syncrude continued to operate in the decades that have followed, with Imperial Oil and its Exxon owners playing a central role in maintenance and energy management support for the project. In 2021, Suncor took over operations at Syncrude, but Imperial Oil still owns 25 per cent of the operation.

The InsideClimate News investigation, the revelations of which became known as “Exxon Knew,” was a finalist for the Pulitzer Prize in public service as well as the recipient of a White House Correspondents Association award, and other accolades.

Yet Exxon rejected the work as “deliberately cherry-picked statements” that were “taken completely out of context” and that “ignored other readily available statements demonstrating that our researchers recognized the developing nature of climate science at the time which, in fact, mirrored global understanding.”

The company continues to claim it has not misrepresented its research or climate disclosures to investors or the public, calling “Exxon Knew” a “coordinated campaign perpetuated by activist groups with the aim of stigmatizing ExxonMobil.”

Yet it also appears to continue to engage in climate denial. A U.S. congressional investigation has recently revealed internal Exxon documents showing how the company pushed for the removal of comments in a 2019 policy statement that could have committed it to advocate on decarbonization goals.

Imperial Oil says it supports the Paris climate agreement and wants to “mitigate emissions” at its facilities. Like Suncor, it has also committed to reaching “net zero emissions” by 2050. But so far it has only committed to cutting its emissions intensity, not its absolute emissions.

The Narwhal offered Imperial Oil a chance to comment on any steps the company took while involved in the origins of Syncrude to address any scientific warnings about climate change. Spokesperson Lisa Schmidt said the company has nothing to add to the story.

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The Ontario Energy Board has rejected a request to immediately investigate Ontario Power Generation (OPG) for selling $5.5 million in clean energy credits to unidentified customers outside of the province.

The energy board is tasked with regulating the province’s electricity industry in the interest of ratepayers. In May, the non-governmental organization Environmental Defence asked the board to look into Ontario Power Generation’s sale of clean energy credits, which it has been doing without government oversight. The power company has declined to identify who purchased the credits or reveal any detailed information about the sales.

In May, Ontario Power Generation said the $5.5 million revenue it earned from these sales was immaterial. In an August 25 letter to Environmental Defence lawyers it published online, the energy board agreed. Mary Ellen Beninger, a spokesperson for the board, told The Narwhal that for a company the size of Ontario Power Generation, a review would be more likely for transactions of at least $10 million.

Each clean energy credit represents one megawatt-hour of electricity from carbon-free sources that businesses and consumers can buy to meet pollution reduction targets or commitments. Environmental Defence called for an investigation into whether it was legitimate for the power generator to profit from selling what the conservation group believes to be public assets. Environmental Defence also asked the board to review how the company used the revenue.  

Other environmental organizations and the City of Ottawa wanted an investigation as well. In a separate letter to the board, Ottawa’s environment manager, Mike Fletcher, said the city was concerned these sales were “removing the environmental attributes from the electricity our community consumes” and increasing emissions from electricity.   

In her letter last week, the board’s chief commissioner, Lynne Anderson, wrote that it would be “premature” for her organization to explore Ontario Power Generation’s sale of emissions credits right now because the provincial government has decided to explore creating a registry.

Ontario currently has no official, centralized registry to sell clean energy credits. In May, The Narwhal broke the story that Ontario Power Generation had been selling credits outside of the province regardless. 

Soon after, in June 2022, Energy Minister Todd Smith instructed the Independent Electricity Systems Operator to look into creating a voluntary registry. It would legitimize sales of clean energy credits by all of the energy generators in the province and create a public accounting system. Ontario Power Generation, which is the province’s largest generator, has agreed to be regulated under such a system if it comes into place. 

The government’s public consultation on this system, which it is obligated to do by law, began in August and is open for comments until September 16. 

In her letter, Anderson said the Ontario Energy Board will monitor the government’s consultations, which she believes will be adequate for collecting public comment on sales like the ones made by the power generator. She said the issue of how revenue from such sales should be used is also within the scope of the government’s consultation, as is the issue of how clean energy credit sales should be reported, tracked and used.

Beninger told The Narwhal “there may be other matters for the OEB to consider” once the government’s consultations are over. “For example, there may be value in a [clean energy credit] reporting requirement for utilities,” she wrote in an email.

On Friday, the energy board released a series of questions it had posed to Ontario Power Generation after the calls for an investigation, with responses. Sent in July, the power generator’s answers were echoed in the energy board’s recent letter — Ontario Power Generation stated that the government consultations precluded decisions about how it would use the $5.5 million in existing revenue and how it would sell credits or manage revenue in the future. The generator also told the board that if the government did not provide any clear direction, it would propose its own regulatory process for approval.

“Such a mechanism would only address future revenues,” Ontario Power Generation told the board.

Beninger did not directly answer The Narwhal’s questions about whether it has a responsibility to ratepayers to ensure that these sales did not undermine Ontario businesses and municipalities which are calculating their own output of greenhouse gases based on an assumption that the province has a virtually emissions-free grid.

Anderson wrote that the board considered establishing “a new deferral or variance account to track any OPG revenue from the sale of [clean energy credits], but has determined that doing so at this time is not warranted.” 

“Again, these are matters best considered after completion of the Government’s consultation,” Anderson wrote.

Palmer Lockridge, a spokesperson for Energy Minister Todd Smith, told The Narwhal the minister is aware of the board’s decision. He said the proposal for the registry would allow the minister “to direct how revenues from [clean energy credits] for Ontario Power Generation should be used, including the future development of new clean energy in the province, and returning value to ratepayers.”

Kent Elson, a lawyer for Environmental Defence, said he hopes Ontario’s auditor general will investigate these sales. “We have not seen a commitment from OPG to stop or hold off on these sales,” Elson said. “That’s really concerning.”

“These continued sales could be making things worse by giving companies an excuse to keep on polluting,” Elson said.

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Ontario Power Generation made $5.5 million selling clean energy credits in a private revenue-making scheme, according to a regulatory document obtained by The Narwhal.

The $5.5 million figure was listed in documents filed with the Ontario Energy Board (OEB) in May, the day after The Narwhal disclosed the sales of the unregulated credits. At the time, the power company hadn’t publicly announced its credit sales. The energy board regulates the province’s electricity industry and is currently investigating Ontario Power Generation’s revenue-making scheme.

In the May letter, Ontario Power Generation deemed the $5.5 million sales figure “immaterial revenues.” Although it confirmed the amount to The Narwhal, the company has been secretive about its program, declining to answer questions about how it used the money, who purchased the credits and whether it was still in the business of selling the credits to customers. 

The absence of immediate answers appears to show how the company can operate without adequate oversight, and profit from province’s largely clean grid at the expense of Ontarians.

Clean energy credits are guarantees that one megawatt-hour of electricity comes from carbon-free sources like hydro, wind, solar and nuclear. Purchasing them allows businesses and consumers to claim that a certain amount of their energy comes from green sources, thus satisfying their environmental and sustainability commitments. Previously, the company told The Narwhal that its credits are based on its production of hydroelectricity.

Ontario has no official, centralized registry to track purchases of clean energy credits for electricity. The registry Ontario Power Generation has created is similar to voluntary registries that exist in more than a half-dozen U.S. states including Ohio, Pennsylvania, Illinois, Indiana and Wisconsin.

Kent Elson — a lawyer who represents the non-governmental organization Environmental Defence at Ontario Energy Board hearings and who first asked the board to investigate the sales  — told the board that Ontario Power Generation’s private credit sales could equate to approximately 6 million megawatt hours of clean energy or almost 10 per cent of the generator’s energy output. 

Ontario’s electricity grid is 94 per cent emissions free — a fact widely publicized by the power generator and the government for years. This fact forms the basis for all the emissions accounting done by Ontario municipalities and businesses. But regulators are failing to monitor whether credits sold by Ontario Power Generation to markets outside the province represent emissions-free energy that’s also being counted towards sustainability goals by locals — whether the credits are actually offsetting pollution from the buyers, or whether these buyers are paying for hot air. 

An Ontario Power Generation executive previously told The Narwhal in an interview that there is no double-counting of these credits, noting the sales are “tracked and monitored carefully” through third-party brokerage systems. 

In its May 6 letter to the energy board, Ontario Power Generation said revenue from these sales “will either flow back to ratepayers or be used to support future clean energy projects.” No evidence has been provided to The Narwhal to show this has occurred.

“The OEB is carefully considering this matter and we will be prepared to comment further at the end of our process,” Mary Ellen Beninger, a spokesperson for the board, said in an email. Beninger did not specify what the timeline of the investigation is. 

While the investigation continues, Ontario’s re-elected Progressive Conservative government is pushing forward with its plan to create a voluntary clean energy credit registry that would legitimize these sales and create a public accounting system for them. Ontario Power Generation has agreed to track its sales in this registry once it exists.

In August, Ontario posted the proposal for the registry for public feedback, as it is legally required to do. Its proposal outlines that the registry would require generators to register to certify their clean energy production, after which each sale would be tracked and each credit retired afterwards, so that environmental credits are not resold, or counted more than once. The province’s goal is to monetize Ontario’s existing emissions-free energy while also incentivizing new clean energy generation. 

In an email to The Narwhal, Palmer Lockridge, a spokesperson for Ontario’s energy minister, Todd Smith, said this type of registry is “a proven tool, used across North America and Europe, which would allow businesses to demonstrate that their electricity has been sourced from a non-emitting resource, while supporting the future development of new clean energy generation in the province and providing value to ratepayers.”

“Establishing a common registry to track the creation, trading, and retirement of all [clean energy credits] produced and consumed in Ontario will ensure transparency, accountability and preserve the cleanliness of Ontario’s electricity supply,” Lockridge wrote. 

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A majority of British Columbians agree the province’s oil and gas royalty framework is in need of comprehensive reform and say B.C. needs to develop a new system as quickly as possible that accounts for impacts to the environment, increases the economic value of the sector and reduces dependence on fossil fuels, according to the results of a provincial survey published last week.

More than 75 per cent of respondents to the Ministry of Energy, Mines and Low Carbon Innovation request for input said the current system is ineffective and noted “environmental protection” should be the highest priority when finalizing changes to the current regime.

“The message is clear: What may have worked 30 years ago does not work today and a new approach is essential for our future,” Bruce Ralston, Minister of Energy, Mines and Low Carbon Innovation, said in a statement.

The engagement process — which took place from Nov. 10 to Dec. 10, 2021 — consisted of an online survey and an open call for written submissions. Most of the respondents live and work in the Lower Mainland or on Vancouver Island, with only five per cent from the northeast and four per cent out of province. Most of those who said they live and work in the northeast or outside of B.C. were associated with an oil and gas company or industry group.

The province cautioned the results of the survey could be skewed given the voluntary nature of participation (which required participants to be aware of the process and make their way to the website.) This means respondents likely have strong views on the topic, whether for or against. 

B.C.’s royalty programs, developed more than three decades ago, were the subject of an independent assessment, commissioned by the province in 2021. The damning review found the credit programs deeply flawed and noted they may be propping up extractive and emission-intensive operations that would otherwise be uneconomical. 

The independent assessment also noted “piecemeal changes” to the credit programs over the years led to an overly complex system that became onerous and costly for the government to administer.

To date, B.C. has doled out credits to oil and gas producers through its royalty programs to the tune of more than $7 billion. Those credits, of which $3.75 billion remain on the books, reduce the revenue B.C. would have otherwise received from the extraction of fossil fuels, a public resource. 

It’s no surprise, then, that the general public is dissatisfied with the province’s oversight of the sector.

“It’s a regime that basically subsidizes production and doesn’t provide a good return to the treasury and is contrary to our climate and environmental goals,” Marc Lee, senior economist with the Canadian Centre for Policy Alternatives, told The Narwhal in an interview.

Donna Forsyth, former legislative advisor with the province, who worked on the Oil and Gas Activities Act in the mid-2000s and more recently helped draft the Water Sustainability Act, compared the current situation to making the minimum payment on a credit card.

“You’re technically doing something but you’re ignoring this exponentially increasing problem down the road,” she said in an interview. “It’s time to start paying down the debt.” 

The ministry told The Narwhal in an emailed statement it is reviewing the results in consultation with First Nations.

“A public announcement on next steps is expected in the coming months.”

Royalty review provides B.C. with opportunity to end fossil fuel subsidies

The results summarize more than 5,000 responses to the province’s engagement process — 91 per cent of which came from members of the general public. Of the 4,632 emails the province received, only 123 were unique compositions and the rest were part of letter-writing campaigns, nine opposed to the oil and gas sector and one in support of the industry. 

Forsyth said the lack of responses from the people who are most impacted — residents of the northeast — is noteworthy.

“Even that community is not going to necessarily step up and support the industry the way they could have,” she said.

As well as support for increased royalty rates, a system that disincentivizes new production and protects the environment, respondents called on the province to require companies to pay fees for “the use of water in operations that leave the water contaminated, such as fracking” and for methane leaks.    

Lee said he was pleasantly surprised by the overall results and is hopeful the government will respond in good faith.

“I think they could be setting themselves up to be able to say, ‘We’re eliminating fossil fuel subsidies as part of our commitment to climate action,’ and that would be a really good thing,” he said. “Obviously, the devil will be in the details around exactly what they’re eliminating, and how they do it and what kind of timelines those are all on, but I think they’re in a position to be on the side of the angels on this one.”

In its summary of the responses, the province noted most respondents favoured a new system that does not include credits for capital recovery. Under the current system, producers can apply for discounts to offset the initial costs of drilling of new wells before paying out any dividends on profits made. 

The authors of the independent assessment, economists Jennifer Winter and Nancy Olewiler, said this system created an environment where companies could use the government credits and subsidies to generate profits on projects that would otherwise be uneconomical, noting in their report the credit programs can “encourage extensive development beyond what would occur in their absence.” 

Under a system with no capital recovery, companies would only be able to develop high-yield operations that promise a healthy return on investment.

Industry respondents, which the provincial report noted represent two per cent of survey responses, argued for a system that retained the upfront credit, citing reasons such as a need to be “cost-competitive with other jurisdictions” and higher costs associated with extraction and transportation.

“B.C. needs to ensure it does not get left behind in the global push to grow natural gas supply and develop a competitive environment that attracts investment here rather than to countries that do not match our high environmental standards,” Geoff Morrison, B.C. manager at the Canadian Association of Petroleum Producers, wrote in a statement provided to The Narwhal. “The royalty review offers an opportunity to do just that.” 

Morrison said the association and its members provided feedback on the review to the province and will continue to work with the government to “enhance competitiveness for the industry while balancing the objectives of economic development and environmental protection as well as continuing to provide a fair return to British Columbians.”

Forsyth said she’s glad to see the province acknowledge the issue of water contamination but stressed the importance of ensuring companies are held financially responsible for their impacts on water — and that the fee structure should serve to decrease contamination.

“Previously, government’s response to ‘Should water be part of the royalty review?’ was, ‘In the independent assessment, they made no link between water and royalties,’ so I give them credit for now putting in the water issue as an assessment that needs to happen,” she said. 

But she noted an important point was overlooked in the province’s analysis of public responses — much of the water used in fracking is never going to be treated. 

“It basically infers that [companies] are going to remediate the water and they don’t  — they shove it underground. That’s a huge cost savings to the industry at the expense of potential risks to groundwater, and also the earthquake issue.”

Backlog of credits could continue to decrease B.C. government revenue for years  

While Lee remains hopeful the province will take this feedback from the public and create a new royalty framework, he warned that B.C. could still face years of fossil fuel development with few benefits to the economy.

“We still have this backlog that is tantamount to ongoing subsidies which diminish the revenues that we get back,” he said. “The government can raise the royalty rate, but the credits are kind of like money in the bank for the companies until they get production underway.”

More than half of the respondents said they felt the government should find a way to recoup those credits already on the books.

Andrew Gage, a lawyer with West Coast Environmental Law, said there could be legal options for the province to reclaim those credits but noted doing so would require new legislation and could raise issues with international trade agreements. Instead, the province could factor in outstanding credits when setting new royalty rates, he said.

“The government has pretty broad discretion to set royalty rates,” he wrote in an email to The Narwhal. “They could set a royalty rate that is moderately higher than they would otherwise set, reflecting the fact that there are a lot of royalty credits in circulation. The credits would then likely be used in the near future in order to keep production economical, with the available credits dropping in future years and the price of production increasing at that time, which could fit well with a transition strategy.”

Lee said it’s important the province factor in feedback on water usage in fracking and added he would like to see B.C. apply higher royalty rates to an often overlooked product: natural gas liquids. Those liquids and condensates are mostly exported to Alberta and used to dilute bitumen, he said. 

“They help bitumen flow through the pipeline, so it’s a pretty important and economically rich part of production,” he said, noting these liquids represent 20 to 25 per cent of B.C. production.

“Companies won’t drill a site that’s just natural gas — it’s got to have a certain content of these natural gas liquids, because that’s where they’re getting more economic value. I think that the B.C. regime is not recognizing that so we’re getting a low amount of royalties associated with that production.”  

New regime should reflect ‘true cost’ of B.C. oil and gas extraction

The province’s review process could be of great consequence for the management of land, water, wildlife and communities in the gas-rich portion of northeastern B.C.

The recent landmark B.C. Supreme Court case found the province infringed on Blueberry River First Nations’ treaty rights by giving a green light to so much industrial development in the region that the Indigenous communities could no longer trap, hunt and fish on their own territory. Fracking operations, which are growing to support both oil production in Alberta but also a growing liquified natural gas export industry on B.C.’s coast, have also encroached on farmland in the province’s northeast.    

Forsyth said she’d like to see the province bring more people to the table when creating a new royalty framework, noting that representatives from the Ministry of Environment, Ministry of Health and independent scientists would contribute valuable and important perspectives.

“I strongly feel that this absolutely clear division between what the people want and what industry wants has to be addressed,” she said. “Unless they bring in parties with unbiased expertise in these issues, where are they going to get the input?”

For Lee and others, the review of the system is an opportunity for the province to take a more holistic view of the impacts of the industry held against socio-economic benefits.

“We need a regime that fundamentally raises royalty rates, reflecting the true cost of taking those fossil fuels out of the ground, all the way from local health impacts up to global climate change.”

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The B.C. government is being urged to make oil and gas companies pay more for their use of billions of litres of water in fracking operations, as provincial officials review royalties collected by the province from the industry.

Several public advocacy organizations say the government’s ongoing review is “flawed” because it has failed to consider “outdated” water-use policies that are allowing some companies to extract fresh water for free.

Almost all the natural gas in B.C. is produced through hydraulic fracturing, or fracking, a process in which a slurry of water, chemicals and sand is pumped into horizontal wells, creating cracks underground. These cracks are kept propped open by the sand, allowing gas to flow through the fractures in the earth to the surface.

Oil and gas companies withdrew 4.2 billion litres of water under short-term approvals and water licences in 2020, a spokesperson for the BC Oil and Gas Commission said in a statement to The Narwhal.

What a company pays for the use of that water varies from nothing to just a few dollars for every million litres taken.

In 2020, oil and gas companies withdrew 3.5 billion litres of water under water licences, at a cost of $2.25 for every one million litres — or just less than $8,000 for all licences combined. The charge is deemed a rental fee by the B.C. government and comes in addition to an application fee that ranges from $1,000 to $10,000 depending on the use and volume of water used.

Another 712.3 million litres of water were withdrawn by oil and gas companies under use approvals, which are intended for short-term use. According to the provincial commission, companies are exempt from Water Sustainability Act application and rental fees for water taken under use approvals. Instead the commission’s administrative costs are covered by the fees oil and gas companies pay when they apply for their operating permit, the regulator’s spokesperson said. These use approvals are good for 24 months and can be re-issued indefinitely.

The BC Supreme Court upheld the commission’s right to re-issue these use approvals, rather than issue full licences that require greater environmental considerations, in a 2014 case between Encana Corp. (now Ovintiv) and several environmental organizations.

Oil and gas companies also withdrew nearly 316 million litres in 2020 from wells that are at least 300 metres deep, and located in certain areas, from which water-taking is free.

Some advocacy groups and experts say the numbers show that the money collected is not enough to cover what companies are consuming.

In B.C., “you simply cannot have natural gas production, without water … and, I have to underscore copious amounts of water,” said Ben Parfitt, a policy analyst with the B.C. chapter of the Canadian Centre for Policy Alternatives. 

Canada’s main oil and gas industry lobby group, the Canadian Association of Petroleum Producers, estimates between five million and 30 million litres of water is used in each fracking well. Thirty million litres is roughly equivalent to the amount of water in 12 Olympic-sized swimming pools. 

There are currently 10,180 active natural gas wells in the province, according to the BC Oil and Gas Commission. Of those, 6,742 have been fracked.

“BC Oil and Gas Commission experts — including Regional Water Managers and Hydrologists — monitor northeast B.C.’s water resources, track oil and gas water use withdrawals and water availability and require quarterly and annual water use reporting from industry,” a spokesperson for the commission said.

The spokesperson added use approvals “can be rescinded in times of drought.”

In 2020, oil and gas companies used 0.0035 per cent of the average annual runoff from rain and snow in northeast B.C., according to figures provided by the commission.

In an open letter last month, the Centre for Policy Alternatives and 10 other organizations, including the Sierra Club BC, the Canadian Association of Physicians for the Environment and Stand.earth, urged the provincial government to include water in its review of the oil and gas royalty system.

“Both the subsidized access to water and the future liability resulting from the lack of wastewater treatment must be addressed when considering whether the industry is paying fair value for public resources,” the letter says.

“Otherwise, the royalty review will be seriously flawed.”

B.C. moving forward on campaign promise to review natural gas royalty system

The BC NDP committed in the party’s 2020 election platform to undertake a “comprehensive review” of oil and gas royalties in the wake of repeated calls from environmental groups for governments in Canada to end all fossil fuel subsidies. But there’s no mention of water in this promise.

Almost a year after being re-elected, the B.C. government released an independent assessment in October which concluded that the province’s oil and gas royalty system was “broken” and in need of a “comprehensive overhaul.”

Royalties are meant to be the public’s share of the profit private companies earn from extracting oil and gas from public lands, but a series of subsidies, called royalty credits, have eroded provincial earnings.

In a statement issued when the independent assessment was released, Energy, Mines and Low Carbon Innovation Minister Bruce Ralston said the provincial “government takes this situation very seriously and will work toward an overhaul of the current system that eliminates outdated, inefficient fossil-fuel subsidies and ensures British Columbians get a fair return on our resources.”

Subsequently, the ministry released a discussion paper for public feedback outlining its goals for the new system and options for a new royalty structure.

The word “water” appears just once in the discussion paper, and only to note that many British Columbians use natural gas to heat their water.

This is a source of alarm for the organizations behind the open letter, who argue “the royalty review will be seriously flawed” if direct and indirect water subsidies are not assessed alongside royalty credits.

In a statement, a spokesperson for the Ministry of Energy, Mines and Low Carbon Innovation said “the Independent Assessment found there is no direct relationship between the royalty system and water use, which is why water is not currently a focus on the royalty review.”

The ministry did not provide details on why it felt there was no direct relationship between the two.

The ministry also declined to respond directly to The Narwhal’s question asking if the ministry is considering expanding the royalty review to include direct and indirect water subsidies. 

B.C. oil and gas industry’s water use ‘hugely subsidized’ 

The open letter was written in support of an analysis submitted to the government by Donna Forsyth, a former legislative advisor at B.C.’s environment ministry. Forsyth called for the royalty review to be expanded to address what she describes as “outdated subsidies, policies, and regulations governing water used by the oil and gas industry.”

Forsyth, who helped draft B.C.’s water management legislation, the Water Sustainability Act, raises several issues with existing water policies in her analysis, including the practice of charging oil and gas companies “rental rates” for water that is effectively removed from the local watershed.

While other industrial users that pay rental fees for water are expected to treat their wastewater at significant costs and eventually return it to the environment, where it becomes available for other users, oil and gas companies are required to do neither, she said in her analysis.

“This use of water rentals for the oil and gas industry results in the hugely subsidized rate of $5.62 for every Olympic-sized swimming pool of water the oil and gas industry is permanently removing from the water cycle,” she wrote.

A spokesperson for B.C.’s Ministry of Environment and Climate Change Strategy said water rentals are “charged based on the purpose of the water use and the volume of water authorized, regardless of whether the use of water is considered ‘consumptive’ or ‘non-consumptive.’ ”

A spokesperson for the BC Oil and Gas Commission added in a separate statement that while water is removed from the water cycle, water is also created when the gas produced is eventually burned to produce electricity or heat.

“It has been consistently shown that a greater amount of water is contributed to the water cycle through the combustion than is lost by disposal of water used for fracturing,” the spokesperson said.

When asked for a source or study for that statement, the commission referred The Narwhal to research published in the journal, Environmental Research Letters, which also found that fracking resulted in impacts on climate and weather by releasing water that was “more likely to be distributed and/or far removed from the site of fuel production, thereby not directly offsetting the water intensity of fuel production.”

A spokesperson for the commission said the study was provided for informational purposes and not to suggest that the water vapour released during combustion was desirable or a justification for lower fees for water use.

Greenhouse gases that cause climate change are also released when natural gas is combusted.

Meanwhile, the B.C. government allows for the wastewater from oil and gas operations to be injected deep underground through disposal wells, a practice Forsyth argues amounts to a “huge indirect subsidy” by removing requirements for costly water treatment imposed on other industrial users.

Forsyth also said she worries about the long-term implications of pumping polluted wastewater deep underground and whether there are risks of that chemical-laden liquid migrating over time, particularly given the incidence of earthquakes associated with fracking projects.

“What we’ve created is a toxic dump,” she said in an interview. 

In response, the BC Oil and Gas Commission said in a statement that “all applications for disposal of wastewater are reviewed by the Commission’s reservoir engineering staff and hydrogeology staff and only where it is verified that any disposed fluids will be contained and isolated in the disposal reservoir is an approval granted.” 

“There are regulatory requirements for operation and monitoring of disposal wells that are developed to protect shallow groundwater resources,” the statement said.

With regards to the millions of litres of water that oil and gas companies can withdraw for free, Forsyth wrote in her report that ministry staff had previously recommended it be restricted to water with a certain level of salinity and therefore not usable for consumption.

However, today there are no salinity requirements for these deep well exemptions, she said, and no requirements for the industry to monitor potential impacts of using these wells on other groundwater resources.

The spokesperson for the BC Oil and Gas Commission said that under the Water Sustainability Act, adopted in 2016, the water drawn from these deep wells is considered “deep groundwater.” 

“And, by this definition, is considered separated from freshwater aquifers by a thick layer of permeable cap rock,” the statement said.

Wastewater from the fracking process is also disposed of below this impermeable layer, it said.

The Narwhal did not receive a direct response from the provincial government as to why these deep wells are exempt from water licensing and environmental assessment processes.

Instead, the Ministry of Environment and Climate Change Strategy offered background information on the existing rules for deep water wells. The spokesperson noted, for instance, that section 53 of the Water Sustainability Regulations under the act gives a provincial water manager the authority to order a company to stop using deep groundwater, if there are “reasonable grounds” that the use of that groundwater is negatively affecting the rights of another water user. 

For the oil and gas industry, this power is held by the B.C. Oil and Gas Commission who, the ministry told The Narwhal, has never issued an order for a company “to stop diverting and using deep groundwater.” 

Climate change creates urgent need for review of B.C. water subsidies and policies

In the context of a changing climate, Parfitt said a review of water-use subsidies for the oil and gas industry is particularly pressing.

“Climate change is affecting water supplies everywhere,” he said.

Northeast B.C., the hub of natural gas production in the province, is expected to experience “increased stress to water systems,” according to a 2019 climate projections report for the region by the Fraser Basin Council.

“Lengthened periods of low flows may challenge the oil and gas sector, causing more frequent suspensions of short-term water licenses by the oil and gas commissions,” the report says.

While the industry may be affected by climate change, it’s also contributing to it through the emissions of greenhouse gases.

The Narwhal asked the Canadian Association of Petroleum Producers what the lobby group thought about the concerns raised by Forsyth, the Canadian Centre for Policy Alternatives and others regarding direct and indirect water subsidies.

Geoff Morrison, the lobby group’s B.C. manager, sent an emailed response that did not specifically address those concerns, but instead touted the importance of the industry. Morrison wrote in the statement that “natural gas is expected to be one of the fastest growing sources of energy globally for decades to come as countries look to reduce their reliance on coal. British Columbia produces some of the cleanest and lowest emission natural gas on the planet.”

“The natural gas industry will work in earnest with the provincial government to enhance the competitiveness of our industry while protecting the value our resources deliver to British Columbians,” he said.

As part of its royalty review, the government says in its discussion paper that it is aiming to minimize the “environmental impacts of the sector while achieving a fair return on the public resource and encouraging economic development.”

The province’s new royalty regime is expected to be announced in February.

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The B.C. government is moving forward with a long-promised review of its decades-old oil and gas royalty program — a system described as “broken” in an independent expert assessment published on Thursday.

Commissioned by the province, the expert assessment found the outdated royalty system isn’t consistent with broader government and societal goals, including B.C.’s commitments to reduce greenhouse gas emissions that cause climate change.

“It is our view that nothing short of a comprehensive overhaul of the royalty system will ‘fix’ it,” concludes the report, written by Nancy Olewiler, a Simon Fraser University economist, and Jennifer Winter, an economist at the University of Calgary.

Over the course of the last three decades, a series of changes were made to the royalty regime to address changing market conditions and technology, Winter explained in an interview with The Narwhal. But without a more comprehensive review, those changes led to an overly complex system that’s costly for the government to administer.

At the same time, she said, the royalty system was created at a time when there was less concern about climate change.

What’s needed now is a “very broad conversation about how to maximize value for British Columbians, and that’s both the people and the firms operating in B.C., and how the royalty system interacts with other policies and other concerns,” Winter said.

“Little tweaks are not going to cut it.”

Energy, Mines and Low Carbon Innovation Minister Bruce Ralston acknowledged in a news release that a comprehensive review of the royalty system is “long overdue.”

“Government takes this situation very seriously and will work toward an overhaul of the current system that eliminates outdated, inefficient fossil-fuel subsidies and ensures British Columbians get a fair return on our resources,” he said.

As part of the review, the province will publish a discussion paper in early November and seek public feedback on options for a new royalty regime, with a goal to implement a new system by March 2022.

Environmental and other civil society organizations have long called for comprehensive changes to B.C.’s oil and gas royalty system and will be watching closely as the review unfolds.

“The whole regime is a mess,” Marc Lee, a senior economist with the Canadian Centre for Policy Alternatives, told The Narwhal in an interview. 

“It doesn’t make sense in terms of climate, and it doesn’t make sense in terms of good revenue policy,” he said.

Royalties are meant to be the public’s share of the profit that private companies earn by pumping oil and gas from public lands. But through a complex system of royalty credits, the public’s share of those earnings has been significantly eroded.

“Essentially, what we’ve been doing is allowing companies all of these really generous credits for digging deep wells and fracking and associated infrastructure, that negate the royalties that they then pay back to the people,” Lee said. “So, we have basically been getting almost nothing for the resource.”

In their report, Olewiler and Winter note that “the credit programs may be contributing to or possibly overcompensating” for the costs of developing oil and gas in B.C.

For instance, B.C.’s production rate reduction incentives, which offer lower royalty rates for products pumped from less productive wells, “may be encouraging continued extraction from wells that should have reached their economic end date,” the assessment says.

“Encouraging the production of more gas supply, particularly from less productive wells, when natural gas markets are oversupplied, adds downward pressure on prices and increases greenhouse gas emissions that might otherwise not have occurred,” it continues.

Olewiler and Winter also raise concerns about the infrastructure credit and deep well royalty credit, which has so far reduced royalty payments by $3.56 billion and could reduce payments by a further $3.755 billion if all existing credits are used. 

“If there were no deep well credits or infrastructure credits, it is likely fewer wells would be drilled,” they write in their assessment.

The credit programs have ultimately served to reduce the economic benefit to the public of B.C.’s oil and gas resources over time, the report notes.

Sven Biggs, Stand.earth’s Canadian oil and gas program director, said in a statement to The Narwhal, that the expert assessment confirms what the environmental organization has said repeatedly — “the B.C. royalty system for natural gas and oil is broken.” 

He raised concerns, however, that the report focused too heavily “on cutting red tape for the industry rather than addressing the broader goals of the B.C. government, including securing a fair return for B.C.’s natural resources, meeting our climate goals and reconciliation with Indigenous Peoples.”

As B.C. moves forward with its royalty review, observers say climate change must be a central consideration.

Lee said the B.C. government should not only stop issuing new oil and gas leases, it should also establish a program to begin buying back leases from companies to slow down fossil fuel production.

Royalty rates should be increased and fossil fuel subsidies, including the deep well and infrastructure credits, eliminated, he said.

Ultimately, “it should be much more expensive to take fuel out of the soil of British Columbia and put it in the atmosphere where it’s heating up the planet,” he said.

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A new report names B.C.’s top ten fracking companies, showing how they get “sweetheart deals” from the provincial government through lucrative fossil fuel subsidies that are often worth more than what companies pay in taxes and royalties. 

“These companies are the ones that are causing us to fail to meet our climate targets in B.C.,” report author Peter McCartney, climate campaigner for the Wilderness Committee, told The Narwhal. 

“They are specific companies and I think it’s good for the public to know who is doing this and whose fault it is when the provincial government comes out and says we’re 28 to 44 per cent away from meeting our climate targets.”

At the top of the list, by volume of gas produced, is Denver-headquartered Ovintiv Inc. (formerly Encana Corporation), with 705 active wells and a tenure totalling almost 400,000 hectares, mainly in the Montney shale formation around Dawson Creek, which is home to the province’s highest concentration of fracking wells.

Ovintiv paid $3.7 million in provincial taxes last year and $72 million in royalties over a three-year period ending in 2018, according to the four-page report.

McCartney found that Ovintiv received more than twice that total amount — $167 million — from the B.C. government in deep well royalty credits over two fiscal years starting in 2016. 

Shell Canada and Petronas Canada, two companies in the LNG Canada consortium, are fifth and sixth on the list.

Shell, the global behemoth of the top ten fracking companies, with revenues of $404 billion, paid $2.3 million in B.C. taxes in 2020 and $6 million in royalties over a three-year period from 2016 to 2018. It received more than ten times that combined amount — $99 million — in drilling royalty credits over two fiscal years starting in 2016.

Petronas, with assets of $198 billion, paid $5.2 million in B.C. taxes in 2020 and $27 million in royalties over a three-year period ending in 2018. The company received roughly five times the total — $165 million — in drilling royalty credits over two fiscal years starting in 2016.

A Wilderness Committee table showing B.C.’s top ten fracking companies by volume, along with the B.C. taxes they paid in 2020. The table also shows how much each company paid in provincial royalties over a three-year period ending in 2018 and how much they received in deep well royalty credits over two fiscal years beginning in 2016. Graph: Wilderness Committee

In second place on the top ten list is ARC Resources, a Calgary-based company with $5.8 billion in assets that paid $1.8 million in B.C. taxes last year.

ARC has 250 active wells and a tenure totalling more than 227,000 hectares — the size of 567 Stanley Parks — mainly northwest of Fort St. John and north of Dawson Creek in the Montney formation.

ARC paid $157 million in B.C. royalties over a three-year period from 2016 to 2018 and received $74 million in drilling royalty credits over two fiscal years from 2016 to 2018, making it the only top ten company to pay more into provincial coffers than it received in drilling credits, according to McCartney’s research. 

The province’s third largest fracking company is Calgary-based Tourmaline Oil, one of Canada’s largest natural gas producers, with assets of $10 billion. Tourmaline paid $1.7 million in provincial taxes in 2020 and $71 million in royalties over the three-year period, the report says. 

The company, whose operations are scattered throughout the Montney formation, was granted $137 million — almost twice that amount — in drilling royalty credits over two fiscal years starting in 2016.

Canadian Natural Resources Ltd., the country’s second largest natural gas producer, is fourth on the list of B.C.’s top fracking companies by volume but has the largest tenure — more than 1.9 million hectares — and the most active wells in the province, with 782. 

The company, which has $76 billion in assets, also received the most drilling royalty credits — $210 million over two fiscal years starting in 2016. It paid less than half that amount in 2020 taxes ($12.3 million) and royalties over a three-year period ending in 2018 ($91.6 million).

A map showing the tenures of B.C.s top 10 fracking companies by production volume. Map: Wilderness Committee

Fracking only profitable with ‘government handouts’: report

“Fracking companies are only able to operate with enormous public giveaways from the NDP government,” McCartney said.

 Deep well drilling credits were introduced when fracking — a technique that involves blasting a mixture of water, chemicals and sand into a well to break apart rock formations and release previously inaccessible gas deposits — was a relatively new, expensive technology.

But the credits remained in place after fracking became cheaper and widespread. 

Depending on the depth of a well, a company can receive a rebate worth between $440,000 and $2.8 million on its resource royalty payments to the province, according to the report, which lists six other provincial subsidies that “whittle away any benefits to the public purse” from fracking, including carbon tax exemptions. 

Read more: Natural gas royalty credits cost B.C. $1 billion more than expected over last four years

“There are all of these insidious ways that these companies don’t have to pay,” McCartney said. 

“The provincial government is rolling out the red carpet for fracking and LNG companies — some of the biggest polluters in the province — and they’re not being treated in the same way as every other industry in the province.”

In response to questions from The Narwhal, the B.C. Ministry of Energy, Mines and Low Carbon Innovation (formerly the Ministry of Energy, Mines and Petroleum Resources) said it is reviewing oil and gas royalty credits “to ensure they meet B.C.’s goals for economic development, a fair return on our resources, and environmental protection.”

Natural gas fracked in B.C. is composed mostly of methane, a potent greenhouse gas with a climate warming potential 25 times that of carbon dioxide on a 100-year timescale. 

Global efforts are underway to curtail methane emissions and, as part of Canada’s international commitments, B.C. set a goal of reducing provincial methane emissions 45 per cent by 2025, compared to 2014 levels.

The energy ministry said B.C. will continue to implement “world-leading technologies” to support detection and reduction of harmful methane emissions. 

Late last year, the B.C. government admitted its much-touted Clean BC plan falls 28 to 44 per cent short of the province’s 2030 target for reducing carbon emissions.

In its email, the ministry pointed to December’s announcement that B.C. will miss its near-term 2025 emission reduction target, saying the adjusted 2025 target will enable the province to stay on track to achieve climate targets for 2030 and beyond. 

“Our government is fully committed to strong climate action, accountability and a clean economy for everyone through CleanBC,” the ministry wrote, side-stepping questions about how the government intends to square its stated goal of reducing carbon emissions with its support of increased fracking and what role fracking companies have played in B.C. missing its near-term climate target.

The release of the Wilderness Committee report follows an announcement from U.S. President Joe Biden that federal agencies will no longer subsidize the fossil fuel industry, as part of a suite of new policies aimed at curbing global warming before greenhouse gas emissions in the Earth’s atmosphere reach a dangerous tipping point that scientists warn will cause cascading impacts such as faster sea level rise, making some coastal communities uninhabitable. 

The Wilderness Committee and other environmental and public interest groups have long criticized Canada and B.C. for generously subsidizing the fossil fuel industry. A 2018 report revealed that Canada provides more government support for oil and gas companies than any other G7 nation and is among the least transparent about fossil fuel subsidies. 

In September 2020, a Stand.earth report found B.C.’s NDP government had doubled fossil fuel subsidies over a two-year period, to $1 billion.

“The government of British Columbia, elected to fight climate change, continues to prop up the fossil fuel industry, using tax dollars to fill the coffers of fracking companies,” Julia Levin, climate and energy program manager for the advocacy group Environmental Defence, told The Narwhal.

“The lion’s share of these subsidies have gone towards expanding the province’s fracking sector — a sector that would not be profitable without government handouts.”

Levin said the B.C. government spends twice as much on tax breaks and direct subsidies for fracking companies and LNG as it does on its plan to fight climate change.

“Subsidies are often justified by politicians on the basis that royalties will generate more public revenue. But B.C. pays out substantially more in fossil fuel subsidies than the province earns in oil and gas royalties — and that gap is growing year over year.”

Royalty revenues have fallen from more than $1 billion per year one decade ago to less than $200 million, even though B.C.’s total gas production has increased by more than 60 per cent, Levin noted.

B.C. natural gas production has increased in recent years while the amount of revenue generated by the province through royalties has significantly declined. Deep well credits and other subsidies and tax breaks are part of the reason. Source: B.C. Ministry of Finance. Chart: Carol Linnitt / The Narwhal

“On top of that, the government has allowed fracking companies to stockpile over $3 billion in outstanding royalty credits. This is foregone revenue that is being borrowed from future generations.”

In an emailed statement, Jay Averill, media relations manager for the Canadian Association of Petroleum Producers (CAPP), said the natural gas and oil industry has invested $90 billion into B.C. since the deep well royalty credit program was introduced in 2003 — in-turn generating $24 billion in direct provincial government oil and natural gas revenues.

Averill said the upstream natural gas and oil industry is the largest private investor in B.C. and is forecast to invest $3.9 billion in the province this year, up from $3 billion last year. 

“This is desperately needed investment growth that will put British Columbians back to work, generate government revenues and help the economy recover from the devastating impacts of the COVID-19 pandemic,” he said.

Top fracking companies charged multiple times

The report also lists charges against each of the top ten companies for violating provincial regulations.

Tourmaline was charged once from 2007 to 2019, making it the company with the fewest charges, according to a spreadsheet the Wilderness Committee obtained from the BC Oil and Gas Commission through a Freedom of Information request.  

The spreadsheet shows Tourmaline was fined $15,000 in 2015 for failing to prevent and report spillage. 

Ovintiv was fined more than any other top fracking company, racking up 19 charges from 2007 to 2019 while operating as Encana, according to the spreadsheet. 

In 2010, Ovintiv (then Encana) was fined $250,000 under the environmental emergency act — by far the largest fine levied against any of the top ten companies — after a pipeline rupture near Pouce Coupe released a cloud of gas that contained deadly hydrogen sulfide. The company also received fines totalling about $4,000 for breaching B.C.’s water act.

Petronas (formerly Progress Energy) was charged 16 times, according to the report, while Shell racked up five charges, including four totalling $920 for failing to keep or produce water records.

Progress was fined $10,000 in 2014 for failing to prevent spillage and ensuring fracking water did not pollute or damage any land. The company was fined $15,000 the following year for failure to minimize the loss of well control, while also accruing a $25,000 fine in 2020 for failure to prevent spillage.

Flared gas at gas industry facility north of Farmington, B.C. Local farmer Brian Derfler calls it the “land of northern lights.” Photo: Garth Lenz / The Narwhal

Major growth in fracking needed to feed B.C.’s LNG industry

The LNG Canada project in northwestern B.C., which will become B.C.’s largest carbon polluter when it comes online in 2023, will ship fracked gas from Kitimat to Asia. LNG Canada, a consortium of some of the largest and most profitable multinationals in the world — Royal Dutch Shell, Mitsubishi Corp., Petronas, PetroChina Co. and Korean Gas Corp. — has been granted more than $5.3 billion in provincial government subsidies, including tax reprieves, tax exemptions, cheaper electricity rates and an exemption from carbon tax increases. 

A July 2020 report by earth scientist David Hughes found that emissions from B.C.’s oil and gas sector will exceed the province’s 2050 emissions reduction target by 54 per cent, even without emissions from LNG exports.

B.C.’s emissions compared to B.C.’s emissions targets and anticipated emissions from the LNG Canada project, which is expected to become the singled largest source of emissions in the province. Graph: Carol Linnitt / The Narwhal

Hugh’s analysis, based on the Canada Energy Regulator’s oil and gas production forecast and federal emissions data, found the oil and gas sector would exceed B.C.’s 2050 target by 160 per cent if emissions from producing and liquefying the gas required for LNG Canada were added — even if all other sectors of the economy reached zero emissions.

Averill, from CAPP, said B.C. can produce some of the lowest emission natural gas and LNG in the world. 

“The rapidly growing global demand for natural gas should be met by resources from Canada rather than other countries that are not making the same efforts to drive down their emissions,” he said.

McCartney said tens of thousands of new fracking wells will be required to supply the LNG Canada project and two other LNG projects approved in B.C — the Woodfibre LNG project in Squamish, owned by Indonesian billionaire Sukanto Tanoto, and Kitimat LNG, owned by Chevron Canada and Woodside Energy, Australia’s largest natural gas producer.

Hughes concluded that B.C. will exceed its 2050 emissions reduction target by 227 per cent if Kitimat LNG and Woodfibre LNG are built in addition to the LNG Canada project.

Gas for the Woodfibre LNG project would come from Pacific Canbriam, a Singapore-based company that is eighth on the list of B.C.’s top fracking companies. 

Pacific Canbriam paid $2.6 million in provincial taxes in 2020 and $9.5 million in royalties over three years, from 2016 to 2018, while receiving $109 million in drilling royalty credits over a two-year period ending in 2018, according to McCartney’s research.

Carbon emissions from the Woodfibre LNG project would add the equivalent of 170,000 new cars to B.C. roads each year, while the project would use the same amount of freshwater annually as 5,500 households, according to the Pembina Institute. 

McCartney said persistent low prices and global oversupply would spell the end of B.C.’s LNG industry in the absence of “colossal” financial support from the provincial government. 

“Take those subsidies away and this industry doesn’t exist. That’s really why it’s so offensive that the provincial government is propping this whole industry up, when all they really need to do is to let them stand on their own two feet in order to take climate action.”  

“If these LNG plants on the west coast are not built, fracking will just taper off and fall in line with exactly how it needs to decline for us to meet our climate targets.”

About 20,000 fracking wells in northeast B.C. are spread out over an area the size of Nova Scotia, including on farmland. 

The area covered by fracking access roads, seismic lines, well pads, water hubs, pipelines, compressor stations, gas plants and waste disposal takes up five times as much land as Alberta’s oil sands, according to the Wilderness Committee report. 

“It happens in a corner of the province few southerners ever visit,” McCartney said, “but the scale of this industry is staggering.”

Read more: ‘We must protect our water’: B.C. ranchers wage battle over radioactive fracking waste

Update February 9, 2021 at 7:55 a.m. PST: This article was updated to correct a typo. A previous version of the story reported CNRL paid $12.3 billion in 2020 taxes. In reality the company paid $12.3 million in 2020 taxes and the story has been updated to reflect that.

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.

Over the past 10 years, the Yukon government has collected a mere 0.03 per cent of the value of placer and quartz resources on behalf of all Yukoners, the rightful owners of those minerals.

An independent panel appointed by the government to review the territory’s mining legislation found that, during this period, miners extracted minerals worth an average of $335 million per year yet only paid an average of $100,000 per year in royalties. 

The two laws predominantly responsible for mining in the territory, the Placer Mining Act and the Quartz Mining Act, were established in the late 1800s during the Klondike Gold Rush era and are in serious need of modernization, according to the panel’s recent strategy report, which is based on years of public engagement and is intended to inform the Yukon government’s efforts to bring Yukon’s mineral development legislation into the 21st century.

Yukon’s antiquated royalty rates for gold — set into law in 1906 — are famously low at just 37.5 cents per ounce of gold, based on a per-ounce price of $15. In today’s market, one ounce of gold is worth more than $2,300.

“The royalty regime is very old, and it has not been updated in a significant period of time,” Math’ieya Alatini, a member of the independent panel, told The Narwhal. “We have to bring the royalty regime up to date and make it commensurate with the value of the minerals that are being removed.”

Low royalties are something of a sore spot for many in Yukon, including members of the public, First Nations and miners themselves, who argue their industry provides the territory with a cascade of economic benefits not necessarily reflected by royalties. In order for mining to remain sustainable and profitable and continue to have social buy-in, the panel recommends the Yukon government make some key changes to ensure the benefits of mining are more equally distributed through changes to the royalty regime and, potentially, through new taxes.

Yukon’s modern placer mining gold rush

Over the past decade, Yukon has seen a resurgence of mining interest, especially for gold extracted through placer mining operations. According to the Yukon Geological Survey’s latest comprehensive report on placer mining, published in 2018, there are 25,219 placer claims in the territory, the highest number dating back to 1973.

Placer mining involves removing rocks and gravel from streams and wetlands in search of gold and can cause disturbances in water quality that can impair the feeding and reproduction of fish. Over many years, placer mining can destroy irreplaceable wetlands, disrupt waterways and harm unique riparian ecosystems that connect land and water. And although placer mining occurs exclusively in streams and Yukon’s wetlands, there are no specific protections in place to protect these unique ecosystems from this kind of activity. 

Yukon’s modern gold rush, popularized in reality TV shows like Gold Rush and Yukon Gold, has been facilitated by new technologies, machinery and industrial techniques that are a far cry from the humble gold pan of the 1890s. And while the pace and scale of placer mining operations has evolved in recent years, the royalty scheme has not.

“There are going to be detrimental effects [from mining],” Alatini said, noting the resources being harvested are fundamentally nonrenewable. “These minerals are not going to be returned to the ground. … How do we adequately compensate this generation and future generations for the loss of use?”

Read more: Yukon wetlands pushed to tipping point by placer mining, First Nation and conservationists say

The panel suggests the government act on recommendations first made by the Yukon Financial Advisory Panel in 2017 to carry out a comprehensive review of mining policies “with a particular emphasis on ensuring fair and efficient royalty rates.”

Based on the findings of that review, the Yukon government should modernize mining legislation “to ensure all Yukoners receive fair and meaningful financial returns from mining activities while also ensuring competitiveness with other Canadian jurisdictions,” the panel said.

One of the primary ways the panel recommends altering the royalty system is by adjusting royalties based on the profitability of individual mining operations. A profit-based placer gold royalty would require higher royalties from more profitable operators, while “placer operations that are truly marginal in terms of profitability will continue to pay essentially no royalties.”

The panel also suggests the Yukon government consider charging more royalties from non-Yukoners — miners who might simply show up to cash in on high market gold prices — than from local operators who are there for the long haul. 

Read more: Gold seekers are flooding into the Yukon and wreaking havoc on its rivers

New taxes could increase public benefits of mining in Yukon

Royalties don’t represent the only way Yukoners and Yukon First Nations might benefit from mines, however. The panel points to new forms of taxation that could improve mining standards, provide social benefits to local communities and generate greater rewards for local mine workers over itinerant workers at mines.

Currently, Yukon does not charge mine operators anything for the use of water. An industrial water charge, similar to that introduced in British Columbia in 2016, could be used to generate revenue from mines and also create incentives for miners to keep water clean. The panel recommends the government introduce a rolling water tax that rewards operators for maintaining high water quality.

Tyler Hooper, a spokesperson with the B.C. Ministry of Forests, Lands, Natural Resource Operations and Rural Development, recently told The Narwhal that all licensed surface water and groundwater users are required to pay annual water rents. The rental rates are variable and can exclude small-scale placer mining operations. But according to a B.C. provincial government list of example rates, a mine that uses 1.2 million cubic metres of water per year would be charged $2,500 annually or $2.08 per 1,000 cubic metres. 

Lewis Rifkind, mining analyst for the Yukon Conservation Society, previously told The Narwhal the recommendation to roll out a water tax was welcome, but added he would need more detail to understand how such a fee would work in Yukon.

“How will it be applied? Will it be different for quartz exploration to a quartz mine to placer mining?” 

The panel’s report does not go into any detail regarding these matters nor the particulars of how a water tax could be applied to various mining operations in Yukon.

Water licences for mines are issued by the Yukon Water Board and there are more than 100 granted to placer miners in the Indian River watershed directly south of Dawson City, Yukon, alone.

A map showing the location of water licenses in Yukon. The purple dots indicate water licenses for placer mining. Photo: Yukon Government

Rifkind expressed concern that a water tax could simply be added to the general cost of doing business rather than act as a true incentive to improve mining practices and keep water clean.

The panel also recommends applying a payroll tax to people who work but don’t live in Yukon. Right now, personal income tax corresponds with the jurisdiction in which out-of-territory workers live.

“It would allow a sort of prorated amount to be transferred back to the Yukon,” she said, adding that a large portion of Yukon’s workforce is made up of people from other jurisdictions. “We want to make sure some of that money stays in the Yukon to act as a multiplier for the economy.”

The payroll tax would be deductible for Yukon residents, the strategy states.

Read more: Canada’s mining giants pay billions less in taxes in Canada than abroad

Taken together, the water and payroll taxes could help buoy a heritage fund — money that would be held in trust to benefit future generations.

Alatini said the creation of a heritage fund would not only recognize the value of the resources extracted from Yukon, but also capture some of that value for Yukoners “that translates from the work that’s being done in their backyard to something that can benefit everyone that is here.”

“A Yukon heritage fund would provide a visible link between mining activity, royalty revenues from mining and long-term prosperity in Yukon, thereby enhancing sustainability and the industry’s social licence to operate,” the strategy states.

‘Negligible amount’ of royalties are shared with self-governing Yukon First Nations 

Through Yukon’s modern treaties, self-governing Yukon First Nations are able to receive royalties collected by the Yukon government. But because the territorial government receives such low royalties to begin with, only a “negligible amount” is actually making its way to First Nations, the panel found.

Alatini said the creators of Yukon’s Umbrella Final Agreement — a political agreement struck between Yukon First Nations and the Yukon and federal governments — “had contemplated First Nations receiving a portion of the benefits of the resources that are being taken from their traditional territories — full stop,” Alatini said.

The average royalty cheque received by First Nations during the past decade ranged between $6 and $24, Alatini added.

Tr’ondëk Hwëch’in First Nation, on whose territory the vast amount of Yukon’s placer mining takes place along the Indian River, reported receiving a royalties cheque from the government for $65 in 2017. That same year, placer mining along the Indian River accounted for 50 per cent of total placer gold mined in Yukon, according to the Yukon Geological Survey, amounting to more than 350,000 crude ounces of gold. 

The panel recommends that “Yukon First Nations receive a fair financial and social return from mining and exploration within traditional territories by strengthening the connection between revenue flows and Indigenous interests in the land itself.”

Recommendations from the panel also include allowing First Nations, under their final agreements, to charge companies directly for water use or land rental fees, instituting a statute-based template for benefit agreements with affected First Nations and requiring both impact and benefit agreements in advance of quartz mine development, construction, production and decommissioning.

Challenges lie ahead when it comes to new Yukon royalties and taxation structure

Carl Schulze, secretary treasurer for the Yukon Prospectors Association, told The Narwhal industry isn’t thrilled about the idea of paying more taxes, noting that Yukon’s economy is stimulated just by virtue of mines being located in the territory.

“What you’ve got to think about is there’s still the supply chain, service chain, all the employees, all the distribution,” Schulze said. “If you took just payroll for Yukoners, and what you paid your contractors, you know, whoever trucks the ore, whoever supplies geological services, local legal services, anything like that, I mean, it’s an enormous amount of money.”

The Klondike Placer Miners’ Association has also been a vocal opponent of increased royalty rates for years, with former association president Mike McDougall suggesting increased royalties would undercut the profitability of placer mining operations, which he likened to the “family farm.”

Despite dissatisfaction over low royalties from members of the public, First Nations and miners themselves, the mining industry in Yukon averse to paying more taxes, saying the mere presence of mines in Yukon stimulates the territory’s economy. Photo: Malkolm Boothroyd / CPAWS Yukon

But in addition to industry opposition, there are other potential challenges to introducing new and increased revenue generators from mines in Yukon, most notably the territory’s transfer payment from Ottawa.

Under the territorial formula financing arrangement, Yukon receives federal funding every year to pay for public services. But in order to maintain this funding arrangement, the Yukon government can only collect and keep $6 million worth in resource revenues each year.

“For every dollar above that $6 million amount, a dollar is deducted from Yukon’s [territorial formula financing] grant,” Eric Clement, director of communications with the Yukon government’s Department of Finance, told The Narwhal in an email.

That $6 million ceiling may present challenges to Yukon moving forward with some of the most ambitious recommendations of the independent panel, including the creation of a heritage fund.

Six million dollars in resource revenues is simply “too low to capitalize a Yukon heritage fund,” the panel noted in its report. 

Other arrangements could alleviate Yukon’s $6 million limit, however. The panel suggests Yukon look to the Northwest Territories’ arrangement with the federal government, which allows that territory to keep up to 50 per cent of its resource revenues without a specific cap. If implemented in Yukon, this arrangement would allow the territory to receive roughly $54 million in resource revenues without being forced to forego federal support, the panel found.

Alatini said new arrangements might be necessary to re-envision how Yukon generates and holds onto resource wealth. A new agreement would require “that the Yukon government and Canada come to the table,” she said. “We need to have consistently producing mines in order for this to even be an option.”

Updated on Feb. 25, 2021 at 5:40 p.m. PST: Over the past 10 years, the Yukon government has collected 0.03 per cent of the value of placer and quartz resources, not 0.3 per cent as previously stated.

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.

A review of four years of budget documents shows the B.C. government underestimated by $1 billion the amount of revenue it would forgo due to natural gas royalty credits, a shortfall that experts say highlights the volatile nature of markets and flaws in the province’s fossil fuel subsidy program.

Natural gas companies claimed between $163 million and $367 million more in royalty credits than B.C. budgeted in each of those years, with credits totalling more than $2 billion over that period.

In the end, the province brought in between $152 million and $199 million in natural gas royalties each year between the 2016-2017 and 2019-2020 fiscal years — a fraction of the more than $700 million in tobacco tax revenue raised each year during that same period.

The province collected less natural gas royalties than expected in each of the years except 2016. 

“It’s a rollercoaster every year,” said Werner Antweiler, director of the University of British Columbia’s Sauder School of Business Prediction Markets.

In the 2016 budget, for instance, the province estimated it would forgo $132 million from royalty credits in the 2016-2017 fiscal year, but the public accounts show the government actually lost $363 million in revenue.

Similarly, in 2017 the government estimated it would forgo $284 million as a result of royalty credits, but actually lost $447 million. 

The royalty credit estimates fell short by $367 million for the 2018-2019 fiscal year. That year, the government estimated it would forgo $264 million, but actually gave up $631 million in revenue to credits. Again in the 2019-2020 fiscal year, the government estimated it would forgo $317 million in revenue, but actually gave up $567 million in credits.

Contrary to B.C.’s budget estimates, natural gas companies claimed between $163 million and $367 million more in royalty credits than the province had expected from 2016-2019, with credits totalling more than $2 billion over that period. Source: B.C. Ministry of Finance. Chart: Carol Linnitt / The Narwhal

The royalty credits include credits companies can claim for drilling deep wells, as well as credits for road and pipeline infrastructure.

At the same time, the province earned less royalty revenue than expected from natural gas companies in all but the 2016-2017 fiscal year over the same period.

The 2017, 2018 and 2019 budgets overestimated royalty payments by between $30 million and $122 million. (In 2016-2017 the government was paid $24 million more than expected.)

According to information provided by the ministries of Finance and Energy, Mines and Petroleum Resources, royalty credits and revenue depend on market prices and the volume of natural gas produced each year.

Thirteen independent economists on the Economic Forecast Council are involved in the development of the province’s royalty forecasts, which are updated each quarter to “manage unpredictable factors,” the B.C. energy and finance ministries explained in a joint statement to The Narwhal.

B.C. royalty regime ‘taking wealth away from our future generations’: expert

One of the key challenges with forecasting royalty revenue is that the royalty rate isn’t a fixed fee tied to the amount of natural gas production, Antweiler explained.

Instead, royalty rates are tied to the price of natural gas and the volatility of the market makes it “almost impossible” to forecast royalty revenue, he said.

In each of the years reviewed except for 2016, B.C. collected less natural gas royalties than expected. It is difficult to forecast royalty revenue because the royalty rate is tied to the price of natural gas, not the production levels. Source: B.C. Ministry of Finance. Chart: Carol Linnitt / The Narwhal

It’s also difficult to predict the level of credits companies will claim to help reduce their royalty costs, Antweiler added. 

The unpredictable nature of royalty revenue is just one challenge in a system that’s designed to keep the natural gas industry in B.C. competitive.

For Antweiler, that’s the “fundamental problem” with the royalty regime: it doesn’t follow the Hartwick Rule.

The Hartwick Rule, a concept in resource economics developed by economist John Hartwick, argues extracted natural resource wealth — in this case natural gas — should be converted into some other form of wealth to benefit both current and future generations. 

“Royalties really have a purpose, it’s basically the shared wealth of our current and future generations and therefore we have, at least in my view, this duty to be diligent in terms of stewardship of that wealth,” Antweiler said.

B.C.’s support for the liquefied natural gas industry could be at odds with its 2030 climate targets, according to some observers. Photo: Garth Lenz / The Narwhal

But the government’s priority has been keeping the B.C. industry competitive and as a result the province has been giving up royalties, he explained.

“It’s basically taking wealth away from our future generations that actually should have equal rights in the benefits of this natural wealth, because you can only consume it once,” Antweiler said. “Once it’s gone, it’s gone.”  

According to the 2019-2020 report from the Ministry of Finance’s comptroller general office, there are $2.9 billion in outstanding deep well credits alone that can be used to reduce future royalty payments to the B.C. government.

That’s a major concern for environmental groups that have repeatedly called for an end to fossil fuel subsidies, including royalty credits in B.C. and around the world.

Scrutiny of royalty system comes as B.C. struggles to meet climate targets

“The intended way this is supposed to work is natural resources like gas belong to all British Columbians and the province is supposed to balance the need to stimulate the industry with getting a fair price for British Columbia — and that’s not happening anymore,” said Sven Biggs, the Canadian oil and gas programs director with the environmental organization Stand.earth.

“Because of this huge, outstanding debt now that the province is carrying with these royalty credits, we’re likely never going to be able to recoup that,” he said.

“British Columbians can’t afford to be picking up the tab for these companies, especially when they are a major source of climate pollution,” Biggs said.

Royalty credits are the largest fossil fuel subsidies in British Columbia, said Vanessa Corkal, an energy policy analyst. Credits include ones that companies can claim for drilling deep wells, as well as for road and pipeline infrastructure. Source: B.C. Ministry of Finance. Chart: Carol Linnitt / The Narwhal

Vanessa Corkal, an energy policy analyst with the International Institute for Sustainable Development, said “the fact that we have these credits at all is a concern.”

Royalty credits are the largest fossil fuel subsidies in British Columbia, said Corkal, who has co-authored multiple reports on subsidy practices. 

B.C. still needs additional measures to reduce greenhouse gas emissions in order to meet its 2030 climate targets and some observers including Biggs and Corkal say the government’s support for the liquefied natural gas (LNG) industry is incompatible with the province’s climate goals.

Read more: Fact check: are B.C.’s LNG ambitions compatible with its climate goals?

“If LNG Canada goes ahead, especially the phase two of that project, there’s going to be a massive upstream expansion in fracking to create enough gas to fuel that project,” said Biggs.

“As long as that’s the reality we’re dealing with, it’s hard for the environmental community, or I think anyone in the province really when they look at the numbers, to get behind giving money to these polluters to continue to do what they’re doing,” he said.

Attention turns to B.C.’s planned review of royalty credits

During B.C.’s fall 2020 election campaign, the NDP committed to undertaking a comprehensive review of natural gas royalty credits. 

It’s a commitment Corkal called  “promising.”

“It’s really important that we phase out fossil fuel subsidies that are unfairly advantaging the fossil fuel economy — as opposed to the clean energy economy — and many of these royalty credits arguably are doing just that,” she said. 

Antweiler, meanwhile, said a review of B.C.’s royalty system is “long overdue,” and not only because of climate change concerns. 

Antweiler said the system “is so complex that only a few experts actually know what it exactly does and this lack of transparency and accountability is really worrisome.”

“At the very least, this entire royalty court needs to be hugely simplified.”

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.

The Rural Municipalities of Alberta — the organization representing Alberta’s rural counties and municipal districts — has announced it’s facing what it calls a “massive increase” in unpaid taxes owed to small rural governments by oil and gas companies.

The amount owed in taxes has more than doubled since last year, to $173 million, according to a recent survey of Rural Municipalities of Alberta members.

This loss of revenue, the Rural Municipalities of Alberta said in a press release, means “many rural municipalities will struggle to remain viable.”

You might be wondering why, and how, oil and gas companies can simply not pay their taxes. After all, the local government will certainly make sure to collect your property tax. And we’re all well aware that the Canada Revenue Agency is keeping tabs on our income tax. 

But the situation is a little different with the taxes owed by oil and gas companies to the small communities they operate in.

Read on.

What kinds of taxes are oil and gas companies supposed to pay to rural communities?

Oil and gas companies are supposed to pay property taxes, not unlike home and landowners, when they install oil and gas infrastructure. 

These taxes are assessed based on a model set by the provincial government — and there are rumblings that this model could soon be “updated” (more on that later).

Why aren’t these companies paying?

Though rural municipalities have long voiced empathy for oil and gas companies facing low energy prices, they are increasingly alleging that companies are choosing not to pay their municipal taxes because the companies know there are few consequences.

According to the Rural Municipalities of Alberta, companies are increasingly “unable or unwilling to pay.” 

The Canadian Association of Petroleum Producers has previously suggested that rural municipalities “place a disproportionate fiscal burden on industrial property.”

Ron Govenlock, mayor of Woodlands County, told The Narwhal last fall that it’s not reasonable to think that property taxes are the reason companies are struggling.

“There’s a multitude of factors that go into any business in terms of its operational cost,” he said. “So to suggest that it’s the tax burden — that’s been consistent for the past 20 years — that is now going to be targeted as the reason that their profit margin is tighter?” 

“I don’t buy that.”

Oilfield rentals in Fox Creek, Alta. Photo: Amber Bracken / The Narwhal

So, what happens if companies don’t pay these taxes?

Not a whole lot, when it comes to enforcement. 

According to the Rural Municipalities of Alberta, local governments “have no ability to take action to recover owed taxes on this type of infrastructure.”

With other types of tax debts, whether from individuals or businesses, counties may seize assets or post them for sale.

The situation gets even trickier if a company declares bankruptcy. 

Counties “have little recourse to recover unpaid taxes from companies that have declared bankruptcy,” according to the Rural Municipalities of Alberta, as they are near the bottom of the list of creditors who would receive any leftover funds following insolvency.

How much does this matter to these communities?

A lot. In some cases, rural municipalities rely on tax revenue from oil and gas companies for more than 90 per cent of their annual budgets. 

An investigation by The Narwhal last fall found that in at least 20 counties, local governments were relying on these payments for more than half of tax revenue.

Losing that cash flow has led counties to consider cutting back on road maintenance, property tax hikes for residents and hiring freezes. 

Others dipped into emergency funds to bridge what they hoped was a temporary shortfall.

‘Only reason we exist’: why an energy transition is hard to fathom in parts of Alberta

Has this happened before?

When the Rural Municipalities of Alberta announced last year that communities across the province were facing an $81-million shortfall in unpaid taxes from oil and gas companies, they labelled it “unprecedented” and noted it was “worsening at an alarming pace.”

Govenlock told The Narwhal last year that the sudden drop in income left his county “blind-sided.”

What’s the provincial government doing about this?

Last summer, the provincial government announced a program that would seek to cut the taxes paid by some gas producers, under their shallow gas relief program.

That program meant eligible companies received a 35 per cent cut on local taxes on shallow gas wells and pipelines for the 2019 tax year.

In turn, local governments received less tax revenue, so the provincial government promised to reduce the amount of another tax, the education tax, that rural municipalities have to pay by the amount forfeited in gas tax. 

When it announced the program, the provincial government estimated it would indirectly foot the bill for $20 million in taxes for eligible shallow gas companies. 

The program was estimated to only be applicable to about 15 counties, of the approximately 60 spread across the province. An estimated 70,000 wells and pipelines are eligible under the shallow gas relief program.

A campground where workers live year round in Fox Creek, Alta. on July 24, 2018. Photo: Amber Bracken / The Narwhal

Why shallow gas wells?

“Shallow gas” includes conventional wells, and associated pipelines, that are not drilled deep beneath the surface like many fracked sites. 

According to the Government of Alberta, shallow gas wells are “defined as wells less than 1,500 metres in depth, producing only gas … [and draw] from formations that are younger than 98.5 million years.” 

“There’s many of these wells but they don’t produce a lot,” Tristan Goodman, president and CEO of the Explorers and Producers Association of Canada, told the Calgary Herald last summer.

At the same time, natural gas prices have been low for some time.

“Some days we are almost giving this product away for free,” associate natural gas minister Dale Nally said last summer. Government officials have said they are concerned shallow gas producers are paying too much in property taxes.

Not everyone agrees, including Rural Municipalities of Alberta president Al Kemmere, who said in a press release that the “taxation model for shallow gas infrastructure is not the cause of” the industry’s challenges.

Did the shallow gas relief program solve the problem?

Not according to the Rural Municipalities of Alberta, which said in a press release that the government’s program “is not solving the problem of unpaid taxes and industry struggles, but is rather providing many companies with 35 per cent forgiveness on their taxes while the rest remain unpaid.”

That program didn’t sit well with the local government officials The Narwhal spoke to last fall, either.

Bruce Beattie, the reeve of Mountain View, told The Narwhal it didn’t seem fair to give a tax break to some companies while still expecting local governments to maintain the same services.

Under the shallow gas relief program, he said, “everyone else will pay and the shallow gas guys won’t. They’ll get the services but they’ll be paying less.”

The Fox Creek Greenview Multiplex in Fox Creek, Alta, is sponsored in part by Shell. The Fox Creek Greenview Multiplex in Fox Creek, Alta, is sponsored in part by Shell. Funds from industry taxes are also relied upon to provide services to the public in many rural municipalities in Alberta, creating a string of social consequences if companies do not pay their bills. Photo: Amber Bracken / The Narwhal

Is the provincial government continuing its support for municipalities?

Nope.

Despite the fact that the Rural Municipalities of Alberta found that some municipalities attributed up to 98 per cent of unpaid taxes to the shallow gas industry, the provincial government is not continuing its credits for the shallow gas relief program in 2020.

In 2020, according to the Rural Municipalities of Alberta, “municipalities will no longer receive a corresponding credit, and instead must absorb the 35 per cent loss in assessment on these properties.”

What’s next?

There are indications the Government of Alberta is looking to “update” the way property taxes are assessed for oil and gas companies.

The current assessment model, according to a government publication, “does not reflect the circumstances faced by many shallow gas producers with older, lower productivity assets.”

Essentially, the government appears concerned that companies are being taxed too much, in an environment where they’re reaping less profits from their wells.

This, the government says, “has required the province take action.”

This has led to speculation the government will move to reduce the amount of property tax owed to local governments — at least on some types of wells — meaning counties could find themselves struggling even more.  

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.

For more than two years, the British Columbia government has vigorously fought efforts to compel the release of information on the hundreds of millions of dollars in subsidies that it doles out to fossil fuel companies each year.

It has either refused outright to release documents or it has handed over pages of essentially worthless information with all the dollar figures and company names blanked out.

Now, thanks to successive appeals to the Office of Freedom of information and Privacy by the B.C. office of the Canadian Centre for Policy Alternatives, the public finally has details on just how extensive those subsidies are.

The list shows for the first time publicly the astonishing scale of the so-called “deep well credit” program and provides insight into how much companies that drill and frack for natural gas in northeast B.C. continue to be bankrolled by the provincial government.

Established in 2003, the deep well credit program was intended to underwrite some of the costs that fossil fuel companies incurred for drilling deep and later horizontal wells. Back then, such wells were far less common than today and companies that drilled them gained credits for doing so. The credits were then used to lower the royalty payments companies paid to the Province once the gas flowed. Companies only pay royalties at the end of the exploitation and production process.

In the 17 ensuing years, however, such wells have become standard industry practice, meaning that the credit program is effectively an embedded subsidy.

The new information that the government was compelled to release shows that in fiscal year 2018, a total of 26 fossil fuel companies earned a combined $703 million in credits. The biggest credit recipient at more than $143 million was Cutbank Dawson Gas Resources Ltd., led by Encana, a company that made hefty political donations to the provincial Liberals ($1.2 million) and NDP ($113,000) between 2005 and 2017.

When the credits received by the next four largest recipients are added to those of the Cutbank group, they total $464 million, which means that two in every three credits that year went to just five companies.

Included in that list is Petronas Energy Canada Ltd., the Malaysian-owned company that is one of the principle partners in the approved Canada LNG project, which when built will benefit from an array of subsidies including corporate tax breaks, discounted electricity prices and deferred provincial sales taxes on construction costs. If you see a pattern here, you are not alone.

Companies only get to exploit natural gas resources after paying for “subsurface” rights, which are obtained through one-time auctions by the province known as land sales, even though it is not the land itself that is sold but what lies beneath it.

Only after such sales, can companies drill and frack for natural gas. And only after that, do they pay royalties to the province on the gas produced, which recognizes that the resources are publicly owned.

Unlike Norway, which invests its royalty proceeds for the future, B.C.’s royalties go into general revenue. But the royalties flowing into the provincial treasury are rapidly shrinking. In 2018/2019, the total value of all natural gas royalties was $102 million compared to a decade earlier when it reached $1.3 billion.

Making matters worse, the amount of gas produced in B.C. has risen more than 70 per cent over the same time period, meaning the public received far less money as far more gas was produced.

Part of the reason for the precipitous decline in royalties is that they are tied to the market price for gas and market prices have fallen sharply. But it is also the case that the credits have contributed to anemic royalty revenues. And with a combined $2.62 billion in credits sitting in the credit account, thanks to the credit program’s 17-year duration, those anemic revenues will be a fixture for years to come.

This is clearly not information that the government wants made public and may explain why in 2017 it tried to suggest it could not be released because it constituted sensitive “tax” information. When that argument was later successfully challenged under appeal by the CCPA, the government then argued in 2018 that publicizing such figures would harm the interests of undisclosed “third parties.” The CCPA challenged that argument too and eventually after much delay the credit amounts were released.

What the public still does not know, but should, is just how much in royalties Encana, Petronas and others pay annually. This too has been requested by the CCPA. But if you guessed that the finance ministry has refused once again to release it, you guessed right.

So once again, the CCPA has appealed the government’s decision to withhold the documents to the Office of Freedom of Information and Privacy.

We hope that with that information the public will, for the first time, be able to compare the credits to the revenues and ask the questions that ought to be asked, including:

• Is the government lowering royalty fees and effectively propping up fossil fuel extraction that would otherwise be unprofitable? And if so at what cost?

The appropriate thing for the province to do would be to quit the delay game and release the figures.

There is longstanding precedent for doing just that with another publicly owned resource in B.C. — our forests. For decades, members of the public have had access to a database that spells out in great detail what logging companies pay the provincial government for trees cut on public lands.

Significantly, the searchable Harvest Billing System database came into being partly in response to allegations from U.S. lumber producers that B.C.’s timber-pricing policies shortchanged the public. The result was that full public access was provided to detailed information on exactly what individual companies paid for publicly owned resources.

If the dollars paid by Canfor for the trees it logs are part of the public record, then the dollars that Encana pays for the natural gas it extracts from the ground should be part of the public record too. By withholding such information, the public is quite naturally left with the impression that its resources are practically being given away to private business interests with the government’s active and very generous support.

Ben Parfitt is a resource policy analyst with the B.C. office of the Canadian Centre for Policy Alternatives.

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