The Alberta Energy Regulator has indefinitely suspended at least 19 environmental monitoring requirements for major oilsands producers, including Syncrude, Suncor, Imperial Oil and CNRL.

The decisions come one month after the Canadian Association of Petroleum Producers (CAPP) sent a long letter to the federal government outlining requests that environmental and pollution monitoring requirements be put on hold, requirements it described as “low-risk regulatory obligations.”

Now the regulator has issued a series of decisions that include the suspension of some environmental monitoring in the oilsands.

“It’s quite shocking and it is quite concerning,” Mandy Olsgard, a risk assessment specialist and former senior environmental toxicologist with the Alberta Energy Regulator, told The Narwhal.

For some monitoring, “losing this data for a very short amount of time might not affect the overall datasets,” she said. “But some of these clauses are there to understand potential acute risks to health or the environment.”

For Olsgard and others, the regulator’s decisions read like a “wish list” from CAPP.

In an email, regulator spokesperson Shawn Roth said “[the regulator] is in regular contact with industry, including industry groups such as, CAPP and [the Explorers and Producers Association of Canada], as we work together to navigate through the current situation.”

“Looks like CAPP got its way,” Shaun Fluker, an associate professor of law at the University of Calgary, told The Narwhal. 

The regulator has granted suspensions to multiple major oilsands projects for requirements ranging from volatile organic compound monitoring to fugitive emissions leak detection to wetlands and wildlife monitoring to bird monitoring at tailings ponds.

Just days before bird monitoring programs were suspended, Imperial Oil found dozens of dead grebes and shorebirds in their tailings ponds, according to CBC. While the regulator has required that scare cannons and other deterrents remain in place, an Imperial spokesperson said these were not effective in preventing birds from landing at the company’s tailings ponds.

Bird monitoring in the oilsands gained international attention when more than 1,600 ducks were found dead after landing on a Syncrude tailings pond in 2008. More recently, Syncrude was fined more than $2.7 million last year after 31 great blue herons died in their tailings ponds in 2015. Those herons were initially discovered by a contractor working on a bird monitoring program for Syncrude. 

As Olsgard notes, these current suspensions come during an important bird migration season.

The suspension of these requirements is effective immediately, which leaves some experts questioning how sites will be monitored. 

“You don’t know what’s going on in groundwater or surface water or fugitive emissions,” Barry Robinson, a Calgary-based lawyer with Ecojustice, told The Narwhal.

“It really is stepping out into no man’s land by suspending the actual monitoring,” he added.

“You just won’t know what’s happening.”

Olsgard is concerned that while temporarily stopping some monitoring may not pose a huge issue in the long run, other data is critically important to assessing risk to public health and the environment. 

But companies like Syncrude and Suncor emphasized to The Narwhal that these suspensions were necessary for the protection of public health during the ongoing coronavirus pandemic. 

“We understand and know the public expects us to responsibly develop the oilsands, which includes monitoring for potential impacts, but we also want people to recognize that we’re relying on the guidance of Alberta Health Services,” Will Gibson, spokesperson for Syncrude, said.

The Narwhal previously reported the Alberta government had suspended the requirement to report on some environmental monitoring as a result of COVID-19. 

The latest decisions by the regulator put some monitoring itself on hold as well.

Roth said by email that companies must continue to collect the “majority of monitoring information” and make it available upon request.

But with the latest suspensions, experts are concerned some information will never be collected.

“There’s nothing to report if you don’t monitor,” Fluker said.

8 environmental responsibilities Alberta’s oil and gas companies can skip because of coronavirus

‘Unilateral’ decisions

Each decision is labelled as a “unilateral amendment to approval conditions regarding monitoring in response to COVID-19” and was posted on the regulator’s website. “We anticipate that the amendments will be in place as long as the public orders issued under the Public Health Act remain in effect,” Roth said in an email.

For some operations, such as Imperial Oil’s Kearl mine and Cold Lake in-situ project, the list of types of environmental monitoring programs suspended contains 19 items. (Imperial’s Kearl work camp is itself the site of a COVID-19 outbreak.)

According to the decisions issued by the regulator, the companies have “raised legitimate concerns about their ability to meet monitoring requirements” during the ongoing COVID-19 pandemic.

“We made a request to the Alberta Energy Regulator, along with other oilsands operators to suspend certain monitoring activities,” Gibson, the spokesperson for Syncrude, told The Narwhal.

“We made this request because the safety and wellbeing of our employees is a top priority,” he said. “We’re following, and expecting our employees to follow, recommended and mandated government measures.” Gibson said the company wants to “make sure physical distancing is maintained” whether on buses, on site or in work camps.

Erin Rees, a representative for Suncor, reiterated Gibson’s explanations. “Since mid-March Suncor has been focused on doing our part to flatten the curve of COVID-19. Reducing interactions between people on our sites and in our offices is critical in ensuring the health and safety of our workforce and we’ve limited people on site and in offices to essential staff only since the middle of March,” she said in an email.

“We made requests to the [regulator] to postpone some monitoring in order to protect workers and the public from COVID-19 and specifically to ensure public health guidance is respected.”

“To be clear — all requests for postponement of monitoring were due to the number of people required to perform the work, impacting our ability to ensure physical distancing.”

Gibson said Syncrude has dramatically reduced its workforce in other areas as well, noting staffing at its Aurora and Mildred Lake operations have been reduced by more than 1,000 workers.

Some “monitoring activities posed a challenge in terms of maintaining physical distancing,” he added. The company has also reduced its operations maintenance staff.

Olsgard, the toxicologist, noted that with decreased staff on site to run oilsands operations, the risk to public health and the environment may actually be increased. “We’re actually in kind of a high-risk operational state,” she said.

David Spink, a retired Government of Alberta employee and former director of air and water approvals, told The Narwhal by email that he questioned the assertion that monitoring work can’t be done safely. 

“I find it somewhat hard to accept that we can have construction workers doing work on an expansion to our condo building but the oilsands industry can’t have contractors come in and do some of the monitoring that is required,” he said. 

“Having done and seen some of this monitoring it can be done very safely in the context of social distancing and minimal interactions,” he added, noting that companies should be asked to provide much more specific detail about why each monitoring requirement can’t be met, or how the missed data could be mitigated.

Imperial Oil and CNRL did not respond to The Narwhal’s request for comment by publication time. 

Concerns about work camps

Currently, Alberta’s public health rules restrict gatherings of more than 15 people, encourage physical distancing of two metres and restrict business activities to those considered to be essential services.

Essential services are still allowed to operate in the province, and the government has issued a long list to clarify what is considered essential. 

“Petroleum, natural gas and coal” jobs are considered to be essential services in Alberta, as are “environmental services for agriculture, mining, oil and gas.”

Gibson, the spokesperson for Syncrude, emphasized the company was concerned about bringing in contractors from outside the region to complete environmental monitoring.

“Some of the monitoring activities involve bringing in people from outside the province,” he said, adding that he was “not sure if we have that capability right now” to have monitoring be completed in house.

“We understand and respect the need for monitoring,” he added. “We’re not asking for these activities to be altered or taken away.”

For people in the field like Charlotte Clarke, a consultant who works in the oil and gas industry, there are serious concerns about worker safety during the pandemic.

“Whenever we delay inspections, it always is concerning for me,” she told The Narwhal. “But when it came to the choice between that and my safety, it’s a hard one.” 

For Clarke, an engineer who works with in-situ operations in the oilsands, staying in work camps is the real concern, more so than the daily work itself.

“You wouldn’t be able to maintain social distancing,” she says of the mess hall at camp. “It’s pretty much like a school cafeteria.”

“I’m just really glad that I didn’t have to go through that.”

What work is safe during a pandemic?

Minister of Environment and Parks Jason Nixon has previously said that it was his government’s goal to “keep people working … in the oil and gas industry where safe and within the requirements the chief medical officer has set out.” 

“We believe we can do that on lots of projects,” he added. He was referring to the cleanup of inactive and orphan oil and gas wells.

That leaves Robinson wondering why environmental monitoring in the oilsands can’t be done safely as well.

“If the operation is running, the monitoring should be running,” Robinson said.

Olsgard agrees. “They could have developed COVID-specific protocols to address worker safety,” she said. 

Fluker points to other activities deemed essential and the hazards facing workers. “The province is OK with letting Cargill operate,” he said, pointing to the largest single outbreak of COVID-19 in Canada, in a meat-packing facility in High River, Alta. 

Meanwhile, bird monitoring is suspended in tailings ponds at Alberta’s oilsands.

“There’s a real divergence there and it’s hard to reconcile.”

‘No end date, no public notice, no discussion at all’

Olsgard is concerned with how broad the regulator’s recent decisions appear to be. More detailed requirements, she said, “might be there in the background, but I don’t see it from this decision.”

Fluker points to the lack of public consultation and notice as concerning aspects of the regulator’s most recent decisions. 

“If we’re going to relax or waive [requirements], at a bare minimum we have to at least give public notice,” he said. “In this case, the regulator has decided to even do away with that.”

These decisions, he said, amount to “unilateral amendments to a list of monitoring requirements which are easily associated with some pretty significant public interest concerns.”

“And they’re suspended for the foreseeable future with no end date, no public notice, no discussion at all.”

Without public consultation, he said, there’s no chance for input as to “whether or not the essential/non-essential line is being drawn in the right place.”

For Spink, the regulator’s decisions reflect its priorities. “To my mind it is another blank check to industry and reflects a real lack of priority on/for the environment,” he said in an email.

‘You really don’t know’

In April, The Narwhal reported on a series of ministerial orders stemming from Alberta Energy and Alberta Environment and Parks that effectively suspended much of companies’ routine environmental reporting.

For Olsgard, the suspension of monitoring is far more concerning than what previous ministerial orders had laid out with regards to reporting. “As long as they were still collecting the monitoring data, they had a repository that could be requested by the regulator or stakeholders,” she said.

“Then we had those assurances that we would understand what had happened in the environment during this time. But now that we’ve relaxed monitoring, you really don’t know.”

Fluker agrees. “This is clearly, I think, much more problematic from an environmental regulation perspective,” he told The Narwhal.

“Monitoring is often how problems are obviously initially detected.”

“Some of this certainly looks like it’s more of a cost-saving measure than it is a health measure,” he added.

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The Narwhal has obtained a previously unreleased report commissioned by the Alberta government that raises red flags about whether the government’s own program to ensure oil and gas sites are cleaned up is actually working in the long term. 

The 55-page report, obtained through a freedom of information request, cites “mounting evidence” that Alberta’s land reclamation program is not ensuring former oil and gas sites meet regulatory requirements in the long run, and instead confirms that, of the sites studied so far by an internal government pilot project, all but one failed to meet the government’s standards.

A former senior government official (who asked to remain anonymous) with knowledge of the report told The Narwhal that releasing the report was “seen as an extreme risk to the department” and that there was “extreme pushback” against it being made public. 

The former official described the report as a “valuable piece of science” and one “that needed to be publicly reported.”

But “politically inconvenient” reports, the official said, were often “buried” within the department, regardless of the government in power.

The province’s United Conservative Party (UCP) government has indicated that the office that has been working on this research — the environmental monitoring and science department — will soon be eliminated, and its staff “integrated” into other government departments.

‘The public needs to know that this land is being degraded’

There are nearly half a million oil and gas well sites in Alberta, covering an estimated 400,000 hectares — an area approximately five times the size of Calgary. 

For the last century, oil and gas companies have made a promise to Albertans — that the wells they’ve drilled across the province would one day be cleaned up. Companies promised that land would be returned to just as good as before drilling, sometimes even boldly claiming it would end up even better.

The Environmental Protection and Enhancement Act, the legislation that governs how companies must act to protect the environment, requires that operators — like those drilling oil and gas wells — fulfill “the objective of protecting the essential physical, chemical and biological characteristics of the environment against degradation.”

But the report finds that the government’s reclamation certificate program is unable to ensure this is happening in the long run.

The government updated its reclamation criteria in 2010, requiring cleaned-up well sites to achieve a sort of equivalence with nearby land. The government issues certificates to sites to mark them as officially cleaned up, called reclamation certificates. 

However, many reclaimed sites are not actually reclaimed at all, according to the report. 

In farmer’s fields, the exact outlines of well pads may be clearly visible through crop degradation. 

A drone shot used in a presentation made by an Alberta Environment and Parks scientist at an Alberta Institute of Agrologists conference in April 2018. The image clearly shows lingering crop degradation, long after a reclamation certificate was issued. The Alberta Institute of Agrologists told The Narwhal in fall 2018 that “there was unwanted negativity toward s[the] findings.” Image: Alberta Environment and Parks

In forested areas, there may be no trees where wells used to be.

Peter Eggers, a farmer in northern Alberta, told The Narwhal last year that an old well site on his property that has received a certificate is known locally as “the spot where nothing grows.” 

As John Begg, recently retired senior manager of public land policy and former manager of the public land reclamation program with the Government of Alberta, told The Narwhal: “The public needs to know that this land is being degraded.”

“The fact that a … certificate is issued doesn’t mean everything is good — or is going to be good in 20 or 30 years.”

Shari Clare, a professional biologist and one of the authors of the report, told The Narwhal by email that the provincial government is “very focused on the short-term goal of issuing reclamation certificates, with the assumption that once a site is certified it will continue to improve through time.”

But, she said, “there is evidence to suggest that this is not the case.”

Long-term impacts of wells ‘largely unknown’

Companies are supposed to restore an area where a well has been drilled to “equivalent land capability,” a term that — according to the report — has turned out to be more subjective than one might imagine. The government uses an extensive list of criteria to compare an old well site to a nearby piece of land that hasn’t been drilled.

In the public understanding, a reclamation certificate should ensure that the site of an oil or gas well has been returned to an environmentally acceptable state. 

The report’s authors note “the ecological implications of certification remain largely unknown,” citing a number of factors, including a lack of any long-term monitoring of well pads after they are certified.

“[S]ites are underperforming long after certification,” the authors write, referring to reclamation certificates issued by the regulator once it deems sufficient work has been done. 

They note previous research has shown “a large number of certified well sites do not meet an acceptable standard,” as defined by the government.

Alberta Environment and Parks did not respond to The Narwhal’s repeated requests for an interview.

Oil operations near Carseland, Alta. An author of a previously unreleased report on the long-term reclamation of sites like these told The Narwhal that the government and the provincial energy regulator are “very focused on the short-term goal of issuing reclamation certificates, with the assumption that once a site is certified it will continue to improve through time.” Her research found “mounting evidence” that this is not the case. Photo: Todd Korol

Alberta’s reclamation certificate program is overseen by the Alberta Energy Regulator, an independent corporation funded entirely by industry that oversees the regulation of oil and gas activities in Alberta.

The Alberta Energy Regulator declined to make anyone available for an interview and instead requested questions submitted by email.

Shawn Roth, a spokesperson for the Alberta Energy Regulator, said in an emailed response that the regulator has “concerns with the methodology and interpretations made in the report.”

He noted that the sites studied received a reclamation certificate before the government’s current criteria were being used to evaluate equivalent land capability. “A site should not be reassessed using criteria that came into place after its reclamation certificate was granted as criteria evolve over time,” he wrote.

But the report notes that, currently, a “fairly substantive number of reclamation certificates are being issued for sites that do not meet the 2010 criteria,” because the regulator grants exceptions to companies by labelling their applications as “non-routine.”

“This raises important questions regarding long-term liability of these sites, that will eventually shift to Albertans on both private and public land,” the report’s authors write.

Clare, one of the authors of the report, told The Narwhal that “while the government insists that the new (2010) reclamation guidelines will result in better outcomes, there is no requirement to monitor these sites once they have been certified.”

And, as others point out, the massive number of sites that have already been certified as reclaimed may be a liability Alberta needs to deal with.

“Some of the things that are diminished are maybe permanent,” Begg said. “It’s not necessarily fixing itself over time.”

Alberta’s Energy Regulator’s public reporting is ‘not transparent’

The report alludes to a brewing regulatory failure to oversee the reclamation certificate process in the first place.

The report — which dubs the Alberta Energy Regulator’s public reporting as “not transparent with respect to very basic metrics,” “somewhat opaque,” and “unlikely to be informative” — was provided to the Alberta Energy Regulator in 2018 by Government of Alberta staff, according to emails obtained through a freedom of information request. 

The report contains a lengthy analysis of Alberta’s reclamation laws, policies and regulations and raises concerns about the Alberta Energy Regulator.

In it, the authors wave a red flag about the regulator’s audit system, which relies on a program for certification that is largely automated and seldom sends auditors out into the field to check the work of consultants hired to fill out applications for reclamation certificates. 

Less than three per cent of sites that have received reclamation certificates from the Alberta Energy Regulator have been visited as part of an audit of the site’s approval, which is largely automated. The public has frequently been told 15 per cent of sites would be visited for an audit. Graph: Sharon J. Riley, Carol Linnitt / The Narwhal

The authors interviewed practitioners who work in reclamation. Those practitioners felt the “audit system resulted in a greater proportion of poorly performing sites being certified, as there was less regulatory oversight in the audit system.”

Begg, the retired former manager of Alberta’s public land reclamation program, is concerned there are few consequences for a company when an audit reveals a site should have failed. “When there’s an audit failure there’s got to be drastic consequences, other than just failing the site,” he said.

Currently if an audit reveals a site should have failed, the company will simply need to update its application and complete any work to ensure the site passes next time.

The report suggested there is a large amount of leeway for the consultants that sign off on reclamation jobs, even if they may not meet the criteria required by the government.

Following an analysis of data provided by the regulator, the report found a “fairly substantive number of reclamation certificates are being issued for sites that do not meet the [government’s] criteria.”  

And that’s a problem — as the government has no mechanism to monitor the health of sites in the long term.

The report noted “there are no formal or legislated post-reclamation metrics against which to evaluate reclamation outcomes longer-term.” 

And with the soon-to-be elimination of the government division that was looking into long-term monitoring, it seems unlikely there will be any type of metric in the future.

No consensus a reclaimed well site is ‘actually going to grow a tree again’

The report notes that forestry operators have long found that certified well sites in the boreal region “do not support trees with the same growth and yield” and that farmers and landowners report that crop productivity on certified well sites is not comparable to the rest of their fields.

According to Begg, “on forested well sites, there isn’t consensus it’s actually going to grow a tree again.” 

A ‘reclaimed’ oil and gas well in Yellowhead County, 250 kilometres west of Edmonton, Alberta. The landscape has not been returned to its former state. Image: Screenshot / Google Maps

The problem is often with the soil.

As Larry Brocke, former director of the Government of Alberta’s land reclamation division in the ’90s, put it in an interview with the Petroleum History Society, “You can’t put it back the way it was immediately. You just can’t.”

Roth, the spokesperson for the regulator, noted in an email that “companies remain responsible for surface issues related to reclamation for 25 years after receiving a reclamation certificate. They are also permanently responsible for contamination and any infrastructure left beneath the surface.”

But there are concerns that issues with reclamation may not be noticed for years, or even decades, particularly on remote public lands where there is no nearby landowner to keep a watchful eye.

And the question remains: how long does it take for land to get “back to what it was before” after oil and gas development? Or can it?

No one knows what will happen in the future

The Alberta Energy Regulator received the report in 2018. Nothing appears to have changed since the findings were shared among government officials.

Roth from the regulator wrote by email that “while we are not currently working on anything specifically with Alberta Environment and Parks, we are always looking for potential improvements to the reclamation certificate process.”

The Narwhal first reported on the Alberta government’s internal pilot project to evaluate a small number of reclaimed well sites in 2018. 

Since then, some of the results of that pilot project have been published for the scientific community.

In research published in November, University of Alberta scientists and their government counterparts found that “well pad impacts can be long lasting and may remain for decades or more post reclamation,” suggesting that regardless of the criteria used to measure a pass or fail, former well sites simply cannot be said to be recovering from the impacts of oil and gas development.

A paper in the Canadian Journal of Soil Science has detailed some of the results of the pilot project — and is sharply critical of the government’s ability to ensure oil and gas wells are truly cleaned up.

“There is a general lack of assurance to the public that intended goals of reclamation and recovery, as expressed in legislation, are achieved at reclaimed and certified well pads,” the authors write. 

The lead author of the paper is a land scientist with the soon-to-be scrapped environmental monitoring and science division of Alberta Environment and Parks.

The authors lambast the government for its lack of monitoring and its failure to collect scientific evidence.

They write that “even after more than five decades of certification history,” the government has not acted to collect any long-term information about the success of the cleanup of well sites.

”This type of scientific evidence is essential … to assure citizens that public and private land will be protected.”

The authors undertook a pilot project, called the ecological recovery monitoring project, that found “significant” environmental and crop impacts of oil and gas wells long after the government had signed off on reclamation certificates.

The path of a buried pipeline is clearly visible in a farmer’s fields near Fairview, Alta. Some farmers have long been concerned with the impacts of oil and gas infrastructure on their crops. A report obtained through a freedom-of-information request has warned that even after oil and gas sites are certified as reclaimed, there may be long-term issues with the productivity of the land. Photo: Amber Bracken / The Narwhal

The pilot project found “there are long-term oil and gas legacy effects on soils at reclaimed well pads.”

The funding for the ecological recovery monitoring project has since been cut, according to internal emails obtained by The Narwhal through a freedom of information request. 

And in October, CBC reported that the entire environmental science and monitoring division would be dissolved by the UCP government.

‘The most efficient regulatory system is one that doesn’t exist’

It has been internally estimated that it would cost as much as $100 billion for all the wells across the province to meet the government’s standards.

“Given how many of these sites exist on the landscape, and the enormous ecological and public liability that this represents, I think that the provincial government should be giving greater attention to this issue,” Clare, one of the authors of the report, said in an email.

There should be, she added, “less focus being put on the number of applications that are being processed, and more focus being put on the quality of those sites.”

This report raises serious questions about what happens if sites still don’t meet standards, even after they’re certified as reclaimed — at a time when the Alberta government has increasingly put an emphasis on “efficiency” in its regulatory bodies.

“The most efficient regulatory system is one that doesn’t exist,” Begg told me. “It doesn’t create any burden. That’s extremely efficient.”

That sort of system, he laments, would also mean zero oversight for companies operating all over Alberta.

Begg is adamant that more needs to be done to ensure reclamation policies have been working in the province, and that includes ensuring companies invest in reclamation work in the first place. 

“We need policies to have timelines to ensure reclamation occurs,” he tells me.

And, he added, the government — who is responsible for setting reclamation policy — needs to take a step back and fully evaluate whether its program is working (as it appears the report obtained by The Narwhal was intended to do).   

“You’ve got to look back and make sure that the things you’re doing today are delivering what they’re supposed to,” Begg says. 

Eliminating the only government department to date that has tried to do just that, he implies, certainly isn’t helping.

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 vast majority of approvals for Alberta’s oil and gas wells will soon be automated, reducing waiting times for drilling companies to as little as 15 minutes, The Narwhal has learned.

The Alberta Energy Regulator confirmed to The Narwhal by email that it expects to begin implementing automated approval for routine well licences later this year, though lobbying records indicate the system could be rolled out as early as next month.

With the change, staff will no longer review most applications from companies seeking to drill a new oil or gas well.

In lobbying records obtained by The Narwhal through a freedom of information request, Richard Wong, manager of operations with the Canadian Association of Petroleum Producers (CAPP), said the association anticipates 90 per cent of routine well applications could soon be automatically approved by OneStop, the online tool used to submit requests for permits and licences to the Alberta Energy Regulator.

The Narwhal was charged $643.95 by the Alberta Energy Regulator — an industry-funded corporation in charge of overseeing Alberta’s energy industry — to access the documents. The fee was paid by readers who donated specifically to cover these costs.

When asked for details, CAPP told The Narwhal by email that these approvals refer to applications that are “anticipated to be low-risk and, as such, the approval of each of those applications would be expedited.”

Wong, who shared CAPP’s analysis of the proposed new processes with the Alberta Energy Regulator, wrote in the documents obtained by The Narwhal that CAPP anticipated the move to automation could contribute to between $67 million and $136 million in cost savings, and that the “average business days for those approvals would accelerate … to 15 minutes.”

‘A concern for a whole host of reasons’

Thousands of new oil and gas wells are drilled every year in Alberta, and Premier Jason Kenney vowed during the recent election campaign to speed up approvals for new wells, having promised a “rapid acceleration of approvals.”

Over the past year, concerns have been raised about industry’s ability to pay for the cleanup of the hundreds of thousands of wells already drilled in the province, with internal estimates pegging the bill at $100 billion.

Automated approvals are “a concern for a whole host of reasons,” Mark Dorin, an Alberta landowner who has worked in oil and gas for decades, told The Narwhal.

“I’m not an anti-energy person,” Dorin said. “But it’s about fair, balanced decision making.”

“If we put rules in place, I’d have no concerns about new wells whatsoever,” he said.

Dorin is concerned that current processes do not protect the land where wells are drilled, ensure the safety of sites or provide any guarantee that oil and gas infrastructure will be cleaned up by the companies responsible.

Nikki Way, a senior analyst with the Pembina Institute, is concerned efficiency has been prioritized over safety and environmental quality in the regulator’s roll-out of automated systems.

“We’ve seen the announcements about fast-tracking [licences] and saving money, but where are the systems that incorporate the science and data into these automated decisions, which they’ve promised for years?” she asks.

Way is concerned the regulator doesn’t have the systems in place to safeguard air and water quality in rural communities when the regulator is “fast-tracking even more projects with no human oversight.”

How, she wonders, can Alberta “claim that we have a world-class regulator when it hasn’t prioritized the essential systems that fulfill the second half of its mandate that protects families, their land and our environment?”

‘Processed in minutes’

Other activities under the purview of the Alberta Energy Regulator are already largely automated and handled through OneStop — including reclamation certificates.

The Narwhal previously reported that 97 per cent of applications for reclamation certificates are approved without a visit to the site, and 87 per cent are approved automatically without any human oversight.

For companies seeking to drill new wells, applications that do not flag any of the regulator’s automated “risk assessment rules” can proceed automatically, without any scrutiny by staff.

A video produced by the regulator to introduce OneStop boasts that the previous automation of other types of approvals means that “25,000 pipeline applications processed annually — automatically” and that “low-risk applications [can be] processed in minutes.”

CAPP told The Narwhal by email that “CAPP sees OneStop as a significant opportunity to enable a more predictable regulatory process in Alberta, and to help enable industry competitiveness while maintaining environmental, social and regulatory outcomes.”

In an October 2018 statement about its shift to automated systems, the Alberta Energy Regulator said its “new approach is truly game changing and something that few regulators have attempted.”

Approvals are already speedy

Despite the rhetoric employed by Kenney during the recent provincial election campaign, the Alberta Energy Regulator estimates the current processing time for well and facility applications is just “five business days.”

The regulator has an internal goal that 95 per cent of new routine wells applications are approved within that time frame.

In 2018, 97 per cent of 5,691 new routine wells were approved within five days. That figure was lauded as a “big win” in internal emails sent by CAPP and obtained by The Narwhal under the Freedom of Information and Protection of Privacy (FOIP) Act.

When asked how long new well approvals would take once the system is automated, the Alberta Energy Regulator told The Narwhal by email that it “cannot provide details about the process or approval timelines at this time.”

Both CAPP and the regulator were careful to note that only “routine” applications would be processed automatically.

Alberta Energy Regulator spokesperson Samantha Peck confirmed by email that “approximately 95 per cent of new licence applications are routine.”

“An application is considered routine when the applicant has met all requirements (including participant involvement), has no outstanding public or industry concerns and regulatory waivers or relaxations are not requested,” Peck said.

But Dorin is concerned that wells like the ones drilled on his land won’t get individualized attention.

“They are always unique circumstances and they should be dealt with on a one-by-one basis,” Dorin said.

“There are no two wells that are the same.”

CAPP: automation a ‘priority’

According to the documents obtained by The Narwhal, the automation of new well approvals is part of the work of the regulator’s “regulatory efficiency council,” a “committee of senior-level energy industry executives and representatives” formed to “help the [regulator] identify, evaluate and prioritize regulatory reductions.”

CAPP correspondence with the Alberta Energy Regulator states that “automation of routine well licence approvals” has been identified as a “priority” to improve regulatory efficiency.

Last summer, Terry Abel, CAPP’s vice president of Canada operations and climate, wrote to the Alberta Energy Regulator then-president and CEO, Jim Ellis, to express his support of automation on a “priority basis,” noting that CAPP is “pleased” with the regulator’s efforts thus far.

The regulator told The Narwhal it “began work to implement well licence applications into OneStop prior to receiving Terry Abel’s August 2018 letter.”

The documents obtained by The Narwhal contain many expressions of gratitude from industry for the regulator’s efforts to increase efficiency.

“Industry has recently seen clear evidence of the [Alberta Energy Regulator’s] staff’s renewed commitment and increased focus on efforts to reduce unnecessary regulatory burden and costs,” CAPP wrote at one point.

“We wish to thank you for the ongoing efforts undertaken by the Alberta Energy Regulator to deliver a modern, efficient and performance-based regulatory system,” Abel wrote to the regulator in August.

Tim McMillian, CAPP’s president and CEO, wrote to the regulator to laud the “collaborative spirit” that had characterized the two groups’ working relationship.

‘Low-risk’

The regulator says its automated system will only apply to what it calls “low-risk” applications for new well licences.

“OneStop uses a complex set of risk assessment rules that automate low-risk (baseline) applications and forwards higher-risk and more complex applications to technical experts for an additional, manual review,” Peck, the regulator spokesperson, told The Narwhal by email.

“This ensures we are focusing our manual efforts on medium- and high-risk applications, and using our existing and continually growing wealth of data to automate low-risk applications.”

“Any applications considered to have a potential impact on the environment or stakeholders are not automated,” Peck added.

The regulator’s website offers an example of a low-risk application: the company reports to the regulator that “the landscape includes a well that produces shallow, sweet gas,” and that the well will be drilled on “flat, private grazing land and the landowner has consented to the activity, [and] no sensitive species are nearby.”

In this scenario, the approval of the licence to drill the well is automated, though the company is subject to audits and inspections.

The Narwhal previously reported that the number of sites visited for some types of audits is far fewer than previously promised, and the number of field inspectors has declined by 16 per cent since the Alberta Energy Regulator took over compliance monitoring from the government five years ago.

Way, the analyst with the Pembina Institute, is careful to point out that the automation in itself isn’t what she’s concerned about — it’s the underlying assessment of risk.

“The process of automating approvals in the oil and gas industry isn’t inherently a bad idea, if it is matched with checks and balances in that system to ensure that the right information is being considered and integrated into these automated approvals,” she told The Narwhal.

“Our concern is that the [regulator]’s promised programs for that balance have been under-resourced, de-prioritized and all but swept under the rug while the [Alberta Energy Regulator] has gone full steam ahead with automating approvals.”

Dorin said the regulator’s processes are insufficient when it comes to the approval of new well licences.

“They’re just rubber stamping these things like crazy,” he said.

The Petroleum Services Association of Canada has forecast 2,685 wells will be drilled this year in Alberta — a number viewed as low by industry.

Conventional oil and gas wells are drilled thousands of feet below the surface through layers of soil, rock and drinking water aquifers.

As a Government of Alberta fact-sheet put it, the “only way to determine whether a rock formation contains petroleum or natural gas is to drill a well.”

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A new presentation obtained by The Narwhal shows that senior staff at the Alberta Energy Regulator are projecting the number of inactive wells in the province could double in the next decade if there isn’t any change in policy.

In recent years, the backlog of wells in Alberta that are no longer active, but not yet cleaned up, has been steadily increasing. Right now, there are roughly 90,000 inactive wells in the province.

The presentation obtained by The Narwhal reveals senior staff at the Alberta Energy Regulator are privately projecting that number could double to 180,000 by 2030.

The cost of cleaning up wells is huge. Today, the Alberta Liabilities Disclosure Project, a coalition of landowners, oil and gas companies, academics and civil society groups, dubbed the problem of the province’s wells “a massive ticking time bomb.”

Inactive wells have never been plugged or sealed, are unlikely to ever be productive again, and can languish on the landscape for years — or decades. As The Globe and Mail reported last fall, the oldest inactive well in Alberta dates back to 1918.

The presentation — obtained by The Narwhal in a freedom of information request — shows that in 1999 there were approximately 30,000 inactive wells in the province, a third of the number that exist today.

A slide from the AER presentation showing the growth rate of inactive oil and gas wells in Alberta.

In addition to the 90,000 inactive wells today, another 77,000 are what’s known as abandoned — the industry term for safely plugged —  but they too are not yet reclaimed. Reclamation involves restoring the well site’s soil and vegetation. There are hundreds of thousands of wells in the province.

The rapid increase in inactive wells has implications for the estimated tens of billions in liabilities industry faces for well cleanup costs. But these costs are not borne by industry alone. 

Not only is there a burgeoning number of orphan wells in recent years, but taxpayers can end up picking up the tab for rent owed to landowners. The Narwhal reported in February that the rent payments government has made to landowners on behalf of delinquent companies is up 840 per cent since 2010.

“It’s a huge issue,” said Thomas Schneider, an associate professor of accounting at Ryerson University who studies environmental liabilities.

“It’s a pretty sad legacy to leave behind.”

‘We have a problem’

The presentation, entitled “Liability Challenges in Alberta,” was made by the regulator’s vice president of closure and viability, Robert Wadsworth, in a meeting with representatives from the Canadian Association of Petroleum Producers (CAPP) in October.

The presentation was obtained after The Narwhal asked the Alberta Energy Regulator to release a year’s worth of emails and lobbying records with the Canadian Association of Petroleum Producers. The request entailed such a “large volume of records” that the regulator charged The Narwhal $643.95 to access the documents. Our readers quickly stepped up to the plate and donated the money to pay the fee.

“We have a problem,” the presentation began.

Wadsworth presented data on the past 20 years of well closure in Alberta. While the number of wells abandoned annually — “abandoned” is the industry term for sealing or plugging a well, the first step in reclaiming a site — has remained relatively constant, the number of inactive wells has increased at a rate of six per cent per year.

The title page of a 2018 Alberta Energy Regulator presentation released to The Narwhal via Freedom of Information legislation.

The first page of Wadsworth’s presentation that begins, “we have a problem.”

“Industry needs to increase closure activities,” the presentation states.

The presentation also said that a “manageable inactive inventory” would be about 20,000 wells — less than a quarter of the current inventory.

The Narwhal asked the Alberta Energy Regulator by email if Wadsworth’s projection of a doubling of the inventory of inactive wells by 2030 is a situation the organization is anticipating.

A spokesperson did not specifically answer the question, writing instead by email that, “the liability issue has been identified as a corporate priority,” adding, “we are working towards finding solutions.”

In his presentation, Wadsworth indicates that “quotas and timelines” could prevent the explosion in inventory projected in the next ten years.

Alberta’s well liability problem has become an issue of note in the provincial election, with the NDP vowing to “implement clear timelines for when companies need to clean up their abandoned oil and gas wells and require them to justify delays in reclaiming sites.”

The United Conservative Party (UCP) platform makes no such promise, indicating instead it would ask the federal government for tax incentives for reclamation, and “speed up approvals” of new wells.

An editorial in the Edmonton Journal last week declared that the issue of oil and gas liabilities “may be the biggest single issue that has ever faced this province.”

Costly cleanup

Companies may leave wells to sit inactive because it’s expensive to clean them up.

The Alberta Energy Regulator estimates it can cost $12,800 to $134,177 to plug a well, and $16,500 to $42,155 to reclaim the site.

As The Narwhal reported last fall, a researcher at the University of Calgary found that actual reclamation costs can easily be 60 per cent higher than the regulator’s estimates. Others have said the numbers may be far higher.

The presentation obtained by The Narwhal indicates that if current conditions continued, it would take 126 years to plug all wells in the province — and this doesn’t include reclamation of the landscape.

Nor does it take into account what could happen to struggling energy companies if oil prices don’t rebound the way Albertans hope they will.

New data released Monday shows cleanup will cost billions

The Alberta Liabilities Disclosure Project, using data from the regulator’s public estimates, estimates the actual cost of cleanup of each well in the province is between $40 and $70 billion.

The result, according to a press release, is a liability “2 to 3.5 times higher than the $18.5 billion [the regulator has] told Albertans.”

According to the group, $200 million is currently being held as a deposit — less than 0.3 per cent of the group’s estimated total cost of clean up.

“Albertans are at risk of being on the hook for an oil well cleanup bill $22 to $51 billion more than the publicly reported estimates,” the Alberta Liability Disclosure project said in a statement.

“That’s a massive problem.”

The Alberta Energy Regulator did not respond to request for comments on these new figures by press time.

Reclamation certificates before reclamation is complete?

Currently, a company is issued a reclamation certificate from the Alberta Energy Regulator after a wellsite has been fully reclaimed — though questions have been raised about the quality of the work being approved.

Wadsworth’s presentation suggests the regulator might consider issuing reclamation certificates before all reclamation work is completed through the use of “progressive and partial” certificates.

When asked for clarification, a regulator spokesperson said progressive certificates would mark “stages or major milestones of reclamation activity,” while partial certificates would be used when only a portion of an active site has been reclaimed.

It seems a company may be able to receive some sort of credit from the regulator before finalizing full cleanup of a site.

Both new types of certificates are “are still being assessed and reviewed,” according to the spokesperson.

When The Narwhal asked if a partial reclamation certificate would mean a company may be off the hook for making rental payments to landowners, the regulator declined to answer.

Mike Smith, retired oil and gas well reclamation inspector, at a flooded oil lease site in Wainwright, Alta. This site has been suspended, according to the regulator. Smith lives nearby and drives by the site occasionally, to see if any reclamation work is being done. It isn’t. He’s seen plenty of contamination issues over his career. If no one checks, he worries about the long term recovery of sites. “Those problems are still there,” he says. Photo: Amber Bracken / The Narwhal

The wells of bankrupt companies

The regulator has long been criticized for allowing financially precarious companies to obtain licenses for wells associated with large environmental liabilities. The Orphan Well Association lists 2,000 wells in the province that have yet to be ‘abandoned,’ an industry term for properly sealed, and whose owners are now bankrupt.

The presentation suggests that a “corporate health tool” could replace the regulator’s current system for rating liabilities which is used to determine if a new well should be approved.

In the presentation, the tool is described as an automated system used to weigh a company’s ratio of inactive wells with inventory, production and financial health among other factors. In its election platform, the NDP indicated plans to implement a corporate health tool of this kind. (See The Narwhal’s comparison of NDP and UCP platforms when it comes to oil and gas wells here.)

A spokesperson with the regulator told The Narwhal, “we are currently refining a corporate assessment tool to assess risk using financial, behavioural, and inventory risk factors.”

The spokesperson noted that the regulator already has “more discretion to reject applications” than in previous years and that companies are now required to disclose audited financial statements or insolvency proceedings.

But Schneider, an expert in environmental liabilities, is concerned that not even a corporate health tool can predict whether a company will be able to pay for clean up in the future. He also worries that this kind of assessment can favour large companies.

“They look healthy” at first, he said, “then everything goes south.”

Without a deposit on hand, he added, there’s no guarantee that clean-up costs will be covered.

‘Too much room for politics and regulatory capture’

As for whether the province is going to take any serious steps towards mitigating the growth of inactive wells, Schneider isn’t sure.

“It’s a question of political will,” he said. “The only solution is starting to do the actual decommissioning.”

“We need to start getting serious security put to the side,” Schneider says, noting the current system “leaves too much room for politics and regulatory capture.”

There are concerns that a rush to reduce liabilities on paper could lead to lax regulations around certification. A recent investigation by The Narwhal found that the regulator approves 97 per cent of reclamation certificates without sending an auditor to the site, despite having previously assured the public 15 per cent of sites would be visited.

Then there are concerns about what happens to the hundreds of thousands of wells puncturing Alberta’s landscape if the industry becomes less profitable.

“It’s an industry that’s not going to last forever — whatever you say the horizon is,” Shneider told The Narwhal.

The question remains: who’s going to end up with the bill?

In Wadsworth’s presentation, he highlighted that “growing liabilities” are a “shared liability problem” — shared, he noted, by industry, the regulator, government and taxpayers.

Wadsworth pointed to “industry retain[ing] the liability” as a “strategic goal” in the coming years. But no one knows for sure if this is really in the cards.

“The oil and gas industry is legally obligated to fund the cleanup of its environmental liabilities,” Greg Rogers, an environmental risk and liability consultant and member of the Alberta Liability Disclosure Project, said in a press release.

“But the industry isn’t setting aside anywhere near enough money to do it which means the public will be left on the hook for the costs.”

“If it ends up in the hands of Alberta to pay for it, it’s a huge liability,” Schneider said.

Wadsworth AER Presentation Liability Challenges in Alberta by The Narwhal on Scribd

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Documents obtained by The Narwhal reveal that, for the last four years data is available, 2014 – 2018, less than three per cent of oil and gas sites certified as reclaimed have been visited by an inspector from the provincial regulator — a far cry from the 15 per cent the public has been long told.

The data — accessed through a lengthy back-and-forth with the Alberta Energy Regulator’s media team and freedom of information office — shows that since the spring of 2014, more than 9,400 reclamation certificates have been issued, but during that same time period, just 277 sites were actually visited by the regulator for an audit.

This means the vast majority of oil and gas sites are certified as reclaimed without any independent physical assessment by the regulator — and most reclamation certificates are granted by an automated system.

This wasn’t always the plan.

In a 2014 report, the Government of Alberta noted there are “randomly selected field audits on approximately 15 per cent of all sites that have received a reclamation certificate.”

And at a 2015 landowner oil and gas information workshop, government and regulator officials — including Kevin Ball, senior advisor with the Alberta Energy Regulator — told participants that 15 per cent of sites are visited for a field audit.

But this is certainly not the case under the Alberta Energy Regulator, which oversees the certificate program today.

2015 – 2017: not a single subsurface audit conducted

The Alberta Energy Regulator took over handling reclamation certificates from Alberta Environment in 2013. It launched an automated approval system online, called OneStop, in 2016.

Though the audit system is often understood as a way for the regulator to go out into the field to assess the work of the contractor who applied for the reclamation certificates, it has largely come to mean a human eye looking at an application’s details, and has rarely entailed a visit to site.

The percentage of certified reclaimed sites where the regulator completed a surface or subsurface audit between 2014 and 2018. In 2015, the regulator and the government told landowners 15 per cent of sites would be visited for a field audit. In reality, less than three per cent of sites have been visited. Graph: Sharon J. Riley, Carol Linnitt / The Narwhal

When The Narwhal started looking into this issue last fall, the Alberta Energy Regulator initially told us by email that “84 per cent or 1767 of the 2093 issued reclamation certificates were audited” in fiscal year 2017/2018.

When pressed, a spokesperson changed the number. “We discovered that the number provided was incorrect,” she said in an email.

“The [Alberta Energy Regulator]’s audit program flags 15-30 per cent of reclamation certificates for desktop, surface, or subsurface audits,” a spokesperson for the regulator then told The Narwhal by email last fall.

More recently, the regulator told The Narwhal by email that, “on average, 15-20 per cent of reclamation certificates are flagged for desktop, surface, or subsurface audits.”

Either way, none of these statements accurately capture what’s been going on over the most recent four years of data available.

Data shows that 12.7 per cent of approvals have involved any kind of audit at all over the most recent four years data is available, 2014 to 2018. Of those audits, the vast majority are simply a human review of the paperwork, a procedure called a “desktop review” that was introduced in 2016.

Less than three per cent of sites that have received reclamation certificates from the Alberta Energy Regulator have been visited as part of an audit of the site’s approval, which is largely automated (2014-2018). The public has frequently been told 15 per cent of sites would be visited for an audit. Graph: Sharon J. Riley, Carol Linnitt / The Narwhal

Field visits are much more rare.

Since taking responsibility for regulating reclamation, the highest number of sites visited by the regulator in the province in one year is 117, while between 1,110 and 4,500 certificate have been approved annually.

In fiscal year 2015/2016, just seven sites were visited for an audit, while 1,184 were issued reclamation certificates.

Even fewer sites involve what’s known as a subsurface audit, which involves looking below the surface of the site and collecting soil samples for lab analysis.

In 2015, officials told landowners that five per cent of sites would receive a subsurface audit.

In reality, just over one per cent of reclamation certificates have involved a subsurface audit in recent years.

Between 2015 and 2017, not a single subsurface audit was conducted, while nearly 6,000 reclamation certificates were approved.

The regulator cites “budget constraints” as the reason for not conducting any subsurface audits in those years.

The Alberta Energy Regulator is an independent corporation funded entirely by industry. It is mandated by the provincial government to oversee regulation of oil and gas activities in Alberta.

A spokesperson says the program was in a “state of transition” and that it has only been auditing under its current system for one year (five per cent of sites were visited for any kind of field audit last year). Thirty-six per cent of reclamation certificate applications were audited — the vast majority of which were desktop reviews — last year, up from five per cent in 2016-2017.

The rest were approved by the regulator’s automated system.

The vast majority of reclamation certificates in Alberta are approved via an automated system and never audited by the regulator (2014-2018). Sharon J. Riley, Carol Linnitt / The Narwhal

Up until 2003, Alberta’s reclamation program involved field visits to every site applying for a reclamation certificate. Government inspectors would head out to former wellsites to make sure clean-up efforts met government standards.

That all changed in 2003, when the government moved to an audit system, with a spokesperson telling The Globe and Mail at the time that random field audits would help ensure compliance, and that the province planned to audit 15 per cent of the sites.

‘Bingo-dauber agency’

In 2003, 14 people gathered around a long conference table to talk about the future of reclamation certificates in Alberta. They were the Oil and Gas Remediation and Reclamation Advisory Committee, created to provide recommendations to the minister on the new system that had just been designed to “enhance capacity needed to deal with an increasing workload” — in other words, they were overwhelmed with applications for reclamation certificates.

Some committee members were representatives of Alberta Environment, the Surface Rights Federation, the Farmers’ Advocate and the Energy and Utilities Board, among others. Two representatives were there on behalf of the Canadian Association of Petroleum Producers (CAPP).

Peter Eggers, a director with the National Farmers Union who farms near La Glace, Alta., was there, too. He was representing the Alberta Conservation Tillard Society.

Eggers had had his own problems with a certified reclaimed well pad on his property — he told The Narwhal that the Orphan Well Association had paid for its cleanup, and removed thousands of tonnes of soil. Still, Eggers said, the quality of the site has never been the same. His neighbour, he told The Narwhal, refers to the certified reclaimed well pad as “the spot where nothing grows.” It’s been a long-standing headache.

Eggers was interested in the reclamation certificate process, and was optimistic he’d be able to have input. “People said the oil companies were dictating how things would happen,” he remembers.

He wanted to find out for himself.

CAPP ‘put their fist down’

Eggers told The Narwhal he was paid an $8 per diem to attend the meetings in Edmonton. The purpose, he says, was to develop a way to “streamline” the process through which companies could receive reclamation certificates.

On the final day, Eggers told The Narwhal, the CAPP delegates sat at one end of a long conference table, Alberta Environment representatives at the other. The two parties, Eggers said, looked only at each other. Other participants watched from the sidelines, literally.

“The CAPP people were dictating to the [Alberta] Environment people” he said. “The CAPP people would always kind of put their fist down.”

“The rest of us were there just for the alibi.”

The end result, according to Eggers, is a “bingo-dauber agency” — now the Alberta Energy Regulator — that approves reclamation certificates without what he considers to be sufficient regulatory monitoring.

“It’s an agency that supposed to appear to the public that they have really good oversight,” he said.

“But it lets sites slip through the cracks.”

Active wells near Hays, Alta. Photo: Theresa Tayler / The Narwhal

Certificates approved ‘within a matter of hours’

The Alberta Energy Regulator’s annual report advertises that the majority of applications are approved using its automated system, OneStop, boasting that at one point 2,100 reclamation certificates (which it deemed “low-risk”) were processed “within a matter of hours” — no human oversight, no field visit, no inspection of the land or soil’s condition.

In Eggers’ committee’s recommendations to the minister in 2004, it was made clear that 15 per cent of all reclamation certificates were to be audited, and that an audit would involve a “field investigation component,” including the possible use of soil sampling equipment or laboratory analysis — a far cry from a desktop review.

At some point, the 15 per cent standard was apparently dropped, and the “field” was dropped from “field audit.” Prior to the introduction of “desktop audits,” all audits involved a field visit.

Eggers is clear that this is not how the program was initially intended to function: “An audit is also a site visit to verify that the written report and the actual condition [of the site] matches,” he said.

When asked for comment, the Alberta Energy Regulator responded to questions by email.

When The Narwhal asked if there had ever been a public announcement of this shift from field audits to primarily desktop audits, we were pointed toward a brief announcement unveiling OneStop. There is no mention of field audits.

“The [Alberta Energy Regulator] does not have a specific audit target for reclamation certificates,” Samantha Peck, a spokesperson for the regulator, wrote to The Narwhal.

“Our audit program was revised in 2016 and now uses statistics and confidence intervals to determine the number of audits that will be conducted within a given period,” Peck continued.

“[The Alberta government] does not provide direction or guidelines on the percentage of audits completed by the [Alberta Energy Regulator],” Peck said by email.

Slides from a Government of Alberta and Alberta Energy Regulator presentation delivered to landowners that indicates 15 per cent of oil and gas sites receiving reclamation certificates would be audited.

Peck referred The Narwhal to Alberta Environment and Parks for answers to questions about previous public commitments to conduct field audits at 15 per cent of sites.

The Narwhal first requested an interview with the Alberta Environment and Parks land reclamation policy team about this topic on Feb. 6.

After following up on Feb. 14, Feb. 15, Feb. 27, March 1, March 4, March 9, March 11 and March 19 — including sending questions by email, as requested — The Narwhal was told that the communications team was “not able to get the messages through approvals before the election was called… Sincere apologies.”

‘Perverse incentives’

There are tens of thousands of inactive wells on the landscape, and the number has been growing every year.

Unlike in other jurisdictions, such as in parts of the United States, there are no required timelines in Alberta as to when a company has to clean up a site. It becomes a calculation — costs versus benefits for the company.

Once a company does decide to invest in cleanup, obtaining a reclamation certificate removes the liabilities it keeps on its balance books, and relieves it of the obligation to pay rent to the landowner where the pipeline or well is located

“Reclamation is not always simple or cheap,” Regan Boychuk of Reclaim Alberta told The Narwhal by email. “Auditing is crucial in order to protect Albertans from long-lasting risks and consequences.”

“Issuing certificates on the basis of paperwork without verification in the field creates perverse incentives for industry to forego expensive remediation and instead gamble it will ever be uncovered,” he said.

“Regulators have repeatedly chosen to prioritize industry’s interests over the health and safety of Albertans and their environment.”

The Alberta Energy Regulator points out that its automated approvals allow it to focus more energy on what it deems to be high-risk applications.

“To improve efficiency, the [regulator] is focused on improving application turnaround timelines, ensuring modern, effective requirements, and continuing to transform how we operate in order to keep up with market and technology changes that affect industry,” a spokesperson for the Alberta Energy Regulator told The Narwhal by email last fall.

Peck, a regulator spokesperson, told The Narwhal that it maintains that it “continually refines its reclamation certificate program to ensure the [Alberta Energy Regulator]’s mandate can be met, requirements remain effective, and assessment rules remain relevant.”

The Narwhal previously reported that the number of field inspectors has declined by 16 per cent since the Alberta Energy Regulator took over from Alberta Environment in 2013.

Necessary checks and balances?

Whether audits are necessary at all is up for debate.

The current system requires that an accredited professional — an agrologist, a forester, an engineering technologist or similar —contracted by the company, signs off on a reclamation certificate application before it is submitted to the Alberta Energy Regulator.

For some, that professional assurance is enough — professionals could lose their accreditation if they sign off on subpar reclamation efforts — but for others, regulatory oversight is necessary, and even professionals need to know their work may be checked.

As one professional who spoke to The Narwhal last fall on the condition of anonymity put it, the company a contractor is evaluating a site for is also “going to be signing off on [their] invoice.”

Numerous contractors told The Narwhal there can be pressure to pass sites.

David Lloyd, CEO of the Alberta Institute of Agrologists — whose members are among the professionals contracted by companies to sign off on reclamation certificate applications — told The Narwhal by email that, “unless the professional body has specific practice standards in place related to a specific activity (like reclamation or remediation) and unless the profession is conducting a practice review of their members related to that practice standard, governments, I believe, should be auditing all professions equally and fairly.”

“If professions are not conducting practice reviews of their members, then how is the profession and the public to know that work is being done to a defined standard?” he asked.

The Alberta Institute of Agrologists has recently begun conducting its own random practice reviews — completing eight in December — and plans to resume in the fall.

Lloyd told The Narwhal that he isn’t aware of any other professional organizations involved in signing off on reclamation certificates in the province doing something similar.

Inspections show reclaimed sites don’t meet government standards

The Narwhal reported last fall that a pilot project from Alberta Environment and Parks found that the vast majority of certified reclaimed sites studied were not meeting the government’s own standards for “equivalent land capability,” with lingering impacts on soil, plant and crop quality.

Eggers is skeptical that Alberta’s reclamation certificate program is working as it was intended, especially without on-the-ground audits being conducted regularly by the regulator.

“In our experience,” he said, “[companies] always try to get away with as much as they can.”

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On Thursday, the Supreme Court handed down a long-awaited decision on the Redwater case, which has major implications for the cleanup of oil and gas wells across the country.

The case has often been regarded as a crucial test of the ‘polluter pays’ principle.

But how did the case come about? What does the decision really mean? And does this mean Albertans are in the clear when it comes to the billions of dollars in environmental liabilities associated with oil and gas wells in the province?

You have questions, we have answers. Read on!

What the heck is ‘Redwater’?

This all started with an oil and gas company in Alberta, called Redwater Energy Corporation.

The company was founded in 2009, with headquarters in the small town of Okotoks, just south of Calgary. It was a small-ish operator — as far as oil and gas companies go — with dealings across western Canada. It owned 100 wells, pipelines and related facilities.

And then, in 2015, it went bankrupt.

Okay, so how did the Redwater case end up at the Supreme Court?

When an oil and gas company goes belly-up, it leaves behind some assets. In this case, that included 17 producing wells. But it also leaves behind liabilities — money it owes to creditors and the cost of environmental cleanup of inactive wells.

When Redwater went bankrupt, its trustee argued that its creditors (such as the banks that lent it money) should collect what they were owed before any leftover funds were used to pay for environmental cleanup.

In essence, the trustee argued that cleaning up was the last priority when divvying up leftover funds.

Cue the Redwater case.

A lower court agreed with the trustee. Chaos ensued as people scrambled to cope with the idea that companies could walk away from the messes they make. The Orphan Well Association and the Alberta Energy Regulator appealed the lower court’s decision.

Eventually, the case headed to the Supreme Court.

What exactly did the Supreme Court decide?

The Supreme Court overturned the lower court’s decision, with a 5-2 majority.

Writing in a summary, the Supreme Court said Redwater’s trustee couldn’t walk away from cleanup costs — Redwater’s estate, so to speak, couldn’t just abandon its obligations to the public, to landowners and to the environment.

Farmer and Action Surface Rights chairman Ron Huvenaars stands beside active oil and gas infrastructure on his family farm. Increasingly, he’s worried that companies in Alberta aren’t taking into account the costs they’ll have to pay to clean up wells like this one when they reach the end of their productive life. Photo: Theresa Taylor / The Narwhal

According to the court, the money left over from Redwater’s assets must now be used to clean up the wells it left behind.

The Alberta Energy Regulator said it was “pleased.” Alberta’s Energy Minister, Margaret McCuaig-Boyd, called it “good news.” The Pembina Institute called it “reassuring.” Ecojustice called it a “win.” Greenpeace called it “a victory for the ‘polluter pays’ principle.”

There’s a caveat to some of the celebrating, though. As The Pembina Institute put it in a press release, “we aren’t out of the woods.” (More on that in a minute.)

Why does the Redwater case matter across Canada?

The Alberta Energy Regulator was concerned about the implications for any future cleanup — and who would pay for it.  

“If this decision is upheld by the Supreme Court of Canada, we — and every other regulator in Canada — will no longer be able to hold companies accountable for cleaning up their mess,” it wrote last February.

The decision wouldn’t just have implications in Alberta — but across the country, where other provinces are also dealing with a big backlog of wells to clean up, as well as the environmental liabilities of other industries, such as mining.  

Canada’s northern ‘zombie mines’ are a lingering multi-billion dollar problem

On top of that, people wondered what would stop companies from spinning off their less-profitable assets into separate companies, letting them go bankrupt and then walking away from the mess.

As Keith Wilson, a long-time lawyer working on behalf of landowners with wells on their land put it to The Narwhal last year, “If a restaurant could dump all of its garbage out the door and not pay anything, why wouldn’t it?”

Oil and gas companies aren’t restaurants, and their garbage is of a slightly, um, larger magnitude. The C.D. Howe Institute has estimated there are approximately 450,000 wells in Alberta — a well for every 1.4 square kilometres in the province.

And of those wells that are inactive in one way or another, one University of Calgary study pegged the time it would take to get everything cleaned up, using the current rate of spending, at 177 years.

What’s involved in cleaning up an old oil or gas well?

Well, first and foremost, it takes dollar bills. Conventional wells can be thousands of metres deep.

Once the well is no longer producing, what’s left behind is probable soil and water contamination, a risk of explosion and a constant release of air pollutants, Jodi McNeill, a policy analyst with The Pembina Institute, told The Narwhal last fall. And then there are the emissions.

“When something hasn’t been plugged, it just continually releases greenhouse gases into the atmosphere,” McNeill told The Narwhal.

So once a well has had its moment, you might assume it would be cleaned up. Not so fast.

A flooded and inaccessible oil lease site owned by Sequoia in Wainwright, Alta. on Monday, November 5, 2018. Photo: Amber Bracken / The Narwhal

Alberta doesn’t currently have any time frames on when a well should be properly sealed and reclaimed, while many other oil-producing areas do — deadlines on sealing a well range from six months to 25 years in the United States, for example.

It’s also worth noting that even after environmental cleanup is all said and done  — and a site has been issued an official reclamation certificate — there are serious concerns about whether that land will ever actually recover.

The Narwhal uncovered the Government of Alberta’s own research that documented issues with crop productivity and ecological health long after a site had been reclaimed.

This is but one reminder that Alberta is not free and clear when it comes to oil and gas liabilities, even now that the Supreme Court has made its decision on Redwater.

Umm, quick aside, why are financially precarious companies allowed to drills wells?

Well, funny you should ask.

You’d think that provincial regulators might be able to put a stop to this problem before it starts. You might wonder, ‘if a company can’t afford to pay for cleanup of the mess it makes, why should it be allowed to make the mess in the first place?’

As it turns out, the Alberta Energy Regulator has been giving out licences and allowing companies to drill for years, even if they don’t have enough money to pay for cleanup.

There is a system in place that is supposed to ensure that financially unstable companies get weeded out — or that they pay a deposit for cleanup if they can’t prove they have sufficient assets to take on new liabilities.

The trouble is, that system is woefully out of date.

The Narwhal’s investigation into this system last year found the regulator is still valuing oil at over $100/barrel — something Albertans are all too aware is no longer the case. And it’s underestimating the cost of cleanup, according to recent research from the University of Calgary.

As Wilson, the lawyer, put it to The Narwhal, it is, at best, a “rosy picture.”

And painting that rosy picture means the regulator has allowed many companies to continue to operate — and to expand those operations — without having nearly enough money to pay for cleanup. And the way the regulator looks at the books means many companies haven’t had to put down a deposit for cleanup, either.

In November, the regulator estimated total liabilities to be $58.65 billion.

According to the Pembina Institute, “only $1.2 billion is currently held in securities to protect the public.”

Mind the, erm, $57.45-billion gap.

Can’t the Orphan Well Association just deal with this?

The Orphan Well Association is funded by oil and gas companies, which must pay a deposit (based on those calculations we talked about before) before getting a licence. It also gets money in the form of grants and loans from taxpayers, both federally and provincially,

The association brought in $30 million from the orphan well levy in 2017 — this part comes from energy companies. But since 2009, the Alberta government has given the Orphan Well Association more than $30 million in grants and, in 2017, it moved to loan the organization $235 million. Last year, the federal government also announced it would allocate $30 million to efforts to clean up orphan wells in Alberta.

Lars DePauw, executive director of the Orphan Well Association, spoke to The Narwhal last year, after our article came out about Alberta’s well-liability problem. He told us industry has contributed $314 million to the association to date, noting “this is a substantial amount that companies have paid for other company’s missteps.”

An orphaned oil and gas well on private property near Taber, Alta. Photo: Theresa Tayler / The Narwhal

Currently, the association’s inventory includes more than 3,000 orphan wells that haven’t been properly sealed yet (sealing is, curiously, known in the industry as “abandoning,” leading to countless confusing headlines) and another 1,500 orphans that have been sealed but still need to be reclaimed.

As The Narwhal reported last fall, the association spent more than $30 million in total expenditures in 2017. And, in that same year, it reported sealing just 232 wells.

So, no, the Orphan Well Association probably isn’t equipped to deal with too many more orphans.

What will a post-Redwater Alberta look like?

In a statement, the regulator acknowledged that improvements remain to be made. “[W]e must manage liability differently,” it wrote, “in order to continue protecting Albertans, our environment, and our province’s many responsible operators.”

The Pembina Institute appears to agree. “While the Supreme Court’s decision ensures bankrupt companies’ remaining assets first go to clean up, those assets are often insufficient to cover full costs,” it wrote.

That gets us back to the original problem: even if it’s been confirmed that the funds of bankrupt companies have to be used for cleanup — is that enough?

The regulator has long allowed financially precarious companies to operate and trade licences, so it’s no surprise that even after the Redwater decision, there’s still more work to do for the province to ensure the public isn’t left on the hook in the future.

Not yet out of the woods, indeed.

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For years, Alberta’s government has reassured the public that it has a plan to ensure the oilsands’ 1.2 trillion litres of hazardous tailings are permanently dealt with after mines shut down.

That assertion is becoming less convincing by the day.

Industry still hasn’t decided on a viable long-term storage technology to begin testing. The fund to cover tailings liabilities in case of bankruptcy is arguably extremely underfunded. And there are concerns from the likes of the Pembina Institute that the future costs for tailings treatment will be far greater than anticipated.

Martin Olszynski, assistant professor in law at University of Calgary, told DeSmog Canada such questions simply can’t be left unanswered.

“It would the height of unfairness if at the end of all this massive profit and wealth generation, Albertans were left on the hook for what will be landscape-sized disturbances that are potentially very harmful and hazardous to humans and wildlife,” he said.

Oilsands Tailings Plans Nonexistent

The history of tailings regulations is a short one in the province: there simply hasn’t been anything binding. Toxic tailings have been allowed to expand for decades without any real constraints. The last attempt by the province’s energy regulator to require companies “to minimize and eventually eliminate long-term storage of fluid tailings in the reclamation landscape” completely failed.

Every single company breached their own targets.

Directive 085, introduced by the Alberta Energy Regulator (AER) in July 2016, is intended to rectify that.

On March 17, the AER somewhat surprisingly rejected the first tailings management plan that was submitted under the new rules by oilsands giant Suncor for a series of reasons, including its uncertain timelines and reliance on the “unproven technology” of end pit lakes or water capping (the practice of sealing fine tailings under freshwater with the expectation ponds will evolve into healthy aquatic ecosystems).

“What this most recent rejection of Suncor’s proposal suggests to me is they haven’t done the work, and they’re not yet doing the work,” Olszynski says.

“And they need to do the work.”

No Definite Plan A and Definitely No Plan B For #Oilsands’ Tailings https://t.co/scnvuXz9OV #ableg #cdnpoli #YEG #YYC #oilandgas

— DeSmog Canada (@DeSmogCanada) April 21, 2017

Provincial Auditor General Warned of Risk of Oil Price Drop

In July 2015, provincial auditor general Merwan Saher issued a harsh indictment of the fund intended to ensure that Albertans won’t be on the hook for reclamation expenses when oilsands and coal mines shut down.

At the time, only $1.57 billion was held as security deposits in the Mine Financial Security Program for all of Alberta’s reclamation liabilities, worth an estimated $20.8 billion.

As of September 2016 that total is now $1.38 billion with oilsands companies responsible for $940 million of the total. The other $19 billion or so is expected to be paid by companies in the last 15 years of a project's life, with reserves effectively serving as collateral — but that's a risky approach, especially with declining oil prices.

There is a “significant risk that asset values…are overstated,” Saher said..

“If an abrupt financial and operational decline were to occur in the oilsands sector,” wrote the auditor general., “It would likely be difficult for an oilsands mine operator to provide this security even if the need for the security was identified through the program.”

Oilsands Accounting Expert Says Situation Is “Major Concern”

That very thing has happened.

Thomas Schneider, assistant accounting professor at Ryerson University who has written extensively on oilsands liabilities, said in an interview that “it’s a major concern” given the recent decline in asset values.

“The main asset securing the liabilities now as per the government and people of Alberta — and ultimately Canada I guess as I don’t know who’s going to have to pay for it if it doesn’t get cleaned up — are supposedly the assets in the ground,” he told DeSmog Canada. “That’s where it stands right now.”

The province’s $20.8 billion estimated liability is already based on shaky market grounds; the asset-to-liability approach considers “proven” (90 per cent likely to be commercially viable) and “probable” (only 50 per cent likely to be commercially viable) reserves as equally valuable, allowing companies to avoid putting in additional securities to the fund so long as assets are assessed at three times that of liabilities.

It’s a potentially troubling prospect in the era of massive write-downs of reserves by the likes of ExxonMobil and ConocoPhillips.

Schneider says at this point in time, the government is supposed to re-evaluate the asset-to-liability ratio and require companies to cover off any missing securities with letters of credit or other financial instruments.

A government spokesperson didn’t respond to a question about whether the government has taken a recent look at the ratio.

No Definite Plan A and Definitely No Plan B For Oilsands’ Tailings

Companies and industry groups are putting a lot of work into developing new technologies to deal with tailings.

Nina Lothian, senior analyst at Pembina, said in an interview with DeSmog that there are pros and cons to every tailings technology — end pit lakes, centrifuges, atmospheric fines drying, consolidated tailings — with no clear best choice. Based on the recent rejection of Suncor’s plan, it’s clear the AER is expecting more from companies.

However, there’s the obvious related problem of if those plans fail.

The AER has established an unfortunate reputation in some circles for failing to implement required monitoring and enforcement actions to ensure compliance when it comes to pipeline safety and orphaned wells.

Lothian says that end pit lakes are considered a bit of a “silver bullet” by industry.

The Canadian Oil Sands Innovation Alliance, a joint effort by 13 companies, has long planned to build a Demonstration Pit Lakes Project, made up of over a dozen test water bodies and based off of learnings from Syncrude’s Base Mine Lake. The alliance’s website still notes that “phase one of the project could move to construction with potential operation by 2017.” However, when contacted by DeSmog, a spokesperson was unable to provide any information on the status of the Demonstration Pit Lakes Project.

Olszynski says that it will likely require 15 years of monitoring data to know if any particular plan worked. He says that as a result, we wouldn’t have solid results until 2032. But the alliance hasn’t even started building the project.

“For me, the big problem here is we’re well into 2017 at this point, we’re staring down the productive life of some of these sites, and we do not yet have a proven tailings mitigation technology,” he says.

Recent Mining Disasters and Abandonments Point to Potential Dangers

As to whether or not security deposits are meant to include the treatment of tailings, Lothian says Pembina has had no success in answering that question.

Neither Alberta Environment and Parks or the AER have provided clear responses to Pembina. Lothian says that submissions from companies under the Mine Financial Security Program include related reclamation costs like land contouring and revegetation, but there’s no indication of whether funds have been set aside explicitly for tailings treatment.

“We know from all this work with the tailings management plans how many billions of dollars are associated with the treatment side of things,” she says.

In 2011, University of Alberta energy economist Andrew Leach wrote in an Alberta Oil article: “As long as companies expect to pay the full costs of reclamation, there’s no reason to expect that deferring environmental security payments will appreciably increase investment.”

In other words, the “asset-to-liability approach” might not even have notably increased investments, and instead exposed Albertans to serious costs down the road if companies go bankrupt.

That’s assuming companies expect to pay the full costs of reclamation.

There have been numerous examples in recent years that indicate mining companies can get away without fines or charges for catastrophic tailings breaches, most notably the Mount Polley mine disaster in B.C. and Peabody bankruptcy in the U.S. (the latter of which left around $2 billion in unfunded liabilities).

Provincial Regulator Has Variety of Options to Pursue, Critics Say

But regulators like the AER could take a different approach to avoid such financial disasters.

That could include providing clarity around what the Mine Financial Security Program actually covers, revoking leases for non-compliance, update calculations to acknowledge the distinction between “proven” and “probable reserves” and tap into financial instruments such as letters of credit which Olszynski describes as “bankrupt-proof.”

It would ultimately be up to the AER as an independent agency to craft new calculations for required security deposits or improve communication of the scope of the Mine Financial Security Program. But such shifts would likely require pressure from the government.

In fact, Premier Rachel Notley appeared reasonably convinced of that fact when serving as opposition environment critic, asking during Question Period in 2010: “will this government commit to eliminate the existing lakes of poisonous sludge within 20 years and to exercise all authority necessary to make sure it happens?”

However, since forming government the Alberta NDP has said little publicly about tailings management that served as contrast to previous decisions; Environment Minister Shannon Phillips responded to the 2015 report by the auditor general by stating: “We need to analyze whether the asset calculation needs to be changed. We need to update this security program and conduct that detailed risk analysis.”

Nothing appears to have been changed or updated since then.

“This is a really common strategy, where industry just kicks the can down the road over and over again until they are able to get out of cleaning up the waste themselves at the end of operations,” said Jodi McNeill, policy analyst, from the Pembina Institute, in a recent webinar.

“There’s a lot of reason for us to be very concerned.”

Image: Alberta oilsands tailings pond. Photo: Alex MacLean 

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By Barry Robinson, Ecojustice.

The Alberta Energy Regulator (AER) is Alberta’s one-stop regulatory body for the oil and gas industry. When it was created in 2013 by the merging of the former Energy Resources Conservation Board and parts of Alberta Environment and Parks, the AER made bold claims about transparency, enforcement and becoming a “world-class” regulator.

Unfortunately, the AER has failed to live up to its promises. The AER has shown over and over again that it is either unable or unwilling to enforce its own laws, directives and orders. The AER has become a toothless regulator.

As a public interest lawyer I see first-hand how the AER’s failures affect Albertans.

Take for example two of Ecojustice’s clients. Tony and Lorraine Bruder operate a cattle ranch near Pincher Creek. A preliminary environmental site assessment conducted at an abandoned sour gas well site on their property showed that the site was potentially contaminated with drilling waste, salts, metals, and hydrocarbons, including polycyclic aromatic hydrocarbons — all nasty things that you do not want on your property.

In September 2015, as a first step towards cleaning up this mess, the AER ordered Nomad Exploration Ltd., the licensee of the well site, to complete a more detailed environmental study by the end of November 2015.

Nomad ignored that order. Over the next few months, we repeatedly asked the AER what it was going to do about Nomad’s failure, but the AER took no action.

Finally, in May 2016, the AER ordered Nomad to prepare a plan by the end of June 2016 to complete the more detailed environmental study — that is, to prepare a plan to do the very thing the AER had already ordered Nomad to do six months earlier.

Most competent regulators escalate enforcement when an operator does not follow its orders — when you do not follow the rules, the consequences get more severe. In this case, the AER de-escalated enforcement. The penalty for not completing the detailed environmental study was just an order to “try again.”

This time, the AER said that Nomad must include in the plan a schedule to complete the detailed environmental study by the end of August 2016. After an extension of time and a couple of failed attempts, Nomad never did provide the AER with a schedule to complete the study. The AER then ordered Nomad to complete the study regardless by January 3, 2017, but then at Nomad’s request extended that date to February 15, 2017.

And guess what — Nomad again failed to meet that deadline.

Three Ways to Improve Alberta’s Toothless Energy Regulator #abpoli #abandonedwells @ecojustice_ca https://t.co/Zi2xiTuCrq

— DeSmog Canada (@DeSmogCanada) April 7, 2017

When we recently asked the AER what they were going to do about this continued non-compliance by Nomad, the AER’s response was “the AER is continuing to gather and assess the relevant facts and information in order to determine the most appropriate response moving forward.”

In other words, 18 months after ordering Nomad to complete the detailed environmental study, the AER still does not have a plan on how to enforce that order.

The Bruders’ case is only one example of a much broader and systemic problem of lack of enforcement by the AER. 

In July 2014, the AER announced that approximately 37,000 wells out of 80,000 inactive wells were not in compliance with the requirements for inactive wells. How does a regulator, that bills itself as “world class,” allow almost half of all inactive wells in the province to be out of compliance?

More recently, we have seen situations where the AER issued numerous warnings and orders to companies with no effect, with the end result that the only option was to transfer hundreds of wells to the Orphan Well Association, leaving financial responsibility for these sites to be borne by other industry members, the Canadian taxpayer, and eventually the Alberta public. The AER has numerous enforcement tools at its disposal but it simply refuses to use these tools to ensure compliance.

Which leads me to my response to the question, “How do you solve a problem like the AER?”  In a recent letter to Shannon Phillips, the Alberta Minister of the Environment and Parks, and Margaret McCuaig-Boyd, the Minister of Energy, we made three recommendations.

First, before drilling a well, the operator should have to deposit sufficient funds with the AER to pay for the clean-up. Then, when an operator refuses to carry out the clean-up work, or goes bankrupt, the AER would hold the necessary funds to complete the work.

Second, in 2014, the Responsible Energy Development Act stripped the Minister of Environment and Parks of her power to enforce environmental orders against energy companies and gave those powers to the AER. Given that the AER appears unwilling to use those tools, we think that those powers should be given back to the Minister.

Third, we think that it is time to consider whether the AER should continue to exist. If the AER is unwilling to enforce Alberta’s laws and its own directives and orders, perhaps the AER’s role should be transferred to the Departments of Energy and Environment and Parks.

In a recent publication, Jim Ellis, the President and CEO of the AER, said that regulators like the AER “hold a moral and ethical obligation to initiate bold and courageous action to improve the human condition.”

Perhaps before the AER embarks on the lofty goal of changing the world, they should get the simple stuff right — like enforcing the law.

Image: Pumpjack in rural Alberta. Photo: Kris Krug/DeSmog Canada

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The Alberta Energy Regulator — responsible for regulating more than 430,000 kilometres of pipelines in the province — has finally started to try to clean up its image.

In the last two weeks of February, the agency launched a “pipeline performance report” that graphs recent pipeline incidents, it levelled a $172,500 fine against Murphy Oil for a 2015 spill that went undetected for 45 days and it shut down all operations by the notoriously uncooperative Lexin Resources, including 201 pipelines.*

But critics suggest there are major systemic flaws in the Alberta Energy Regulator (AER) that still need to be addressed if pipeline safety is to be taken seriously.

“It’s absolutely ridiculous,” says Mike Hudema, climate and energy campaigner for Greenpeace Canada. “You’re talking about a spill that went undetected for 45 days. And the company was fined an amount that they could likely make in less than an hour. That doesn’t send any message to the company. It definitely doesn’t send any message to the industry. And it doesn’t reform company behaviour.”

Ecojustice lawyer Fraser Thomson agrees there are major gaps in oversight.

“There are still significant, significant issues with transparency and accountability on what the AER calls ‘incidents’ within the oil and gas sector,” Thomson said.

AER Accused of Mixed Mandate, Industry-Friendly Structure

The AER was formed in late 2012 with the merging of the Energy Resources Conservation Board and some duties of the ministry of environment and sustainable development.

It’s been under fire from critics ever since.

For one, it’s often accused of having a mixed mandate. Only a month-and-a-half after forming government in 2015, Alberta Premier Rachel Notley suggested the AER can’t do the job of environmental protection and monitoring when its “overarching mandate is to promote energy development.”

Notley reported the government would review the AER’s mandate and potentially split it into two agencies: one for monitoring, another for approvals. But only six months later, the AER received a letter confirming the current organizational structure would be maintained.

“We haven’t really seen much sea change,” Hudema said. “Until that happens, unfortunately Alberta will be plagued with the pipeline problems that has plagued it for decades.”

It hasn’t helped matters that the AER’s chair Gerry Protti was a former Encana executive and founding member of the Canadian Association of Petroleum Producers, or that the AER is entirely funded by industry.

In 2013, Notley — then serving as the NDP’s environment critic — called on AER CEO Jim Ellis to resign due to his involvement in a scandal about the suppression of anti-oilsands dissent by government, describing the situation as “banana republic stuff.”

It’s a sentiment reflected by renowned ecologist Kevin Timoney, who recently reported that the AER has vastly underestimated spill volumes and recovery efforts between 1975 and 2013.

“There was some movement towards improving monitoring [in recent years] but those efforts have been undermined by senior management,” he writes in an e-mail. “Enforcement is still little more than a facade.”

Online Database An Improvement, But "Pretty Frail"

Duncan Kenyon, director of the Pembina Institute's responsible fossil fuels program, says the AER first made it a serious priority to deal with pipeline spills following the 2012 release of 461,000 litres of sour crude oil into the Red Deer River by Plains Midstream.

That same year, the provincial government ordered a pipeline safety review, which ended up being itself criticized by Notley and others for failure to consult or actually consider incidents (instead opting to simply compare regulations to other jurisdictions).

Recent spills haven’t exactly bolstered the regulator’s reputation.

The aforementioned Murphy Oil spill in 2015 resulted in 9,000 barrels of condensate spilling onto public land near Peace River. A spill at Nexen Energy’s Long Lake facility that same year released 31,000 barrels of emulsion between June 11 and July 15, despite being a brand new pipeline.

Around 1,500 barrels of oil emulsion was also spilled by Trilogy Energy near Fox Creek in October 2016.

Thomson notes that an incident first reported in 2013 involves a Canadian Natural Resources Limited in-situ project near Cold Lake in which bitumen started bubbling to the top over the period of months and years. The AER’s compliance dashboard lists the incident as “ongoing” with the “emergency phase over July 17, 2013.”

He says that he still can’t get an answer to whether the spill is happening or not.

“When it comes to the information that people want to know — what’s the risk here, is it safe, is there a safety risk to humans, wildlife environment and treaty rights — the compliance dashboard is a pretty frail tool to access it,” Thomson said.

In addition, he notes that language used by the AER often confuses things for the public: for instance, the regulator will use “produced water” in reference to “toxic water” with a high concentration of salts that are dangerous to local environments and often have oil residue in them.

Similarly, he says the AER will report “no recorded impacts” as opposed to “impacts unknown.”

“I think it would be reasonable for the public to read that and assume there weren’t impacts, when it’s really a turn of phrase,” Thomson says.

#Alberta’s Pipeline Oversight a ‘Facade’: Experts https://t.co/4942NmkdkM @james_m_wilt @HuffPostAlberta @ProgressAlberta #ableg #cdnpoli pic.twitter.com/nq8N7xd0CJ

— DeSmog Canada (@DeSmogCanada) March 23, 2017

Self-Reporting Only Works If Regulator Ensures Compliance

The AER claims that the length of pipelines in Alberta has grown by 11 per cent over the last decade, with “incidents” dropping by 44 per cent.

But Timoney’s recent report complicates the matter even further, suggesting that many spills weren’t recorded, and that many former oil spill sites that have reportedly been reclaimed are still contaminated from pipeline leaks.

“According to the data that I have received from the regulator, the number of spills has declined in recent years,” he explains in an e-mail. “However, it is important to remember that those data are based on industry self-reporting; they are not independently verified. Incidents occur that are not reported, but the frequency of unreported incidents is not known.”

Kenyon agrees: “If you don’t have a regulator who’s going out and actually seeing if people are complying — going out there and doing audits and seeing if what they said in their self-report is accurate — then none of that data is worth anything.”

Alberta’s Fines Well Below National Average

That’s why many point to the lack of enforcement as a key problem.

That starts with fine limits, which is established by the province. Alberta has fairly low caps on penalties compared to other provinces, Thomson says.

Data compiled by Ecojustice and shared with DeSmog Canada indicates a clear trend: the provisions that are most often used — Section 108(2) and 109(2) of the Environmental Protection and Enhancement Act, concerning the “release of substance causing adverse effect to environment” — has a cap of $500,000 in Alberta, compared to a cap of $1 million in B.C., Saskatchewan, New Brunswick, Nova Scotia and Newfoundland.

In Ontario and Quebec, the maximum limit for first conviction is $6 million. The only provinces that have an equal or lower cap are Manitoba ($500,000) and Prince Edward Island ($50,000).

Cheaper to Pay Fines Than Maintain Pipelines

But the “administrative penalties” issued by the AER often fall well below that $500,000 mark.

The largest fine issued yet by the regulator was $250,000 against Pengrowth Energy for the 48-day spill of 537,000 litres of oil emulsion in late 2013. The recent fine against Murphy Oil was also one of the highest penalties in the AER’s history; Thomson says it was calculated based on every day the company failed to report it, which is a “positive development.”

The strange reality is that many pipeline companies do have leak detection systems in place. It’s just that companies often don’t direct resources into maintaining them, following what Kenyon calls a standard compliance versus non-compliance cost comparison model; in other words, it’s cheaper to ignore and risk the fine than pay for annual maintenance.

In the case of the Murphy Oil spill, the company failed to check for internal corrosion and perform maintenance on the leak detection system for three straight years even though it was required to check annually.

“You can put a management system in and then have it down in paper, but not everything is operating the way it’s supposed to,” he says. “And then you can claim when there’s a foul up that it just wasn’t operating as it was supposed to. But you never turned it on the way it was supposed to.”

More Boots on the Ground Needed

An AER spokesperson emphasized in an e-mail that the agency is working on addressing data collection issues and improving reporting spill clean-up.

In addition, the spokesperson said the regulator requires operators to implement “comprehensive integrity management programs and safety and loss management systems,” conducts “pipeline inspections on a regular basis” and provides “education on pipeline integrity.”

However, changing the trajectory of the AER ultimately requires new “marching orders” from the provincial government via an expansion of mandate, pressures to prioritize compliance and an increased limit on fines. It’s something the NDP has appeared reluctant to do; Kenyon says there “might have been more pressure coming on pipelines under the previous government.”

The press secretary for energy minister Margaret McCuaig-Boyd says via e-mail there are no plans to revisit the government’s decision to keep the AER as is.

Thomson says he’s not convinced that splitting up the regulator would address some of the systemic problems, which ultimately require more boots on the ground: “Industry needs to know that if they submit data and monitoring to the AER, that there’s a good chance it will be checked.”

Meantime, the Alberta government continues to push for any and all new pipelines, from Kinder Morgan Trans Mountain to Trans Canada’s Keystone XL and Energy East.

“I really feel like the government should get its own pipeline problems in order before it’s pushing for new pipelines to new jurisdictions,” Hudema concludes.

“When you’re averaging over one spill a day, it’s not something that you should be bragging about or pushing into new communities.”

*Correction: The article originally stated that the AER had recently launched its compliance dashboard. The dashboard has in fact been available for a few years. The regulator recently launched a “pipeline performance report” that graphs recent pipeline incidents

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This article originally appeared on The Tyee.

Two University of Calgary law professors have demanded Alberta’s energy regulator withdraw its “inaccurate and misleading” statement on a Supreme Court of Canada ruling that a landowner couldn’t sue it for alleged rights violations.

The court ruled Friday, in a split decision, that Jessica Ernst couldn’t sue the oil and gas regulator for allegedly violating her Charter rights.

The Alberta Energy Regulator posted a statement on its website in response to the highly technical ruling.

“The Court did not find there was a breach of Ms. Ernst’s Charter rights, and made no findings of negligence on the part of the AER or its predecessor the ERCB,” declared the statement.

But law professors Shaun Fluker and Sharon Mascher have written in a popular legal blog that the regulator’s claim isn’t true.

“The AER Public Statement is inaccurate and misleading, and is not the sort of action we would expect a quasi-judicial tribunal to consider appropriate,” they write. “The Supreme Court made no finding at all on a breach of the Charter in the Ernst decision.”

In 2007, Jessica Ernst, an oil patch environmental consultant, sued the Alberta government, Encana and the regulator for negligence over contamination of local aquifers near her Rosebud home allegedly caused by the hydraulic fracturing of shallow gas wells in 2004.

After Alberta courts ruled that Ernst could sue the government but not the regulator due to an immunity clause passed by the legislature, Ernst took her case to the Supreme Court.

Her lawyers and the BC Civil Liberties Association argued that an immunity clause should not prevent a citizen from suing for violations of Charter rights.

Ernst’s lawsuit claimed the AER breached her rights by branding her a security threat in 2005 and refusing to communicate with her unless she stopped criticizing the board publicly.

In a split ruling, five members of the Supreme Court dismissed Ernst’s Charter claim based on the immunity claim and the argument that she should have sought a judicial review of the regulator’s actions — something that lawyers familiar with Alberta courts say is almost impossible.

Fluker and Mascher question the Alberta Energy Regulator’s judgment in posting the response to the case.

“The Ernst proceedings are, at their core, allegations that the AER acted punitively,” they note. “One might think that a quasi-judicial tribunal, accused of acting like a bully, would be happy to let these sort of proceedings end quietly in its favour. But apparently not.”

“This Public Statement on the Ernst decision is long on self-vindication and short on facts,” they wrote. “Most problematic is that the AER incorrectly states the Supreme Court has cleared it of wrongdoing in its dealings with Jessica Ernst.”

The regulator’s statement said the Supreme Court “made no findings of negligence on the part of the AER or its predecessor the ERCB” (Energy Resources Conservation Board).

But the issue before the court wasn’t negligence but the constitutionality of the immunity clause, Fluker and Mascher note. “To suggest that the Court made no findings of negligence suggests that it made a finding of ‘no negligence’” they wrote.

The AER is responsible for overseeing the lifecycle of nearly 400,000 active and inactive well sites as well as bitumen mines, pipelines, coal plants and gas processing facilities. Its comprehensive activities affect groundwater, farmland, air quality, land prices, provincial revenues and First Nation rights.

But critics say the adversarial agency works for the oil patch and is now chaired by Gerard Protti, a former energy lobbyist, and is largely funded by industry.  

Among landowners the AER has a checkered history. In 2007, the regulator was caught spying on citizens opposed to a power line.

First Nations and environmentalists have also repeatedly criticized the board for restricting access to public hearings.

One 2014 review concluded “the institutionalized processes of participation have been restricted to the point of nullifying the possibility of effective, democratic control over the expansion of the tar sands.”

Although the AER is supposed to arbitrate disputes between landowners and oil and gas companies over pollution, land devaluation and public health impacts, it rarely performs that function, said Fluker in an interview.

“Any landowner who has a problem with industry has to go to the AER,” said Fluker who runs a public clinic to help rural citizens impacted by energy developers. “But they are not going to get a fair shake. The AER is there to look after industry and that’s a big problem.”

Diana Daunheimer, a landowner suing Bellatrix Exploration over pollution near her land in Didsbury, said the regulator is entirely captured by industry interests.

“The AER does everything in its power — which by the way is totalitarian — to discredit or disregard Albertans harmed by oil and gas operations,” she said. “The AER has no public interest or public health mandate. How can the AER purport to protect public safety, when they have no mandate to protect public health?”

When mother and landowner Kimberly Mildenstein raised questions about traffic congestion caused by fracking trucks in central Alberta between 2011 and 2012, she says the AER did nothing.

“Basically the AER listens to community complaints very well and then ignores them very well,” said Mildenstein. “As citizens residing in fractured communities, we are lured to believe regulation for our safety exists.” It doesn’t, she said. Mildenstein and her family eventually moved to Vancouver Island due to regulatory inaction on fracking abuses.

Some members of the legal community have expressed dismay over the Supreme Court ruling.

“The Charter guarantees everyone the right to an appropriate and just remedy if their constitutional rights are violated, but a majority of the Court has now said that in some circumstances, legislatures may shield certain government administrative decision makers from Charter scrutiny,” noted Laura Track of the BC Civil Liberties Association.

“This decision has worrisome implications for people across the country seeking to hold government-appointed decision makers accountable for egregious unconstitutional actions.”

Ernst’s landmark lawsuit against the Alberta government and Encana over groundwater contamination caused by shallow gas fracking has now been before the courts for 10 years.

Not one piece of evidence has yet seen the light of day in court. 

In an email, the Alberta Energy Regulator’s senior public advisor Ryan Bartlett said the board welcomed comment from “all stakeholders” but “stands by its statement."

Image: Mysterious foamy water collected after heavy rainfall near a fracking site. Joshua B. Pribanic/Public Herald.

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This article originally appeared on The Tyee.

The Supreme Court of Canada has ruled Jessica Ernst can’t sue the powerful and controversial Alberta Energy Regulator (AER) over alleged violations of her Charter rights.

The split ruling Friday — five justices rejected her claim, with four supporting it — is a setback for the protection of groundwater and the rights of landowners dealing with provincial energy regulators, often funded or captured by industry interests, say many critics and lawyers.

The majority, led by Justice Thomas Cromwell, upheld an immunity clause passed by the legislature that protects the Alberta Energy Regulator from any Charter claims or lawsuits.

In 2007, Ernst, an oil patch environmental consultant, sued the Alberta government, Encana and the regulator for negligence over the contamination of local aquifers near her Rosebud home allegedly caused by the hydraulic fracturing of shallow gas wells in 2004.

Alberta Regulator 'Sought to Punish' Ernst for Her Public Criticisms

After Alberta courts ruled that Ernst could sue the government but not the regulator because of an immunity clause (Encana never contested the lawsuit), Ernst took that part of her case to the Supreme Court of Canada.

Her lawyers, along with the BC Civil Liberties Union and David Asper Centre for Constitutional Rights, argued in January 2016 that no regulatory body had the right to block citizens from seeking remedies for violations of their fundamental Charter rights and that no citizen should be unfairly silenced by Canada’s energy boards.

Alberta’s Energy Regulator accused Ernst of “criminal threats” in a 2005 letter and refused to communicate when she persistently asked embarrassing questions about the effectiveness of its enforcement actions on noise pollution and water contamination related to the fracking of shallow coal seams near her home.

According to Ernst’s original statement of claim, an AER lawyer admitted during a taped interview with her in 2007 that the board never considered Ernst a criminal threat but felt “humiliated” by her public criticisms of its abusive conduct. That exchange was witnessed by Liberal MLA David Swann.

The five justices in the Supreme Court majority concluded that immunity clauses are in the interests of “good governance.”

“Opening the Board to damages claims could deplete the Board’s resources, distract it from its statutory duties, potentially have a chilling effect on its decision making, compromise its impartiality, and open up new and undesirable modes of collateral attack on its decisions,” they wrote.

But four dissenting judges, including Chief Justice Beverly McLachlin, took the opposite view.

“We see no compelling policy rationale to immunize state actors in all cases, including where, as here, the impugned conduct is said to have been ‘punitive’ in nature,” they wrote. “To be precise, what Ms. Ernst alleges is that the Board, far from exercising an adjudicative function, effectively sought to punish her by barring access to those functions so long as she continued to criticize the Board in public.”

Ernst: 'All Canadians Have Lost in This Decision'

The Supreme Court decision is the latest chapter in a costly 10-year legal fight that has focused attention on regulation of the disruptive and chaotic technology of hydraulic fracturing.

“All Canadians have lost in this decision,” Ernst told The Tyee. “Whenever any Canadian is harmed by pipelines or fracking and they present evidence of harm to a regulator and then that regulator ignores or denies that evidence, citizens can no longer sue for justice.”

“I believe that split decision will generate a lot of debates among lawyers and judges across the country,” added Ernst. “I think some good will come from this terrible decision on a level we can’t yet imagine. I will keep going until I run out of money or die or whatever comes first.”

Cory Wanless, one of Ernst’s lawyers, said the split decision makes it difficult to fathom what the Supreme Court really means. Four judges supported the immunity clause; one raised separate constitutional issues in rejecting Ernst’s case; and four argued in favour of her right to sue the AER. “The whole issue will have to be resolved another day,” Wanless said.

In press release on Friday, the Alberta Energy Regulator hailed the Supreme Court decision as an important one for regulators across the country. It added that, “The Court did not find there was a breach of Ms. Ernst’s Charter rights, and made no findings of negligence on the part of the AER or its predecessor the Energy Resources Conservation Board.”

But the Supreme Court decision was not related to either of those points. It instead ruled that an immunity clause protected the regulator from Charter claims, but that “judicial review is an alternative, and more effective, remedy for Charter breaches by the Board.”

In fact, no court in Alberta or Canada has yet allowed or asked to hear the full evidence on Ernst’s Charter breaches, including extensive interview transcripts that document the regulator’s behaviour.

The AER press release also noted that court’s decision recognized “that permitting the claim would hinder the AER’s ability to carry out its statutory duties effectively and in the public interest.”

Yet new legislation in 2013 removed “public interest” from AER’s mandate. It is now a corporation largely funded by industry.

Jessica Ernst Loses Landmark Supreme Court Case Against #Alberta #Fracking Regulator in 5-4 Ruling https://t.co/GUyB6qX42I #ableg #cdnpoli

— DeSmog Canada (@DeSmogCanada) January 15, 2017

Lawyers Concerned Decision Fails to Defend Charter Rights

Ray Anand, a senior constitutional and human rights lawyer in Toronto, said he found the decision baffling. “I didn’t anticipate that none of the nine judges would decide the constitutional issue: whether a legislature can prohibit a constitutional damages claim against an agency of the government.”

In the meantime, Ernst’s lawsuit against the Alberta government and Encana can now proceed through Alberta courts.

After a decade of legal wrangling, Ernst has spent more than $350,000 on a straightforward contamination case and not one piece of evidence has been heard in court.

Other lawyers expressed alarm with the Supreme Court decision.

“With great respect to the Court, we’re disappointed by this decision, which denies Ms. Ernst the ability to use the Charter to defend her right to free expression in this case,” said Laura Track, counsel with the BC Civil Liberties Association, an intervenor in the case.

“The Charter guarantees everyone the right to an appropriate and just remedy if their constitutional rights are violated, but a majority of the Court has now said that, in some circumstances, legislatures may shield certain government administrative decision makers from Charter scrutiny. This decision has worrisome implications for people across the country seeking to hold government-appointed decision makers accountable for egregious unconstitutional actions.”

The decision is a missed opportunity to allow Ernst to seek redress for what she alleges were serious violations of her Charter rights, echoed Lynda Collins of the University of Ottawa’s Centre for Environmental Law and Global Sustainability.

“The behaviour described in her statement of claim represents a serious incursion on her democratic rights, and a disturbing departure from the Board’s environmental protection mandate,” Collins said. “I agree with the dissent that she should have been given the opportunity to make the case for Charter damages.”

Alberta Energy Regulator 'Immunized' from Legal Scrutiny

Shaun Fluker, an associate professor of law at the University of Calgary who has dealt with the AER in court, said the majority Supreme Court decision “simply piles on to the existing list of barriers constructed in the law to immunize the AER from proper legal scrutiny.”

Those existing barriers include the AER’s ability to refuse to hear landowners and other interested members of the public on energy development concerns and the expectation that landowners must fund their legal challenges before one of the nation’s most powerful regulators. “The [Supreme Court] adds to the list by effectively immunizing AER actions from Charter scrutiny,” Fluker said. “This is perhaps a bit of an overstatement, but not by much.”

The dissenting justices noted that the difficult case raised novel and important issues for the entire nation.

“The issues raised by Ms. Ernst’s claim are of significant public importance. The allegations against the Board are serious. She says that the Board abused its powers to punish a citizen and to curtail her freedom of expression, thereby breaching her Charter right. Whether Ms. Ernst may advance a claim for Charter damages against the Board in the face of a statutory immunity clause which may bar such claims will have consequences which extend far beyond the facts of this case.”

The majority justices argued that Ernst should have pressed the AER for a judicial review.

But no such remedy exists, said lawyers familiar with the AER and Alberta law.

In fact a judicial review can only be triggered when the quasi-judicial energy regulator actually makes a regulatory decision, notes Fluker. But in Ernst’s case the board did not exercise any adjudicating function or hold a public hearing.

“There is no policy decision to review here,” said Fluker. Getting a judicial review, he added, would be “next to impossible in Alberta” and would also require the permission of the Court of Appeal.

Avnish Nanda, an Alberta litigation lawyer, tweeted that “Ernst is a good example of why #SCC needs regional balance. Majority + Abella don’t understand Alberta law.”

A 2014 Harvard Law School report on fracking in the U.S. set out a key issue raised by Ernst’s case.

As complaints of water contamination in areas being fracked by industry were rising, regulatory statutes and procedures were “often insufficient to respond adequately to landowner concerns,” the report found.

In addition, hydraulic fracturing has caused thousands of earthquakes in the Western Canadian sedimentary basin, with little or no monitoring of the impact on groundwater and gas migration.

Alberta, home to more than 400,000 oil and gas well sites, still does not have a formal protocol for investigating groundwater contamination as a result of petroleum drilling and fracking.

The AER, which many landowners regard as arbitrary and biased toward unfettered development, is chaired by Gerard Protti, a former energy lobbyist and Encana vice-president.

Image: Jessica Ernst. Photo: Colin Smith

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.