This article was produced with the support of the Local Journalism Initiative.

When Richard Wyman, president of Calgary-based Chance Oil and Gas, thinks about the Eagle Plains Basin in northern Yukon, he conjures images of a small, bustling oil and gas operation providing a region that’s remote with much-needed energy and jobs. 

That vision was in mind when Chance submitted a proposal to the Yukon Environmental and Socio-economic Assessment Board for a workover of eight idle wells owned, but not currently operated, by the company. The maintenance proposal, which includes flow testing to assess the basin’s resource potential, could lay the groundwork for a new exploration program in the Eagle Plains, an expansive area of rolling hills between mountain ranges 400 kilometres north of Dawson City.

Wyman told The Narwhal upwards of 30 exploration wells could eventually be drilled in the Eagle Plains if there’s enough gas there to make it financially worthwhile.

The possibility of development in the sensitive area is reigniting concerns about the impact oil and gas development would have on the Porcupine caribou herd, one of the largest migratory barren ground caribou herds in North America, which over-winters on the plains. It’s also forcing Yukoners to address whether or not the territory should consider fossil fuel development in a time of climate crisis, the impacts of which are being felt more acutely in the North than in the rest of the world.

The Chance proposal comes in response to a nudge from the Yukon government to assess the suspended wells and either shut them up for good, in a process known as well abandonment, or convert them to active wells once again. Four of the wells are legacy wells bought by Chance that date back to the ’50s and ’60s. The other four wells were drilled by Chance in 2012 and 2013, before the territory introduced a 2015 moratorium on fracking (the company has so far been unsuccessful in its attempt to sue the Yukon government for $2.2 billion in claimed damages stemming from that ban). Now Chance is hopeful that, with enhanced flow testing, some of the wells might show signs of oil and gas resources that could be developed without the use of fracking.

But others say there’s no point in searching for resource potential in an area that should remain permanently closed to oil and gas development.

“It’s always been an extremely marginal project, which is why it’s not gone anywhere,” Sebastian Jones, wildlife and habitat analyst for the Yukon Conservation Society, told The Narwhal. 

“It’s a very remote area. It’s expensive to operate, the conditions are harsh. There’s never been any bankable resources there.”

Jones said oil and gas development in the Eagle Plains “risks causing damage and harm to the environment for no obvious reason.”

But Wyman says the full economic potential for development in Eagle Plains is currently unknown.

“The sedimentary basin has not been fully explored,” Wyman told The Narwhal. 

“If operations are allowed to proceed and the exploration program is successful, it could have a profound economic benefit, both to the territory and the north Yukon, where it’s economically depressed.”

Eagle Plains drilling a test for Yukon climate strategy

Wyman’s interest in creating jobs in the remote region is shared by some Yukoners and members of First Nations who have submitted public comments in support of potential development. Peter Charlie, from the Vuntut Gwitchin First Nation community of Old Crow, about 195 kilometres northwest of the potential development area, said he supports the idea of oil and gas taking off in the region. “We need work. It would be good to have people working. There is not much happening up here [in Old Crow], right now,” Charlie said in a submitted comment delivered by phone. “Everyone is going through a hard time. We have to get jobs up here. A lot of young people are not even doing nothing up here. Everyone is talking about this project. We have to get something going here. The project would give us work. It would be good for young kids too.” 

The proposal, currently moving through a slow review process with the board, has also attracted a significant amount of criticism, notably for its potential to introduce ecological threats to a delicate northern ecosystem for a fossil fuel project that seems out of step with the territory’s own climate strategy. 

The territory’s emissions grew by 11.8 per cent between 2009 and 2017, the most recent year for which data is available. In its 2020 climate change action plan, the Yukon government emphasized the need for more renewable energy, especially for the territory’s remote and often diesel-dependent communities, to meet a goal of reducing emissions 30 per cent from 2010 levels by 2030.

There is very little oil and gas development in Yukon and the vast majority of the territory’s electricity needs are met by hydroelectricity. But many remote communities not connected to the territory’s grid rely on costly, and highly polluting fossil fuels that are imported from other provinces. The territory currently spends about $50 million annually on fossil fuel imports.

Wyman argues there’s an environmental advantage to developing oil and gas in the territory, pointing out that Yukon is heavily reliant on fossil fuels for energy generation that have a high emissions footprint because they have to be transported in from out-of-territory.

“However you want to slice it, there’s thousands and thousands of kilometres of supply line … with its own greenhouse gas emissions,” he said. “If we were to find some hydrocarbons that were suitable for consumption in Yukon, we would significantly reduce the greenhouse gas emissions associated with the supply line. You’re going to get a net impact that’s positive.”

“The only question is going to be, does the Yukon give a shit about all the greenhouse gas emissions that are emitted outside the territorial boundary?”

Shortly after Yukon’s governing Liberals were voted into power in 2016, Ranj Pillai, Minister of the Department of Energy, Mines and Resources, received a mandate letter directing him to “promote responsible resource development balanced with environmental management and demonstrable benefits for Yukon by promoting oil and gas development outside the Whitehorse trough and without fracking.”

Brigitte Parker, a spokesperson for the Department of Energy, Mines and Resources, told The Narwhal in an email that Pillai’s letter continues to form the department’s mandate.

“Energy transitions take time and demand for oil and gas may continue into the foreseeable future,” she said.

Assessing the impacts of Eagle Plains drilling to Porcupine caribou

Chance first floated the idea of commercial oil and gas development in Eagle Plains in 2014, but a regional office of the Yukon assessment board determined that the company’s proposal to drill 20 new oil and gas wells could have significant adverse effects for the transboundary Porcupine caribou herd, one of North America’s last healthy caribou populations, which has come under increasing threat from oil and gas development in a thawing north.

According to an evaluation report conducted at the time, the impacts on the herd would have included habitat loss, injury and mortality.

The Chance project proposal area falls within the territory of Vuntut Gwitchin First Nation, which is currently undertaking renewed analysis of how Chance’s current proposal could affect the herd.

Erika Tizya-Tramm, director of natural resources for Vuntut Gwitchin First Nation, told The Narwhal the Vuntut Gwitchin and Yukon governments “are working together to determine both the state of the herd and what those possible impacts could be and what the implications are” in response to Chance’s proposal. Vuntut Gwitchin First Nation, Tr’ondek Hwech’in, Inuvialuit and other nations harvest the Porcupine caribou for subsistence.

In its maintenance proposal, Chance noted it would only be able to carry out its work in the winter months, when the ground and snow conditions would be conducive to heavy trucks and machinery moving around on access roads. But the winter months are when the Porcupine caribou are most likely to be nearby. 

Chance said if more than a dozen caribou are observed from the project area, or if caribou show up and hang around for more than three days, then the company will engage a qualified environmental professional to determine if site-specific mitigation measures are needed.

That plan struck members of the public and even Environment and Climate Change Canada as insufficient. 

In response to Chance’s application, the federal department requested the company “describe the site specific mitigation measures that would be implemented in response to observations of more than a dozen caribou or caribou remaining in place for greater than three days.” 

Environment Canada also noted Chance should describe the specific measures it would take should caribou show up. 

The Yukon Environmental and Socio-Economic Assessment Board also wants to see more from Chance when it comes to assessing and planning for impacts to the herd. In April the board sent 21 specific questions to Chance, including a request for more information about the scientific foundation of the company’s plans.

Among other things, the board says it isn’t clear why Chance chose the threshold of more than a dozen caribou, or the need to establish mitigation plans if caribou linger for more than three days. 

“It is not clear why these numbers have been chosen as thresholds or the conditions and triggers that would result in the need for site-specific or tailored management measures,” the board wrote to Chance.

Amelie Morin, manager of the board’s Dawson designated office, said numerous public comments have noted concerns about impacts to Porcupine caribou. 

“We have seen comments through our seeking views and information period that identified potential impacts to Porcupine caribou and linking that to proposed activities … we’re certainly aware of that and will consider that in the evaluation,” Morin told The Narwhal. 

Tizya-Tramm said there is a lot more work to be done when it comes to understanding how Eagle Plains oil and gas development could impact the herd and to ground mitigation plans for Chance in stronger analysis.

“We’re working to produce more materials around caribou, including safe operating distances and determining significant numbers of caribou that would trigger oil and gas development work to stop or continue.”

In its proposal to the board, Chance did not clarify how its project proposal was informed by engagement with the Vuntut Gwitchin First Nation or identify how the nation would be involved in cleanup activities should an accident or spill take place, according to the First Nation’s submitted comments.

“We need to be at the table every step of the way,” Tizya-Tramm said.

Waste injection, flaring at Eagle Plains also a concern

Before full-scale development can even be considered in Eagle Plains, Chance would have to submit a formal application to receive permits for that level of development. 

Wyman said in the meantime, Chance needs to conduct this currently proposed work to determine if there are, in fact, resources available in the basin. 

“There is no certainty that all this work will happen,” Wyman told The Narwhal. “The actual amount of drilling and seismic data acquisition will depend on results as the program unfolds.”

“At this time, we do not have specific locations where we will drill or where we will gather more seismic data.”

“The idea would be to get some more information about well capabilities, reservoir performance and help provide more insight as to what a development might look like with those wells,” he said. 

To get that information, Chance hopes to perform extended flow testing, an activity that involves measuring volumes of natural gas and any associated liquids, such as propane, that may be produced from specific wells. 

“All of this is relevant for designing development plans and engaging potential purchasers of natural gas and any associated liquids,” Wyman said.

He said the wells would be returned to a suspended state following the tests.

According to the company’s project, the tests would involve flaring for roughly six weeks. Flaring is used to dispose of any natural gas that may be produced during testing.

Jones said flaring would cause “considerable disturbance” for wildlife in the area.

“When you burn the gas off, it doesn’t just vanish,” he said. “There are byproducts from burning — carbon dioxide is obviously one of them. There are going to be fallouts of soot and chemicals and stuff like that onto the land around there. It’s also pretty noisy, it’s also pretty hot, it’s also pretty bright.”

Wyman said flaring stacks would be tall to mitigate potential environmental impacts. “The risk of doing anything untoward to the surface should be pretty limited,” he said.

Chance’s proposal also identified another opportunity to use some of the wells for waste disposal. 

Two wells in particular “represent opportunities for deep zone injections,” Wyman said.

Injection wells, which are used primarily to dispose of certain fluids, including propane and waste water, are not readily available in Yukon.

“Rather than taking fluids 2,000 kilometres to a disposal site in British Columbia, which has its own environmental risks, we’d just dispose of them locally,” Wyman said, noting he wants to see the wells already drilled in Eagle Plains put to good use for local communities, either now or in the future.

“This [proposed] project is to protect assets that are viable for future use,” he said.

Wyman said any future exploration work would be done intentionally to be smaller in scale and span a longer period of time, “partly to minimize environmental impacts, but also to help develop local capacity to participate.”

The exploration program has been presented on “several occasions” to affected First Nations, including Vuntut Gwitchin First Nation and the Gwich’in Tribal Council, he said.

But many wonder if extended flow testing or flaring ought to be permitted under the auspices of a well maintenance proposal. 

When asked if flow testing is considered an aspect of well maintenance, Morin from the Dawson designated office told The Narwhal, “I can tell you extended flow testing is an exploration activity. It’s related to exploration. It’s not related to the maintenance activities.” 

Chance Oil and Gas was unable to respond to all of the board’s requests for additional information by its May 10 deadline. The company indicated it would answer those questions within a one-year timeframe.

Chance has until Feb. 22, 2022, to provide responses to the board’s questions. 

— With files from Julien Gignac

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 Alberta government failed to recoup more than $8 million in land rents it paid to landowners on behalf of oil and gas companies last year, data obtained by The Narwhal via a freedom of information request reveals.

Industry paid back just $302,000, or less than four per cent of what was owed in 2019 — a continuation of a trend that has seen companies rack up nearly $30 million in rent debt to the government since 2010.

“If companies can’t afford to pay landowners to operate on private land, that’s a flashing red light that something is terribly wrong,” Regan Boychuk of the Alberta Liabilities Disclosure Project told The Narwhal.

“There’s no effort afoot to solve this problem,” he added.

Companies are supposed to pay rent to landowners when they drill a well on their land. If a company doesn’t pay, a landowner can apply to the Government of Alberta’s Surface Rights Board for compensation. The government is then tasked with recouping that money from delinquent oil and gas companies.

But data shows it is seldom successful.

Since 2010, Alberta oil and gas companies have racked up nearly $30 million in debt to the Alberta government in this way.

Data obtained through freedom of information requests shows only $638,000, or just over two per cent, has been recovered over that period.

The total amount paid out by government to landowners on behalf of delinquent oil and gas companies has skyrocketed in recent years, increasing 1,183 per cent since 2010. Data: Surface Rights Board / FOIP request with Alberta Environment and Parks. Graph: Carol Linnitt / The Narwhal

Meanwhile, the amount paid out by the government for land rent on behalf of delinquent oil and gas companies has increased 1,183 per cent since 2010.

At the same time, the province’s Orphan Well Association has been loaned more than half a billion dollars in recent years and in April the struggling conventional oil and gas industry in Alberta has been handed $1 billion in grants from the federal government to plug and clean up inactive wells languishing on the landscape, to be administered by the provincial government.

The Government of Alberta is currently accepting applications for the second phase of the $1-billion grant package, with $100 million earmarked specifically for the cleanup of sites owned by companies for which taxpayers have had to pay their land rent. For accepted wells, the government will now also pay for 100 per cent of well plugging and cleanup.

“We have to start asking the question, ‘why can’t they pay basic bills?’ ” Boychuk said. “And that leads to some uncomfortable answers about the future of the industry.”

In 2019, less than four per cent of the more than $8.4 million paid out by government on behalf of delinquent oil and gas companies was recouped, leaving taxpayers to cover the rest of the bill. Data: Surface Rights Board / FOIP request with Alberta Environment and Parks. Graph: Carol Linnitt / The Narwhal

‘Gaming the system’

There are more than 336,000 oil and gas wells across Alberta, according to the provincial government. Many of them are on private land. 

If a company fails to pay the annual rent they have agreed on, the landowner can apply for a “recovery of rentals” from the Surface Rights Board, as per the Surface Rights Act, and receive their compensation from Alberta’s general revenue fund. That’s taxpayer money.

The Narwhal reported last year that the tab for taxpayer money paying land rent on behalf of oil and gas companies was already $20 million. It’s now grown by close to $10 million, according to data provided to The Narwhal by the Surface Rights Board. 

This is supposed to be a temporary fix, as the government is then meant to recoup taxpayers’ money by tracking down the company and collecting the funds. 

When an application is addressed, the board will try to contact the company and order them to pay. If that doesn’t work, the board directs the Minister of Environment and Parks to pay the landowner out of the government’s general revenue. (Alberta Environment and Parks and the Surface Rights Board did not reply to requests for an interview by publication time.)

To Daryl Bennett, a farmer and director with the landowner group Action Surface Rights, who has spent years trying to help landowners get the payments they’re owed, the government’s efforts are seldom enough.

“In the past, there’ve been cases where they just didn’t try,” he said. In those cases, barring a company from the site will have little effect, as the well is likely inactive anyway. 

Bennett said he believes companies have learned that skipping out on land rent can be a way to cut their costs.

“It’s just the way the system is — the way the law is. If companies don’t pay, the government is supposed to step in,” Bennett told The Narwhal. “A lot of companies have learned to game the system and take advantage of it.”

“It’s the business. When times are good, it’s good,” he said. “When it’s not, then they easily socialize the losses.”

“They’re just abusing the system to cut payments to landowners and kick the can down the road for years,” Bennett said.

Daryl Bennett of landowner group Action Surface Rights. Photo: Theresa Tayler / The Narwhal

Companies ‘just don’t have the money’

Boychuk points to a number of other bills many oil and gas companies have been struggling to pay in recent years, from municipal taxes to levies owed to the Alberta Energy Regulator. 

“A lot of those companies just don’t have the money,” Bennett said, noting that this was a problem prior to the COVID-19 pandemic, too.

“Even before the pandemic, a bunch of them were hoping that the oil price would rise enough that they could sell their stuff to somebody and get their money out of it. They were already underwater,” he said.

Then the pandemic hit, flattening demand at the same time a global supply glut pushed benchmark prices into negative numbers.

Jay Averill, media relations manager for the Canadian Association of Petroleum Producers, told The Narwhal that current events have forced many oil and gas companies into financial hardship.

“Since the middle of March over $8.6 billion in capital expenditure cuts have been announced in the Canadian upstream oil and gas sector,” Averill said in an emailed statement. “This is in response to the low commodity prices resulting from the global economic slowdown caused by the COVID-19 pandemic along with the oil price war between Saudi Arabia and Russia.”

Others, like Boychuk, point to a longer-term trend of reduced profitability in the oilpatch, noting it’s not just the pandemic that has pushed companies into the red. Either way, unpaid bills have been increasingly falling on taxpayers, often the same people most affected by the volatility of the industry.

“It’s a catch-22 situation,” Bennett said. “If you force [companies] to pay, they go bankrupt. Then they don’t pay anything and you lose all the jobs and everything else.”

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

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

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

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

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

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

Read on.

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

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

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

Why aren’t these companies paying?

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

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

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

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

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

“I don’t buy that.”

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

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

Not a whole lot, when it comes to enforcement. 

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

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

The situation gets even trickier if a company declares bankruptcy. 

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

How much does this matter to these communities?

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

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

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

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

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

Has this happened before?

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

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

What’s the provincial government doing about this?

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

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

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

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

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

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

Why shallow gas wells?

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

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

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

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

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

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

Did the shallow gas relief program solve the problem?

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

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

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

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

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

Is the provincial government continuing its support for municipalities?

Nope.

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

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

What’s next?

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

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

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

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

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

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

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.”

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.

It didn’t exactly come as a surprise. For months, pollsters have been predicting a sweeping win for Jason Kenney and his United Conservative Party (UCP).

Here we are: the election theatrics are over, and Alberta is settling in with a new premier-elect. Now what?

We know where the party stands on pipeline issues, but what else has the UCP promised it will do when it comes to energy and the environment?

Welcome to a new world — a world of “war rooms,” red-tape reductions and some rapid-fire repeals of existing programs and legislation.

1. Regulation? Let’s cut it.

Kenney has made it clear that a UCP government will be all about “streamlining” and “efficiencies.”

As part of that plan, the UCP government will ramp up approvals for new energy projects. Kenney described his plan as a “rapid acceleration of approvals.”

At the same time, his “red tape reduction action plan” will “cut red tape by a third.” There will be a new so-called “one-in, one-out” rule that will require that every new regulation created is offset by the elimination of an existing regulation.

He’ll even appoint a “Minister for Red Tape Reduction.”

Red tape, according to the UCP, is a “costly and growing burden” that “kills jobs.”

2. Parks: privatized services and more booze!

Given the heated backlash over the province’s Bighorn Country proposal earlier this year, it won’t come as a surprise if the UCP doesn’t pursue the planned parks and recreation areas.

Kenney had previously described the NDP’s Bighorn land-use plans as “an extreme approach to land use which cuts out local residents and legitimate economical and recreational use.”

The UCP has, however, pledged to provide $10 million to support the creation of a new urban provincial park within Edmonton city limits.

It has also pledged that “major environmental protection proposals” will be subject to a review of their economic impacts to ensure they are not harmful to the economy — a “balance,” the party says, to current environmental impact assessments of industrial projects.

The party’s platform outlines an increased emphasis of partnerships with park societies, and suggests the UCP will support increased volunteer activities to maintain parks.

An initial pilot project will determine if nearly all park services could be privatized, by examining “whether park societies could effectively be contracted to assume all park management responsibilities from [Alberta Environment and Parks], with the exception of enforcement.”

But, hey — soon we’ll be able to relax with a glass of wine after a long day of trail maintenance. The UCP has pledged to “relax liquor constraints in a number of provincial parks” as well as loosening liquor laws in municipal parks.

3. Support for renewables? Nah.

Alberta’s NDP government committed to source 30 per cent of the province’s electricity from renewable energy sources by 2030.

The UCP government has not made any similar commitments and, in the party’s platform, it’s made clear that subsidies to a fledgling renewable energy industry are not in the cards.

Instead, it says it will “welcome market-driven green power.”

As part of the UCP’s carbon-emissions reduction plan (more on that soon), funds raised will go toward “Alberta-based technologies that reduce carbon emissions.”

But the platform does not list renewable energy as an example of these technologies (Alberta has some decades-long contracts with alternative energy providers and the future of those contracts are unclear). Instead, the UCP focuses on carbon capture and new oilsands extraction technology.

Currently, coal is the biggest source of electricity in the province.

4. Making the province’s industry-funded energy watchdog more industry-friendly

Kenney wants to reduce regulation across the government, but he particularly wants to reduce what he calls red tape at the Alberta Energy Regulator, the industry-funded corporation responsible for enforcing rules surrounding the province’s energy industry.

This is the same regulator that issues 97 per cent of reclamation certificates without sending an inspector out to the oil or gas well in question for a field audit.

A Kenney government is promising to “identify efficiencies” within the regulator within the first 180 days of forming government.

5. Oilsands emissions cap?

What oilsands emissions cap?

Kenney has promised he will “absolutely” scrap the cap.

The oilsands emissions cap was enacted to limit emissions from the oilsands to 100 megatonnes. The province currently estimates total emissions to be around 70 megatonnes.

Canada’s climate commitments include an 80 per cent reduction of greenhouse gas emissions below 2005 levels by 2050. This means cutting total emissions to 150 megatonnes — across the entire country — in three decades.

Projects that have already received approvals add up to 131 megatonnes, according to the Pembina Institute. But even if emissions from the oilsands were capped at Alberta’s old 100-megatonne cap — they would take up two-thirds of Canada’s total emissions budget by 2050.

6. Goodbye, Energy Efficiency Alberta

In early March — before the election got underway — Kenney made headlines for announcing that Albertans “don’t need bureaucrats changing our shower heads and our light bulbs.”

According to the Edmonton Journal, Kenney also said “programs under the agency would be ‘gone.’ ”

Energy Efficiency Alberta is a public agency mandated to support reductions in energy consumption in homes and businesses across the province, and is supported in part by revenue from the carbon tax.

Alberta was the only jurisdiction in North America to not have any energy efficiency agency prior to the program’s launch in early 2017.

7. Adios, carbon tax

One of the first promises of UCP leader Jason Kenney’s platform was well-known, and oft-repeated: The UCP government will scrap the carbon tax — on day one — boasting that, “at $1.4 billion, this will be the largest tax cut in Alberta’s history.”

Carbon pricing was enacted by Alberta premier Rachel Notley in 2015. The program involves collecting a levy on carbon-producing activities, then reinvesting that money into designated programs, as well as returning a portion of the funds to taxpayers through a means-based rebate program.

When Alberta repeals its own carbon-pricing plan, the federal government’s system will be put into place by default.

The UCP has a plan to target large industrial emitters, defined as “existing facilities with emissions above 100,000 tonnes of carbon dioxide.”

Those large emitters will be required to reduce their emissions intensity, which is not the same as total emissions (intensity refers to a ratio with economic output).

Large emitters will be required to reduce emissions intensity by 10 per cent initially (then increasing by one per cent per year), compared to their own emissions, averaged out between 2016 and 2018.

Large emitters that fail to reduce their emissions by the required benchmark will either pay a per-tonne price (lower than the current price) or buy offsets.

The UCP’s plan — called the Technology Innovation and Emissions Reduction (TIER) Fund — has been criticized as being a “symbolic” tax that will not be as effective in incentivizing reductions in carbon emissions as a broad-based carbon-pricing scheme.

8. Hello, lawsuit

Kenney has a plan to fight back against the federal carbon tax that will be imposed on Alberta. He’ll sue.

The UCP will “challenge the constitutionality of the Trudeau carbon tax by filing a judicial reference to the Court of Appeal, while continuing to support similar challenges by the governments of Saskatchewan and Ontario.”

Ontario’s Progressive Conservative party budgeted $30 million for its lawsuit, and Saskatchewan, Manitoba and New Brunswick have since joined in on the fight, too.

9. What about Alberta’s inactive oil and gas well crisis?

The Narwhal reported earlier this month that the Alberta Energy Regulator had privately predicted that the number of inactive wells in the province will double in the coming decade unless there’s a significant change in policy.

In a presentation obtained through a freedom of information request, the regulator noted that without the implementation of deadlines on when wells need to be plugged or cleaned up, and without a more robust tool for assessing whether companies can actually afford to clean up after drilling is done, the province has “a problem.”

In 1999, there were 30,000 inactive wells in the province. By 2030, the regulator is predicting there could be 180,000.

The cost of cleaning these wells up has been pegged at $100 billion.

The UCP’s platform includes a few measures to request help from the federal government in incentivizing well clean-up, but few other specifics on how the government will curb the problem, which has been described as “a massive ticking time bomb.”

10. Remember our fight with B.C. over wine? Let’s do that again, but bigger

In the final days of the election campaign, Kenney amped up his anti-B.C. rhetoric, mocking Vancouver’s goal of being zero-emissions by 2040, and taunting the city’s mayor by announcing that a Kenney government would ensure “a carbon-free Vancouver by 2020” . . . by turning off the taps and restricting shipments of Alberta fuel to B.C.

The threat is in the party’s platform, too. The party pledges it will “use the ‘Turn off the Taps’ legislation should provinces, including British Columbia, continue to obstruct the construction of pipelines.”

Gas prices in the Lower Mainland of B.C are already reaching record levels.

11. Fights — expect more of   ’em

We’re going to fight the carbon tax.

We’re going to fight Trudeau.

We’re going to fight Horgan.

We’re going to fight the Canadian confederation.

We’re going to fight environmental charities.

We’re going to fight foreign “special interests.”

We’re going to fight HSBC.

The UCP platforms declares that the Alberta government will boycott companies, such as HSBC, that boycott Alberta products.

It also states the party will “ask the energy industry to significantly increase its advocacy efforts” and will “support” companies willing to do so.

A UCP government will also “challenge the charitable status of groups that are funneling foreign money into anti-Alberta campaigns.”

(But wait, in the era of global markets and multinational corporations, what is all this foreign-funding talk even referring to?)

It all adds up to a lot of fighting.

12. Expect to hear a lot more about ‘foreign-funded environmentalists.’ We’re getting an energy war room!

Jason Kenney has been busy touring around Alberta touting the conclusions of Vancouver-based blogger Vivian Krause, who he describes as “intrepid,” saying she “deserves a great deal of credit.”

He’s planning to launch what he calls an “energy war room,” which will, in the words of the UCP’s platform, “fight fake news and share the truth about Alberta’s resource sector and energy issues.”

The war room will have a $30 million annual budget.

Its goal? To “stand up to well-funded foreign special interests who have been waging a decade-long campaign to landlock Alberta’s oil and gas with their campaign of defamation.”

If you’re scratching your head, read this. And then maybe go have a glass of wine in a park.  

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

A 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

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.

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.”

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.

Information obtained by The Narwhal reveals that oil and gas companies owe the Alberta government more than $20 million in unpaid land rents accumulated since 2010 — and annual payments by government on behalf of delinquent companies have increased 840 per cent between 2010 and 2017.

When oil and gas companies drill wells on private property, they enter into a contract with landowners to pay an annual fee — rent for the land.

However, when companies don’t pay, landowners can apply to a government tribunal — called the Surface Rights Board — that steps in and pays the rent using taxpayer money. The government is supposed to recoup that money from the companies, so taxpayers aren’t footing the bill.

“The vast majority of operators [whose rents are being paid by taxpayers] are in bankruptcy proceedings, receivership or insolvent,” Mike Hartfield, spokesperson for the Surface Rights Board, told The Narwhal.

The Narwhal reported in January that Alberta recouped less than two per cent of all money paid on behalf of delinquent oil and gas companies in 2017 .

The new data obtained through a freedom of information request spans eight years and shows that not only is this practice the norm, but the problem is getting steadily worse.

A bombshell of a piece from @sharonjriley. “If people are worried about 3,000 [current orphan wells] then they won’t know what hit them with 80,000 coming.” https://t.co/btj8RU1Sca #ableg #abpoli #cdnpoli #oilandgas

— The Narwhal (@thenarwhalca) February 12, 2019

Rent recovery applications up 580 per cent

The government documents reveal that of the money paid on behalf of delinquent oil and gas companies, less than two per cent has been recouped during the past decade.

The number of applications from landowners for what’s known as rent recovery has increased 580 per cent since 2010.

In 2016, less than half a per cent — just $15,000 — was recovered from companies. In 2007, just $312 was recouped.

In total, oil and gas companies currently owe the Alberta government more than $20 million in unpaid land rents accumulated since 2010.

The amount the Alberta government has paid in land rents on behalf of delinquent oil and gas companies has been steadily on the rise in recent years, with more than $20 million paid since 2010. Less than two per cent of that money has been recouped from companies.

Not (yet?) orphans

The wells in question are not orphans. These are wells owned by companies that are still in operation — but are just (way) behind on their bills. In these case, landowners apply to Alberta’s Surface Rights Board to be compensated for the rent they’re owed by delinquent companies.

Orphan wells are different. They’re wells left behind when a company formally declares bankruptcy, and are taken over by the Orphan Well Association.

Lars De Pauw, executive director of the Orphan Well Association, talked to The Narwhal about the influx of new orphan wells added to the association’s inventory.

“We are well funded,” he said in an interview in November, noting that the association is primarily funded by industry. “Industry to date has contributed over $314 million.”

“This is a substantial amount that companies have paid for other company’s missteps.”

Companies pay into the orphan fund based on a formula set by the Alberta Energy Regulator that’s based on their share of the estimated total cost of clean up in the province.

But it isn’t technically just industry funding the Orphan Well Association. The Alberta government has given the association at least $30 million in grants since 2009, and announced that it planned to loan the organization $235 million in 2017. Last year, the federal government also said it would allocate $30 million to the cause.

The association’s inventory currently includes more than 3,000 wells that need to be properly sealed and another 1,500 that are sealed but still need more reclamation work. The inventory doubled between 2015 and 2018, according to its annual report.

Many of the wells the Alberta government has been picking up the tab for aren’t orphans yet, but given that companies are defaulting on payments, they soon could be.

‘They won’t know what hit them’

Many of the wells the Alberta government is picking up the tab for are inactive — no longer producing any oil or gas.

“You hear newspaper articles with the alarm that we have 3,000 orphan wells and how this is such a big number,” Lucija Muehlenbachs, an associate professor of economics at the University of Calgary, told The Narwhal. “And of course it’s scary that it’s growing at a fast rate.”

“But in comparison to the number of inactive wells, this is, like, peanuts,” she said.

In a 2017 paper, Muehlenbachs reported there were 80,000 inactive wells in the province — wells that her research found were very unlikely to ever produce again, even if prices increased.

In its most recent annual report, the Orphan Well Association reported “the increase in orphan properties is expected to continue,” noting that dozens of companies in Alberta were insolvent at the time.

“If people are worried about 3,000 [current orphan wells],” Muehlenbachs added, “Then they won’t know what hit them with 80,000 coming,” noting that not all inactive wells will necessarily become orphans.

“If people are worried about 3,000 [current orphan wells] then they won’t know what hit them with 80,000 coming.” — Lucija Muehlenbachs, economics professor

If companies are struggling to pay the rent owed to landowners, there are valid questions about whether they can stay afloat — and pay for their environmental liabilities — in the long run.

And if they can’t, they’ll end up on the ever-growing list of the Orphan Well Association. In the meantime, the Alberta taxpayer foots their land rent bills.

“It speaks to how much liability is being accumulated in Alberta,” Muehlenbachs said.

More costs could ‘fall to the public or to the landowners’

Questions remain about whether the Orphan Well Association can handle any more increases in its inventory.

“We do know there is a potential for the fund to be depleted or underfunded and those costs… [could fall] to the public or to the landowners,” Lewis Manning, a lawyer for the Canadian Association of Petroleum Producers told the Supreme Court of Canada last year.

(De Pauw of the Orphan Well Association told The Narwhal he was optimistic the association is finding new ways to minimize costs and increase efficiencies, a sentiment the organization echoed in a recent press release).

Manning was in court as part of the Redwater case — which recently resulted in the decision that paying reclamation costs takes priority over repaying creditors.

The ruling applies only to companies that have declared bankruptcy — and only helps if the company has any assets left over.

The government data The Narwhal obtained shows that Alberta’s environmental liability problem is not limited to already bankrupt companies. Many more companies are apparently already in such a precarious financial situation that they aren’t paying even the most basic of expenses — including the compensation owed to landowners.

As Muehlenbachs noted, many people assume that the Orphan Well Association is paying the expenses of wells when companies can’t or won’t.

But, she added, “this is a clear case where Albertans at large are paying.”

Alberta taxpayers footing bill for delinquent oil and gas companies, investigation reveals

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.

Perry Nelson has been farming near Provost, Alta., for more than 50 years — since he took over from his dad in 1965. He runs mostly cattle, some grain.

In 2012, he bought some more land, for extra pasture for his cattle. As with so much land in Alberta, it came with oil and gas wells already drilled deep down below the surface.

“The wells were on it when I bought it,” Nelson told The Narwhal. “Abandoned wells.”

“I don’t think [the company] had any intention of paying,” he said of the company that owned the wells and owed him money in the form of annual rent for drilling a well on his land.

“That guy’s gone broke I don’t know how many times,” he told The Narwhal. “[The regulator] still lets him start over again.”

Sure enough, according to Nelson, the company was soon a year behind on the annual rent payments it owed.

Nelson, a director with the Alberta Surface Rights Federation — a group of landowners concerned about oil and gas activity on their land — wasn’t having it.

“They have a contract that says what they’re supposed to pay,” he told The Narwhal. “That’s the way they should be paying.”

So Nelson did what many farmers do in this situation — he filed an application to Alberta’s Surface Rights Board. The Surface Rights Board is a tribunal that uses taxpayer money to reimburse landowners what they are owed by oil and gas companies.

Nelson’s was just one of thousands of cases that have been brought forward in recent years.

The government is supposed to recoup the money it pays out to landowners  from companies so taxpayers aren’t footing the bill — but new data obtained by The Narwhal shows that’s simply not happening.

Less than two per cent of funds recovered

There are 450,000 oil and gas wells registered in Alberta. They’re dotted across the province — one for every 1.4 square kilometres — and are on both public and private land.

For many landowners, they have become an enormous burden: there’s the added difficulty of farming around a wellhead, the noxious weeds, the dust, the added traffic.

But it’s goes beyond that. For many farmers and landowners — who are not receiving the basic compensation owed to them by oil and gas companies — there’s a financial headache as well.

In Alberta, landowners are supposed to receive compensation in the form of annual rent, to reimburse them for lost productivity, nuisance and adverse effects.

Far too often, advocates say, the company simply doesn’t pay.

If a company fails to pay a landowner the annual rent they have agreed on, a landowner can apply for a “recovery of rentals” from the Surface Rights Board, as per the Surface Rights Act, and receive their compensation from Alberta’s general revenue fund — in other words, taxpayer money.

This is supposed to be a temporary fix, as the government is then meant to recoup taxpayers’ money by tracking down the company and collecting the funds.

The trouble is, the Crown basically never gets that money back.

Information obtained by The Narwhal shows that, in 2017, less than two per cent of all money paid by the Alberta government on behalf of delinquent oil and gas companies was recovered.

Graphic: Carol Linnitt / The Narwhal

That means that taxpayers are on the hook for the annual rent owed by these absentee oil and gas companies — millions of dollars annually. And the number of cases is only increasing.

“It’s getting worse all the time,” Nelson said of the situation with delinquent oil and gas companies.

“It’s just spiralling down.”

Influx of applications

In 2017, 1,934 cases were brought before the Surface Rights Board, which already had a backlog of 1,990 from previous years — something many landowners say leads to frustratingly long wait times.

“It’ll probably take a year and a half before you get paid,” Nelson said.

“It’ll probably take a year and a half before you get paid.” — Perry Nelson, farmer

“It’s almost suicide,” said John Alpin, another landowner who spoke to The Narwhal, of the long process of applying for compensation.

The Surface Rights Board declined a request from The Narwhal for a phone interview, but Mike Hartfield, a spokesperson for the board, acknowledged long wait times by e-mail.

“Considerable emphasis is placed on processing these applications in a timely manner,” he said. “However, the board has to balance that with having a fair and thorough review process to ensure landowners are entitled to the monies being paid — this does take time.”

“[T]imely decisions on these matters is very important to us,” Hartfield added, noting that the board has increased the number of staff it employs to deal with applications, and concluded that the board is, “now in a great position to manage this influx of applications.”

Reporter Sharon J. Riley inspects an abandoned well with Daryl Bennett, a director with Action Surface Rights, near Taber, Alta. Photo: Theresa Tayler / The Narwhal

‘I’m paying myself’

When an application is eventually addressed, the board will try to track down the company and order them to pay. If they can’t, the board directs the Minister of Environment and Parks to pay the landowner out of the government’s general revenue.

The board can also suspend a company’s access to the wellsite, but this is often little punishment when a well is inactive anyway.

The Narwhal found that the board issued 1,537 rental payment orders to the Minister of Environment and Parks in 2017. Those orders amounted to requests that more than $6 million  — roughly the amount the government has budgeted for the Stollery Children’s Hospital’s critical care program — be paid to landowners on behalf of delinquent oil and gas companies.

In theory, this shouldn’t end up being a taxpayer expense.

According to the board, “where the Minister pays an operator’s compensation owing, the amount paid and any expenses incurred constitute a debt owing by the operator to the Crown.”

In turn, the crown debt collections division — part of Service Alberta — is supposed to go after companies to recoup that money.

But the result of their efforts is measly. In 2017, with millions of dollars owed by oil and gas companies, just over $100,000 was recouped.

In the end, taxpayers are footing the vast majority of the bill to reimburse landowners who are owed money by delinquent oil and gas companies.

At a meeting of Alberta Surface Rights — a group of landowners from across the province who are concerned about oil and gas activities on their land — in Camrose, Alta., attended by The Narwhal last month one refrain came up over and over again: “I’m paying myself.”

‘Dire financial situation’

When Regan Boychuk, a founder of Reclaim Alberta — a group advocating for the cleanup of inactive wells in the province as a job creation program — tried to find more information about how much taxpayers were on the hook for when it comes to covering for oil and gas companies, he was told that many companies lack the resources to pay in the first place.

A Government of Alberta representative told him in an e-mail that “in the vast majority of cases, an operator fails to pay the landowner not because of willful negligence or non-compliance, but that the operator is in dire financial situation (i.e., in receivership or bankrupt) and is not able to pay, therefore the likelihood of [the government] recovering any amount is very limited.”

Hartfield, the spokesperson for the board told The Narwhal by e-mail that, “The vast majority of operators [whose rents are being paid by taxpayers] are in bankruptcy proceedings, receivership or insolvent.”

Financially unstable companies have long been able to obtain licences and to drill new wells through a flawed system liability rating system administered by the Alberta Energy Regulator — a system that allows companies to exaggerate their assets by assuming oil prices of more than $100 per barrel and underestimates the costs of safely sealing and cleaning up wells.

These financially shaky companies then negotiate contracts with landowners. At the Alberta Surface Rights general meeting in Camrose, landowners alleged that companies had failed to pay — or sent out notices saying their rent would be unilaterally reduced.

The Narwhal also heard complaints that companies threatened to not pay farmers anything at all — if they didn’t accept a 50 per cent reduction in annual rent.

“We encounter this type of concern regularly,” Peter Dobbie, the Farmers’ Advocate in Alberta, told The Narwhal by e-mail, when asked about the allegations.

Rent recovery applications up 283 per cent

Some companies reportedly tell landowners that times are too tough to keep paying the agreed-upon rent, hoping their woes will hit a chord with Albertans.

According to a presentation by Michele Delcolle, a representative of the Farmers’ Advocate Office, at the Alberta Surface Rights meeting in Camrose, “a landowner is under no obligation to accommodate the changing financial circumstances of a company.”

But, Delcolle’s presentation added, “companies are stating economic hardship and believe reducing annual surface lease rentals will contribute to a strong economic health of the company.”

Other companies just don’t pay at all.

“Companies are becoming defiant,” Delcolle told the room. “They know the process.”

Their thinking, she continued, is often “‘rents are the highest part of our expenses… the Surface Rights Board is behind, so [we] have a year.’” In other words, companies can defer — or avoid altogether — paying expensive rents by gaming the system. (Delcolle didn’t respond to The Narwhal’s questions by press time.)

Whatever the reason, it appears to be becoming more prevalent.

Landowner applications for rent recovery are up 283 per cent compared to 2014.

When companies stop paying annual rent, landowners can apply to the Alberta Surface Rights Board to recoup money they’re owed. In 2017 applications were up 283 per cent from 2014, according to information from the board. Graphic: Carol Linnitt / The Narwhal

“The board has experienced a substantial increase in the volume of rental recovery applications since 2016,” said Hartfield, the spokesperson for the board.

“We expect that trend to continue.”

Changing hands

Another common problem faced by landowners happens when a well changes hands — when it is sold off to another company, often as part of a package.

“As the landowner, you won’t be notified of that,” said Nelson. Too often, he said, landowners aren’t paid after a company changes hands.

“The first time you know is when you don’t get paid. You phone the company and they say the phone number is no longer in service.”

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.

“Every single wellsite failed.”

That’s what Keith Wilson, a lawyer who has worked on surface rights issues for 30 years, says he heard at a presentation by the Alberta government earlier this year.

Wilson was listening to a representative from Alberta Environment and Parks give a lecture entitled “An analysis of Alberta’s Conservation and Reclamation program — does the program work as intended?”

The answer, in short, was no.

Daryl Bennett, a director at a group called Action Surface Rights, was there too. What he heard about the ecological condition of former wellsites — which had been officially certified as reclaimed — was alarming.

The government’s own research studied wellsites where reclamation certificates had been issued — and found they were nowhere near back to normal.

Nor were they meeting the government’s own regulations about the condition of the land.

Daryl Bennett, director of Action Surface Rights, poses beside inactive oil and gas infrastructure near Taber, Alberta. Sites like these need to be plugged and reclaimed before they can get a reclamation certificate but research shows certificates have been handed out even when adequate reclamation work has not taken place. Photo: Theresa Tayler / The Narwhal

There are currently no legislated timelines requiring when an oil and gas company reclaims a wellsite. Last month, Alberta’s Minister of Energy said she is “looking at targets and timelines,” for when reclamation is cleaned up, but did not herself commit to a timeline to implement any new rules.

In the meantime, companies are faced with the same trade-off they’ve had for years — continue to pay annual rent to the landowner where the well is located, or pay to clean up the site.

But as the government study found, the ecological and agricultural effects of industrial activity may linger — seemingly indefinitely — even if a company chooses the latter.

This has left some to wonder if the regulator has been allowing industry to get away with sub-par reclamation efforts — for decades.

Automatic approvals

The Alberta Energy Regulator issues reclamation certificates to companies that apply for them. For the vast majority, no inspection by the regulator is necessary — just the required paperwork, signed off on by a certified practitioner. Most applications are approved by the regulator automatically.

Alberta has accumulated more than 100,000 wellsites that have received reclamation certificates — or that are exempt from reclamation based on their age — during the past 50 years. The liability for these sites eventually reverts back to the taxpayer.

And this doesn’t include the massive backlog of inactive wells in Alberta. Officials within the regulator tasked with ensuring oil and gas wellsites are cleaned up have privately pegged the bill at as high as $100 billion.

The presentation Wilson and Bennett saw was about a pilot project, conducted by Alberta Environment and Parks. It looked at 73 wellsites from across Alberta, representing forested, cultivated and grassland landscapes, that had been issued reclamation certificates.

Some sites had been certified as reclaimed as many as 54 years ago, others as recently as 2011.

The presentation warned that if reclamation hasn’t truly restored the landscape, the province could potentially face an even larger bill in the future. “Certified site liabilities will begin to transition from industry to public,” it concluded, adding, “public interest is not served as intended.”

The research examined whether the sites studied had met the regulated objective of returning a wellsite to “equivalent land capability” to ensure that the ecological, agricultural or other productive capacity of the land is restored.

In test after test, the sites were found to be in worse condition than nearby undisturbed areas assessed for the sake of comparison — even the sites that hadn’t seen any industrial activity for decades.

But when The Narwhal asked the Alberta Institute of Agrologists for permission to view video of the presentation, the Institute declined, adding, “the topic ended up being a bit of a contentious issue.”

“There was unwanted negativity towards [the] findings.”

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

‘Gradual downward spiral’

Mike Smith, a retired reclamation inspector, knows about that kind of unwanted negativity.

The Narwhal met with Smith and his wife, at their home in Wainwright, to talk about his storied career.

Smith retired five years ago, after working for the Alberta government for over 36 years — in Hanna, Grande Prairie and Wainwright.

When a company applied for a reclamation certificate, Smith would head out into the field to see if the reclamation was up to snuff, and to see if the site was worthy of being certified.

“When I first started with them in 1976, they didn’t even issue us shovels,” he told The Narwhal. “We used the toe of our boot.”

Mike Smith looks through notes and records he collected during his career as an inspector for the Alberta government at his home in Wainwright, Alberta. Photo: Amber Bracken / The Narwhal

At that time, he said, he was tasked primarily with ensuring a company had cleaned up the debris leftover from drilling — metal casings from the well, caps, cables, random debris — and that they had leveled off the ground so farmers could plant new crops.

“We’d go out with the landowner and see if it was smooth enough for him to farm,” he explains. A second local inspector would accompany him, representing the county or municipal district.

It was a job Smith took seriously.

“I would have to look at it through my own eyes.” He’d ask himself, “if I owned this land, would it meet my standards?”

Smith loved his job, he told The Narwhal. “It felt like I was doing something worthwhile.”

But reclamation inspections have changed dramatically. At first, Smith thought things were improving — he was issued a shovel, for starters — and it seemed like reclamation was being taken seriously.

“There was lots that was happening that was good,” he said, “until Ralph Klein.”

Since the 1990s, according to Smith, Alberta’s reclamation program has been in a “gradual downward spiral.”

By 2003, Smith’s job changed dramatically. He would no longer go out to inspect a site before a reclamation certificate was issued.

Instead, the majority were expected to be done from his desk. He was tasked with auditing approximately 15 per cent of the applications.

“You didn’t see the soil anymore. You didn’t get to feel it, you didn’t get to look at it,” he told The Narwhal. “You were scrolling.”

“We weren’t happy, let’s put it that way,” he said, when asked about the morale of inspectors at the time.

Pressure to pass audits

When Smith did get to out to a site, he might find gas leaks or evidence of soil compaction — or that crops and other vegetation weren’t growing properly.

“That’s still lasting,” he said. “Those problems are still there.”

“Many of the applications that I audited failed,” he told The Narwhal. Still, he said, failing sites was often not encouraged by his employer.

“It was tremendous — the pressure you received,” he said, of feeling compelled to issue sites a passing grade. He wasn’t, as he put it, a “fan favourite,” among oil and gas companies seeking certificates.

At one point, he said, a company that owned a wellsite that he had failed complained to his director. He remembers one of his bosses telling him, “Mike, work with these people.”

For Smith, the message was clear: “Get these things through.”

Smith was not alone in the people The Narwhal spoke to who expressed similar concerns.

“The oil company has an agenda,” he said. “They want to get a reclamation certificate.” Once a reclamation certificate is issued, oil and gas companies no longer have to pay rent to the landowner where the well was located — and the liability is off their books.

“This has been a problem for me for many years.”

Mike Smith at a flooded oil lease site in Wainwright, Alberta. 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

Mike Smith pages through his records at his home. Photo: Amber Bracken / The Narwhal

“We have some of the best legislation on the environment,” Smith told The Narwhal. “But we don’t have the enforcement.” Photo: Amber Bracken / The Narwhal

In 2013, all inspection and enforcement was taken over by a newly created arms-length corporation — the Alberta Energy Regulator — and Smith had had enough. “I submitted my request to retire. I could see what was happening… I couldn’t put myself in that position, where I would be beholden to industry.”

“We have some of the best legislation on the environment,” he laments, acknowledging that reclamation criteria have improved over time. “But we don’t have the enforcement.”

‘Automated’ review process, no human regulator needed

Until 2003, reclamation certificates were only issued after a government inspector like Smith had gone out to a wellsite to review the application, collect data and interview landowners.

But by 2003, the government had accumulated a large backlog of pending approvals. And with only 15 government inspectors at the time, they decided the most efficient way to speed up the process was to rely, essentially, on industry self-regulation.

With a backlog of close to 30,000 wells that had applied for reclamation certificates — and another 18,000 pipelines — the government was bogged down. “We weren’t going to be able to keep up with the program with the demand we were anticipating,” a spokesperson told the Globe and Mail at the time.

Getting rid of government inspectors, a spokesperson said, would more than double the number of certificates that could be issued annually. In its place would be steeper fines, random audits and an increased liability period.

Five years later, the regulator began requiring “professional sign off,” by a contractor hired by companies, in order for an application to be submitted.

Fast forward to 2018, and the Alberta Energy Regulator — funded by industry and whose board was, until recently, helmed by chairperson Gerard Protti, formerly a founding president of the Canadian Association of Petroleum Producers (CAPP) — is still trying to speed up the process.

The regulator is responsible for reviewing tens of thousands of energy development proposals annually, conducting inspections to ensure industry is compliant with government standards, administering penalties for non-compliance and conducting hearings on proposals. In short, the corporation “oversee[s] all aspects of energy resource activities” — no small feat.

The regulator has introduced new procedures to speed things up.

Today, it requires only that companies submit the required paperwork using an online system called the “OneStop Reclamation Certificate and Onestop Application tool.”

Eighty percent of applications proceed with a standard, “automated review” of the application — no human regulator needed, and certainly no field visit.

A video released by the regulator last year lauded the “administratively friendly” automated online platform that would mean “low-risk applications processed in minutes.”

https://www.youtube.com/watch?v=U0rEss_BmSI&t=72s

“Not kidding,” the video added.

The video advertised $7 million in annual savings and advertised that it would enable “25,000 pipeline applications processed annually — automatically.”

The video celebrated how easy it would be for industry to apply for reclamation certificates.

“Hello easy drop-down menus,” it boasted.

The regulator, which declined The Narwhal’s request for a phone interview, defends its move to increased efficiency. “For Alberta to be competitive, we need to enable further development by removing unnecessary costs in our regulatory system, while still maintaining high standards for environmental protection and public safety,” Samantha Peck, a spokesperson for the Alberta Energy Regulator, said in an e-mail.

“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,” she added. (After two weeks of back and forth, this was the only question the regulator was able to answer by press time.)

It’s long been clear that the regulator takes much of its direction from industry.

“The private sector is placing increasing pressure on regulatory bodies to… simplify cumbersome regulatory processes,” the regulator’s former head told the industry magazine Daily Oil Bulletin last November.

Oil and gas companies, he continued, “are asking us to be innovative in our regulations.”

‘Surprisingly little research’ done on reclamation

The regulator may well have heeded industry’s requests for simplifying cumbersome regulatory processes, but the pilot project from Alberta Environment and Parks — which has not committed to conducting any further field research — appears to be ringing alarm bells about the reclamation process.

This pilot project is one of the first of its kind to actually attempt to establish whether reclamation has been successful in returning sites to “equivalent land capability.”

Anne McIntosh, an assistant professor of biology at the University of Alberta, worked on the pilot project. “What do we already know? Very little,” she told The Narwhal. “Surprisingly little research has been done on reclamation.”

“I was just shocked when I started on this project.”

A flooded and inaccessible oil lease site in Wainwright, Alberta. Sites like these need to be reclaimed, but there are currently no timelines in Alberta for when a company needs to clean up a site. Photo: Amber Bracken / The Narwhal

The project sought to establish the “ecological recovery” of a site, using various methodologies to determine if reclamation had brought the area back to the original, pre-drilling condition of soils and vegetation — as is required by legislation.

Researchers took samples from old wellsites — looking at soil condition, crops, plant life, noxious weeds and tiny microorganisms — then took the same samples not far away, to establish a baseline. The research involved “goes beyond what’s done as part of the reclamation assessment process,” according to the project’s director.

They then calculated what’s known as an ecological recovery score — assuming the higher the score, the closer it might be to actually achieving the legislated requirement of “equivalent land capability.”

The results are startling.

The project found that over two thirds of the sites — all of them certified as reclaimed— in forested and grassland areas had recovery scores of less than 50 per cent.

In forested areas, for example, 90 per cent of wellsites studied had recovery scores of less than 50 per cent when it came to soil, meaning the soil was substantially more compact, had a higher pH and was generally in worse condition than adjacent reference sites.

And when researchers looked at soil mesofauna in agricultural areas — the tiny invertebrates like mites and nematodes often used as indicators of soil health — they found much lower concentrations at reclaimed wellsites.

On croplands, some wellsites were found to be “unsuitable” for crop production — despite being officially reclaimed.

Drone images presented at the conference showed examples where former wellsites could clearly be seen from above, their exact outline visible through the degradation of crops that have been planted on top of them — though they were certified as reclaimed more than twenty years ago.

A drone shot used in the government presentation, showing ineffective reclamation. Image: Alberta Environment and Parks

The implications of the government’s findings could be far-reaching.

If the pilot project’s preliminary results are indicative of what’s going on in the rest of the province — and researchers are careful to note that they can’t make assumptions about the bigger picture — the true costs of reclamation could continue to increase well into the future.

When asked for details, Alberta Environment and Parks’ Environmental Monitoring and Science Division initially responded by e-mail, noting that “although reclamation activities are intended to re-establish the capability of the land, important elements like plant and bird communities, soil properties, and nutrient cycling may not be fully established for years or even decades.”

Alberta Environment and Parks declined to make the scientist who gave the government presentation available for an interview with The Narwhal, saying “we are not able to get you in touch.”*

In a later interview with Dan Farr, Alberta Environment and Parks’ Director of Biodiversity and Ecosystem Health Sciences — who oversees the pilot project — told The Narwhal he’s “not surprised” that wellsites differ from reference sites, and declined to comment on the implications of the project for the reclamation certificate process.

When asked if the preliminary results of the research suggested reclamation certificates were not ensuring equivalent land capability — as is the requirement — he paused.

“Equivalent land capability,” he noted, “is more qualitative than quantitative.”

“If we consider equivalence to [mean] equal ecologically,” he said carefully, “then the answer is clearly no.”

But if it is interpreted to mean the land “delivers similar functions,” he said, then one needs to look, for example, at whether “cultivated lands grow crops.”

He acknowledged that the government’s findings indicated that many wellsites had reduced the land’s ability to grow crops.

“It looks like there’s a legacy related to the fact that there was a well pad there before,” he concluded.

‘Not recovering with time’

According to McIntosh, sites examined in the government pilot project often show a “halted or arrested successional trajectory” — meaning they are on a slow, or virtually non-existent, path to full recovery.

“We’ve always sort of thought if you gave them enough time, they’d go back [to their previous condition],” she said.

Terry Osko, a reclamation research consultant with a PhD in wildlife ecology, who has worked in the field for 20 years is hesitant to draw too many conclusions about the future. “Moving forward there should be fewer and fewer,” sites that show such stilted recovery, he told The Narwhal. Site reclaimed today, he said, “are probably not going to be in as rough of shape as ones that were from the 70s.”

Others worry that no one is checking that sites certified today are recovering.

An orphaned oil and gas well near Taber, Alberta. According to the Government of Alberta’s research, well sites like these, once reclaimed, often show long-term negative effects, despite regulations that require “equivalent land capability.” As it turns out, many years of industrial activity are difficult to undo. Photo: Theresa Tayler / The Narwhal

Alberta Environment and Parks’ Land Policy Branch told The Narwhal by e-mail that “no policy changes are being contemplated at this time for long-term monitoring of lands” that have received reclamation certificates.

Researchers, presenting in New Orlean this past August at the Ecological Society of America’s annual meeting, made the government project’s conclusions clear.

“Wellsite development impacts can be long lasting and may remain for 50 years or more after reclamation,” they noted.

“Some sites are not recovering with time.”

“Our goal is getting the science out,’ McIntosh told The Narwhal. “It’s in the government’s hands to decide to what do with it.”

An Alberta oil and gas well lease from 1949 that states land used must be restored “to the same condition.”

Alberta’s 1978 rules stated oil and gas sites must be reclaimed “to a condition of as good as or better than the original site.” Industry has long promised to restore oil and gas well sites but government research finds this is most often not the case. Image: Report of the Select Committee to Review Surface Rights, 1981 / University of Alberta Rutherford library

Desktop audits

Despite the poor scores of reclaimed sites studied by the government, less than three per cent of certificates have been cancelled by the regulator since 2016.

Some twenty per cent of applications are audited. An audit can mean only a desktop review of the application done by a human “reclamation assessor” — were all the application’s fields filled out correctly? Is the site location correct? — but does not imply any field work is done by the regulator.

The regulator declined to comment on the number of field inspections they have conducted.

Information obtained by The Narwhal found the number of field inspectors — who can accompany reclamation assessors on site inspections — has declined by 16 per cent since the Alberta Energy Regulator took over enforcement from Alberta Environment in 2013.

The regulator was unable to tell The Narwhal how many reclamation assessors it currently employs.

This means that the majority of on-site evaluation is left to the company, and the professional tasked with signing off on the application — ranging from foresters to agrologists to engineering technologists.

According to the government’s presentation, it’s a “professional judgement-based system,” rather than an “evidence-based” system.

10 different people, 10 different ways to interpret something

Terry Osko, the reclamation research consultant, has faith in his colleagues. “I think it would be quite rare to have shoddy work done in the field because [consultants] are good people by and large and all regulated by professional organizations,” he told The Narwhal.

The Alberta Institute of Agrologists is one of those professional organizations. It’s made up of about 2,800 members, according to David Lloyd, the Institute’s CEO.

Lloyd told The Narwhal that the organization’s members are held to a code of ethics, and the profession has a new set of standards meant to “identify the knowledge, skills, experience and the kinds of judgment or decisions that one should make.” The standards are meant to be “self-assessed,” he said and “are not punitive, but supportive.”

He added that the Institute plans to start “random practise reviews” of its members in the very near future — something that no other professional organizations in the field do.

“I believe our members are ethical and competent,” he said. “And if they’re not, we’ll hear about it… from landowners [or] another professional colleague.”

A flooded and inaccessible oil lease site in Wainwright, Alberta. Photo: Amber Bracken / The Narwhal

If a professional is reported to have violated their code of conduct, and an investigation finds the claim to be credible, the Institute has a variety of punitive tools available, according to Lloyd — ranging from revoking or suspending professional practise permits, levying a fine to requiring courses be taken (like an ethics course).

But some worry the regulator has insufficient capacity to oversee industry and the consultants it contracts. As one consultant, who asked to remain anonymous, put it, “the [regulator] is just watered down. It doesn’t have the capacity. It’s jack of all trades, master of none.”

Reclamation consultants, he said, need to be prepared to be “challenged” by companies eager to “get that liability off the books.”

“I’ve heard that the clients of our members can sometimes put pressure on [them],” Lloyd told The Narwhal. “It’s up to [the professionals] to decide how to handle that as professional. They have a requirement to make the right decision.”

When it comes to interpreting standards, some worry there’s too much leeway. One agrologist who spoke with The Narwhal on the condition of anonymity, said “10 different people [have] 10 different ways to interpret something.”

‘I’m not setting it on a trajectory to heal’

One consultant who has worked in reclamation in Alberta’s boreal forests for more than 10 years — who asked his name not be used because he’s “not old enough to retire” — told The Narwhal he’s very concerned about the standards used when he’s asked to assess a site.

“Disturbed sites are extremely hard to reclaim,” he said.

He works in forests, and sees a disturbing trend in re-planting. “What we’re doing now in reclamation — what I’m required to do — does not come anywhere close to [proper reclamation],” he told The Narwhal.

“I’m not setting it on a trajectory to heal. They’re monocultures.”

He acknowledges that reclamation criteria have improved over the years — a company can no longer simply plant an area to grass if it used to be forest, for example — but he still sees issues with the reclamation criteria.

“Many of the decisions they’re making are based on money,” he says, explaining that the “simplest” or “easiest” species to replant are often chosen, with very little regard for biodiversity, and that there is too often a lack of training of the people doing the reclamation, so that many replanted trees often die.

When he goes out to check if a forest has been restored on a site, he just needs to find “some woody species,” even if the replanted trees have died, he explains. Rose bushes will often do. If he finds some, he says, “I can still certify it.”

“That is nothing like the forest we cut out.”

While he’s adamant this has negative impacts for the area, he has no way of following up, as monitoring isn’t required once that certificate is issued. “I don’t know how long that site is going to be stagnated for,” he laments.

“I’ve never had to return to a site,” he said. “I’ve had sites where I wished I could have, but I didn’t have to, because they passed.”

‘Still a lot of cowboy stuff’

Another consultant who also spoke with The Narwhal on the condition of anonymity — a professional agrologist with 20 years of experience in the field — said that he was mostly concerned with the front-end of oil and gas activity: the construction of wellsites.

“When it comes to any sort of disturbance of any kind of ecological system,” he said, “you’re destroying the natural ecosystem.” The goal, then, is to try to do the best you can to get it on the right path from the get-go.

But he’s concerned that there’s little environmental input until a company decides it wants to reclaim a site.

The attitude during construction, he said, is too often, “move the dirt, get it out of the way, get the pad drilled, get it producing.”

While regulations and ideas about reclamation have improved over time, he said, “[contractors] just do what they did ten years ago.”

“There’s still a lot of cowboy stuff.”

He’s concerned that the majority of the environmental input is thrust onto reclamation, and that education and pre-planning could help solve a lot of problems. “They’re on the back end, trying to fix what happened on the front end.”

Effort varies

Osko, the reclamation research consultant with a PhD in wildlife ecology, has a pragmatic approach. “Since I started back in 1999, the improvement in practise is taking off kind of exponentially,” he told The Narwhal.

But the reclamation process could, in his mind, still be improved — perhaps a preliminary reclamation certificate could be issued, for example, with a required follow-up before it’s finalized. The timing of that, he added, could take into account the expected recovery time, based on site type or local ecology.

“It varies within industry, within companies, and with sort of the economic situation, how much effort is put into the process,” he noted.

And when it comes to the notion that companies will only meet the minimum standard required of them, he said, “everybody pays income tax, nobody wants to pay more income tax then the government wants them to pay.”

But he’s encouraged by companies he’s worked with who, he said, are motivated to do more than the minimum. There is, he told The Narwhal, “both economic and social incentive for responsible stewardship.”

Overall, Osko is optimistic that industry is on an upwards trajectory. “Some days I’m discouraged by what I see, but I stay in it because I’m overall encouraged.”

‘Small but numerous’

Though each individual wellsite is small, the cumulative effects of so much industrial activity may be much larger.

As a 2017 study published in the journal Forests put it, the footprints of oil and gas activity are “small but numerous, creating many disturbances across a large area.”

“They’re sort of little postage stamps peppered across the landscape,” said McIntosh.

There are approximately 450,000 wells in Alberta, roughly one for every 1.4 square kilometres — and that’s not including the tens of thousands that have already been issued reclamation certificates.

Billions are dollars need to be spent in Alberta just to get wellsites to the reclamation certificate phase — and there are concerns about whether industry will be able to pay.

And some wonder if the buck will stop there. If certified sites aren’t recovering ecologically — or agriculturally — critics worry that Albertans have given up more than they signed up for.

For many, there are questions — shouldn’t the regulator be checking the work of industry and private consultants? And who is ensuring that reclamation is truly a restoring a landscape, if no one ever goes back to find out?

Over the course of numerous interviews, one particular sentiment came through loud and clear: Albertans deserve to know whether the province’s reclamation program is functioning as intended — and whether anyone is checking to make sure it works in the long-term, too.

Mike Smith holds the shovel he used in his work as a well site inspector. Photo: Amber Bracken / The Narwhal

A shovel head that Mike Smith had used during his career as an inspector for the Alberta government. Its label reads, “snapped under pressure.” Photo: Amber Bracken / The Narwhal

‘Snapped’

Back in Wainwright, Mike Smith warms up some of his wife’s soup for lunch, then goes down into his basement to retrieve some of the mementos he kept from his long career. He wants to show us the inspirational quotes he tacked up next to his desk, and a shovel he used to inspect sites for years.

After checking the soil at countless sites, the shovel finally broke, so Smith — sentimental about it after all those years — cleaned it up, took it back to his office and affixed a message to it.

“Snapped under pressure,” it reads.

The shovel hung on the wall next to his computer until he retired.

*Update December 7, 2018, 9:30am pst. To address reader questions, this article was updated to note that Alberta Environment and Parks declined to make the scientist who gave the presentation related to well reclamation available to The Narwhal for an interview.

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.