Alberta, industry are gambling that energy transition disruption happens closer to 2050 than 2030, with plenty of time to clean up hundreds of thousands of wells. What if they’re wrong?
Dwight Popowich wants to sell his farm and retire. Unfortunately, an orphaned gas well on his property is thwarting that plan. No buyer wants to risk the unknown costs of reclaiming the site, especially if soil is contaminated, and no bank will finance a sale without reclamation. Thousands of farmers and ranchers across the province face similar situations. Landowners aren’t the only victims.
Taxpayers are up next. Premier Danielle Smith has already proposed that Alberta pay $6 billion of the estimated $100 billion to $130 billion bill to clean up industry’s conventional oil and gas environmental liabilities. The “moral hazard” – if the government pays once, it will be pressured to pay again and again – of her RStar program represents a serious financial risk for Albertans. And there will be plenty of pressure from the industry, which has seen bankruptcies soar since the price bust of 2014.
Alberta producers are under intense pressure: capital is scarce and costly; international and Canadian climate policies require significant investments to reduce greenhouse gas emissions; and the rapid electrification of transportation is already cutting demand for oil. Peak oil demand is less than a decade away, according to the International Energy Agency. The energy transition is disrupting the global energy system far more intensely than we imagined even a few years ago.
Alberta’s response to the energy transition’s existential threat is tepid, at best. The reason is rooted in an outdated view of how energy transitions work.
Alberta politicians, business leaders, and CEOs think of energy as a commodity (coal, oil, gas) that grows linearly, small incremental steps over a long time. But energy as a technology (wind, solar, batteries, EVs, etc.) is rooted in electronics and grows exponentially, with hockey-stick adoption curves. This is the fundamental difference between the energy transitions of today and yesterday.
As long-time electronics executive Mike Andrade explains (see below), linear growth thinkers believe they have decades before fossil fuels are threatened while exponential growth thinkers argue that peak demand is imminent, with decline beginning by decade-end.
Not surprisingly, linear-thinking Alberta has hunkered down to protect the energy status quo. But believing Alberta has decades to solve its oil and gas liabilities problems suggests that companies will eventually step up – or be forced to step up – to address their responsibilities.
Energi Media will argue that Alberta oil and gas CEOs have no intention of paying the full cost of their liabilities. To be accurate, no CEO or industry association has ever said that, but it is the most likely outcome given the industry’s long history of evading responsibility for its environmental liabilities and the serious possibility that stress created by the energy transition will cause more companies to fail, resulting in many, many new inactive and orphan wells and no progress cleaning up the current huge inventory.
Then, oil and gas companies will almost certainly do what they have always done, ask for subsidies. Like Premier Smith’s RStar.
From an exponential growth point of view, Alberta is on the cusp of an environmental liabilities crisis. The clean up bill for old wells and infrastructure is massive, likely to grow significantly, and the Alberta Energy Regulator does not have the policy mandate or the regulatory powers to fix the problem.
This crisis is rooted in 70 years of regulatory failure. Recent improvements to conventional oil and gas liability regulations are modest and, according to experts interviewed by Energi Media, unlikely to lead to real change.
In Part 1 of this series, Energi Media argued that not fixing the problem could lead to a Doomsday scenario where Alberta is overwhelmed by the environmental damage left behind by the oil and gas companies while provincial coffers are overwhelmed by the cost of trying to clean up the mess.
Readers can judge for themselves how likely that scenario is for the conventional oil and gas side of the sector. Thousands and thousands of farmers and landowners like Dwight Popowich can attest that Alberta is not acting fast enough to avoid it.
At the very least, the evidence provided in this investigative report explodes the “ethical oil” argument.
By the Numbers
As of March, 2023, there are a total of 328,728 wells in Alberta, according to the regulator. How many of them are “orphan wells”? There is no easy answer, unfortunately.
Generally speaking, an orphan well has no “parent.” The well’s owner is either bankrupt or can’t be identified. Most Albertans probably think of orphan wells the same way. Not so the AER.
In Alberta, a well technically becomes an orphan when the AER transfers it into the inventory of the Orphan Well Association (OWA), established 20 years ago. The OWA currently has about 7,000 orphan well sites in various stages of reclamation (sites can take years before being fully decommissioned and reclaimed). More later on the OWA, which is an important part of the story.
Another type of well is “abandoned.” This means the wellbore has been plugged with cement and sealed so that methane and other gases can’t leak (though they sometimes do).
As of March, 2023 according to AER data, there are 36,675 (7.9% of the total) wells of this type that are “reclamation exempt.” Another 96,562 (20.8%) are fully abandoned and reclaimed. Another 90,991 (19.6%) are sealed but the site is not yet reclaimed; additional work is required on those sites and that could include remediating contaminated soil, which can be costly.
The category of most interest is “inactive/suspended.” We’ll refer to wells of this type simply as inactive.
Sour gas (containing potentially deadly hydrogen sulphide) wells must be inactive (not producing) for six months and other wells must be inactive for 12 months before they are “suspended.” This category of wells may be old and depleted, uneconomic under current prices, or inactive for some other reason. There are 82,635 inactive wells (17.8%) in Alberta, up from 30,000 in the early 1990s, though the peak was reached in 2021 at 97,000.
The key question is, how many of these wells are likely to become orphans?
We shouldn’t assume all of them because sometimes inactive wells are reactivated when prices improve. But a 2017 study by University of Calgary economist Lucija Muehlenbachs suggests most of them are permanent residents on the list.
“…the [computer] simulations that model scenarios where prices are substantially higher or where production technology is significantly improved, clearly show that the vast majority of these wells will never be reactivated, no matter how dramatically conditions improve,” she concludes.
Why doesn’t the AER designate more wells as orphans and transfer them to the OWA? The usual reason: money.
Industry funds the Orphan Fund via an annual levy. Every oil and gas company receives an invoice for their share. Last year the levy was $72 million and companies loudly complained. You can imagine the grumbling when the 2023 levy was set at $135 million. And the levy is the cost of reclaiming a small fraction of the potential orphan wells.
The final category of interest is included in the active wells. These are “marginal producers” (making less than 10 barrels per day) that are either uneconomic or likely will be soon. The American term is “stripper well.”
“Out of our active well populations 61% of them are marginal producers which means they are producing 10 or less barrels of oil or oil equivalent a day,” Wadsworth noted in his 2018 presentation.
That’s 95,150 wells. How many will end up on the inactive list and go on to become orphans? Impossible to say, but the CER oil demand scenarios showing falling demand and low prices after 2030 suggest Alberta’s future likely holds many more, not fewer, uneconomic wells.
Historically, the number of Alberta’s problem wells has never declined, at least not for more than a brief blip on the timeline. Regulator data shows there were 30,000 in 1986, 60,000 in 1995, and by 2020 about 90,000.
There is one exception. Over the past three years, in part because of the federal COVID-19 relief program that provided $1 billion for well clean up in 2020. Higher prices in 2021 and 2022 also helped. Higher industry spending required by the UCP government’s new mandatory spend requirements also contributed to the fall.
Given that federal support has ended and that the industry continues to drill thousands of new wells every year, plus the potential for marginal producers to slide into inactive/suspended, a good argument can be made that Alberta is at best treading water. Perhaps the steady increase in potential orphans has been slowed, but even that is too early to tell.
Not all wells, however, are created equal. “Industry is not prioritizing end-of-life obligations,” the AER noted in a 2019 “liability narrative” obtained by The Narwhal through a freedom of information request, preferring to reclaim “dry” wells that never produced oil or gas wells because reclamation costs are higher than oil well sites, which often have contaminated soil.
This practice continues the age-old industry practice of kicking today’s problems down the road and letting someone else worry about them.
Wells are also not the only conventional oil and gas liabilities. There are approximately 440,000 kilometres of pipelines within Alberta that fall under the purview of the AER. And “there are over 90,000 licensed facilities in Alberta,” says the liability narrative, but “the number of inactive facilities is uncertain; however, less than 3% have been fully reclaimed.” Some liabilities – “partial upgraders, borrow pits, remote sumps, and access roads etc.” – were excluded altogether by the AER.
Experts interviewed by Energi Media often mentioned human health risks as one consequence of old leaky wells dotting rural Alberta, but neither the AER nor the provincial government seem to have a good handle on the magnitude of that risk.
The picture painted by the data is of a rural landscape overrun with unreclaimed oil and gas infrastructure. How much of it leaks? Is it all properly secured? If there is an owner, does the company inspect and test the equipment regularly as regulations require? The answer, sadly, is that no one knows for sure. The AER doesn’t have the resources to perform inspections and far too often wells have no owners.
What’s the Bill for Cleaning Up Conventional Oil and Gas Liabilities?
In February, 2018 and then later in June of that year, Robert Wadsworth made two presentations to private groups about the cost of reclaiming Alberta’s oil and gas liabilities. Someone leaked those presentations to reporters from Global News, the National Observer, and the Toronto Star who were working on a joint investigation into the oil and gas industry. The headlines focused on the big numbers: $260 billion in total, $130 billion each for conventional production and the oil sands.
The conventional production costs broke out as $100 billion for wells and $30 billion for pipelines, with no mention of costs for facilities and other infrastructure. Wadsworth, the AER’s vice-president of closure and liability, cautioned that even his team’s much higher estimates were likely conservative.
At the time, Energi Media criticized the story for not taking full advantage of the treasure trove of information and insights in the presentations. The story was obviously so much bigger. The Unethical Oil series is, in part, a response to the deficiencies of the reporting about oil and gas liabilities over the past five years.
Another point we made was that Wadsworth’s numbers were only relevant if the entire Alberta industry was vapourized overnight. If every well, every facility, every pipeline required immediate reclamation. The prevailing view among the international experts we interviewed about the energy transition at the time was that changes to the global energy system would happen more slowly, taking decades past 2050 for significant change to happen. The past five years have proven that view to be wildly wrong.
The AER responded to the sensational headlines by claiming that the $260 billion was an absolute worst case scenario. A more accurate number for conventional wells, they said, was $58.65 billion. But as the AER’s 2019 “liability narrative” noted, “The current liability calculations are not an adequate reflection of liability in the province.”
That year, The Alberta Liabilities Disclosure Project – a coalition of landowners, advocacy groups, and concerned citizens – was created to refine the AER data even further. Their ultimate goal was to pressure the provincial government, the regulator, and industry to clean up the unreclaimed well mess.
Citizen Group Finishes AER’s Work
“For decades, we’ve looked the other way as the number of ageing oil and gas wells threatening farm lands and drinking water continues to grow,” lead researcher Regan Boychuk said in a press release. “We need the government to tell Albertans the truth, so we can make a plan to deal with this ticking time bomb.”
The Disclosure Project used freedom of information requests to obtain the AER’s internal liabilities study created by Wadsworth’s team. The study contained 368 cost scenarios for various types of wells. As the coalition noted, “the ALDP simply finished what the AER started.”
Where Wadsworth simply multiplied the number of unreclaimed wells by $275,000, a rough cost of reclaiming a well, the Disclosure Project’s software sorted “hundreds of thousands of wells into hundreds of cost scenarios developed by the AER based on wells’ ages, depths, types, and regions,” according to its 2021 The Big Cleanup report. The new study estimated the number of unreclaimed wells to be over 300,000, with minimum clean up costs between $40 billion and $70 billion for wells alone.
Pipelines, however, were not included in the Disclosure Project’s estimates. That adds another $30 billion of costs, according to the coalition. In the end, the Disclosure Project’s numbers are $70 billion to $100 billion. Add costs for the tens of thousands of unreclaimed facilities and other types of infrastructure, not to mention higher costs to clean up contamination, and they are probably in the range of $100 billion to $130 billion, not far off Wadsworth’s total.
Another important finding of the Disclosure Project’s study is that 80 per cent of Alberta’s unreclaimed wells are beyond their “economic limit.” This means the amount of hydrocarbons the well is likely to produce for the remainder of its life would generate less revenue than the cost of reclaiming the well.
If accurate, there already may not be enough future revenue to pay reclamation costs for conventional oil and gas liabilities even if companies wanted to. And only around $200 million is held as security by the AER against those liabilities.
Where will the money come from to cover the oil and gas industry’s enormous liabilities?
“An ethical, well-governed fossil fuel industry would pay its own way without billions in public subsidies and would clean up its own mess. As this report clearly shows, that’s not what’s happening in Alberta today,” said report co-author Dr. Dianne Saxe, former Ontario environment Commissioner. “This makes a mockery of Alberta’s claims that its oil and gas industry is an ESG leader.”
And a mockery of Alberta’s claims to extract “ethical oil.”
Contamination Increases Uncertainty
Something wasn’t quite right. Dr. Kevin Timoney’s review of hundreds of AER oil and gas spill records showed that every one, without exception, claimed that 100 per cent of the fluid spilled was recovered. This is scientifically impossible. Imagine, he says, pouring a litre of water on your lawn and then trying to get it all back.
“I graphed spill volume against recovery volume,” the scientist wrote in his 2021 book, Hidden Scourge. “It was a straight-line 1:1 relationship. In short, the spill recoveries were too good to be true. At that point, I smelled smoke and went looking for the fire.”
Over the course of six years, he examined regulators’ oil and gas spill data from over 100,000 incidents in Saskatchewan, North Dakota, Montana, and the Northwest Territories, but by far the most (almost 80,000) was in his home province of Alberta.
The AER’s numbers are simply not to be believed. Given that data is the lifeblood of oil and gas regulation, this is a serious blow to the regulator’s credibility. Energi Media will examine the AER’s data problems in more detail later in this series.
For now, though, Dr. Timoney’s work raises a troubling question: just how badly contaminated are Alberta’s oil and gas wells?
His book’s conclusion is that contamination is far more serious than the AER and the industry are admitting. But no one really knows. The data is so bad, so torqued and unreliable, as to be useless. In fact, conventional oil and gas contamination is rarely raised in the many regulator documents that have been reviewed by Energi Media to date. The assumption seems to be that contaminated sites are a minor issue.
But Dr. Timoney’s research suggests the opposite conclusion. If he’s correct, then the cost to properly remediate conventional Alberta’s oil and gas liabilities is probably much higher than the AER and the industry think.
That makes an already bad situation that much worse. This is more evidence that it’s time for Albertans to understand and prepare for the worst case scenario, not the best.
How Did Alberta Get in this Mess?
The idea of “polluter pays” is simple: if you pollute, you pay to clean it up. Putting the principle into practice is trickier. Industries push back, citing high costs and job losses. Sometimes allocating responsibility between polluters is difficult. Nevertheless, “polluter pays” is a mainstay of environmental law, including in Alberta.
“Alberta’s liability management system is based on the ‘polluter pays’ principle that if energy companies (licensees) are going to profit from Alberta’s resources, they must safely close (abandon, remediate, and reclaim) their wells, pipelines, and facilities once they are finished with them,” Auditor General Doug Wylie said in his 2023 report about the many failings of the AER’s conventional oil and gas liability management.
“In upholding this principle, Albertans are to be shielded from having to cover the costs of these closure obligations and be sufficiently protected from health and safety risks and environmental harm.”
The principle in one form or another has been embraced by Alberta regulators down through the years. Many times the iterations of the regulator have sounded the alarm bells as the province’s unfunded conventional liabilities steadily grew. They have produced papers outlining the problems, convened committees with industry to devise solutions, and fretted behind the scenes at Alberta’s inability to halt the march of growing liabilities.
Yet, as late as 2019, the AER was lamenting in the liability narrative brief about its passive approach to managing liabilities: “The current liability management system is largely reactive; we are not proactively managing companies and their liability. It is imperative the [policy] framework change to meet today’s realities and to ensure that the liability associated with end-of-life obligations remains with industry.”
The reason liability management is reactive and not proactive lies with choices made decades ago.
Alberta governments as far back as the 1930s prioritized industry growth and profitibilty, which ruled out taking full security for reclamation when the well was drilled. At the beginning of the “well lifecycle,” as the regulator describes it.
Taking security or forcing the producer to clean up liabilities at the end of that lifecycle is ineffective because the company is often bankrupt. As the AER wryly noted in the liability narrative, “managing end-of-life obligations in insolvency is too late in the lifecycle.”
Or, as is often the case today, larger companies prefer to spend capital on income-generating projects, not reducing liabilities. This curious approach explains a great deal about why producers prefer to leave wells inactive rather than cleaning them up.
An Odd Way of Thinking About Oil and Gas Liabilities
Dan Wicklum was head of COSIA (Canadian Oil Sands Innovation Alliance) for seven-and-a-half years. The organization was created by the oil sands producers (some of whom are significant producers of conventional oil and gas) to share research and technology. His job included working with CEOs and senior executives to help find solutions to complex problems like tailings pond reclamation.
He learned that oil companies view environmental liabilities not as an unavoidable cost of doing business, but as just one more business unit that competes internally for capital. Can reclaiming tailings or a well site earn a profit? Can it earn a higher return on capital than drilling a new well?
“The first priority is following the law, being regulatory compliant,” Wicklum told Energi Media. “Anything more than that, it needs to be a source of income, not a net financial cost to the company.”
Reclaiming old well sites is almost never a source of income, but have oil companies discovered other types of value that might persuade them to allocate capital for reclamation? Will Ratliffe thinks they have. He is a professional geologist and has spent most of his oil patch career working with liabilities.
Companies’ attitudes are slowly changing, he said.
The first step is understanding the type of liability sitting in a company’s inventory, then determining how much reclamation costs. The liabilities sit on the company’s balance sheet, says Ratliffe, and investors appreciate when management lowers that obligation, thereby improving its financial position.
“A quiet change is happening within companies, even on the financial and accounting side,” he said. “These folks are doing a good job of point outing internally that $10 spent on asset retirement should reduce liabilities by $10. That’s something industry has struggled with.”
In the past, depleted wells would be sold to stripper well operators. That practice is changing, in part because of recent high-profile cases that involved lawsuits (e.g. Sequoia Energy, see below) or intervention by the regulator (e.g. Shell’s sale of sour gas assets to Pieridae Energy ).
“The risk from doing that now, I think, is much more apparent and very well understood by corporations,” says Ratliffe.
How widespread is that understanding? To what extent are companies prepared to act on it? We don’t have answers to those questions yet and may not for some time. We do know, however, know how oil and gas companies thought about their liabilities in the past.
The dilemma for Alberta regulators, then, has always been where and how to effectively intervene in the well lifecycle.
Alberta is not the only North American jurisdiction that failed to solve this puzzle.
The Incumbency Dilemma
Alberta is suffering from the incumbency dilemma: faced with disruptive change and no acceptable responses, the incumbent doubles down on the status quo. The forces of change (new energy technologies, vigorous climate policies) are denied or minimized. The agents of change (renewables, electric vehicles, etc.) are demonized. And, critically, soothing narratives (“ethical oil”) allow incumbents to fool themselves that all is well.
Often it is, until the last minute. The newspaper industry, for example, enjoyed its most profitable years just before tech platforms like Google and Facebook destroyed its advertising revenue model. One day, like newspapers all over North America, incumbents wake up to find themselves mired in a cascade of crises, failures, and eventually insolvency.
Perhaps it’s just coincidence that Alberta’s big oil and gas companies enjoyed record profits in 2022?
As noted American economist Phil Verlager told Energi Media (see below), oil and gas (especially the conventional production) is now a mature, sunset industry. What do sunset industries do? For starters, they consolidate. Over the past decade, the once mighty juniors (production under 10,000 barrels per day) have been devastated by bankruptcies and now intermediates (production under 50,000 barrels per day) are failing at an alarming rate. The pool of oil companies available to pay for reclaiming liabilities is steadily shrinking.
Incumbents also return capital (as opposed to earning returns on that capital) to placate shareholders. The Alberta majors are promising to return three-quarters, and sometimes more, of their free cash flow to investors. During disruption, this is the only way to bolster stock prices, ensure access to capital, and keep the CEOs and their executive teams employed.
Admitting to investors that Alberta’s liability crisis is much worse than previously thought would undermine confidence and cause serious headaches in C-suites all over downtown Calgary.
US States Also Struggled with Security
During an interview with Patrick Montalban, the vice-chair of the US National Stripper Well Association mentioned that every state oil and gas regulator required oil companies to take out a surety bond against future reclamation costs. This ensured, he said, that as the wells became more and more depleted, and slid down the oil patch food chain to smaller and smaller companies, money would be available to seal the wellbore and reclaim the site.
The evidence shows that the state regulatory systems were just as as flawed as Alberta’s and, in some cases, even worse. The surety bonds (sometimes letters of credit or other types of security) represented only pennies on the dollar of the eventual reclamation costs. Many states permitted “blanket bonds” that covered dozens and even hundreds of wells.
Just as in Alberta, oil companies found it much cheaper to walk away from wells than reclaim them.
The United States now has close to four million wells and as many as 1.5 million orphan wells. No one knows the exact number, Adam Peltz of the Environmental Defence Fund’s orphan well program told Energi Media. Pennsylvania, for example, drilled its first well in the 1850s and never established effective regulation of the industry until a century later.
The data is spotty and many wells are undocumented. Health hazards are a serious concern. The United States may be a preview of Alberta’s future if corrective action is not taken soon.
Cognitive Dissonance in the Oil Patch
For Part 2, Energi Media reviewed a number of historic and current Alberta oil and gas regulator documents. There is a curious thread that runs through most of them, going back to at least the 1980s, that readers should keep in mind.
Documents for public consumption often start with bromides like “Alberta has a long history of responsible oil and gas development” or “the Alberta Energy Regulator is recognized as a world class regulator.” Then the document will go on to describe horrendously serious regulatory problems that completely disprove the earlier assertion. Sometimes there is a palpable tone of desperation to the writing.
This tension between the public and private faces of the regulator is revealing. It shows the extent to which even the regulator has succumbed to the “ethical oil” narrative. Or, more likely, that’s a feature, not a bug, of the Alberta regulatory regime’s design.
It helps explain why the AER claims to be transparent and open, but in practice jealously guards information and data from prying eyes. A number of industry sources have told Energi Media that past iterations of the regulator were far more forthcoming.
As Dr. Timoney discovered, the AER’s opaqueness made him wonder what the regulator is hiding and then he discovered it was quite a lot, actually.
One Family’s Struggle
In 1999, Dwight Popowich and his wife Sharon, a nurse at the local hospital, bought 75 acres five minutes south of Two Hills in east-central Alberta. Nine years later they were approached by one of the intermediate oil companies that wanted to drill a gas well on their land. Popowich says he signed an agreement in part because he wanted to be a “good Albertan.”
Untold numbers of Alberta farmers fell for the same spiel.
“When the [oil company’s] landman went to a farmer’s property and talked to the family about what the company wanted to do, the story was, ‘we’d like to drill an oil and gas well, we’re a big responsible corporation that really knows how to do things safely,’” says Chris Severson-Baker, whose job at the Alberta Energy Regulator’s Drayton Valley office a decade ago was to work with local landowners who had inactive or orphan wells on their property.
“‘This is a temporary use of the land surface. You’ll be compensated for your trouble. And then at the end of the 10, 15, 20-year period, we’ll restore things to exactly how they were when we showed up.’ That was a great story. People just didn’t have a lot of experience to question that.”
In Popowich’s case, the company appeared to be financially secure. He believed the AER would have his back if problems cropped up in the future. Still, he had a few concerns that he insisted be added to the agreement. Almost from the start there were problems.
No tanks were allowed on the well site, according to the lease, but the company installed one anyway. When Popowich raised the issue with the company, “they just outright refused to do anything about it,” he claims.
The AER was no help enforcing the agreement. Popowich’s only option was to sue the company. The small annual surface rights payment and the accompanying aggravation simply didn’t make it worth his while. He says many farmers in his area are in the same situation. While they grumble about the inconvenience and lost use of their land, few are willing to seek recourse.
The system is rigged in favour of the oil companies and appears to have been from the beginning.
A regulatory change 37 years ago made things worse.
The Beginning of the Modern Conventional Well Crisis
Informational Letter IL 86-1 dated February 21, 1986 informed oil and gas operators that the Energy Resources and Conservation Board had decided to not bother with even the pittance of security it had been collecting from new well operators.
“The requirement that each applicant for a well license provide a deposit to guarantee the proper drilling, control, completion, suspension, or abandonment of the well has been dropped…The deposit amounts were so small that little protection was afforded against large expenditures where a licensee did not exist or was not able to meet his responsibilities, and increasing the deposit to a meaningful amount was not considered feasible.”
Instead, the Board proposed an abandonment fund “which might be necessary in the few instances where a licensee cannot be found or is unable to carry out proper operations.” The letter says that the Alberta government and industry trade associations “agreed” to the fund.
Depending on oil and gas operators to do the right thing, followed by having the industry inadequately fund reclamation when they inevitably didn’t do the right thing, would be Alberta’s liabilities management strategy for most of the next four decades. From then until now, the regulators’ various schemes to get oil companies to reclaim their wells, facilities, and infrastructure, have been one failure after another.
Hitching the Regulatory Wagon to Funds
University of Calgary law professor Shaun Fluker has created a useful timeline of Alberta’s ineffective liability management policies.
When the ERCB stopped taking security in 1986, it introduced a $3 million Special Well Fund created from unreturnable security deposits and additional funds from the regulator. “The intention was that interest earned by the Fund would cover costs incurred by the ERCB to abandon orphaned wells,” University of Calgary law professor Shaun Fluker told Energi Media in an email.
In a 1989 document, “Recommendations to Limit the Public Risk from Corporate Insolvencies Involving Inactive Wells,” the ERCB noted that the Special Well Fund could only pay the reclamation costs for 200 orphan wells. The Board wasn’t sure how many there were. Their best guess was 17 to 243. The real problem was the 25,000 inactive wells that “are neither producing nor are they properly abandoned.” Up to 1,600 of these wells did not have “traceable owners,” making them orphans for all practical purposes.
The regulator continued to assume that if an inactive well had an owner, the asset would be reclaimed by that owner at some point. But low oil and gas prices during the late 1980s, which led to a rapid increase in oil company bankruptcies, began to change that view.
In the spring of 1991, ERCB senior manager JR Nichol presented a paper about orphan wells (to a drilling conference in Calgary) that is notable for its heightened level of concern about liability dumping. The regulator was also worried about the “ever-increasing population of suspended or inactive wells” and their potential for becoming orphans.
“…the Board was concerned about the rationalization of assets that was ongoing in industry which was resulting in the sale of wells from large companies to many small players,” he told the audience during his presentation. “Some of these new licensees had little or no background or experience in the oil business and in the Board’s view some had questionable financial responsibility and capabilities.”
The ERCB’s proposal was to widen the pool of those responsible for reclamation. It proposed a “chain of responsibility in descending order” that began with the current owner or licensee, then the receiver acting on behalf of insolvent licensees, owners of a percentage of a well (called working interest participants), previous licensees who had sold the well, lessees and previous lessees of mineral rights, and finally, minerals rights holders.
Industry strenuously objected to the proposal. It’s not hard to see why. Big producers who thought they had jettisoned environmental liabilities would once again be on the hook.
The companies countered with a proposal that has implications for today’s liabilities crisis: “Industry has thus recommended that the chain be limited to the current licensee and working interest holders and the receivers on behalf of any or all of those parties, and that an industry-sponsored fund be established to pay for the share of abandonment costs of bankrupt owners [emphasis added].”
The highlighted text is critical: oil and gas producers proposed the principle that industry is collectively responsible for orphan wells.
Landowner advocates like Mark Dorin and Dwight Popowich argue that the principle applies whether that responsibility is for a few wells, as was the case in the early 1990s, or the hundreds of thousands of wells, pipelines, and facilities of today. Companies, not the people of Alberta, must be on the hook for every penny of the $130 billion of oil and gas liabilities.
The Abandonment Fund was created in 1994. Revenue was to be generated by fees on new well licensees and an annual levy on inactive wells. Orphan pipelines and facilities were included in 1996.
The following year brought the Long Term Inactive Well Program, the first inventory reduction policy not directed specifically at orphans. Wells inactive for more than 10 years had to be abandoned, be put back into production, or have security posted against future reclamation. The program lasted just two years before being cancelled.
Liability Mis-management Rampant After 2000
An AEUB memorandum dated September 27, 2000 and written by Howard Fedorak, a coordinator of the surveillance branch of the corporate compliance department, explains why the Long Term Inactive Well Program was ended: “Further consideration for cancellation of the LTIWP was based on a concern from industry that the LTIWP program requires licensees to address or place deposits on specific wells. It has been suggested that this prescriptive approach hampers industry’s ability to selectively administer its wells.”
The memorandum notes that the LTIWP was quite successful, with 1,200 long-term inactive wells being abandoned (cut, capped, and sealed) and $24 million of security being taken against another 1,500 wells. This observation is reflected in the fact that the number of inactive wells stopped rising during the brief tenure of the LTIWP.
“The regulator’s ‘rationale’ doesn’t totally make sense,” says Yewchuk. “None of the documents provide a clearly reasoned explanation why they cancelled the LTIWP rather than fixing the problems. For instance, that it only covered abandonment, not reclamation, and the required deposits allowed in place of abandonment were too low.”
Licensee Liability Rating
The new system was called the Licensee Liability Rating (LLR) Program. It turned out to be a spectacular failure.
The regulator had previously used a simple screening tool – the ratio of active wells to inactive wells – as a proxy for oil and gas company financial solvency, a tool that didn’t work very well. Instead, assets and liabilities of a licensee would now be calculated every month. If assets equal liabilities, the ratio was one, the licensee was considered insolvent, and the regulator required action, such as a security deposit. A liability ratio between one and two was considered the danger zone where a licensee could easily slip into insolvency.
“The LLR will more accurately assess the asset to liability ratio of each licensee and require financial security deposits from licensees not achieving the specified LLR threshold [of 1.0],” Fedorak wrote. “Corporate Compliance believes that the LLR requirements will not only support, but enhance, the fundamentals of the Long Term Inactive Well Program…”
The number of inactive wells exploded, almost tripling from 35,000 in 2001 to over 90,000 in 2017 (see chart below). This happened despite drilling numbers collapsing in 2007 because of the global financial crisis and economic slowdown, then not recovering after, in part because of the oil price crash in late 2014.
Yewchuk also points to the number of well licenses that slipped into the danger zone. In 2012 there were 22,877 licenses belonging to companies with an LLR of 2.0 or less. By 2018, that number had soared to 118,572, according to data obtained from the AER.
“That’s the marginal wells being sold down the chain [liability dumping] to the financially doomed operators,” says Yewchuk.
What caused the sudden hockey stick-type growth starting in 2001? This is an important question because what was previously a serious liabilities problem quickly morphed into a crisis.
Regulatory failure appears to have played a big role.
One example of this failure is that many oil and gas companies now focused on managing the regulation instead of reclaiming wells. The AER noted in its liability narrative that “in the absence of targets or timelines, some licensees focus only on regulatory requirements and closure work that improves their Liability Management Rating…As a result, industry does not allocate appropriate funding or address all closure obligations, including the remediation of contaminated sites, resulting in increasing liabilities.”
Oil patch veteran Mark Dorin points out that the Western Canadian Sedimentary Basin, which is mostly located in Alberta, was beginning to mature. “The good fields, with wells that had high flow rates and slow decline curves, had been largely depleted,” he told Energi Media. “Companies were also drilling a lot of coal bed methane gas wells, which have short lives, during that period.”
Perhaps the most damning criticism of the LLR program is that many oil and gas companies with LLR ratings far higher than 2.0 failed and declared bankruptcy.
“The LLR was an outrageous mess. Difficult to believe the scope of how bad it was,” Yewchuk concludes.
The AER admits as much on its website:
“It is clear that how we manage liability has not slowed the growth of inactive wells. Historically, liability management has been largely reactive and not focussed on the full life cycle of energy development. In particular, the liability management rating (LMR), which is a rating based on a company’s liabilities and assets, is not an accurate measure of whether a company will be able to address their end-of-life obligations.”
Fortunately for Alberta, the second part of the new system performed better than the first.
The Orphan Well Association
An important part of Alberta’s approach to managing oil and gas liabilities for the past 20 years is the Orphan Well Association (OWA). The OWA’s purpose is to close oil and gas assets (wells, pipelines, infrastructure) where the owners are bankrupt.
The organization is the continuation of the 1993 deal industry agreed to in exchange for the Alberta government and the regulator not extending liability to past owners of oil and gas assets.
The OWA is a nonprofit whose board is composed of industry representatives. The annual levy that funds its closure work is invoiced to every oil and gas company in Alberta. The NDP government loaned $235 million to the OWA in 2017, the UCP government lent another $100 million, and Ottawa lent an additional $200 million, plus another $30 million to cover interest. It should be noted that the OWA did not administer the federal government’s $1 billion pandemic support program for well clean up.
The interview with OWA executive director Lars de Pauw was instructive. As one might expect, he takes a very legalistic view of Alberta oil and gas well types, especially what is and what is not an orphan. He estimates that the number of wells that are fully decommissioned (instead of “abandoned,” which used by the AER) and designated as orphans is about 7,000.
But other categories of unreclaimed wells could very easily become the Alberta taxpayers’ problem.
“If those companies are insolvent and struck from the corporate registry, then the OWA could do those ones,” he said, speaking of the more than 80,000 inactive wells. de Pauw says that those wells have licensees attached to them and, therefore, are not orphans. The fact that the licensees might be inactive and exist only on paper? Not his problem.
The AER’s own license data suggests that most of the 173,626 inactive and abandoned but not reclaimed wells are licensed to insolvent companies or those teetering on the brink.
At a minimum, in 2023 there are 215 companies holding 8,525 licenses with an LMR of zero, while 297 licensees holding 29,216 licenses (each license representing a well) with an LMR below one. The odds of those companies reclaiming their wells is zero. Companies with an LMR between one and two, 138 of them, hold 75,180 licenses. History suggests that the odds of those companies reclaiming their wells are poor.
The OWA may consider them viable licensees because they have not been struck from the corporate register, but law professor Shaun Fluker says that plenty of oil and gas companies with no assets manage to exist only on paper. “Many, if not most, companies registered in Alberta will have an account with a downtown law firm and someone in that firm files the annual return every year,” he said.
Landowner advocates such as Regan Boychuk and Mark Dorin would argue that those 104,390 wells are de facto orphans.
They may be in the “suspended/inactive” or “abandoned site not reclaimed” categories, but for all intents and purposes they will never be properly cleaned up by their owners, who in many cases cannot be identified or found. Boychuk and the Alberta Liability Disclosure Project would probably go even further to argue that 80 per cent of the 155,984 active wells have passed their economic limit and in the near future should be declared orphans.
Whether the OWA should be given responsibility for those hundreds of thousands of wells and the industry levy increased (to billions per year) is a controversial idea that would be opposed by both the government and industry.
Trusting Oil Companies to Do the Right Thing Leads to Liability Dumping
If Alberta regulators couldn’t intervene at the beginning or the end of the well lifecycle, the fallback position appears to have been to trust companies to do the right thing and voluntarily clean up their old well sites.
Drew Yewchuk, a University of Calgary public interest lawyer found this 1995 quote from the Energy Utility Board, an AER predecessor, in documents obtained through a freedom of information request:
“…rigid and immediate compliance to our requirements was not critically important as we knew the company would ultimately have to abandon and reclaim the site, thereby having to absorb any costs associated with non-compliance. Over the past several years this assumption has been proven very wrong with most major operators divesting themselves of older projects which are on the downward slope of profitability.”
This is known as “liability dumping.”
Large companies drill the will and produce the hydrocarbon throughout the most profitable part of its lifecycle, then sell the asset to a smaller company with lower overhead and production costs. Many Alberta wells have had multiple owners over their life.
Eventually, wells often end up with a marginal producer that fails and declares bankruptcy during the next dip in prices.
Supreme Court of Canada’s Redwater Decision
The bankruptcy of a small operator was at the centre of a controversial legal battle known as “the Redwater decision.”
In late 2014, Saudi Arabia tried to punish upstart American shale producers by opening the spigots, flooding oil markets, and driving down prices. Small Alberta producers already hanging on by their fingernails began to fail. One such company was Redwater Energy, which owned just 100 wells, only 17 of them still producing.
ATB sued to recover its loans to the company. Redwater’s bankruptcy trustee agreed that the financial institution and other creditors were a higher priority than environmental liabilities. Two lower courts agreed.
“The Redwater case has turned the very foundation of that system—the provincial legislation that says polluters must pay to clean up their mess—on its head,” said AER CEO Jim Ellis.
As a consequence, “receivers and trustees involved in 28 insolvencies renounced their interest in more than 10,000 AER-licensed sites (wells, facilities, and pipelines) with deemed liabilities of almost $335 million,” according to the regulator. “In that same period, the OWA’s inventory of wells increased more than 300 per cent from 768 to 3,100.”
The OWA and the AER took the case to the Supreme Court of Canada and won in 2019. No longer could oil and gas companies declare bankruptcy and walk away from their liabilities.
There were, however, repercussions for the industry. For starters, lenders began using the LMR system “for purposes never intended,” the AER said in its liability narrative, like withdrawing credit as licensee liability ratios dropped close to 1.0. That led to a credit crunch, and failure, for some producers.
Nevertheless, Redwater positives far outweighed negatives. Most importantly, the “polluter pays” principle was upheld, ensuring that the regulator had the legal authority to prevent oil and gas companies from walking away from their environmental liabilities.
The problem is that the Alberta industry has a long history of doing just that. The rapid growth of inactive wells from 35,000 in 2001 to 97,000 in 2020 is testament to that fact.
As the case of Sequoia Resources demonstrates, they sometimes resorted to convoluted corporate transactions to do it.
Sequoia Resources and the Popowichs
In 2018, the annual $2,500 surface lease payment failed to arrive in Dwight Popowich’s mailbox. “How I found out that we ended up with Sequoia Resources was the check didn’t show up,” he said. “Nobody sends us a notice.”
It turns out that Popowich’s well had been sold to one of the Perpetual Group companies (Perpetual Energy, Perpetual Operating Trust, Perpetual Operating Corp.). Buying and selling assets is common practice in the oil patch. There is nothing sinister about the practice.
And we can’t say with certainty that what happened to Popowich’s well, and thousands like it, is sinister. The Sequoia story is complex, difficult to untangle, and the subject of lawsuits, some of which have not yet been resolved. The reader is advised to keep this in mind.
But the litigation is also “significant because the case relates to the ability of oil and gas companies to use complex corporate structures and transactions to avoid financial responsibility for abandonment and reclamation costs,” Yewchuk wrote in a the University of Calgary law faculty’s blog.
In 2016, Perpetual Trust owned roughly 2,400 gas wells valued at $6 million, while environmental liabilities and unpaid municipal taxes totalled $229 million. Then it purchased a total of 800 wells from three other companies.
As best we can tell, those transactions that generated the lawsuits started with Perpetual Trust transferring all its assets to Perpetual Operating Group. The valuable producing assets were then sold to another Perpetual company that later became Alphabow Energy (suspended from operating by the AER in early June and currently fighting appeals to keep operating). The poor producing wells and their facilities bearing the liabilities were sold for $1 to a numbered Alberta company wholly owned by Kailas Capital Corp., which was owned by Hao Wang and Wentao Yang, two low-profile investors with ties to China, according to the Globe & Mail. The numbered company’s name was changed to Sequoia Resources Corp. and it failed 18 months later, leaving more than 2,000 wells to the Orphan Well Association.
Was Sequoia a liability dump with more twists and turns than a Disneyland roller coaster or a miscalculation by the owners? The fact that Sequoia Resources seems to have operated as a stripper well business seems to support the latter view.
Bankruptcy trustee PwC noted in a report that management’s strategy was to “acquire gas assets, some at close to the end of their life cycle…reduce overall costs to the Company both in the field and at head office…reduce the operating costs of the assets, in part, by cleaning up older wells, and…abandoning and reclaiming well sites, reducing long term surface, mineral and carrying costs.” Management bet that gas prices, “at historic lows and thought to be at the bottom of a commodity cycle,” would recover. They fell lower and the company failed in 2018.
Two important issues concern the AER’s role in this story.
The first is whether the AER should have stopped the initial transfer of well licenses from Perpetual Operating to Sequoia Resources. The regulator says it didn’t have to review the transfer. “The AER had no direct authority to regulate corporate transactions (purchase and sale agreements),” the AER told Energi Media by email. “The situation with Sequoia, as well as other licence transfers, exacerbated a gap.”
Yewchuk has discovered documents in the AER’s Integrated Application Registry that show the transfers were automatically red flagged (presumably because one or both companies had an LLR below 1.0), reviewed, and approved a day later.
When asked for comment about the transfer document, the AER replied that as “this matter is currently before the courts, we cannot comment further on this specifically.”
The second issue is how Sequoia’s LLR appears to have been calculated by the AER. As part of the complex transactions, Sequoia had retained a one per cent ownership of the productive wells, but the AER gave the company credit for 100 per cent ownership. This would have inflated Sequoia’s LLR, presumably above the 1.0 required for the transfer to proceed.
Sequoia’s purchase of wells from bankrupt Waldron Energy is also being questioned. In that instance, the Globe and Mail reported that Sequoia, Waldron, and the AER, which was asked to “apply discretion” that enabled the purchaser to pass a toughened solvency test.
“For the AER, this situation has exposed a gap in the system and raised questions with respect to how we better manage liability in the future,” AER CEO Jim Ellis said in a 2018 statement. “In some cases, our governing legislation did not provide us the necessary flexibility to do what is needed, while in other cases our own requirements and processes were limiting. We are working to fix both.”
What about the apparent review and quick approval of the transfer of Perpetual Operating’s assets? Was the regulator’s decision to give Sequoia LLR credit for 100 per cent of assets that the company only owned one per cent of a system failure or a reviewer error? Why was discretion applied in the purchase of the Waldron wells?
These sound like mistakes, not “requirements and processes” that were “limiting.” Or, worse yet, perhaps they’re business as usual with the regulator. Either way, Sequoia Resources is a disturbing peek behind the curtain of the internal operations of the AER.
Unfortunately, blaming loopholes on “the system” and the “governing legislation,” then promising to fix it with yet another new and improved liability management system, is standard operating procedure for the regulator.
The upshot of the Sequoia story is that Popowich’s well didn’t make it into the OWA inventory. His well is essentially in limbo, stuck in the inactive category. It doesn’t qualify for provincial programs to reclaim problem wells. And he has no idea if it will ever be transferred to the OWA.
Working Toward a New Liability Management Framework
By 2017, an alarming number of inactive wells, the Redwater decision, more disputed bankruptcies of medium-sized producers, and a general recognition that the current system was broken, finally provoked AER executives to think about overhauling liability management regulations. The AER began consultations with landowners, municipalities, industry, non-governmental organizations, government agencies, and indigenous communities.
“Alberta’s current approach to governing the clean-up of these wells was put in place decades ago, when the oil and gas industry was largely focused on growing production and building new infrastructure,” the regulator explained, as if growing the industry and cleaning up depleted oil and gas assets were somehow incompatible in the past.
In the 2019 liability narrative, the AER identified three key issues a new system needed to address.
No Timelines for Clean Up
The first is the absence of rules to enforce the “timely closure” of depleted wells and infrastructure. As long as a well was properly suspended, it could sit in the inactive well category for decades – or, forever, really – under the previous regulation.
“Prior to 2020 when the new Liability Management Framework was introduced, there were no government policies in place that required companies to move their inactive well inventory to closure,” the AER told Energi Media in an email, which also pointed out that “ the Government of Alberta sets policy direction to regulate energy development, and the AER is responsible for implementing that policy.”
As a consequence, “regardless of commodity prices, there has been inadequate allocation of capital resources to curb the growing liability deficits and debt,” the 2019 liability narrative noted, adding that the number of inactive wells had grown from 60,000 to 93,000 in just 10 years.
Too many old wells
The second key issue is “unfunded and legacy liabilities” that have no financial backstop. These include pipelines (440,000 kilometres in the province), certain types of facilities and well types, “closed” wells that are now leaking, and “legacy sites where no standards were in place at the time of closure.”
Just how much liability are we talking about here? The AER doesn’t seem to know. Or, if it does, the regulator isn’t sharing with the public. The Wadsworth presentation, however, pegged pipeline reclamation costs at $30 billion, which suggests that including the other “unfunded and legacy liabilities” would significantly inflate that estimate.
The regulator’s conclusion that the “current liability calculations are not an adequate reflection of liability in the province,” is an epic understatement.
Not enough security
The third key issue is inadequate security collection in the existing framework. “While the regulatory framework allows for the collection of security as a backstop for liability, it is not currently an effective measure of control,” the AER wrote.
The only time an Alberta regulator tried to use security effectively was the short-lived Long Term Inactive Well Program that collected $24 million in two years, then was shuttered because of industry pressure.
The Licensee Liability Ratio replaced it in 2000, but could only collect security after the LLR dropped below one, at which point the company was insolvent and had no funds to post. The LLR was woefully deficient from the start, yet the regulator Band-aided it for 20 years before finally throwing up its hands in despair.
The New Improved Liability Management Framework
The new liability management framework introduced in 2020 by the UCP government is not perfect nor is it even close to sufficient to solve the huge conventional oil and gas liabilities crisis.
That said, it is the best designed system yet. Whether it will work as designed is an entirely different question.
The new framework incorporates five initiatives that try to address issues that are now familiar to readers.
The first is “practical guidance and proactive support” for distressed operators. While preventing ailing companies from failing may in theory prevent more inactive or orphaned sites, the move also plays into what the AER calls a “regulatory dilemma.” The regulator can use its existing blunt toolkit (collecting security, enforcing closure obligations) and risk tipping the company into insolvency or it can “exercise grace” and hope the operator can extract what value is available from the company, thus preventing the assets from ending up in the OWA.
History suggests neither option is effective. How the new approach will differ isn’t clear.
The second initiative means ditching the old LLR system and creating “a more comprehensive and accurate corporate health assessment by taking into account a wider variety of assessment parameters.” While LLR measured only two variables, the AER will now employ a more “holistic” view to gain a better understanding of a licensee’s financial health before, say, approving license transfers for wells.
This approach has to be better, if for no other reason than LLR was such an unmitigated disaster.
The Inventory Reduction Program, introduced in 2022, holds the most promise for finally shrinking the inactive well list because it requires companies to spend a minimum amount on reclamation each year. The program also requires companies in the same region to work together on reclamation (called “area-based closed”), which could lower costs by 40 per cent. Landowners with inactive wells can “nominate” wells to the AER for closure, a move that has proven popular in rural Alberta.
Of course, the program comes with a long list of caveats. Requirements can be changed if prices are low or if “unforeseen exceptional circumstances” arise, for example. But, as is always the case with the regulator, rules are applied with discretion, including after lobbying pressure from industry associations. Mandatory spending started in 2022 with $600 million being spent, which was 40 per cent above the minimum, the AER said in an email. Time will tell what future years bring.
The final initiatives are also good ideas.
Creating a panel to review “legacy and postclosure sites, or sites that were abandoned, remediated or reclaimed before current standards were put in place and sites that have received reclamation certificates and the operator’s liability period has lapsed” is smart. The regulator appears to have a very poor handle on how many of these sites there are or where they are located, and if they are contaminated whether they pose a threat to human health and should be properly reclaimed to modern standards.
Finally, the Orphan Well Association will gain new powers to more actively intervene when companies fail. In several cases, companies walked away from thousands of wells and other facilities, leaving no one in charge of operations. The OWA took emergency action to properly close or operate the asset in order to protect the public. These situations were rare, but the regulator appears to be concerned they will become more common in the future.
The new liability framework looks to be a significant upgrade on the old one. But as Auditor General Doug Wylie dryly noted in his scathing 2023 review of Alberta’s oil and gas liability management, the “AER has work remaining to design and implement a system responsive to the full spectrum of risks that historically impaired the performance and intended outcomes of the previous liability management system.”
In other words, Alberta has been down this road before, the results were poor, and no one should assume this time will be different.
In fact, one of the wild cards that could have a significant impact on the success of the new framework is Premier Smith’s pet project, RStar.
Smith, RStar, and Moral Hazard
Alberta’s UCP premier plied her trade as a radio talk show host for many years before retiring in 2021 to become a lobbyist for and president of the Alberta Enterprise Group, a business advocacy group. Top of her list of issues promoted to the UCP government she would later lead was the hugely controversial RStar program.
University of Alberta economist Andrew Leach explains RStar:
Rewards “firms with tradable credits to be used against future well royalty obligations, with one credit issued for each dollar spent on regulator-mandated clean-up. Companies then apply R-Star credits to future production to get discounted royalty rates. Royalties increase with oil prices so, at today’s $110-per-barrel (Cdn) price, $1 million worth of required cleanup would net R-Star credits that reduce royalties by roughly $280,000. The same credits would be worth about $115,000 if oil prices dropped by half.”
Smith has mused publicly about offering companies double credits to speed up reclamation, according to Dorin.
In a letter to then Energy Minister Sonya Savage, Smith suggested that Alberta provide $20 billion of RStar credits, which would reduce government royalty revenue by $6 billion, according to Leach.
“The proposal does not align with the province’s royalty regime or our approach to liability management and upholding the polluter-pays principle,” Savage wrote to a landowners association in a June, 2021 letter, according to the Globe and Mail.
Then the UCP turfed Premier Jason Kenney in late 2022 and Smith became premier. She appointed Peter Guthrie, a vocal champion of RStar, as energy minister. Most importantly, she announced her intention to implement RStar.
Albertans were not pleased. Loud and alarmed opposition forced Smith to shelve the full-scale RStar in favour of a three-year, $100 million pilot project. The Premier left little doubt that if the pilot was successful, whatever that means, RStar is back in business.
Potentially blowing $6 billion that should be spent by industry barely raises eyebrows in the UCP government. Jason Kenney, Smith’s predecessor, lost $1.5 billion subsidizing the doomed Keystone XL pipeline proposal and over $2 billion cancelling an oil-by-rail project because NDP premier Rachel Notley made the deal. No, RStar is bad because of its “moral hazard.”
“Why would any operator spend any kind of money on cleanup right now to deal with any of the reclamation liabilities if they can just hope that they might be incentivized to eventually clean these up?” University of Calgary law professor Martin Olszynski said. “The moral hazard here is just astounding.”
Alternatives to RStar
If the AER’s new liability management framework is inadequate and RStar opens the door for the oil and gas industry to shift the $300 billion of all oil and gas liabilities to the Alberta taxpayer, is there any plan or strategy that might actually address the problem in a timely manner?
The Big Cleanup
In addition to doing the most thorough estimate to date of conventional oil and gas liabilities to date, the Alberta Liabilities Disclosure Project also provided a model for tackling those liabilities: a non-profit Reclamation Trust that would operate independently of government, the industry, and the AER.
The Trust would essentially “take over end-of-life companies and use their remaining revenue to fund the cleanup of their wells,” according to The Big Cleanup report, and then “ wind down their operations in the public good. Wells would be retained and operated to pay for cleanup, and holding licenses, surface and mineral rights would further enable the Trust to fund ongoing reclamation work.”
That’s not the only change the ALDP included in its recommendations. The organization called for the end of liability dumping by closing the relevant loophole in the Bankruptcy and Insolvency Act; introduce an industry levy to “recoup public investments in cleanup”; make former well owners responsible for liabilities (industry agreed to the OWA 30 years ago to avoid such a fate); and reform the AER.
Implementing the ALDP proposal would see the most direct intervention in the Alberta economy since Premier Peter Lougheed during the 1970s. In fact, there would be more because private companies would essentially be nationalized, something that hasn’t occurred in Canada for a very long time. Would it fly politically? Not even Rachel Notley and the NDP are gutsy enough to champion this strategy.
But will it work? At first blush, without the benefit of expert analysis, probably. And it would take intervention of this kind to move quickly and decisively enough to solve the existential threat represented by the energy transition and falling global oil demand.
In the interests of full disclosure, Energi Media has interviewed Dorin many times about oil and gas liabilities, and he provided a great deal of background information and explanation for Part 2 of this series. He has a different view of how to fix the liabilities problem.
“Alberta has a workable, unique, somewhat complex, legislated system in place to deal with the unavoidable situation of corporate failures (financial or failure to act responsibly,” he writes in a paper for the Polluter Pay Federation. “Arguably, the system is not being properly managed.”
To make the system work, Dorin would have industry stick to the bargain it entered into with the creation of the OWA. That means the industry must pay for all unfunded liabilities regardless of the cost. Even if the annual OWA levy is in the many billions of dollars per year.
“As clarified by the courts, setting the levy is the task of the Regulator to accomplish the goal that the public NEVER pays for the costs that should have been borne by a defunct well or facility licensee,” he wrote. A levy big enough to do the job and some tweaks to the system coupled with a clear and powerful mandate for the regulator is Dorin’s recipe.
Will this approach work? Given that it would use the existing system but with some major and minor changes, (again) probably. But like the ALDP’s reclamation trust idea, putting Dorin’s idea into practice would require a provincial government with almost superhuman fortitude.
Readers can decide for themselves if Alberta is ready for the political blitzkrieg that either proposal would unleash from industry and its supporters. But at least both the ALDP and Dorin present what appear to be workable models. That is far more than 40 years of regulator attempts have accomplished.
If Energi Media’s view of the energy transition and the existential threat it presents to the Alberta oil and gas industry is correct, the province may very quickly be searching for solutions to its imminent liabilities crisis.
Could American-style “Stripper Wells” Buy Alberta More Time?
In the United States, “stripper wells” like those operated by Patrick Montalban’s members produce less than 15 barrels per day, often between two and five barrels, and account for eight per cent of total US oil production, around one million barrels per day. They are owned by mom and pop businesses that operate on a shoestring.
Alberta had its own stripper well industry for decades, according to Ted Gladsyz, head of the Independent Oil and Gas Association from 2002 to 2009. It appears that a rapid expansion of stripper well operators combined with widespread liability dumping is primarily responsible for the number of Alberta companies rising from 70 or 80 in 1974 to over 700 in 1995, according to Yewchuk’s document.
In Gladsyz’s narrative, Alberta stripper well operators produce a barrel of oil at the least cost and out-perform the bigger companies with their expensive overhead and downtown Calgary offices. He claims the provincial regulator’s inactive well list is chock-a-block with wells that are still economic if produced by stripper well companies. The AER noted in its 2019 liability narrative that “wells can move from an active to an inactive or inactive to active status on a regular basis…”
While some wells do move in and out of the AER’s “suspended/inactive” category, Muehlenbachs’ modelling suggests that once a well lands there, it rarely leaves. If oil prices rise 200 per cent, just 12 per cent of oil wells and seven per cent of gas wells are reactivated. Innovations that improve recovery lead to reactivation of 10 per cent of oil wells and six per cent of gas wells.
“In all cases, the amount of oil and gas production that would change one way or the other…is marginal and not of meaningful benefit to Albertans,” she concludes, which suggests that most of Alberta’s 82,635 inactive and suspended are already orphans simply waiting for the AER to transfer them to the OWA. Then there are the roughly 95,000 still active marginal producers in danger of landing in “suspended/inactive” that would be future orphans.
Gladsyz argues that the AER deliberately used the new LLR system after 2001 to chase Alberta stripper well operators out of business. Gladsyz says that the regulator’s crude measure of company finances found most of his organization’s members had ratings under 1.0, making them appear insolvent. The AER demanded security or it would padlock wells, he claims.
“None of the major companies or even the medium-sized companies had to put up anything,” Gladsyz told Energi Media. “But the mom and pop operations, they’re the ones that got put under by the board.”
Gladsyz opines that thousands of inactive wells could still be profitably produced if the AER would end its war on stripper well businesses. This idea could remove a number of liabilities from the AER’s inventory, perhaps for a decade or two, thus buying time the industry will be short of in the near future. And perhaps there is a way to marry the low-cost operations of stripper wells with the ALDP’s proposal to produce inactive assets and use some of the revenue to pay for the large clean up bill.
But who pays to clean up the stripper wells when they’re finally depleted? asks Dorin.
This example illustrates the difficulty regulators have had over the decades devising solutions once the decision had been made not to collect security at the start of a well’s life.
Will Industry Ever Pay for its Liabilities?
Apropos of Premier Smith’s RStar proposal, economist Andrew Leach addressed the larger question of what it meant for the future.
“When the premier comes out and says, ‘This is reclamation that would not have otherwise happened,’ that’s a big shot across the bow to the industry,” Leach told the CBC. “”Because she’s essentially saying, ‘You oil and gas producers are not going to meet your legal obligations to Albertans.'”
He also noted that the proposal would have implications for future oil sands reclamation, including the 37 giant tailings ponds that contain 1.6 trillion litres of toxic fluid. It’s worth noting for context that the AER’s Wadsworth pegged oil sands liabilities at another $130 billion. That makes a total of $260 billion for the entire sector.
Alberta’s oil and gas industry has spent the better part of a century evading responsibility for its environmental liabilities. A succession of governments of various political stripes has happily colluded with companies that have put profits above their social, if not legal, responsibilities. Are we to believe that the tiger will ever change its stripes?
Even if we assume that industry is sincere, there are five good reasons to believe companies will never fully clean up their liabilities, ultimately sticking Alberta taxpayers with the bill.
The first is history. Alberta oil companies have spent 70 years devising clever ways to foist their environmental liabilities on someone else. That’s not the narrative, which is that Alberta produces the most environmentally responsible oil and gas in the world, but it is the reality. As the AER noted in a 2019 “liability narrative,” reclamation activity remained the same regardless of oil and gas prices. Past actions are usually a pretty good indicator of future behaviour.
The second is where companies are allocating capital. At present, that means increasing returns to shareholders via higher returns and share buybacks, and reducing greenhouse gas emissions in advance of stricter federal regulations, not increasing reclamation budgets. Follow the money, right?
The third is that the industry is only a few years from declining demand for oil. Predicting oil prices has always been a mug’s game, but at the very least Alberta can expect increased volatility. At worst, fierce competition among suppliers for their slice of an ever shrinking piece of the pie results in long-term low prices and revenue, with companies scrambling to stay afloat. Reclaiming depleted wells and old infrastructure is unlikely to be at the top of the priority list.
The fourth is that there are fewer oil companies to pay for a growing inventory of liabilities. The oil bust that started in late 2014 and lasted most of the next four years pretty much wiped out the once mighty junior sector (under 10,000 barrels of oil equivalent or BOE per day) and some intermediates (10,000 to 50,000 barrels per day). More failed during the COVID-19 pandemic. This trend suggests the liabilities inventory will grow, not shrink.
The fifth is the moral hazard attached to Premier’s Smith’s RStar program. She may have defanged it for now by shunting RStar into a three-year pilot project, but the odds are better than even that it will be resurrected at some point. If that happens, then why would any oil company reclaim its liabilities if it believes the Alberta government will pay to do so sometime in the future?
Whither Alberta’s Conventional Oil and Gas Liabilities?
The situation midway in mid-2023 is that Alberta likely has somewhere between $100 billion and $130 billion of unfunded conventional oil and gas liabilities. The industry and the OWA will spend about $1 billion per year for the next five years to begin reclaiming some of the 82,635 inactive wells and a few thousand orphans. At the same time, the AER estimates there are 155,000 active wells, of which 61 per cent (about 95,000) are marginal producers making less than 10 barrels per day of oil equivalent. These wells will soon need to be reclaimed. And the industry drills several thousand new wells every year.
Based on expert interviews undertaken for this report, a best guess is that Alberta will tread water for the next five years, with the value of reclaimed liabilities (including facilities and pipelines) equaling new liabilities generated by small producers failing and future liabilities created by new drills. Even if the industry outperforms expectations, still no more than a small dent will be made in the current unfunded liabilities.
The problem is that big.
Albertans should understand that this is a strategy, a calculated gamble by the industry and the provincial government that energy transition disruption to oil and gas markets will happen closer to 2050 than 2030.
If the gamble pays off, industry has several decades to make serious progress reclaiming liabilities, including cleaning up Dwight Popowich’s old Sequoia well and tens of thousands of wells just like it scattered across Alberta. Will companies take advantage of the opportunity? Not voluntarily, as argued above.
A provincial government with a strong mandate from Albertans to fix the liabilities, however, could make the necessary changes, which might resemble the approaches suggested by the ALDP and Mark Dorin, or something else. As Dan Wicklum noted, regulatory compliance drives change in the oil and gas sector, at least for the intermediate and major operators.
This is probably Alberta’s only hope to avoid a Doomsday scenario (both environmental and financial catastrophe, as discussed in Part 1 of this series) caused by industry’s 70 years of evading responsibility for its environmental liabilities.
If the gamble fails, and prices become even more volatile between now and 2030, then worse in the next decade, the conventional side of the industry could be thrown into chaos. Companies failing left and right. Marginal producing wells shut in, meaning the inactive well count (and future unfunded liability costs) soars. At that point, producers will be focused on surviving, not cleaning up non-productive assets.
This is the recipe for the Doomsday scenario.
Energi Media’s reporting over the past decade suggests that the worst case is much more likely than the best case. If that happens, then Alberta’s gamble fails spectacularly and the consequences for Albertans are grim.
What can Alberta do today, in the short-term, to avoid the worst case?
“The first step is breaking the government’s secrecy around liabilities,” argues Drew Yewchuk. “I’m hoping the next steps will become clear once that one is finished.”
Perhaps the second step is for the province’s political, industry, and regulatory leaders to ditch the “ethical oil” narrative, acknowledge the realities of today’s liability crisis and their roles in creating it, then be frank with Albertans about the enormously risky gamble they are taking with province’s future.
Both steps need to happen in a hurry. Alberta is running out of time.