Pembina Institute: The oilsands in a carbon-constrained Canada

The collision course between overall emissions and national climate commitments

The oil and gas industry has made big contributions to Canadian society: providing jobs, technology and research excellence, while warming homes, fuelling cars and powering our electricity grids. Today, the oil and gas sector is facing unprecedented pressures. While dramatic fluctuations in the price of energy commodities are not new, increasing automation, adoption of new disruptive technologies, shifting market demands, and climate commitments are reshaping the future of this sector. Business-as-usual no longer applies — significant changes are necessary.

In a continuing effort to depolarize the conversation, this report seeks to help establish a basic, commonly agreed-upon set of facts about Alberta’s oilsands, their emissions performance and trajectories, and what Canada’s commitment to achieve deep decarbonization will mean for the sector.

Download the full report, or read the Executive Summary below.

Executive summary

Alberta’s oilsands are at a crossroads.

The oil and gas industry has made big contributions to Canadian society: providing jobs, technology and research excellence, while warming homes, fuelling cars and powering our electricity grids. Today, the oil and gas sector is facing unprecedented pressures. While dramatic fluctuations in the price of energy commodities are not new, increasing automation, adoption of new disruptive technologies, shifting market demands, and climate commitments are reshaping the future of this sector. Business-as-usual no longer applies — significant changes are necessary.

In a continuing effort to depolarize the conversation, this report seeks to help establish a basic, commonly agreed-upon set of facts about Alberta’s oilsands, their emissions performance and trajectories, and what Canada’s commitment to achieve deep decarbonization will mean for the sector.

Key points:

  • Carbon emissions from the oilsands sector are the fastest-growing source of emissions in Canada. This continuing upward trajectory not only reduces the country’s ability to meet its 2030 reduction commitments, but is on a clear collision course with Canada’s plan to become carbon-neutral by 2050. (Figure 1.)
Graph: Share of the oilsands emissions in national carbon budget to meet Canada’s 2030 targetFigure 1. Share of the oilsands emissions in national carbon budget to meet Canada’s 2030 target

  • Oilsands products are not homogeneous and there is a wide range in performance when it comes to carbon emissions intensity. As a result of variations in bitumen quality and extraction technologies, the range between the highest and lowest upstream emissions intensity per barrel is nearly threefold.
  • The oilsands industry has worked toward decreasing the emissions intensity of its products in the past decades. Continuous improvements have reduced the carbon intensity of specific oilsands products, ranging from a 4% to 21% reduction since 2009.
  • Despite these improvements in carbon intensity, absolute carbon emissions from the oilsands continue to increase overall, as growth in production outpaces gains from reductions in per-barrel intensity.
  • Studies reviewed for this report consistently find oilsands products to be more carbon intensive than lighter, conventional oil sources. Recognizing limitations of emissions intensity research and the challenge of comparing studies, the best estimate currently available suggests a barrel of oil produced in Canada is associated on average with 70% more GHG emissions than the average crude produced globally.
  • Acknowledging oil demand will not disappear overnight, most outlooks predict demand will plateau or decline within the next decade. Subsequent global shifts toward lower-intensity energy options are likely to put more carbon-intense crudes — such as the bulk of oilsands products — at risk over the next decade.
  • The rapid development and deployment of breakthrough technologies — as opposed to incremental improvements — is needed for the sector to decrease its absolute carbon emissions in line with our climate commitments, and to remain competitive as global energy systems change.

Recognizing the improvements that the oilsands industry has made to date and the commitments leading companies have announced to achieve ambitious targets in the future, there is still a need for the sector to embrace its responsibility to reduce overall carbon emissions in accordance with Canada’s 2030 and 2050 targets.

The Pembina Institute calls for both the Alberta and federal government to recognize the willingness of leading companies to adopt aggressive decarbonization targets, as well as mounting investor pressure to decarbonize the sector, and implement policies that will drive toward carbon-neutral — or even carbon-negative — oilsands production.

It’s time to have a national conversation about how to reconcile oilsands emissions with Canada’s goal to decarbonize its economy by 2050. The intention of this report, carefully and explicitly supported by available evidence and research, is to further fact-based dialogue, as we all embark on this tough, but necessary Canadian conversation.

Recommendations to improve oilsands climate performance

1. Establish strong regulations to decarbonize the industry

Intentional effort is required to encourage a shift toward low- and zero-carbon production, by creating strong incentives for the development and deployment of breakthrough innovation. Recognizing the willingness of leading companies to adopt aggressive decarbonization targets, as well as mounting investor pressure to decarbonize the sector, governments need to implement policies that will drive carbon-neutral — or even carbon-negative — oilsands production.

2. Define and enforce sector emissions targets for 2030 and 2050, with five-year increments

Meeting our 2030 and 2050 climate targets will require all sectors of our economy — and all Canadians — to do their fair share to contribute to the global effort of limiting the average temperature increase to 1.5°C. Decreasing GHG emissions reduction targets need to be set for the oil and gas sector, in five-year increments that would allow Canada to meet its 2030 national objective and its pledge to become a net-zero carbon emitter by 2050.

3. Support an innovation ecosystem to deliver breakthrough technologies

A robust ecosystem to support innovation, research and development, needs to be funded and fostered so it can deploy solutions aimed at delivering breakthrough reductions — beyond incremental improvements — in emissions of current oilsands projects, as well as non-combustion uses of Alberta’s oil and gas resources.

4. Improve emissions monitoring and reporting

Existing measurement, monitoring and reporting processes for oilsands emissions must be reviewed, strengthened and standardized in order to produce coherent data and enhance the transparency of the sector. As well, further analysis looking at existing and upcoming technology pathways is required to better situate oilsands products’ carbon intensity on the global supply curve.

5. Appoint credible and effective energy regulators

Effective energy regulators are needed both provincially and federally. They must be transparent and independent, with the ability to incorporate robust environmental and climate considerations into their decision-making, while having both the mandate to enforce regulations and the capacity to follow through on that enforcement. SOURCE

Study finds federal regulations for methane more effective than Alberta’s, but both can improve

New research compares 2 plans as Alberta and Ottawa negotiate agreement on rules for oil and gas industry

A pumpjack works at a wellhead on an oil and gas installation near Cremona, Alta. Both the federal and Alberta governments have proposed regulations that will reduce methane from oil and gas extraction. (Jeff McIntosh/The Canadian Press)

new study suggests that the federal government’s proposed regulations to reduce methane emissions, a potent greenhouse gas emitted by the oil and gas industry, would be more effective than competing regulations proposed by the Alberta government.

But there’s room for improvement for both, and a question mark over whether either set of regulations would meet Canada’s methane reduction targets.

The goal is to reduce methane emissions from the oil and gas industry by 40-45 per cent from 2012 levels by 2025. The goal stems from a leaders summit in 2016, when Mexico, the U.S. and Canada agreed to these methane reductions. The goal has now been incorporated into Canada’s official climate plan, the Pan-Canadian Framework.

“Absolutely that kind of methane reduction is achievable,” said Matthew Johnson, an engineering professor at Carleton University who is a leading expert on emissions in Canada’s energy sector.

“We would say that the federal government [proposal] will just meet that target. Are there things in here you could do to improve both regulations? Hundred per cent. Neither regulation is perfect.”

Matthew Johnson, a professor at Carleton University, is a leading expert on emissions from Canada’s energy sector. (Mike Pinder/Carleton University)

 

Alberta and the federal government are currently in equivalency negotiations to decide which methane regulations will go into effect. Under the law, Alberta’s regulations would apply if they are found to be as or more effective than the federal regulations. The negotiations are meant to determine if the provincial regulations are equivalent to the federal ones.

Both have proposed regulations aimed at reducing leaks of methane from conventional oil and gas facilities, through a swath of new requirements that target everything from how the facilities are run, how often they are inspected, the equipment they use and how methane leaks are detected.

There are leaks of methane throughout the extraction of oil and gas, from the wellheads, through pipelines and pumps to delivery to market.

Johnson’s analysis found that the federal government’s regulations would achieve net reductions of 40 per cent — just reaching the lower end of the goal — while Alberta’s regulations would be behind at 35 per cent reduction.

Methane gas is 25 times more potent than carbon dioxide as a greenhouse gas, and accounts for 15 per cent of Canada’s total greenhouse gas emissions, according to Environment and Climate Change Canada (ECCC). Reducing it is a key part of Canada’s climate change plan, and a major policy directed toward reducing emissions from the oil and gas sector.

But the methane regulations don’t apply to a significant part of that industry — Alberta’s oilsands mines. The oilsands are a completely different mining operation than upstream oil and gas facilities, and account for about 19 per cent of Alberta’s methane emissions. The current regulations are focused on the other sources of emissions, for which a clearer path to reduction exists.

Johnson’s study pointed out that even without any new regulations, methane emissions from sources that are not oilsands mines have fallen from 2012 to 2018.

In contrast, emissions from oilsands mines have gone up. If emissions from the oilsands keep rising, it could cancel out any reductions from the new methane regulations.

“So which trend wins? If that oilsands trend increases faster than any additional non-regulation reductions at the top, then those targets are in jeopardy,” Johnson said.

The Alberta Energy Regulator and the federal ECCC, the departments that crafted the methane regulations, did not comment directly on Johnson’s paper. ECCC said the process of working toward an equivalency agreement requires comparing the “environmental outcomes” between the federal and provincial proposals.

“ECCC is always open to working with interested jurisdictions, including Alberta, toward equivalency agreements,” said an ECCC spokesperson in an emailed statement.

Johnson’s paper suggests several options for Alberta’s regulations to be tweaked to reach, or even exceed, the methane reduction targets. He said he hopes that the analysis in his paper can be used to improve the regulations in the next few years.

“Methane is not a solved problem. Not even close. And these regulations aren’t final, and I think that the regulators will tell you they’re not final,” Johnson said. SOURCE

“To my understanding, there’s an intent for both the federal government and the provincial government to revisit these regulations, and look for opportunities to improve or adjust as things change in the near term.”

Crude price plummet raises spectre of spending cuts, job losses in Canadian oilpatch

‘This is one of the biggest shocks we’ve seen in the last 40 years,’ analyst says

The downturn in oil prices hammered Canadian energy stocks on Monday, with the S&P/TSX capped energy index down more than 27 per cent. (Larry MacDougal/The Canadian Press)

Plunging oil prices landed with a giant thud in Canada on Monday, sending tremors across the oilpatch and raising the spectre of spending cuts, production cuts and job cuts.

The collapse was triggered by a severe double whammy — fears the spread of COVID-19 could trigger a global recession and an oil price war between Saudi Arabia and Russia.

The immediate consequences were grim.

The benchmark price for North American oil, West Texas Intermediate, initially fell by the most in one day since the 1991 Gulf War, before eventually settling at $31.13 US per barrel, down $10.15 US, on Monday.

“This is one of the biggest shocks that we’ve seen in the last 40 years,” Jeremy McCrea, an analyst with Raymond James, said early Monday.

The global benchmark, Brent crude, closed down 24 per cent at $34.36 US a barrel.

Canadian energy stocks were also hammered, with the S&P/TSX capped energy index down more than 27 per cent.

Now, the country’s oil and gas sector — like others worldwide — is weighing the fallout and trying to assess the potential repercussions if prices stay this low for months to come.

The energy sector accounts for more than 11 per cent of Canada’s gross domestic product.

WATCH: Drop in oil prices another blow for Alberta ​​​​​​:

Alberta’s struggling economy was dealt a devastating blow with a major drop in oil prices on Monday. 1:48

 

Market watchers have already warned that the most vulnerable companies will be those carrying too much debt, have high operating costs and limited access to funding.

McCrea said the situation will be a test of companies’ financial health.

“The question is who has …  the staying power and the balance sheets to make it through this disagreement that those countries have,” McCrea said.

In the near term, he expects companies could reduce their capital spending plans by 30 to 40 per cent. Oil production could also come down very quickly.

It’s unwelcome news for an oil and gas sector that has had its share of struggles in recent years, whether its pipeline bottlenecks or a glut of crude that spurred Alberta to curtail oil production in the province.

Further decreases in Canadian production might actually relieve some pressure on the pipeline network. But Monday’s news won’t ease current anxiety around the oilpatch, still stinging from thousands of jobs losses in recent years.

Alberta Premier Jason Kenney said Monday that his government’s priority would be protecting jobs and the economy.

But when crude prices drop and stay low, oil companies feel the financial squeeze. For some companies, the pressure point might be $45 US a barrel. For others, it could be in the $30s.

“The Canadian sector really starts to feel the pain under $40 a barrel,” said Peter Tertzakian, executive director of the ARC Energy Research Institute in Calgary.

“But, I emphasize, it’s not just Canadian oil and gas companies. This is a global industry.”

Specialist Glenn Carell, right, works on the floor of the New York Stock Exchange, Monday. Stocks went into a steep slide Monday on Wall Street as coronavirus fears and a crash in oil prices spread alarm through the market, triggering the first automatic trading halt in over two decades. (Richard Drew/Associated Press)

 

Indeed, some commentators see the new price war as a way to target U.S. shale oil producers, which are already facing greater investor scrutiny after spending big on aggressive growth in recent years.

Canada’s oilpatch, on the other hand, enters the fray leaner, more efficient and innovative than five years ago when oil prices hit the skids. In many ways, the Canadian sector is “battle hardened,” Tertzakian said.

“We, here, have really been innovating quite significantly, on average, and are better positioned than we were in 2014 to weather this,” he said. “But that’s not to say that under $40 is going to be easy to take.”

The most important, and most difficult, question to answer is how long will this situation last.

When it comes to the dispute between Russia and Saudi Arabia, at least there’s some history to lean on.

Tertzakian said price wars — regardless of the industries involved — have four phases: the declaration of war, the weeding out of high-cost participants, capitulation and, finally, a return to normal pricing.

“Every company is different, but under $40, we see certainly a lot of a lot of strain,” said Peter Tertzakian, executive director of the ARC Energy Research Institute in Calgary. (Monty Kruger/CBC)

 

He doesn’t expect either side to surrender for probably a quarter or two, but no one can know for sure.

Reuters reported the world’s top two oil exporters each have war chests of around $500 billion to weather economic shocks and are making bullish noises about their stamina as they square up.

Moscow said on Monday it could withstand oil prices of  $25-$30 US per barrel for 6-10 years. Riyadh, meanwhile, can afford oil at $30 US a barrel, but would have to sell more crude to soften the hit to its revenue, according to Reuters sources familiar with the matter.

The impact of the coronavirus might even be more difficult to predict, with stresses on the health-care system, consumer behaviour, trade and the global economy. All those things will affect oil consumption, as demonstrated by the steep drop in oil demand in China so far.

The International Energy Agency said this week that it expects global demand to drop this year for the first time since the financial crisis in 2008/2009.

As Alberta’s premier, Kenney, said Monday, “We are in uncharted territory.” SOURCE

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If Teck offered lessons, it’s not clear Alberta is learning them

Alberta Finance Minister Travis Toews insists the federal government is mainly to blame for the cancellation of the Teck Resources oilsands project.

By the time the Frontier mega-mine proposal died a swift and unexpected death last week, the proposal had taken on a national significance that dwarfed even the 29,000 acres of forest and wetland it sought to take over.

To Alberta’s United Conservative government, its approval would indicate whether Prime Minster Justin Trudeau really supported the oilsands. To environmentalists, it was a scourge.

But to Teck Resources, the Vancouver-based company behind it, it was a chance to balance oilsands development with environmental rigour, in a project they believe should have satisfied both sides. But, they argued in their letter to the federal environment minister, Canadian regulations have not caught up.

Global markets are changing fast, Don Lindsay, CEO of Teck, wrote in the letter last weekend.

“Investors and customers are increasingly looking for jurisdictions to have a framework in place that reconciles resource development and climate change,” he said.

“This does not yet exist here today.”

But if it’s true that oilsands projects are now forever tangled up in the climate change debate, observers say Alberta isn’t learning that lesson.

Mike Holden, the vice-president of policy and chief economist of the Business Council of Alberta, said he was surprised that the provincial budget had lots of plans for what they hope is a coming upswing in the oil industry, but almost nothing to say about climate change.

“I think that there was an opportunity that the province could have taken to spell out a climate strategy that could have helped with investor confidence, that could have helped with sending a message to the federal government that it was serious about working in this area, and it didn’t do that,” he said.

“That’s not to say that it might not at some point down the road, but it was fairly silent.”

The budget has one reference to the global challenge that is climate change, and notes that Alberta’s “global leadership in clean energy and (greenhouse gas reducing) technologies is also key to investment attraction.”

It also includes their TIER, or Technology Innovation and Emissions Reduction, program, which places a $30 per tonne tax on large emitters. According to the budget, it will put $969 million into climate technology and emission reduction over 3 years.

Despite Teck’s lengthy letter, Alberta government officials don’t believe that the Teck cited the real reason for cancelling the project.

When asked about Teck’s decision in advance of the budget being tabled Thursday, Finance Minister Travis Toews cast the blame east.

“We have a federal government who didn’t categorically affirm its support for a project that’s gone through in every environmental hurdle put in front of them,” Toews said.

“The fact that the goal posts were seemingly, potentially to be adjusted at the last minute has a profound effect.”

In this, Toews echoed Alberta Premier Jason Kenney, who has put the blame for the cancellation at the feet of rail blockade protesters across the country who have been affecting transportation for nearly three weeks, as well as federal inaction.

On Monday, Kenney said “there is absolutely no doubt” that the blame for the decision lies with the federal government and called for action from Ottawa to restore investor confidence in the province.

But Chris Severson-Baker, the Alberta regional director of the Pembina Institute, says sound climate policy is a major way to attract investors. It’s possible to pursue climate goals while still investing in oil development, he said, but there should be incentives for projects or types of development that are lower in carbon.

He said he was disappointed to see little talk of climate in the new budget, especially as the current federal government plans for Canada to be carbon-neutral by 2050.

He points to the oil industry leaders who have publicly supported a carbon tax. He says that many in the industry realize that many big oil projects now have to prove their green bonafides to get approval.

“Until this is resolved, it’s going to be a barrier to make further investments in Canada and in Alberta,” said Severson-Baker. SOURCE

$500M investment means construction to start on Canada’s largest solar farm this year

Travers Solar project will be built in southern Alberta

The Travers Solar project in southern Alberta just secured a $500-million investment. When complete, it’ll be the largest solar farm in Canada. (Susan Montoya Bryan/The Associated Press)

Construction of what will be Canada’s largest solar farm will soon start in southern Alberta after the project secured a major funding partner.

Greengate Power announced Monday that the Travers Solar project in Vulcan County will receive $500 million in funding from Denmark-based Copenhagen Infrastructure Partners.

Construction is set to start midway through this year and will finish in 2021.

Greengate Power president and CEO Dan Balaban said the investment demonstrates investor confidence in Alberta’s renewable energy market.

“It’s a $500-million foreign investment in Alberta, and at a time where we’re talking about the flight of capital from Alberta … this is an example that demonstrates Alberta is still a very attractive place to invest.

“It’ll create more than 500 jobs during construction, provide an ongoing income stream for landowners that are participating in the project, and a really substantial form of annual municipal taxes that’ll be realized for Vulcan County,” he said.

The project will consist of 1.5 million solar panels that will generate about 800 million kWh per year, enough to power more than 100,000 homes.

“To put that in perspective, that’s about the size of a third of the island in Manhattan. So it’s a large project that will have the ability to make a very substantial positive impact on our economy and our environmental performance,” Balaban said.

Greengate is also responsible for the largest wind energy project in the country, also located in Vulcan County.

Balaban said he sees renewables as the obvious solution as the province looks to phase out coal. But, he doesn’t think supporting green energy should contribute in any way to political polarization.

“As long as the world is using oil and gas, I believe it should be Alberta oil and gas but at the same time, we should be investing in the way the energy system is heading. We’ve got phenomenal renewable energy resources in this province and a great opportunity to diversify our economy,” he said.

Copenhagen Infrastructure Partners said in an emailed release that the investment is the fund management company’s first in Canada.

“Alberta is an attractive market for investment, and we look forward to working with Greengate, one of Canada’s leading renewable energy developers, to bring Travers Solar online,” CIP senior partner Christian Skakkebaek said.  SOURCE

Alberta’s looming multibillion-dollar orphan wells problem prompts auditor general probe

There are 3,406 deserted oil and gas wells in the province, with growing concern about more joining the list

This oil well near Two Hills, Alta., has been inactive since 2012, and its owner, Sequoia Resources, ceased operations in 2018. Dwight Popowich, who owns the land, wonders who will clean it up. (Kyle Bakx/CBC)

As Alberta struggles to clean up thousands of oil and gas wells left behind by bankrupt companies, the province’s auditor general is set to investigate how the problem became so big and why the industry regulator’s efforts to collect security deposits came up so short, CBC News has learned.

Often referred to as orphan wells, there are currently 3,406 such wells scattered around the province, usually on the properties of rural landowners, where they lie untended.

There are another 94,000 inactive wells in the province, with the worry that many of these may become orphaned as their owners struggle — and taxpayers could be left with the bill.

The auditor general’s office will look at whether the province is doing enough to prevent wells from becoming orphaned in the first place, and whether it is prepared for more to be added to the list due to ongoing pressure on Alberta’s energy economy.

“We will be focusing on both whether the government — and specifically the Alberta Energy Regulator — has the systems and processes to assess whether orphan oil and gas sites are being managed and reclaimed efficiently and economically in the best interests of Albertans,” said Val Mellesmoen, spokesperson for the Office of the Auditor General of Alberta.

The Alberta Energy Regulator (AER), an arm’s-length agency of the provincial government that oversees the energy industry and its activities, has a liability management system that is supposed to make sure companies that are permitted to drill have a healthy enough bottom line to pay for cleanup later on.

Val Mellesmoen, spokesperson for the Office of the Auditor General of Alberta, says they are set to review the orphan wells issue. (CBC)

If a company’s estimated assets fall below the cost of its environmental liabilities, the AER can collect and hold what’s effectively a security deposit to make sure there’s money on hand for cleanup if the company later walks away from the well.

But the regulator has been using a formula based on out-of-date commodity prices that has inflated the assets of many companies. As a result, companies were not asked to put down large enough security deposits for future cleanup.

The province’s own estimate of the eventual cleanup bill for every oil and gas well in Alberta is $30 billion, while the AER only holds $227 million in financial security.

“The promise of this production was that companies would clean up their mess,” said Nikki Way, a senior analyst at the Pembina Institute, a clean energy think-tank based in Calgary.

“I’m disappointed that we’re at the point where the ‘polluter pays’ principle is not being upheld and we’re considering cleaning up a bill that was always supposed to be accounted for.”

Alberta has asked the federal government to help pay for cleaning up orphan wells. In a November 2019 letter sent by Alberta Finance Minister Travis Toews to Bill Morneau, his federal counterpart, the province asked Ottawa for funding and tax instruments to encourage investment in well reclamation.

“This system is just not sustainable,” said Lucija Muehlenbachs, an economist at the University of Calgary who specializes in the energy industry.

“It’s not functioning, so it will have to be completely thrown out the window. But it’s many years too late.”

 

The AER uses a liability management rating, or LMR, to determine whether a company has enough money to clean up its wells down the line. If the company’s estimated assets — calculated based on the amount of resources in its wells — are less than the estimated cost of cleaning up the wells, the company has to pay a security deposit.

But the AER has been using commodity prices from 2008-2010, back when oil prices were much higher, to estimate the value of assets. Even though the regulator assesses these assets every month, because of its use of old commodity prices, many companies that should be putting up security deposits have not had to.

And simply adjusting the calculation now to account for current prices isn’t an easy fix, according to the AER, because it could force struggling companies into bankruptcy.

“In many cases, this would have negative consequences for those already facing financial difficulties, and increases the risk that end-of-life obligations would not be addressed,” AER spokesperson Shawn Roth said in an email.

Landowners left in the lurch

Meanwhile, landowners who agreed to lease their land to oil companies so they could drill wells were promised the companies would clean up after the wells were done producing and restore the surface of the land to its original state.

Instead, many are left with inactive wells that nobody is monitoring, let alone cleaning up and closing.

Dwight Popowich has been left in limbo and unable to sell his land while it has an inactive well left behind by a company that ceased operations in 2018. (Kyle Bakx/CBC)

Dwight Popowich has an oil well on his property near Two Hills, Alta., about 100 kilometres east of Edmonton, that was drilled in 2008. It stopped producing in 2012, and its owner, Sequoia Resources Corp., stopped operating in March 2018. No remediation work has been done on the well.

Popowich is waiting for the well to be transferred to the Orphan Well Association, which is an industry- and government-supported group that is trying to manage orphan wells. But, in the meantime, no one is monitoring the well on his property.

“We don’t know if it’s safe. We don’t know if it’s leaking. Nobody’s showing up to even take a look at it,” Popowich said.

Sequoia held licences for 2,300 wells when it ceased operations in 2018.

For Popowich, the well has become a financial headache in addition to an environmental problem. He wanted to subdivide his land and sell off half of it to help pay for his retirement. But the well is in the way.

“Nobody wants to buy the land if they have to deal with a well that’s in limbo,” he said.

A better way

Across the border in North Dakota, as oil prices declined, the state saw a growing number of inactive wells, but it has not experienced the same problem with orphan wells as Alberta.

North Dakota has strict timelines in place to deal with inactive wells. If a well stops producing for as little as three months, it’s immediately flagged. The state also collects a bond from companies upfront — $50,000 US if the company is drilling one well — and can use that money to pay for plugging and remediating wells.

North Dakota, which is the second largest crude oil producer in the U.S. after Texas, has only 1,683 inactive wells — and not one of them is an orphan.

The head of North Dakota’s regulator says a combination of a bond system and plugging and reclamation fund is essential for preventing orphan wells.

“You’ve got to start somewhere,” said Lynn Helms, director of the North Dakota Department of Mineral Resources.

Alberta, on the other hand, does not have any timeline for how long a company can leave a well inactive. This has raised concerns that many of the approximately 94,000 inactive wells in Alberta may become orphaned before their owners clean them up.

Looking ahead

Alberta’s industry knows the liability management system needs to change, and the AER and provincial government have said they are reviewing the program. The AER says a new system would gather more company-specific information to gain a more holistic view of whether a company can meet its environmental obligations.

But the government and regulator have to tread lightly on an industry that’s struggling.

Inactive wells that are not properly plugged and cleaned up could leak contaminants into the soil and air. (Kyle Bakx/CBC)

“We want to see progress on the file, but you have to manage the unintended consequences,” said Brad Herald, vice-president of Western Canada operations for the Canadian Association of Petroleum Producers.

“You don’t want to create more defaults. There are a lot of companies struggling. We are empathetic to that.”

Nikki Way of the Pembina Institute says concerns over low oil prices should not stop the government from taking action now. New wells can be treated differently, with more financial security collected prior to drilling.

She points out that while the government has to balance the profitability of the industry with any new regulations, the liability problem will continue to grow if nothing is done.

“The pressures aren’t going away any time soon,” she said. “So the scope of the problem needs to be front and centre and transparent.” SOURCE

 

Just Transition: Can oil and gas workers adapt to a green energy future?

There were times when I was taking home about $3,500 a week.” That was in the oil sands, during the boom before 2014. Lliam Hildebrand was a young welder who had come to the Athabasca oil sands for work.

Before that, the Victoria, BC, native spent his first eight years after high school in heavy machinery repair and steel fabrication, often on oil field equipment such as flare stacks and rig platforms. He says serving the oil field’s needs was “the bread and butter” of his work, with an occasional job building renewable-energy equipment such as parts for a biofuel facility.

“I really loved that job,” he says, but opportunities in the North called and he spent the next half dozen years in the oil sands, doing similar work, primarily during spring and autumn, when sites get set up and stripped down. He found it exciting, interesting—and lucrative.

Then came the downturn. As international market forces sent the price of Western Canada Select plummeting from close to $100 per barrel to at times less than $20, oil sands operations struggled to survive, especially as the break-even price for many operations was as high as $80 per barrel. The opportunities that brought thousands like Lliam north evaporated.

“It was crazy,” he says. “Every single day in the lunchroom we were having conversations about who was getting laid off… and when would we be laid off?”

Worldwide, the price crash saw more than 440,000 petroleum jobs disappear. Bloomberg UBS predicts that between a third and as many as half of those 440,000 jobs will never return. In Canada 46,000 oil and gas workers were laid off, mostly in Alberta. Pipeline purgatory and the spectre of fossil fuels’ decline dominate public and political rhetoric on the subject.

What hasn’t been at the forefront is talk of an escape plan for tens of thousands of oil workers. In the past, when industries from carriage makers to cod fishers suddenly crumbled, workers were abandoned. Now the hope is for a “just transition.” The concept of just transition holds that when an industry or sector declines, particularly if that decline is mandated by government policy, the workforce is entitled to planned support to move people to new gainful employment, ideally in their own community.

In theory it’s a grand concept and one of the best ways to gain support for climate change policies from the affected workforce. In practice, “just transitions” have had mixed results.

Alberta and Canada had a practice run in coal. Canada’s coal phase-out got its start in 2012 when the Harper government imposed emissions limits for coal-fired power plants that effectively guaranteed their shutdown. Technological solutions that would sufficiently lower emissions at these generators weren’t cost-effective, especially in the face of coal’s declining competitiveness worldwide.

Alberta followed suit in late 2015 when the Notley government announced similar limitations as part of its Climate Leadership Plan and soon after mandated that at least 30 per cent of Alberta’s electricity grid be powered by renewable energy by 2030. At the time, coal fed over half of the province’s electricity needs, and its production here was greater than all other provinces’ combined. Coal directly supported roughly 3,150 jobs in Alberta, mostly in mining and processing rather than plant operations. Coal workers include engineers, welders, mechanics, electricians, heavy equipment operators and maintenance staff. The economies of some 20 communities were tied tightly to the industry.

Pipeline purgatory and the spectre of fossil fuels’ decline dominate public and political rhetoric.

Hanna is one of those coal towns, and perhaps the poster child for the phase-out thanks to its vocal mayor, Chris Warwick, and the town’s concerted efforts to meet the phase-out head on.

Hanna’s population is 2,500, 210 of whom work in the nearby Sheerness coal mine and power plant. The mine operations prop up the town’s economy, inflating incomes above what would be expected in a remote farming community, allowing business and public services to thrive where they likely wouldn’t otherwise.

While Warwick’s efforts have focused on the town’s economic transition, councillor Connie Deadlock devotes her time to the workforce. “There have been a lot of conversations about just transition from the provincial and federal governments, as well as everyone else,” she says. The mine and the power plant are still operating, but the town is already affected by the inevitable changes, and residents are anxious.

“Not only do we have to worry about the direct job losses, there is no other industry, so many people and families will have to relocate,” Deadlock says. “Housing prices have already been declining, our schools are affected, our businesses, and the list goes on and on.”

She says that because the power plant will convert to run on natural gas, not everyone will lose their jobs, but the new operation will require far fewer employees.

Immediately after the phase-out announcement in 2015, Hanna’s leaders scrambled to find a way not only to keep the town alive but to maintain its quality of life. They contracted Calgary’s Urban Systems to make an analysis of the town’s predicament and attributes and outline a path forward. The resulting Cactus Corridor Economic Opportunities Report has good news and bad for the little town.

“Be realistic,” it recommends. “Living in a community/region can make one unrealistic about its potential.” Also, expect some decline, because “it’s unlikely high wage primary industry jobs can be replaced. If workers in these industries want to stay in the community, they may have to accept a reduction in income and work with less status.” Don’t rely on ongoing subsidies or bailouts, it adds; don’t look for a panacea; establish a sense of urgency.

Coupled with the phase-out, Hanna, like many coal communities, is also rural. It is already subject to the pressures of rural decline, making it even harder to replace coal in its economy.

Hanna does have some business opportunities. Urban Systems points out it has some of the best solar power potential in the country, and likely good wind power possibilities too. As a farming community, it is surrounded by arable land and a fair water supply.

Government hasn’t abandoned Hanna and other coal towns, either. In addition to setting an end date for coal, the NDP government had the foresight to consider the transition—especially important given the phase-out only had 50 per cent public support province-wide. The government wanted widespread support as it made major changes to the way Alberta dealt with climate change issues.

The provincial government gave Hanna $450,000 to set up community action teams and help establish an economic plan. Unfortunately, Hanna was left off the list when the government committed funding at the end of 2018 for the municipal training centres many people say are integral to a successful labour transition.

“Our community has so many ideas for business and expansion, but no funds to bring them to fruition,” says Deadlock. “The employees at the mine don’t feel they will benefit very much from any programs that are offered. There needs to be some significant changes.”

Disconnect between what workers say they need and what the transition programs actually offer is a pervasive problem in Canada’s just transition efforts for the coal industry. “The most requested thing is for the government to offer training and other programs while people are still employed, [but] none of the programs are a benefit while still working,” says Deadlock. “Employees feel that if they could do some upgrading, training or education while still working and having an income, they would have a better chance.”

In response to how initial transition programs were designed, Jamie Kirkpatrick of Blue Green Canada says, “I think that was stupid.” Blue Green is a collaboration of labour unions and civil and environmental groups that has spent the past 10 years advocating for workers affected by environmental issues. It has primarily focused on the fate of Canada’s coal workers as coal-fired electricity comes to an end. Kirkpatrick says requiring workers to lose their jobs before they can begin retraining for a new career sets them back from the start. He and Deadlock agree the reason transition programs often don’t resonate with labour is because many of the plans were made without on-the-ground consultation.

“You actually learn more talking to people who are going to be affected by this than telling them what’s going to happen,” Kirkpatrick says.

Governments issuing decrees rather than including affected groups in the decision-making has been a major sticking point among workers and labour unions throughout the phase-out, seriously eroding any support the decision may have garnered from those most immediately affected by it.  MORE

‘No excitement at all’ as oilpatch interest wanes for drilling rights auctions

Sales of Crown drilling rights have fallen off dramatically in Western Canada this year.


In Alberta, twice monthly auctions are on track for a record low with two sales left to go in 2019. (Larry MacDougal/The Canadian Press)

A key indicator of future oil and gas drilling activity in Western Canada is sliding lower as the industry deals with a lack of pipeline capacity, Alberta oil production curtailments and difficulty accessing capital markets.

Sales of Crown drilling rights — needed to allow energy exploration on land where mineral rights are held by the province — have fallen off dramatically in B.C., Alberta and Saskatchewan this year.

“When drilling rights are going well, it tends to mean somebody has found either a good reservoir or a good way to produce a known reservoir and so you get a lot of excitement,” said Richard Masson, an executive fellow with the School of Public Policy at the University of Calgary.

“This says to me, there’s no excitement at all right now. People are doing little bits of infill land buying but there’s nothing that looks like a very prospective play that would excite the industry and excite new capital to come in.”

In Alberta, which produces about 80 per cent of Canada’s oil and about 70 per cent of its natural gas, twice monthly auctions are on track for a record low with two sales left to go in 2019. Through 11 months, the province has raised $100 million by selling rights on 616,000 hectares.

The current low mark was set in 2016, when $137 million was paid for the rights to drill on 937,000 hectares, the lowest since the auction system was adopted in 1977.

The high was in 2011, when a bidding frenzy for lands for the Duvernay underground oil-bearing formation resulted in $3.5 billion spent to buy rights on 4.1 million hectares.

…Industry insiders say the declines are mainly due to the lack of new pipeline capacity to allow more oil and gas production, and the resulting loss of confidence by investors that has starved the sector of debt and equity funding. Production limits in Alberta imposed by the government to better align supply with pipeline capacity are another overhang on activity. MORE

Flood of Oil Is Coming, Complicating Efforts to Fight Global Warming

A Norwegian oil platform in the North Sea. Norway’s production has declined for two decades, but its development of the Johan Sverdrup deepwater field should reverse the trend.
Credit: Nerijus Adomaitis/Reuters

HOUSTON — A surge of oil production is coming, whether the world needs it or not.

The flood of crude will arrive even as concerns about climate change are growing and worldwide oil demand is slowing. And it is not coming from the usual producers, but from Brazil, Canada, Norway and Guyana — countries that are either not known for oil or whose production has been lackluster in recent years.

This looming new supply may be a key reason Saudi Arabia’s giant oil producer, Aramco, pushed ahead on Sunday with plans for what could be the world’s largest initial stock offering ever.

Together, the four countries stand to add nearly a million barrels a day to the market in 2020 and nearly a million more in 2021, on top of the current world crude output of 80 million barrels a day. That boost in production, along with global efforts to lower emissions, will almost certainly push oil prices down.

Lower prices could prove damaging for Aramco and many other oil companies, reducing profits and limiting new exploration and drilling, while also reshaping the politics of the nations that rely on oil income.

Canada, Norway, Brazil and Guyana are all relatively stable at a time of turbulence for traditional producers like Venezuela and Libya and tensions between Saudi Arabia and Iran. Their oil riches should undercut efforts by the Organization of the Petroleum Exporting Countries and Russia to support prices with cuts in production and give American and other Western policymakers an added cushion in case there are renewed attacks on oil tankers or processing facilities in the Persian Gulf.

Daniel Yergin, the energy historian who wrote “The Prize: The Epic Quest for Oil, Power and Money,” compared the impact of the new production to the advent of the shale oil boom in Texas and North Dakota a decade ago.

“Since all four of these countries are largely insulated from traditional geopolitical turmoil, they will add to global energy security,” Mr. Yergin said. But he also predicted that as with shale, the incremental supply gain, combined with a sluggish world economy, could drive prices lower. MORE

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Cenovus Energy to add 70,000 barrels per day of oilsands output


Rail cars wait for pickup in Winnipeg on March 23, 2014. The Alberta government is easing production limits on oil companies that ship their product by rail. File photo by The Canadian Press/John Woods

Cenovus Energy Inc. says it will add as much as 70,000 barrels per day of oilsands output following the Alberta government’s decision to ease production curtailments for producers that add crude-by-rail capacity.

The company can quickly add 10,000 to 20,000 bpd of raw bitumen output from its Christina Lake and Foster Creek northeastern Alberta thermal oilsands projects, said CEO Alex Pourbaix during a conference call Thursday morning after the decision was announced.

Meanwhile, it plans to begin startup procedures on its $675-million, 50,000-barrel-per-day Christina Lake phase G oilsands expansion project with production expected within six to 12 months.

Construction of the expansion was completed earlier this year but commissioning was put on hold until market access questions were answered.

“We think it’s a great way to incent further rail takeway capacity out of Alberta and we applaud the government for moving forward with this initiative,” said Pourbaix.

He added the move doesn’t remove the necessity of building more oil export pipelines.

Under the previous NDP government, Alberta put a cap on the amount of oil the industry can produce starting in January as a way to narrow local price discounts that grew as oil production exceeded the ability of pipelines to get the crude to market.

The measure was continued by the United Conservative government when it was elected last spring. The total industry quota is to increase to 3.81 million barrels per day in December, up 250,000 bpd from the original limit of 3.56 million barrels a day.

“Overall, we believe this program will be an important addition to the efforts to increase market access,” said Energy Minister Sonya Savage on Thursday.

“Looking ahead, maximizing the amount of crude shipped by rail is an important factor in moving forward towards an orderly exit out of curtailment altogether, which, under the enhanced policy, is scheduled to be concluded by the end of December 2020.”

Alberta currently ships around 310,000 barrels per day on rail, she said, but the rail system has the capacity for daily shipments of 500,000 to 600,000 barrels.

The new program is to be available as of Dec. 1 and operators will need to apply on a monthly basis and verify their rail shipments.

The province is still working on a plan to divest railcar contracts signed by the NDP government, Savage said.  MORE