Far from the giddy days following the Paris Agreement, Canada’s carbon tax has recently run into strong headwinds — despite recent polling that shows a majority of the public is on board.

The tax is set to come into effect in January, but Ontario’s newly minted premier, Doug Ford, is hard at work pulling the province out of its cap-and-trade system; meanwhile, Jason Kenney is looking likely to win the Alberta election next year and is promising to axe Alberta’s carbon tax.

Saskatchewan premier Scott Moe is staunchly opposing any carbon tax in his province.* U.S. President Donald Trump is running as fast as he can in the opposite direction from climate action, promoting the coal industry while mocking alternatives.

In the face of these political headwinds, earlier this month the federal Liberal government proposed to scale back its own commitment to taxing carbon — in the name of protecting international competitiveness for heavy-emitting industries.

What had been a plan to tax 30 per cent of emissions is being rolled back to just 20 per cent for most large emitters. This will mean less incentive for companies to invest in efficient technologies and processes, and less reward for companies that are already ahead of the curve.

It almost certainly means more carbon will be emitted, and that Canada’s climate goals, committed to under the Paris Accord, will be that much harder to meet.

“Clearly, competitiveness concerns are re-permeating through every policy conversation these days, and they have been doing so for a little while,” Isabelle Turcotte, interim director of federal policy at the Pembina Institute, a sustainable energy policy think tank, told The Narwhal.

“The government was somewhat overly cautious here… and [has] given a little more relief than it needed to really mitigate these risks.”

Canada’s carbon tax a moving target

Central to the new scheme is a system designed to limit the negative impacts on industries that by their nature emit lots of greenhouse gases, such as the oil and gas industry, cement manufacturers or steel mills.

The way this system — the so-called “output-based pricing system” — will work is somewhat more complex than a simple tax on emissions.

First, the government will determine the national average emissions intensity for an industry — so the amount of carbon produced per unit of production (say, a barrel of oil).

Next, it will set a target level lower than that average.

In its draft regulations in January, the government set the level at 70 per cent of the average emissions for most industries. Finally, the tax will be applied to any emissions that go above that target.

What the government is now proposing is to increase that baseline target — giving industrial sectors more room to pollute without being taxed.

Imagine three steel producers. One, Company A, is emitting 30 kilograms of CO2 for every load of steel it sells. Company B is much less efficient; it produces 60. Company C is slightly less efficient than Company A, and right on the target set by the government. Under the proposed rules, Company B would be taxed on its carbon emissions over the target, while Company A would be generating credits that it could sell to Company B. All three have an incentive to reduce their emissions, but only Company B will be paying carbon taxes.

The carbon tax plan also sets targets within — rather than across — industries. That means less carbon-intensive industries won’t benefit as much as they would if they were compared directly with big polluters.

But cleaner performers within industries — for example, a cleaner oilsands mine — will get a leg up over a dirtier one.

Carbon pricing electricity ‘awkward’: expert

It’s one thing to applying the carbon pricing system to ultra-competitive, internationally exposed industries that can’t help but produce carbon emissions — like steel.

But the new pricing system will also apply to the production of electricity, which is “somewhat awkward,” Turcotte said.

“Electricity generation is not emissions-intensive by necessity,” she said.

It’s also not exposed to pressure from international markets in the same way as steel or agricultural fertilizers are, meaning it doesn’t need the same protection from other countries that don’t have carbon prices, like the U.S.

The reasons for including electricity generation in the system are not entirely clear, although it could prevent an immediate increase in electricity prices for some consumers.

“I don’t think they had to do that, but they did do that,” Chris Ragan, director of the Ecofiscal Commission, said.

“Surprise, surprise, there’s politics that plays a role in these policy designs too — not just pure economics.”

The reasons may not be clear but the effects appear easy to predict: namely, a slower transition away from fossil fuel electricity.

Electrical generation makes up about 10 per cent of Canada’s greenhouse gas emissions, according to the National Energy Board. Turcotte said the decision to include electrical generation in the output-based pricing system could mean trouble for meeting Paris targets.

“We’re concerned by the approach to pricing emissions in the electricity sector, and we’re not sure how these align with our Paris agreement targets, and to getting to our renewable energy targets as well,” she said.

It could also mean that less emissions-intensive sectors will have to pick up the slack for the heavier polluters in meeting a national goal.

Canada’s gap between projected emissions and Paris targets is growing, something the government blamed on a combination of growth in oil and gas and “demographic changes.”

When The Narwhal inquired as to how ‘demographic changes’ relate to growing emissions, Environment Canada declined to elaborate on what relative contribution oil and gas were expected to make compared to demographics.

“We have a target as a country, and when a sector is unwilling to take leadership — when it’s given all these really enabling conditions with great incentives that actually give them the money to make those investments — it increases the burden on other sectors of our economy and of society,” Turcotte said.

International trade concerns

A major concern the federal government says it’s trying to address with the new system is the concern that Canadian firms could be put at a disadvantage relative to foreign counterparts who don’t have the same tax.

The way economists see it, a Canadian firm paying more under the carbon tax could lose customers to an American firm that isn’t paying for its emissions because the American goods would be cheaper. If the American firm started producing more while the Canadian one ramped its production down, the total pollution hasn’t actually decreased, it has just “leaked” across the border.  

Some industrial sectors are both big emitters and are exposed to competition from international trade. Nationally these sectors amount to only about five per cent of the economy, but in Alberta and Saskatchewan, it’s about 18 per cent.

“To not do anything for these sectors is to increase their costs and then walk away, and then let them shrink,” Ragan said. “The goal of climate policy isn’t to reduce emissions by shrinking our economy. The goal is to reduce our emissions by maintaining a healthy economy…but get cleaner.”

Ragan believes the government’s approach to pricing within sectors is the right way to address this problem, and says the changes in the threshold for emissions intensity are “pretty small” and “in a good direction.”

He, like Turcotte, believes government could be doing more to publicly defend the importance of a carbon tax.

The lack of a real push makes implementation harder politically than it needs to be — and opens the door for opposing parties and jurisdictions to reject the tax in favour of less elegant solutions.

“It is not well enough understood [by the public] why carbon pricing is economically the best way to do this, relative to the alternatives,” he said.

If Ottawa proceeds with its draft plan and allows for an 80 per cent threshold for most industries’ emissions intensity, Turcotte and Ragan say the next step should involve gradually lowering the cap as other trading partners introduce their own carbon pricing systems.

Essentially, this would provide incentive for companies to gradually improve operations — or face higher taxes.

There is not currently a plan to lower the cap, but an increase in the tax rate itself is built in, from $20 per tonne to $50 per tonne by 2022.

*This article has been updated to reflect this fact that Scott Moe is the current premier of Saskatchewan, not Brad Wall.

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Earlier this week, the federal government published a bombshell report on carbon pricing, predicting that a nationwide price of $50 per tonne by 2022 will cut emissions by 80 to 90 million tonnes of carbon pollution.

That’s equivalent to shutting down up to 23 coal-fired power plants or taking as many as 26 million cars off the road. In other words, a pretty big deal for the climate.

The stunning news spread quickly in online circles, shared by renown energy economists, clean energy experts and pollsters.

Journalist Justin Ling tweeted: “There’s been an incredibly disingenuous effort to suggest that carbon pricing won’t reduce CO2 emissions, or at least to contend that there’s no evidence to support the claim. So Ottawa went and produced the research.”

But nobody slowed down to check if the numbers were actually reflective of reality.

And they’re not.

The research that Ottawa went and produced isn’t really evidenced-based at all.

According to an analysis by Simon Fraser University energy economist Mark Jaccard, the federal carbon pricing policy will only reduce emissions by 10 to 15 million tonnes below 2005 levels — but it will take until 2030 to get there.

So the federal government’s claim of a 80 to 90 million tonnes reduction by 2022 is raising some eyebrows.

“When I see that, I’m like ‘oh come on guys, you’re trying to pull a fast one on us.’ ” Marc Lee, senior economist at the Canadian Centre of Policy Alternatives, told DeSmog Canada.

“People who ought to know better are just uncritically praising it.”

Carbon pricing being used as tool to justify new pipelines

This might just seem like a boring and wonkish debate over numbers. And in a way, it is.

But carbon pricing is currently playing a major role in the current climate policy landscape, viewed as the likes of Prime Minister Justin Trudeau and Alberta Premier Rachel Notley as a key bargaining chip in the campaign to get Kinder Morgan’s Trans Mountain Expansion built.

As a result, the amount of emissions that we think the policy can cut matters a great deal — especially if it’s used to justify a new pipeline and subsequent oilsands expansion.

Carbon pricing can be a very effective tool for increasing the cost of emitting. B.C. has been a shining example of a carbon tax that is both effective and popular with the public.

But disingenuous accounting has undermined faith in both the efficacy of putting a price on carbon emissions and the integrity of climate plans.

“The federal climate plan, overall, is weak,” said Laurie Adkin, political science professor at the University of Alberta, in an interview with DeSmog Canada.

“They keep trying to dress it up, and the latest assessment of anticipated gains from the federal carbon tax may be part of that effort.”

Analysis way overinflated current emissions

So what went so wrong with the federal government’s analysis?

Well, for beginners, it didn’t actually reference any specific numbers. The closest that they came to that was presenting a colourful graph with unclear metrics.

As Bora Plumptre of the Pembina Institute put it: “There are difficulties in actually assessing how they actually got the numbers that they did.”

By manually drawing a straight line from the supposed emissions reduction to the vertical axis (yes, that’s the only way of figuring it out) it appears that government assumes that carbon pricing will cut emissions to 680 megatonnes by 2022.

Given they’re predicting 80 to 90 megatonnes in savings, that means that it thinks emissions without carbon pricing would be between 760 and 770 megatonnes without carbon pricing.

But at last count, Canada’s greenhouse gas emissions were 704 megatonnes. Even the country’s highest year for emissions — in 2007, when we emitted 745 megatonnes — was considerably less polluting than what the federal government used in the analysis.

So the actual starting point appears inflated.

“This is a trick the Conservatives used many times to try to pretend their plans were actually doing a lot more than they were actually doing,” Lee said.

A spokesperson for Environment and Climate Change Canada told DeSmog Canada that they were contacting a “few different branches within the department” for more detailed methodology of the carbon pricing analysis but didn’t provide a response before deadline despite multiple extensions.

Government analysis ignored existing provincial carbon pricing

The analysis also assumed that the four provinces that currently have carbon pricing in place (B.C., Ontario, Quebec and Alberta) don’t already have them in place.

You read that correctly.

B.C. introduced its carbon tax in 2008. Quebec brought its cap and trade scheme into existence in 2013.

For inexplicable reasons, the federal government simply pretended that wasn’t the case and that four of the five highest polluting provinces in Canada didn’t already have carbon pricing. In his critical breakdown of the analysis, Jaccard wrote that it’s “grossly misleading to suggest that current provincial pricing can be attributable to federal policy.”

It also appears safe to assume that the modelling didn’t include industry exemptions and subsidies like gasoline used on farms, or natural gas burned by conventional oil and gas producers, or a large chunk of completely unpriced emissions at oilsands mines via Alberta’s convoluted output-based allocation system.

Experts suggest there’s also a chance that the federal government included significant emissions reductions accomplished by other policy measures.

“It’s very misleading, and also neglects that most of the impact is largely based on regulation, Lee said.

“We didn’t get rid of lead in gasoline because we had a lead tax that was phased in over 20 years. We just said ‘no, you can’t have lead in your gasoline after this date.’ ”

A steep carbon price needed for dramatic cuts

It’s not like carbon pricing couldn’t have these kind of reductions.

In fact, if you plug in a $50/tonne carbon price into the Pembina Institute’s nifty new climate policy simulator, it pops out 114 megatonnes in reductions by 2022.

But Plumptre caveated that by noting the simulator doesn’t include any exemptions or subsidies, and treats all carbon pricing as a tax (instead of including more complex cap and trade schemes, used in Ontario and Quebec).

Furthermore, Pembina actually uses a considerably higher baseline emissions assumption than the federal government due to recently updated global warming potential factors and higher rates of methane leakage, which puts Canada even farther from its Paris targets.

Jaccard and his team at Simon Fraser also reported in a 2016 analysis that Canada could meet its Paris target with a $200/tonne carbon price by 2030.

But they concluded rather starkly: “ It is highly unlikely that our political leaders will implement such a price, given the severe political consequences.”

So without such dramatic increases to the carbon tax and in the absence of transparent government accounting, experts are left scratching their heads at Ottawa’s latest rosy report.

“It’s all just been this black box and they’re basically saying ‘trust us,’” Lee said.

“I feel like the federal government doesn’t have much credibility on the climate file these days because they’re saying ‘we’re all in favour of climate action and we’re also in favour of pipelines,’ which we know are going to increase emissions and are specifically designed to allow the increase of production from the oilsands.”

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Alberta oil and gas companies are wasting so much natural gas each year that Albertans are losing out on up to $21 million a year in provincial natural gas royalties.

Oil and gas companies let an estimated $253 million worth of natural gas escape through undetected leaks and the practice of venting annually.

According to Progress Alberta, a progressive advocacy group, the lost royalties could pay for five new schools, 84 new playgrounds or 36 new nurses.

“This is a valuable resource that Albertans own and it’s money that should be going to things Albertans want and need that’s just being lost to the atmosphere forever,” said Duncan Kinney, executive director of Progress Alberta, in an interview with DeSmog Canada.

In addition to the lost royalties, the potent greenhouse house is leaked into the atmosphere without paying the province’s $30/tonne carbon levy, which results in a further loss of up to $1.4 billion in revenue, according to a new analysis by the Pembina Institute. When that carbon price increases to $50/tonne, as Premier Rachel Notley has indicated it will, those lost revenues rocket to $2.25 billion.

So why is this valuable resource disappearing into thin air?

ICYMI: Canada-U.S. Plan to Nearly Halve Methane Emissions Could Be Huge Deal for the Climate

Alberta underestimating methane leakage by 25 to 50 per cent

Reducing methane emissions from the oil and gas sector is considered to be one of the easiest ways to quickly reduce emissions. Methane has 34 times the “global warming potential” as carbon dioxide over a century.

And Alberta’s oil and sector emits a lot of it, with 31.4 megatonnes of methane entering the atmosphere in 2014 — although a recent study by Carleton University suggestedthe province is underestimating pollution by between 25 and 50 per cent, meaning annual emissions are more likely around the 45 megatonnes per year mark (which is about how much we thought all of Canada was emitting in 2016).

Fouty-five megatonnes a year is the greenhouse gas equivalent to 240,899 vehicles on the road.

Oil and gas companies have resisted changes that would require them to limit the leaking and venting of natural gas, arguing that it would result in job losses.

However, the federal government has committed to reducing methane emissions by 45 per cent below 2012 levels by 2025. Those reductions can be achieved through things like limiting the intentional “venting” of methane, using optical gas imaging cameras to detect unintentional leaks and installing flares to combust methane into carbon dioxide.

Federal draft regulations were released in May 2017, and proposed delaying full implementation of new rules by three years to 2023, instead of 2020. It was expected that Alberta would release its own version of regulations in November.

Industry  won a major concession from government in not having to pay any carbon tax on fuel used in the production of conventional oil and gas until 2023, including vented and flared gas.

The delay of action on reducing methane emissions ultimately impacts the entire country.

“What Alberta does will really make or break the ability to meet that [methane] target at the end of the day,” said Andrew Read, senior analyst with the Pembina Institute and report author.

Alberta oil and gas companies are wasting so much natural gas each year that Albertans are losing out on up to $21 million a year in provincial natural gas royalties. https://t.co/g0ExC0coTF

— DeSmog Canada (@DeSmogCanada) January 26, 2018

Improved leak detection and data collection critical

The federal government anticipates companies will need to spend $3.2 billion in between 2018 and 2035 to comply with the new regulations.

However, the government calculates the economic value of avoided climate change impacts will be more than $13 billion, with another $1.5 billion in conserved gas that can be sold by companies. That combines to a net benefit of $11.7 billion. In addition, a report by the Blue Green Alliance suggested methane regulations will create 1,500 jobs per year.

But for methane regulations to work, there  needs to be robust monitoring of leaked and vented methane.

ICYMI: Five Handy Facts About Alberta’s New Carbon Tax

“Having specific requirements for monitoring the leaks and trying to address them is also very important, so that we can actually tell if this is working,” said Brenda Heelan Powell, staff counsel at Alberta’s Environmental Law Centre, in an interview with DeSmog Canada.

Alberta could be ‘reducing class sizes, or hiring more nurses’ with lost revenue

It’s already taken a long time to get to this point.

The regulator-led Methane Reduction Oversight Committee was formed in September 2016 by the province and included representatives from industry and environmental organizations. But as reported by the Financial Post, talks broke down in the summer of 2017. Discussions with remaining stakeholders were set to conclude by last December.

We’re now less than two years away from when the federal regulations are proposed to start taking effect — and time is running out quickly to get industry ready.

These delays matter.

Environmental Defence estimates that pushing back the full implementation of regulations from 2020 to 2023 will result in an additional 55 megatonnes of methane being released.

That will have serious climate impacts. But it also deprives provincial coffers of potential royalty revenue, which is a pretty big deal for a province facing down a $10 billion deficit.

“We could be reducing class sizes, or hiring more nurses, or building more schools or playgrounds,” Kinney said. “These are things that people want and are demanding.  We’re in this self-imposed austerity in Alberta, and it’s somewhat unnecessary if we were just to follow through on these methane regulations.”

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It just might be the best climate policy you’ve never heard of.

It’s called the Clean Fuel Standard. Proposed back in December 2016 when the landmark Pan-Canadian Framework was signed by most provinces and territories, it’s since been vastly overshadowed by other, splashier policies, such as carbon pricing, the federal coal phase-out and methane regulations.

But as outlined in a brand new report by Clean Energy Canada — a think tank based at Simon Fraser University — the policy has incredible potential to cut Canada’s annual greenhouse emissions: upward of 30 megatonnes per year, compared to 18 megatonnes from the carbon price.

So why hasn’t anyone heard of it? DeSmog Canada took a look at the details to help you make sense of the situation.

What is the Clean Fuel Standard?

Simply put, it’s a federal requirement for fuel suppliers to cut their annual emissions by a certain percentage every year. It’s a way of accelerating the switch to cleaner fuels and technologies such as biofuel, clean electricity, carbon capture and storage and “renewable natural gas.”

By fuel suppliers, we mean mostly oil refineries and natural gas suppliers.

With that said, the policy will impact every producer and consumer of fuels, which include gasoline, diesel, natural gas, heating oil, coal and petcoke.

The key thing about this particular policy is that it won’t just include transportation. A fair few other jurisdictions have crafted clean fuel standards for transportation, including B.C. and California. But if unveiled as expected, Canada’s policy will include fuel used in buildings and industry, two considerable sources of emissions not dealt with by the current B.C. standards

“If implemented the way that the federal government says they would implement it, it would be the first of its kind in the world,” Dianne Zimmerman, director of the Pembina Institute’s transportation and urban solutions program in Ontario, told DeSmog Canada.

How much emissions reduction are we talking here?

The equivalent to removing seven million cars from the road.

Overall lifecycle carbon intensity is expected to drop by 10 to 15 per cent by 2030. That means removing upward of 30 megatonnes of greenhouse gas emissions per year, according to modelling by Clean Energy Canada. In a webinar hosted by Clean Energy Canada on Tuesday, senior analyst Jeremy Moorhouse indicated that could come from 19 megatonnes from transportation reductions and another 15 million tonnes from buildings and industry.

It’s still not enough for Canada to actually meet its Paris climate targets. In fact, Environment Commissioner Julie Gelfand recently calculated that Canada is expected to miss its 2030 market by 44 megatonnes, even if all policies from the Pan-Canadian Framework are fully implemented.

Wait, wasn’t this what the carbon tax was for?

Yes and no.

Warren Mabee, geography professor and Canada Research Chair in Renewable Energy Development and Implementation at Queen’s University, noted in an interview with DeSmog Canada that he sees the carbon price as setting a floor. A minimum price of sorts.

But he says the Clean Fuel Standard will accelerate emissions reductions in certain sectors, especially where there are cleaner technologies and fuels already available. Mabee actually described the standard as essentially “setting an alternative price for carbon.”

It’s similar to what Simon Fraser University economist Mark Jaccard was getting at in his 2016 paper about ‘politically viable’ solutions to emissions reductions. In it, he argued that flexible regulations “approximate the incentives and flexibility of emissions pricing, but comparative surveys of climate policy acceptability… indicate that they are likely to be less politically difficult.”

That approach also helps explain how a Clean Fuel Standard can potentially interact with existing policies known as “renewable fuel mandates” in provinces like Ontario, B.C. and Alberta.

While the jargon might seem a bit redundant, the latter requires fuel producers to integrate a certain percentage of renewable fuel — mostly biofuels — into their product.

The Clean Fuel Standard on the other hand is concerned specifically with the actual carbon intensity of the fuel right at the source.

The two policies work best together in tandem, according to Mabee.

“Honestly, there is no one policy that’s going to solve these problems,” he said. “If there’s going to be a real solution, we’re going to need multiple policies to help push us there. This is one way we can differentiate those.”

The Best Canadian #Climate Policy You’ve Probably Never Heard Of https://t.co/EL9wAhGoLb #cleanfuelstandard @Pembina @cleanenergycan

— DeSmog Canada (@DeSmogCanada) November 8, 2017

What will the standard actually look like?

That’s entirely up to the federal government.

One thing that’s often overlooked is just how customizable climate policies — like carbon pricing or zero-emission vehicle mandates — really are.

Sure, there’s a basic framework required. But governments can handpick prices, exemptions, incentives and penalties.

For that reason, it’s tough to say at this point how new rules will roll out. The federal government has been delaying the release of key parts of the framework and final regulations aren’t due until 2019. But a good place to look for clues is a similar existing policy in B.C.

The B.C. Low Carbon Fuel Standard was adopted back in 2008, requiring carbon intensity of transportation fuels to be cut by 10 per cent by 2020. According to the province, that cut 6.4 megatonnes of emissions between 2010 and 2016.

The controversial 2016 Climate Leadership Plan raised the standard, requiring a carbon intensity cut of 15 per cent be implemented by 2030.

Fuel suppliers have three ways of doing that. They can just cut emissions intensity during production. Or they can buy credits from another fuel supplier: think of a carbon trading system of sorts.

The third option includes entering into a “Part 3 Agreement” with the province, in which a fuel supplier has to take certain actions, which are deemed to be equivalent to actually cutting fuel intensity. That can include building a new pump station that sells gasoline with biofuels mixed in, or testing certain additive formulas for cold weather operability of biodiesel-blended diesel.

This is what’s known as a “flexible” regulatory approach. That’s opposed to a more prescriptive policy, in which emitters clean up or pay (think the carbon price). As a result, fuel suppliers are expected to find the most cost-effective and technologically innovative solutions that work for them.

If things go as planned, Canada could implement a 10 per cent reduction of transportation fuels by 2030 from 2015 levels like B.C. has already done. Then, throw in a 3.5 per cent cut in fuels for buildings and industry, or a five per cent renewable natural gas mandate.

According to Clean Energy Canada, that would result in the 30 megatonnes in reductions.

Hold up…renewable natural gas?

It’s natural gas that comes from landfills and water treatment plants! Pretty neat, actually. It currently escapes and adds to fugitive methane emissions in the atmosphere — but could be captured.

In fact, Moorhouse said in the webinar that if you had a renewable natural gas station at every landfill across Canada, we could meet a good portion of the Clean Fuel Standard using waste.

What would this new standard mean for jobs and fuel prices?

It could be a net plus!

According to Clean Energy Canada, it’ll generate a net growth of 11,100 jobs and $4.1 billion in economic activity.

Indeed, growth would slow in some sectors such as refining and service stations, but would increase in building new biofuel facilities and cleantech investments: between $200 million to $2 billion a year between 2020 and 2030.

As for impacts on fuel prices: it’ll be minimal, between $2 and $5 per month in direct household energy bills including cars, furnaces and electricity by 2030. The important thing to keep in mind is that energy efficiency measures between now and then will greatly cut costs for households.

In the end, Canadians will end up saving between $17 and $82 a month by 2030, depending on things like how efficient your furnace and cars are.

Alright, what’s the catch?

There are certainly challenges.

Zimmerman of the Pembina Institute notes that one of their concerns is that the new fuel standard could be delayed and not be implemented. She calls the schedule by which they’re attempting to get it regulated under the Canadian Environmental Protection Act as “very aggressive.” But we’re already seeing the government fall behind. They also delayed implementing methane regulations on oil and gas producers until well after the next election.

Those delays have consequences.

“Every year there’s a delay of climate policy has implications to further decades,” she said.

There’s also the big question mark about counting reductions, especially related to credit trading. Mabee of Queen’s University noted it’s still unclear how reductions will actually be verified: whether it will be a government agency or something more independent.

“That’s your danger,” he said. “You get a powerful industry lobbying group that says ‘I’m buying so many litres of this biofuel or this low-carbon oil source and therefore I should be getting this benefit.’ But if there’s no proof that it’s actually doing that, and if there’s disputes, who do you go to to resolve the dispute? That isn’t clear yet.”

Now, we just have to hold our breath and wait for the actual policy.

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

This article originally appeared on the Pembina Institute website. This is part 2 of a series on the last 50 years of the oilsands industry. Read part 1 here.

The sheer size and scope of Alberta’s some 20 oilsands tailings ponds is unprecedented for any industry in the world.

According to the U.S. Department of the Interior, one of these ponds — the Mildred Lake Settling Basin — is the world’s largest dam by volume of construction material.

Since oilsands mining operations started in 1967, 1.3 trillion litres of fluid tailings has accumulated in these open ponds on the Northern Alberta landscape. This is enough toxic waste to fill 400,000 Olympic swimming pools.

Unlike tailings produced from conventional hard rock mining, the solids in oilsands tailings will take centuries to settle to the bottom of the ponds. As a result, it is impossible to dewater the waste for timely reclamation without significant intervention.

This problem was recognized as early as 1973 by the Government of Alberta, which identified oilsands tailings as untreatable with existing technologies.

The government recognized that the “continuous accumulation of liquid tailings” was not acceptable and that the ponds must be “restricted in their size, location and duration of use.”

Unfortunately, that is not what happened.

For the next five decades, industry pushed its tailings problem into the future with promises that forthcoming technologies would emerge to deal with them. As the years passed and tailings continued to grow, both industry and government assured Albertans that a silver-bullet technology was just one lab discovery away.

In 2010 Suncor’s CEO Rick George announced “massive change” on the tailings front, which would soon reduce Suncor’s ponds from eight to one. In 2013, Premier Alison Redford declared that tailings ponds would “disappear from Alberta’s landscape in the very near future.”

These promises were never met, however, and today the tailings problem is worse than ever.

According to new plans currently under review by the Alberta Energy Regulator, industry is proposing to let tailings continue to accumulate until 2037 when there will be over 1.5 trillion litres. That will equate to seven decades — from 1967 to 2037 — of industry seeking a technological solution and failing to meaningfully address this massive environmental problem.

Figure 1. Fluid tailing ponds volume growth since 1968

With tailings ponds continuing to grow on the landscape, the risk of failure poses an ever-increasing risk to communities, the environment, and taxpayers.

Moreover, should the oilsands mining industry not survive accelerating global transitions toward decarbonized energy systems, Albertans must be protected from being left behind to foot the bill for enormous clean-up costs.

The Problem of Alberta’s Growing #Oilsands #TailingsPonds is Worse Than Ever https://t.co/nwszGniwa0 @Pembina #ableg #cdnpoli

— DeSmog Canada (@DeSmogCanada) October 23, 2017

However, less than 8 per cent of these costs is held as security by the province, leaving Albertan taxpayers exposed to a significant financial risk for tens of billions of dollars if major companies are no longer around when it’s finally time to reclaim these sites.

Looking at these grim facts, it’s worth asking: when will we as Albertans say enough is enough? Companies have kicked the can down the road on cleaning up their tailings for five decades now, but industry’s own forecasts indicate that the worst is still yet to come.

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By Maximilian Kniewasser and Stephen Hui.

Under Premier John Horgan and the NDP, British Columbia’s government is no longer promoting liquefied natural gas exports as a once-in-a-generation opportunity to snag 100,000 jobs, a $100-billion Prosperity Fund, and more than $1 trillion in economic activity. Nevertheless, proposed LNG development remains a thorny issue to be tackled by the new provincial government.

This week, the Pembina Institute and the Pacific Institute for Climate Solutions published Liquefied Natural Gas, Carbon Pollution, and British Columbia in 2017, an update on the state of the B.C. LNG industry in the context of climate change.

Here are three highlights from our report.

1. 18 LNG Projects Still Eyeing B.C. Coast

No LNG export projects are up and running in B.C. Currently, natural gas products are produced at two small domestic LNG plants, with two additional domestic facilities proposed.

However, 18 LNG export proposals in B.C. are at various stages of development. Only two — LNG Canada in Kitimat and Woodfibre LNG near Squamish — have regulatory approval and are close to being realized. (The latter also has a final investment decision from parent company Pacific Oil & Gas.) A third approved project, Pacific NorthWest LNG in Port Edward, made headlines in July with the announcement that it “will not proceed as previously planned.”

The remainder of the LNG proposals are in the early stages of development. Most are located on the North Coast, with five projects on Vancouver Island and the South Coast.

2. Woodfibre and LNG Canada Make B.C.’s Climate Targets Virtually Impossible to Meet

B.C. was responsible for 63 million tonnes of carbon pollution in 2014. In contrast, B.C.’s legislated greenhouse gas reduction targets call for annual emissions to be lowered to 43.5 million tonnes by 2020 and 12.6 million tonnes by 2050.

B.C. is currently on track to miss its legislated 2020 target by a wide margin, with emissions projected to increase until at least 2030. Measures in the province’s Climate Leadership Plan are forecast to bring annual emissions down as low as 54 million tonnes by 2050 — well short of the legislated goal.

The two approved projects analysed in our report — LNG Canada and Woodfibre LNG — would collectively increase carbon pollution by 9.1 million tonnes per year by 2030, further increasing to 10.2 million tonnes per year by 2050.

That would leave less than 3 million tonnes per year for the rest of B.C.’s economy — including transportation, buildings, and industry — and make it virtually impossible for the province to meet its 2050 target.

If LNG Canada and Woodfibre LNG were built using best practices and technology — including greater electrification, as B.C.’s Climate Leadership Team recommended — emissions would be halved. However, these combined emissions would still make it very difficult for B.C. to meet its targets without drastically eliminating emissions from the rest of the economy.

What's Up with #LNG in B.C.? Three Things You Need to Know https://t.co/0166XLRGt6 @Pembina @StephenHui #climate #bcpoli

— DeSmog Canada (@DeSmogCanada) August 31, 2017

3. Pacific NorthWest LNG Could Rise From the Dead

Petronas-backed Pacific NorthWest LNG’s cancellation was attributed to prolonged depressed prices and shifts in the energy sector.

Prior to the announcement, PNW LNG was among the projects considered most likely to proceed, having secured export, pipeline, facility, and (conditional) environmental approvals, as well as agreements with some local First Nations.

However, other First Nations groups and the SkeenaWild Conservation Trust launched court challenges in an attempt to block PNW LNG, citing issues involving the consultation of indigenous communities, impacts on fish habitat, and carbon pollution.

Although PNW LNG is officially cancelled, various permits for the project remain valid. These include a National Energy Board export licence and a positive environmental assessment decision by the Canadian government.

Until the permits are forfeited or voided, the project should still be considered a potential LNG development along B.C.’s North Coast.

If the permits for PNW LNG were resurrected by the current or a new owner, the project would make the province’s legislated 2050 climate target impossible to reach.

Such LNG export terminals, fully powered by natural gas, are almost four times more polluting per tonne of LNG produced than terminals using clean electricity.

Several policies in place in B.C. are designed to reduce emissions from LNG and associated upstream development. However, these policies fall short of requiring projects to adopt best practices and technologies. They should be strengthened to ensure that, if development proceeds, it is with the lowest impact to the climate.

Maximilian Kniewasser is the director of the B.C. Climate Policy Program at the Pembina Institute, Canada’s leading clean energy think-tank.

Stephen Hui is the B.C. communications lead at the Pembina Institute.

Image: Former B.C. Premier Christy Clark visiting a Petronas LNG facility in 2014. Photo: Government of B.C. via Flickr

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Environmental organizations, labour groups and technology companies are calling on Alberta Premier Rachel Notley to take decisive action on methane emissions from oil and gas activities.

Methane is a particularly potent greenhouse gas, with 25 times the global warming potential as carbon dioxide over a 100-year period. Methane is a huge component of natural gas, so Alberta generates a lot of the stuff because it gets vented in all sorts of ways once you start digging around beneath the earth’s surface.

In an open letter the groups call on Alberta to go above and beyond the draft federal regulations on methane.

“Alberta can lead the country’s methane reduction efforts and keep good job opportunities in the oil and gas sector from going to waste,” the letter reads.

Sounds nice, right?

Well, as alluded to in the letter, the proposed federal regulations are in need of some serious strengthening (which we’ll get into in a sec).

“Alberta can have the greatest impact on methane reductions,” said Jamie Kirkpatrick, program manager at Blue Green Alliance, in an interview with DeSmog Canada. “For them to come out strong means that we’re going to achieve our targets.”

Here are five things the Alberta Energy Regulator should consider while crafting its own set of provincial regulations.

1. Accelerate Timelines

The Pan-Canadian Framework included a commitment to reduce methane emissions from the oil and gas sector by 40 to 45 per cent from 2012 levels by 2025.

Yet under immense pressure from industry, the federal government decided to delay the implementation of its methane regulations. The original plan was to introduce some of the regulations in 2018, with the remainder in 2020. Now, that’s been pushed back three years to between 2020 and 2023, saving industry around $1 billion over a 17-year period.

According to Environmental Defence, that will result in the unnecessary release of a massive 55 megatonnes in methane emissions. The Canadian government has calculated that the “social cost of methane” is $1,165/tonne in 2012 dollars.

Alberta can accelerate the implementation of regulations that will dramatically cut methane emissions. It doesn’t necessarily have to return to the original dates of 2018 and 2020, but the sooner the better.

2. Ban Venting and Flaring

Duncan Kenyon, director of the Pembina Institute’s responsible fossil fuels program, said in an interview with DeSmog Canada that a huge problem with methane emissions is that industry is  still allowed to intentionally leak natural gas — of which methane is the main component — in a process also known as “venting.”

He said that venting is actually most often done by oil producers, as any gas that comes up is seen as “worthless” compared to petroleum.

“If you have a high amount of intentional leaking going on, there is almost no way to differentiate between intentional and unintentional leaking when you visit,” Kenyon said. “Basically, what it does is give industry a huge out for their unintentional leaking.”

To be sure, there are a few policies in Alberta that attempt to reduce venting. Most have to do with an economic test: if it’s not profitable for a company to capture and ship the gas to market, then it’s allowed to “flare” it into the atmosphere.

Kenyon said that flaring — a form of controlled burning that converts methane into carbon dioxide — is a marginal improvement over venting on the climate front, but less beneficial from an air quality perspective. He added that economic test is determined by industry and “everyone knows how gameable that is.”

In other words, industry is currently allowed to release or burn off massive amounts of gas into the atmosphere, making it very difficult to ascertain how much methane is being consistently released (operators obviously won’t vent gas when inspectors are on site).

That’s why a key demand in Environmental Defence’s recent report is to “eliminate routine venting” and “not permit new routine flaring, and phase-out existing flaring practices.”

The federal government’s draft regulations won’t prohibit current practices, and won’t even begin to restrict them until 2023. While it will cost industry around $1.2 billion between 2018 and 2035, the reduction in venting will result in $5.4 billion in savings from climate change damages.

The new Alberta regulations could seriously raise the bar by accelerating a full ban on venting and flaring.

Five Ways Alberta Can Raise the Bar on #Methane Regulations https://t.co/PR7c4CAfMz @envirodefence @Pembina @ProgressAlberta @UniforTheUnion

— DeSmog Canada (@DeSmogCanada) August 1, 2017

3. Increase Frequency of Monitoring

Then there’s the issue of “fugitive emissions” or legitimately unintentional leaks.

Kenyon said that “right now, the option for unintentional is to get on site and look for your leaks. The solution, nine times out of ten, is simply tightening some bolts and fixing some things while you’re there.”

The proposed federal regulations do include a requirement for “leak detection and repair” by a professional using an “optical gas imaging” camera to take place three times per year, starting in 2020.

That’s certainly a good start.

But as pointed out by Environmental Defence, states including Colorado, Wyoming and California already require that inspections happen four times per year. The logic is quite simple: the more inspections, the more methane leaks identified and dealt with. Industry isn’t exactly a fan of the idea, even though it will cost them a mere $374 million over 15 years for a massive $3 billion in societal savings from greenhouse gas damages.

“They’re definitely opposing the idea of having people drive out there,” Kenyon said. “I think they understand the risk with actually catching the leaks is that we’ll actually start to realize how big a problem we have.”

But if done right, Kenyon suggested that within two to three years there will be enough of a marketplace that developing technologies for on-site detection will be deployable. That means there won’t be any humans involved in the actual monitoring: detectors will go off if there’s a suspected fugitive emission, and people will visit the site to repair it.

In the meantime, it’s critical that monitoring and enforcement is dramatically expanded in order to create a culture of compliance. Alberta could lead the way by increasing the number of times that a site is visited every year, and by preparing companies for the new technologies to come.

4. Expand the Scope of Regulations

One of the stranger aspects of the federal regulations is that they will only apply to around 20 per cent of crude oil facilities in Canada, which the government estimates are responsible for 75 per cent of vented emissions.

There are a wide range of other exceptions that have been proposed: the government won’t require inspections during winter, operators can wait more than 30 days to repair the leak if it’s not possible without shutting down equipment and only facilities that vent more than 40,000 square metres of gas per year need to comply with the already weak regulations.

Single wellheads and many heavy oil facilities are also exempt from the leak detection and repair program. These are all pretty stunning omissions for a government ostensibly concerned about climate change.

To reiterate: methane boasts 25 times the global warming potential than carbon dioxide over the span of a century. Smart regulations could almost entirely eliminate methane emissions from the largest source of methane in the country.

Alberta can get out ahead of the game by applying methane regulations to all oil and gas facilities in the province, with monitoring happening year-round and repairs required as soon as a leak is identified.

5. Talk About Huge Potential for Jobs and Cost Savings

The component that almost always gets left out of talk about aggressive climate action is the possibility for new jobs and enormous cost savings.

While a job forecast hasn’t been done specifically in Canada, Kirkpatrick said a recent Blue Green Alliance report in the U.S. can be used to estimate that at least 1,500 new jobs per year would be created if robust methane regulations were implemented.

In an interview, Kirkpatrick said that jurisdictions in the U.S. are already seeing all these benefits and beating out Canada and Alberta on methane management. Specifically, he noted that it would require a lot of local workers as they would need to be near the actual sites to conduct inspections and detection work.

“In that sense, there’s the potential benefit to some of the communities hit [by the price crash],” he said. “I don’t think it’s full recovery or anything, but it is another positive thing and there’s no reason not to do it.”

In addition, robust regulations could actually result in significant long-term financial savings for industry. While the new rules are expected to cost companies $3.3 billion over 17 years, the actual gas that’s captured and sold could amount to $1.6 billion in value. Then there’s the climate change costs, which the federal government estimates will reach $13 billion by 2035.

That combines to $11.7 billion in net benefits.

The challenge, as with many related issues, is rebuffing industry pressures to minimize new regulations. After all, the proposed rules will indeed cost companies $1.7 billion over almost two decades. But it will also result in massive reductions in emissions and associated climate impacts.

At this point, it’s entirely about priorities for the Alberta government: will it focus on appeasing the oil and gas industry or avoiding the worst impacts of climate change?

What’s Next?

The Alberta Energy Regulator (AER) is responsible for drafting provincial regulations. A spokesperson from the regulatory body told DeSmog Canada via e-mail that they will be posted for public feedback this fall.

They also noted that the “multi-stakeholder process will continue as we work on addressing the feedback we receive on the draft requirements.”

It’s a point that’s inconsistent with what Kenyon said, who noted that the multi-stakeholder group broke down and that “the AER has fundamentally written their own conditions.”

Either way, we’ll have to simply wait and see what happens in the fall. Many of the technical issues are easily deployable, with Kenyon noting there are about 170 companies in Alberta alone who have solutions for methane leaks. It’s now just about the AER developing smart regulations and releasing the massive potential energy.

“For the Alberta government to now take a step back from that wouldn’t seem to be the wise move,” Kirkpatrick said. “Why show that courage that was displayed early on to say we’re going to be a leader on climate change and then adopt a direction that puts you in the middle or back of the pack?”

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By Maximilian Kniewasser, Pembina Institute.

Four years ago, the government of British Columbia bet big on the prospect of liquefied natural gas (LNG) exports creating overseas markets for the province’s shale and tight gas resources.

LNG development would deliver 100,000 jobs, a $100-billion Prosperity Fund, and over $1 trillion in economic activity, British Columbians were told. Since then, however, the economics of LNG have shifted, and the predicted LNG boom has yet to materialize.

In order to attract LNG investment, the provincial government has provided myriad incentives, exemptions, and direct transfers to the natural gas industry. Financial incentives that shield the emissions-intensive industry from current and potential future increases in carbon costs are of particular concern to the Pembina Institute.

For one thing, these measures lessen the incentive to reduce carbon pollution — as the world increasingly demands that polluters pay for their emissions. Furthermore, such incentives use scarce public dollars to support the fossil fuel sector at a time when government should be removing barriers to clean innovation and investing in green jobs.

Here is an overview of six carbon-related incentives that benefit LNG projects and the natural gas industry in B.C.

1. Carbon Tax Exemptions

B.C.’s carbon tax currently only applies to combustion emissions and fails to put a price on non-combustion sources (especially venting and fugitive emissions). According to B.C. government reporting, combustion emissions in the natural gas sector account for approximately 60 per cent of total emissions associated with the industry. That leaves 40 per cent of the industry’s emissions un-priced.

The current value of this exemption for the natural gas industry is estimated at over $150 million a year. This value would increase if a substantial LNG industry emerges. As well, a recent report shows that vented and fugitive emissions in B.C.’s oil and gas sector are 2.5 times higher than reported, making the exemption even more valuable.

By expanding the coverage of B.C.’s carbon tax to include all currently accurately measurable emissions, about half of these exempted emissions could be priced.

2. LNG Environmental Incentive Program

The Liquefied Natural Gas Environmental Incentive Program rebates industry 50-100 per cent of the compliance costs of the LNG benchmark regulations established by B.C.’s Greenhouse Gas Industrial Reporting and Control Act (GGIRCA). Of the three most advanced LNG projects, this incentive only applies to Pacific NorthWest LNG (PNW LNG), which is the only project that fails to achieve the emissions benchmark set by the provincial government. The value to PNW LNG is estimated at up to $16 million a year.

3. eDrive Electricity Rate for LNG Facilities

The eDrive electricity rate offers a significantly lower price to LNG projects that choose to use grid electricity to power the main liquefaction process. In 2013, B.C. Hydro announced an LNG-specific electricity rate. The rate was higher than the current industrial rate — to reflect the cost of new supply and to protect existing ratepayers.

However, the eDrive rate reduces this LNG electricity rate to the standard industrial rate. Woodfibre LNG announced that it would proceed with its project on the same day the eDrive rate was made public. The value to Woodfibre LNG is estimated at $26 million a year.

Six Troubling Subsidies That Support B.C.’s LNG Industry https://t.co/hpVLpox3QE #bcpoli #bcelxn17 #LNGinBC #cdnpoli @Pembina pic.twitter.com/y0Tk5TaxIH

— DeSmog Canada (@DeSmogCanada) May 5, 2017

4. Upstream Electricity Infrastructure Spending

In last year’s climate plan, the B.C. government announced it would invest in electricity infrastructure in the Montney basin to enable the electrification of upstream natural gas development. As details are not yet available, the Pembina Institute is not able to quantify the potential magnitude of the incentive.

5. Competitive Electricity Rate for Upstream Development

B.C.’s climate plan states: “Programs are also being developed to close the gap between electricity and natural gas costs.” Under current market conditions, using natural gas is generally cheaper for the industry compared to electricity.

As such, any public programs to equalize the costs of electricity and natural gas would be associated with material costs to government. As details are not yet available, the Pembina Institute is not able to determine the potential value of the incentive.

6. Project Development Agreement with Pacific NorthWest LNG

In 2015, the B.C. government signed a project development agreement (PDA) with Pacific NorthWest LNG. For PNW, the PDA locks in the current GGIRCA — the main legislation regulating carbon pollution from LNG facilities — for 25 years. It also locks in the aforementioned LNG Environmental Incentive Program.

If the government chooses to strengthen GGIRCA or alter the LNG Environmental Incentive Program, it could owe compensation to the proponent. In effect, the PDA is a significant barrier to future administrations strengthening regulations for the industry. This is an important point, because it will be the case over a period that we know must see the ambition of climate policy increase.

Wait, There’s More

This suite of carbon-related incentives for LNG projects and the natural gas industry is substantial in value. In addition, there are numerous non-carbon-related incentives, such as the cutting of the LNG income tax by 50 per cent, federal capital cost allowances, and significant upstream royalty credits that have led to record low royalties from a public resource.

Currently, 19 LNG projects are proposed in B.C. Only three — Woodfibre LNG, LNG Canada, and Pacific NorthWest LNG — are at an advanced stage and have received environmental assessment certificates. Together, the three projects would emit 18 million tonnes of carbon dioxide equivalent (Mt CO2e), making it impossible to meet B.C.’s legislated 2050 climate target of 13 Mt CO2e for the whole economy.

Instead of spending public dollars to bolster the carbon-intensive fossil fuel sector, the provincial government should be putting resources into revving up the clean growth economy. After all, a prosperous future for B.C. depends on investments in the industries of tomorrow — not yesterday.

Maximilian Kniewasser is an analyst at the Pembina Institute, Canada’s leading clean energy think-tank. Learn more: www.pembina.org.

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

That assertion is becoming less convincing by the day.

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

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

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

Oilsands Tailings Plans Nonexistent

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

Every single company breached their own targets.

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

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

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

“And they need to do the work.”

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

— DeSmog Canada (@DeSmogCanada) April 21, 2017

Provincial Auditor General Warned of Risk of Oil Price Drop

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

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

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

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

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

Oilsands Accounting Expert Says Situation Is “Major Concern”

That very thing has happened.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Recent Mining Disasters and Abandonments Point to Potential Dangers

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

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

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

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

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

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

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

Provincial Regulator Has Variety of Options to Pursue, Critics Say

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

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

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

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

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

Nothing appears to have been changed or updated since then.

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

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

Image: Alberta oilsands tailings pond. Photo: Alex MacLean 

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Want to modernize Canada’s National Energy Board (NEB)?

Bring the regulatory agency — first founded way back in 1959 when the realities of climate change weren’t readily known — into alignment with our carbon-constrained present.

That recommendation, coming from the Pembina Institute, comes in a report released Friday to coincide with the end of a federal review of the National Energy Board that brought an expert panel into halls and meeting rooms of 10 cities across the nation.

In the report, “Good Governance in the Era of Low Carbon,” the Pembina Institute states the review is an important opportunity to not only bring the mandate of the NEB into the 21st century, but also to restore public trust in what many see as a broken process.

The National Energy Board has been called a “captured regulator” that has “lost touch with what it means to protect the public interest,” by Marc Eliesen, former head of BC Hydro and former deputy minister of energy in Ontario and Manitoba.

Eliesen was one of many groups and individuals to publicly pull out of the NEB review of the Kinder Morgan Trans Mountain pipeline after the process was called “fraudulent” and an act of "public deception."

“Over the last decade, energy infrastructure proposals — including fossil fuel projects like oilsands pipelines and renewable energy development like wind farms — have become increasingly contentious across Canada,” the Pembina report states.

Modernize the National Energy Board? Here’s How https://t.co/CUp1RVOETT @Pembina #cdnpoli #NEBreview

— DeSmog Canada (@DeSmogCanada) March 31, 2017

“Public trust in energy decision making is at an all-time low, brought on by rapidly changing realities in, and expectations of, the energy sector.”

Erin Flanagan, federal policy director with Pembina and lead author of the report said changes to the NEB could help temper public skepticism by bringing the activities of the agency into alignment with Canada’s climate commitments.

“Canadians need an unbiased and trusted energy regulator capable of supporting Canada’s clean growth agenda,” Flanagan said.

Under the Paris Agreement Canada has committed to reduce emissions 30 per cent below 2005 levels by 2030.

Yet the approval of major fossil fuel projects and infrastructure by the federal government have many wondering how growth in Canada’s energy sector will square with low-carbon commitments.

“National Energy Board modernization is Canada’s opportunity to turn the corner on frustrated project reviews, and instead build processes that work for all interested parties and ultimately deliver credible recommendations to government.”

The report recommends the NEB consider the climate impacts of projects as well as the impact of new projects on Canada’s climate commitments.

“In its current function the NEB…fails to assess climate change impacts in its activities, from project reviews to data production and monitoring,” the report states.

A modernized NEB would apply best-available climate science to project reviews, keep project approvals in line with low-carbon goals and protect the long-term interest of Canadians by quantifying the climate risk associated with projects. 

Currently the NEB does not incorporate an analysis of how energy projects will impact Canada's climate committments, nor does it define what is meant by "public interest."

“The federal government has an opportunity to build on the NEB’s core competencies by ensuring it has a mandate to produce energy data consistent with successful implementation of the Paris Agreement," Lindsay Wiginton, analyst with the Pembina Institute and co-author of the report, said. 

"This is an essential requirement for Canada: data produced by the NEB is widely used for energy policy development and planning across the country, and it should reflect our climate commitments.”

The report also recommends reforms to how and what projects are submitted to the NEB for assessment.

“National and sub-national governments must implement and enforce climate policy commensurate with achieving Canada’s domestic and international climate commitments. This will encourage (though not guarantee) the selection of projects that support Canada’s transition to a decarbonized economy before they arrive at the regulator.”

In addition to addressing climate impacts, the NEB should also operate in a manner that supports Canada’s commitment to respect the rights and title of indigenous peoples, including facilitating the 94 “Calls to Action" intoned in the findings of the Truth and Reconciliation Commission.

Federal project approvals of the Site C dam, the Kinder Morgan Trans Mountain pipeline and the Pacific Northwest LNG terminal in B.C. have each been met with legal challenges from local First Nations who argue the approvals violated aboriginal rights and title or the principle of free, prior and informed consent.

“Modern regulators should conduct their work in the spirit of reconciliation with Indigenous peoples,” the report states, adding changes to legislation made in 2012 unnecessarily limited public participation in project assessments.

A lack of public participation and perceived transparency has also damaged the NEB’s reputation and the credibility of its processes, the report finds.

Pembina recommends a revised energy project review “support systems for the full and meaningful participation of the public and any interested parties” and ensure “provisions for ensuring the independence of commissioners, participating experts and project documents are in place.”

In September a three-member NEB panel recused itself from the review of TransCanada's Energy East pipeline, after the National Observer revealed the panelists quietly met with former Quebec Premier Jean Charest who at the time was working for TransCanada. 

“Public trust in the NEB is at an all-time low because of its perceived (and/or real) state of industry capture and the politicization of its decision-making," the report states, recommending energy regulators be "independent of bias and interferences from government and non-government stakeholders."

The Pembina Institute submitted the report to the expert panel charged with reviewing the NEB. The panel will make recommendations to Natural Resources Minister Jim Carr by May 15, 2017. 

Image: Prime Minister Justin Trudeau and Natural Resources Minister Jim Carr. Photo: Government of Canada

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Across Canada’s north, diesel has long been the primary mode of providing year-round electricity to remote communities — but with the advent of small-scale renewables, that’s about to change.

Northern communities were already making strides toward a renewable energy future, but with $400 million committed in this year’s federal budget to establish an 11-year Arctic Energy Fund, energy security in the north has moved firmly into the spotlight.

“This level of support shows positive commitment from the Canadian government on ending fossil fuel dependency in Indigenous communities and transitioning these communities to clean energy systems,” said Dave Lovekin, a senior advisor at the Pembina Institute.

Burning diesel not only pollutes the atmosphere, but getting it into remote communities is often inefficient in and of itself: it’s delivered by truck, barge or, sometimes when the weather doesn’t cooperate, by plane.

There are more than 170 remote indigenous communities in Canada still relying almost completely upon diesel for their electricity needs.

But, for some, at least, that’s beginning to change. Take the community of Old Crow (Vuntut Gwitchin First Nation), above the Arctic circle in the Yukon.

Despite its northern latitude, and near total darkness between December and February, a 2014 Government of Yukon pilot study demonstrated that solar represents a major untapped renewable resource for the community.

Many homes in Old Crow, north of the Arctic Circle, still rely on diesel, but that's changing. Photo: Matt Jacques.

Now Old Crow has a number of small-scale solar panel installations, including an 11.8 kilowatt array at the Arctic Research Centre — but its sights are set higher. Plans for a 330 kilowatt solar plant are well underway. A 2016 feasibility study estimated that this large-scale installation could offset 17 per cent of the community's total diesel use, or up to 98,000 litres of fuel each year.

“Anything that affects our community, we want to have control over. That’s our goal with this project is to have ownership over the facility,” said William Josie, director of Natural Resources for the Vuntut Gwitchin First Nation. “We burn a lot of fuel up here per capita and we’re trying to reduce that.”

Josie said his community is excited to build further solar capacity.

“This has been in the works for a long time, and it’s just the right thing to do,” he said. “It’s the first solar project of this size in the Yukon with community ownership.”

The Vuntut Gwitchin First Nation has a self-governing final agreement in place with the Government of Canada, the Government of the Yukon and the Council of Yukon First Nations. So too does the Kluane (Burwash Landing/Destruction Bay) First Nation in the southwestern Yukon, which is taking another approach to delivering a similar level of renewable energy capacity.

A major $2.4 million wind power generation project is set to be installed in 2018. Three refurbished 95 kilowatt turbines will deliver just under 300 kilowatts of total power and are estimated to offset 21 per cent of the community’s total diesel use.

“One of the big things for the community is to be self-reliant and self-sufficient. Diesel is neither of those two,” explains Colin Asseltine, general manager of the Kluane Community Development Corporation. “We’re looking at what we can possibly do to reduce our carbon footprint and move off-grid.”

The wind project will expand on the earlier successes in the community. Since 1998, Burwash Landing has used biomass for district heating, and began selling solar power back into the grid not long after installing a 48 kilowatt array in 2003. Along the way, they have been collecting the data required to inform the next steps and increase the impact of the community’s investment in renewable energy.

Meet the First Nation Above the Arctic Circle That Just Went #Solar #yukon #arctic #cleanenergy #cdnpoli https://t.co/B9Um6R7yJq

— DeSmog Canada (@DeSmogCanada) March 28, 2017

A geothermal test well provides promise for increased food security.

“Connecting that to our greenhouse projects will really help with the possibility of growing year-round, and having a positive effect on food sustainability at the same time. Both renewable energy and food security go hand in hand, so we’re working on those together,” Asseltine said.

While these two communities have shown that renewable energy solutions are indeed feasible for remote northern environments, hurdles remain.

“Our biggest challenge right now is just to secure capital costs” Josie said. “We’re looking for $2 million to $2.5 million, depending on the final engineering and design.”

Lovekin, from the Pembina Institute, underscores this point, explaining that “the challenges on the technology side are nowhere near the challenges on the financial and community capacity side.”

Up until now, federal and provincial or territorial funds have focused on financing initial development costs.

“The first focus on funding capital expenditure is good, but governments simply putting in money to get systems built has been shown to not be a sustainable strategy to support these communities to fully develop their projects,” Lovekin said. “The more challenging part is the ongoing operations and maintenance and ability for communities to maintain the systems. Systems will break, nobody's there to fix them, and there's little funding for that.”

And once systems are operational, their long-term economic viability largely rests on the value of the Power Purchasing Agreement (PPA) that is offered by the local utility operators.

“In order for that whole model to be successful, you need a better and more fair PPA price than what has typically been offered in the north. Typically the PPA will simply offer the avoided cost of diesel fuel, so whatever it costs to get a litre of diesel up to the community via winter road or barge,” Lovekin adds.

Renewable energy systems typically have lower operating and management costs, and Pembina and others are working to ensure PPA prices reflect true cost savings.

“The federal carbon tax coming into play will also make diesel systems even more costly, so there’s opportunity to look at a PPA price for renewable systems that will not pay the carbon tax, as well as other externalized costs such as diesel fuel spills, financial bailouts when winter roads deteriorate and fuel needs to be flown up. So addressing all of that in what gets offered via a fair and equitable PPA would be ideal,” Lovekin said.

On the community capacity side of the equation, initiatives such as the 20/20 Catalysts Program and the Indigenous Clean Energy Network are providing essential training, and mentorship for indigenous communities making the transition to renewable energy.

Nonetheless, Lovekin feels there is a critical need for “more training, skill development and job establishment to support the community getting involved in their own transition. There need to be barriers removed to have more capacity built and leadership come from within the community.”

That’s where the new federal funding could be a game-changer.

“The real test will be in the types of policies and programs that are developed and how they are designed to support energy autonomy and create economic development within and for Indigenous communities,” Lovekin said.  

Image: Solar panels in Old Crow, Yukon. Photo: Matt Jacques

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