Alberta sent a draft map on Thursday evening to industry showing where renewable energy projects will and won’t be allowed, which restricts developments in national parks and UNESCO heritage sites, and creates a buffer along the eastern slopes of the Rockies where wind projects would be forbidden.

It also provides more clarity on the government’s vision for keeping developments away from Alberta’s viewscapes — an area of debate and confusion since the province announced in late February that 35-kilometre “buffer zones” would be established around protected areas and so-called “pristine viewscapes.”

How is Alberta defining pristine viewscapes?

The government’s definition for its viewscapes focused heavily on the Rocky Mountains and heritage sites, Affordability and Utilities Minister Nathan Neudorf said in a Thursday interview.

“Globally, there is no uniform universal definition of pristine land because it differs in every single jurisdiction,” Neudorf said.

“When we talk about our pristine landscapes, I think most people immediately go to Banff and the majestic peaks, and we sought to protect our mountain ranges, our foothills, our UNESCO world heritage sites.”

Under the new regulations outlined in the map, Alberta’s UNESCO heritage sites and national parks will be no-go zones for all renewable developments, Neudorf said. To the edge of the Rockies, the province is implementing a 35-kilometre buffer zone in which no wind projects will be permitted, though solar developments will be allowed.

Alberta has also created visual impact assessment zones, most of which are isolated to southern Alberta, where all proposed renewable projects will be reviewed.

None of those zones are expected to affect ongoing oil and gas or forestry activity.

Southern Alberta is known for its windy and sunny conditions, making it a hot spot for renewables development.

There are currently several operating wind developments inside the province’s new no-go zone, including a 28-turbine Riverview wind farm and the 76 MW Castle Rock wind project just outside Pincher Creek. TransAlta also has several wind farms in the windy Pincher Creek area, including its 60-turbine Castle River project.

The province’s map is less restrictive than some had anticipated based off Alberta’s initial signals when it lifted the moratorium on new renewables projects on Feb. 28.

How does industry feel about the new guidelines?

The province is continuing to develop a final framework for renewable projects in Alberta. The full suite of regulations are expected to take shape by the end of the year.

But the map leaves several unknowns for industry, said Evan Wilson, vice-president of policy for the Canadian Renewable Energy Association (CanREA).

“I think this provides more clarity on the government’s intent than anything we’ve seen or heard before,” Wilson said. “But there’s still a lot of work that needs to be done to provide clarity for members who are making $100-, $200-, $300-million decisions on projects . . . We need more information than what is provided in a PDF map.”

The lack of rules to date has been criticized for creating uncertainty in the renewables sector. One developer of a solar project up for approval near Pincher Creek said last week it’s moving forward “amid a period of considerable policy and regulatory uncertainty.”

Jason Schneider, board member at Rural Municipalities of Alberta and reeve of Vulcan County, home to Canada’s largest solar farm, said reaction to the map from his peers in rural Alberta has so far been muted.

“I haven’t heard from any of our members with their hair on fire saying that they’re completely against it,” he said. “Hopefully we can get back to business.”

Releasing the map when the province lifted the moratorium more than two weeks ago would have saved a number of headaches, Schneider said, as debates swirled around the province’s definition of viewscapes and protected areas.

Neudorf said the province has been operating “as quick as reasonably possible.”

“We don’t want to rush things.”

What’s the expected impact of the new regulations?

It’s unclear how the final rules will affect ongoing proposals in Alberta.

The Pembina Institute, a clean energy think-tank, has estimated Alberta’s wind regulations would make 22 projects subject to a visual impact assessment or are in a no-go zone. Combined with the draft agricultural restrictions, 57 projects worth $14 billion could be affected, Pembina estimates.

Neudorf said Pembina’s estimates are possible, but developers have shown interest in changing the location or size of their projects.

“That’s kind of the point, is that we didn’t want a free-for-all where we sterilized agricultural land forever,” Neudorf said.

The Alberta Utilities Commission’s (AUC) review of renewable generation in the province, released Wednesday, said Alberta’s existing regulatory framework is “generally sufficient for the protection of environmental land.” It also said that if all renewable development needed to achieve net-zero occurred on prime agricultural land, less than one per cent of Class 2 land would be lost by 2041.

While many of the issues outlined in the AUC report have been ongoing for years, they didn’t justify the six-month moratorium, Wilson said. The report also recommended that if the province implements development no-go viewscape zones, that regulation should be “industry agnostic.”

“I think there’s a lot of misunderstanding around how well regulated the renewable sector is,” Wilson said. “There was no need for a moratorium to have these conversations . . . This is not the Wild West in terms of renewable energy.”

— With files from The Canadian Press

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How will the province and Alberta Electric System Operator (AESO) complete work on technical design changes by year’s end — and provide the sector with investment certainty — without making abrupt moves that trigger unintended consequences?

And will the changes stabilize and reduce electricity prices, which have jolted Alberta businesses and consumers?

The province’s affordability and utilities minister acknowledges it’ll be tricky to get it right.

“We are trying to find that balance,” Neudorf said in an interview.

“Will they be the same (power) price as they were 10 years ago? I don’t know . . . but I do know it will be stable and I do believe that it will be lower than the peaks that we’ve been hitting the last couple of years.”

The province said Monday it will adopt interim rules to limit the allowed practice of economic withholding by large natural gas generators.

The temporary steps will begin in July and continue until 2027, when a broader retooling of Alberta’s energy-only market is implemented.

Under the larger restructuring, proposed new rules will include day-ahead pricing for the Alberta Power Pool and potentially lifting the current wholesale price cap of $999 per megawatt-hour (MWh) during periods of scarcity.

Prices above this level would be set by the system operator, not generators, and include measures to limit the cap in these periods “once reasonable fixed cost recovery is achieved,” according to the AESO.

The grid operator could even implement negative prices.

“We’ve talked to a lot of market participants, and we say there are two ways for you to make (a) profit. One is you either make a lot on a few hours of running — or you make a little on a lot more hours of running, making it a bit more of a volume business,” Neudorf said.

“Our preference is that we’d see a bit of that stability and volume pricing here.”

However, industry experts point out electricity prices are already dropping. The regulated rate option for power has fallen from a record 31.9 cents per kilowatt-hour (kWh) in Calgary last August to 13 cents in March.

Prices are declining as new supply is expected to arrive this year.

“When the minister says these steps will meaningfully bring down prices, it sort of reminded me of showing up with an umbrella after a rainstorm and saying, ‘I’ll stop you from getting wet,’ ” University of Calgary economist Blake Shaffer said this week.

“You’re capping prices, but after the emergency.”

Albertans have been hammered by sizzling electricity prices over the past two years.

The interim changes on economic and physical withholding of generation should help, Neudorf said.

“I don’t know if it will further drop those prices, but I can tell you that . . . it will not allow it to go very high above that cap,” said the Lethbridge-East MLA.

“It should stabilize that market.”

For investors, it’s not clear what the future will hold.

The broader market overhaul won’t kick in until the end of 2026, although detailed design work on the restructured market is due by the end of the year.

Prolonged uncertainty and tinkering could freeze investment decisions for new power projects.

After the changes were announced Monday, the share prices of two of the largest publicly traded generators in the province dropped. TransAlta Corp. fell 4.7 per cent between Monday and Thursday, while Capital Power dipped 2.7 per cent.

As Scotiabank Global Equity Research analyst Robert Hope said in a report this week, Alberta’s power market change “leaves more questions than answers.”

“At first glance, we view this as a negative in the near term for the Alberta power market as it could limit short-term upward spikes in power pricing that offset periods of low pricing when wind and solar are abundant,” he wrote.

“That said, we have always expected pricing to moderate in 2024.”

A Peters & Co. report pointed out the province’s electricity market watchdog “backtested” the interim economic withholding rules, concluding power prices would have been 23 per cent lower over the past three years if the policy had been in place.

“The long-term impacts are more uncertain, as industry will likely argue that lower power pricing could disincentivize investment in new generation, in turn supporting higher prices.”

Generators are examining the proposed reforms as they prepare for a consultation process later this year.

Capital Power senior vice-president Pauline McLean said the company was encouraged by Neudorf’s remarks that investors in the market need the opportunity to earn a rate of return on, and of, their capital.

As for the interim changes surrounding economic withholding, she noted prices are already going down with new generation coming online.

“The government was clear that they have concerns about affordability and that was the impetus for bringing these regulations into effect. And so, we’re going to figure out how we navigate within a new set of rules,” McLean said in an interview.

“Our view would be there’s perhaps going to be a modest (price) impact, but that’s a trend that we were already starting to see in the market.”

The announcement of short-term measures starting this summer has already lowered prices in the forward market, said electricity consultant Sheldon Fulton.

The question is how the longer-term reforms will affect consumers.

“Remember, energy is only one-third of your bill. The other two-thirds of your electricity bill are a bunch of add-ons, and none of that is addressed,” he said.

“It’s a bit of a fix . . . anything is better than what we have.”

Chris Varcoe is a Calgary Herald columnist.

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The milestone has even surprised one of the economists who designed Alberta’s coal phaseout plan less than a decade ago.

In recent months, the province has experienced several hours in which coal has been completely absent from its electricity mix.

Alberta’s first coal-free hour came on Feb. 2 and lasted 11 hours.

It happened again in early March, with the province’s final two coal plants producing zero energy for nearly 48 hours between March 4 and 6, according to the Alberta Electricity System Operator’s (AESO) metered volume data.

The final step will come this summer when Capital Power’s Genesee 1 and 2 plants finish transitioning two coal-fired plants to natural gas. (The final plant, Genesee 2, is scheduled to shut down at the beginning of June.) As it stands, coal provides a maximum capacity of just 820 megawatts (MW) — less than four per cent of all available generation in Alberta, a steep decline from a decade ago, when coal provided 5,509 MW and 54 per cent of Albertans’ electricity needs.

“It wasn’t long ago that 80 per cent of electricity supply in Alberta came from coal; now we are starting to see hours where there is zero coal-fired generation in the province,” Blake Shaffer, electricity expert and economist at the University of Calgary, said in an email to Postmedia.

Alberta had 18 coal-fired plants in 2016. At the time, Alberta produced more coal pollution than all other Canadian provinces combined.

‘Arguably the largest emissions-reduction policy in Canadian history’

This year’s phaseout is being celebrated as the result of policy introduced under Rachel Notley’s NDP government, and continued by successive UCP governments.

“I think it’s arguably the largest emissions-reduction policy in Canadian history,” said Andrew Leach, economist at the University of Alberta. Leach chaired Notley’s climate leadership panel when the NDP was in government from 2015 to 2019, and led the design of Alberta’s coal phaseout plan.

Part of that was due to Alberta’s industrial carbon pricing framework, currently known as its Technology Innovation and Emissions Reduction Regulation (TIER). The policy resulted in heavy emitters such as coal plants paying significantly more for their pollution than lower-emitting energy producers, with costs increasing each year.

Adam Gaffney, manager of generation forecasting and resources adequacy at AESO, said the carbon pricing system was the “big driver” that got Alberta off coal.

Despite setting a 2030 full phaseout target, Leach said he was struck by how quickly companies such as ATCO, Capital Power and TransAlta announced the costly endeavour of transitioning operations to natural gas. (The Genesee repowering project, for context, was last projected to cost $1.35 billion.)

“This was by no means a conservative target at the time. I thought it was a very aggressive target,” Leach said. “The real shock for me probably came five years ago, when it became pretty clear that we were going to be off coal . . . much more rapidly than anyone thought.”

Coal phaseout ‘a fantastic case study of really good policy design’

Jason Kenney’s UCP government solidified the NDP’s industrial carbon pricing regime with its TIER system, Leach said.

The effort rivalled Ontario’s 11-year coal phaseout, completed in 2014. In 2003, coal provided a quarter of Ontario’s electricity supply.

“It’s a fantastic case study of really good policy design in that we set a target requiring all the coal plants to go away, but then we set up this economic backing, setting a price signal to allow companies to do it in their own way,” said Will Noel, electricity analyst at the Pembina Institute, a clean-energy think-tank.

The transition comes with major emissions-reduction gains: Getting off coal will reduce Alberta’s electricity emissions from about 50 megatonnes (MT) in 2005 to 16.5 MT projected for this year, according to AESO.

For context, Canada’s entire electricity grid produced 52 MT of emissions in 2021, according to the federal Ministry of Environment and Climate Change.

It also comes amid a surge in renewable power in Alberta.

“We thought it was pretty cool how . . . (last year) we were having hours where solar was producing more than coal for a couple hours at a time,” Noel said. “Only a year later, we’re having zero coal.”

— With files from Postmedia

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Think about the mandatory phaseout of coal-fired power generation, large losses at Alberta’s Balancing Pool, the rise of renewables, or the abandoned attempt to replace the energy-only market structure.

Today, another shift is coming — and it’s the largest revamp since the province deregulated the electricity market more than two decades ago, according to the head of the Alberta Electric System Operator (AESO).

AESO chief executive Michael Law rolled out the conceptual elements of the overhaul this week, with reforms expected to be in place by the end of 2026. It could include new elements such as negative wholesale power pricing and a day-ahead market.

The moves are designed to ensure Alberta’s electricity system is reliable and affordable, while decarbonizing the grid by 2050 — no easy feat.

“The realities of our power system are changing,” Law said in an interview Tuesday after speaking at the Independent Power Producers Society of Alberta (IPPSA) annual conference in Banff.

“We need to make some changes in order to have a stable market structure that can facilitate investment, but also ensure appropriate pricing and protect consumers,” he said.

“This is, without a doubt, the biggest shift that we had over 25 years.”

For Alberta’s power system, that’s saying something.

Alberta Power Pool prices have been volatile, jumping from an average of less than $47 per megawatt-hour (MWh) in 2020, to $162 two years later before dipping to $134 per MWh last year.

Demand has increased coming out of the pandemic and several grid alerts have underscored the bumpy transition.

The AESO, which manages and administers Alberta’s power system, is proposing a series of market reforms, part of what Law calls a “high-level blueprint.”

It’s not abandoning the current energy-only system for a capacity market — an idea proposed by the former NDP government but later halted by the UCP in 2019 — where generators are paid for having electricity available, regardless of how much is sent into the grid.

(In the energy-only market, generators are only paid for electricity produced and sold.)

In the short term, the province unveiled changes Monday to limit the current policy that allows economic withholding by generators. The shift is slated to take effect in July and remain in place until 2027.

The longer-term reform will include day-ahead pricing in the wholesale market to reduce price volatility, locking in prices before the operating day.

“We will know well in advance of the actual real-time which generation is available, how much of it is required, so we won’t find ourselves in situations where units that are needed are not actually online,” Law said.

“And it creates a much more stable price.”

If proposed changes are adopted, the Alberta Power Pool will also permit negative pricing, meaning “generators would actually pay to continue to generate and consumers would actually get paid for using,” Law noted.

It would also allow for pricing above the current wholesale price cap of $999 per megawatt-hour (MWh) in Alberta during limited periods of scarcity.

The idea of economic withholding — a feature of the current market that allows generators to offer electricity at prices “sufficiently above marginal cost that the generator is not dispatched, and the pool price is increased as a result,” according to the Market Surveillance Administrator — will also change.

With the proposed longer-term overhaul, higher prices during moments of scarcity will be set administratively by the AESO, “not left to market participants,” Law noted.

But in the complex world of electricity markets, details matter.

The effect on consumers, as well as companies looking to build new power generation as electrification continues, will be key.

The proposed changes are large and will add more uncertainty to Alberta’s power market, said Vittoria Bellissimo, CEO of the Canadian Renewable Energy Association.

“There’s confusion about what this means, not just for the renewable developers, but generators in general,” Bellissimo said in an interview Tuesday.

“It would be very difficult to go to an investment committee right now and say, ‘Alberta looks attractive,’ because we don’t know what it looks like.”

Edmonton-based Capital Power said it was encouraged by the government’s commitment to the energy-only market, while noting the details will be critical.

Shares in both Capital Power and TransAlta Corp., two of the province’s largest generators, both fell on Tuesday.

The temporary changes to economic withholding rules could crimp the ability of generators to recoup their capital costs and potentially affect future investment decisions, said Duane Reid-Carlson, CEO of electricity consultancy EDC Associates.

For consumers, he noted power prices are expected to fall in the next three to five years as a surge of new gas-fired electricity generation and renewable energy arrives on the scene.

The longer-term proposed changes are generally positive for generators, he said.

“Industry is eager to invest and get on with all of this. They just want to see some certainty,” Reid-Carlson said.

Adding a day-ahead market should help the system by allowing for better co-ordination and helping smooth out last-minute spikes — to a degree, said University of Calgary economist Blake Shaffer, an electricity industry expert.

Exploring negative power prices is a common feature in other electricity markets, he noted.

“We don’t have an investment problem for the next several years. But in the five-to-10-year period and beyond, the question marks will remain on how are we going to get the things built that we need,” Shaffer added.

Law said the AESO feels “reasonably comfortable” that supply levels will be adequate into the middle of the next decade, based on the new generation that is expected to come online. It also wants to ensure it compensates generating units that are flexible and dispatchable, ensuring the lights stay on.

The AESO will seek feedback on the proposed design changes, with the market’s technical design completed by year’s end and implemented by the end of 2026.

“This is a substantial change,” Law added.

Indeed, change is the one constant in the province’s ever-shifting power system.

Chris Varcoe is a Calgary Herald columnist.

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The federal government meanwhile says it has already granted Alberta an extension to spend the full $1-billion fund, arguing the province “ailed to spend a large portion of the fund created to give jobs to oil and gas workers laid off in the first months of the COVID-19 pandemic.

Alberta’s request to allocate the funding to site cleanup on Indigenous lands has received backing from chiefs from Treaty 6, 7 and 8 territories, and the Indian Resource Council.

At the heart of Alberta’s request is funding created by the federal government early in the COVID-19 pandemic that was structured to save jobs and jump-start efforts to reduce the number of abandoned wells in Alberta.

In late April 2020, the federal government announced a wide-scale economic response plan that included its Site Rehabilitation Program (SRP) — a $1-billion fund to chip away at Alberta’s backlog of abandoned oil and gas wells. The funding came as thousands of oilfield workers were unemployed during the height of COVID-19, resulting in more than 4,000 jobs being created.

With that program coming to a close, $137 million of that $1 billion in grant funding remains unused. The federal government is requesting it be returned to Ottawa, according to the Alberta government, which currently holds the money.

Cleaning up an abandoned well can cost between $100,000 to several million dollars, according to the federal government.

‘They’ve already allocated this on the books’: Jean

“Even though the money has lapsed, it’s just simply a time in the calendar,” said Alberta Energy Minister Brian Jean. He did not say why the funding hasn’t been fully spent.

“They’ve already allocated this on the books. Just let us keep it, manage it and clean this up.”

In a statement to Postmedia, Katherine Cuplinskas, press secretary to Deputy Prime Minister and Finance Minister Chrystia Freeland, said the federal government has asked the Alberta government several times to return the remaining SRP funds. The initial agreement required Alberta to return outstanding funds in May 2023.

“Given that (the Alberta government) failed to invest a large portion of the $1 billion we provided them, even with an extension of timelines, and that the economy is well into its recovery, we expect the Government of Alberta to abide by the agreement that they signed, and return all unspent funds, as other provinces have,” Cuplinskas wrote.

“Any allegation that the federal government is not helping Indigenous Peoples share in Canada’s economic prosperity, including from the energy industry, is false.”

Cuplinskas added that with the oil and gas sector’s recovery in recent years, Alberta should be able to return the remaining funds without issue.

An Enoch Cree Nation chief said the First Nation has a growing population and limited land base, meaning imminent land stewardship is needed.

“This is a liability of the lessees, and the Alberta government is holding them accountable through the Well Closure Program. However, time is not on our side,” said Chief Cody Thomas of the Enoch Cree Nation.

The SRP has resulted in 1,824 inactive well sites being closed amid the Indigenous community grant program, which set aside $133.3 million to clean up inactive wells in Indigenous communities.

‘This is essentially now an industry subsidy’: lawyer

Martin Olszynski, a University of Calgary resource lawyer and frequent critic of the province’s remediation policies, said the federal program “wasn’t intended to subsidize well cleanup” despite it indirectly having that effect.

“The primary rationale was about sustaining jobs in the context of broader COVID relief,” Olszynski said. As oil and gas companies have rebounded sharply from low commodity prices, both preceding and during the pandemic, some have in recent years posted all-time record profits.

In that context, the SRP’s intended use has come and gone, Olszynski said.

“This is essentially now an industry subsidy. What we’re talking about here is subsidizing well cleanup that should have been done and should be the responsibility of the operators of those wells,” he said. The funding does present economic opportunities for Indigenous communities, he said, but questioned why oil and gas companies aren’t being required to clean up those wells.

Internal documents obtained in January by University of Calgary researcher Drew Yewchuk suggested Alberta’s energy regulator believes the total cost of well cleanup in Alberta to be about $88 billion — significantly more than the $33 billion it publicly estimated earlier this year.

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A lot has changed since then, including the collapse and recovery in oil prices, growing climate concerns, prognostications of peak demand and the imminent completion of the Trans Mountain expansion.

During that time, not a single greenfield oilsands mine has moved forward.

But Fort McKay First Nation Chief Raymond Powder hopes that might change.

The First Nation has signed a memorandum of understanding to examine “a prospective oilsands mine development on our reserve,” Powder said Thursday in an interview.

And it inked the deal with Suncor.

“Fort McKay First Nation wants to continue growing, just like any other First Nation or other communities right across Canada,” he said Thursday.

“This will be not only a financial investment, but also a return for our Nation . . . This is an opportunity for us to manage prosperity, as opposed to managing poverty.”

The agreement is a preliminary step that would explore a prospective development on an oilsands lease about 20 kilometres northeast of Fort McKay.

The property is smack dab in the middle of several oilsands developments in the vicinity. It was considered for possible joint development by Shell Canada in 2006, although that venture didn’t proceed.

As part of the new agreement, Suncor will conduct early stage technical and feasibility assessments, including a drilling program, to examine the size and quality of the recoverable bitumen.

Suncor executive vice-president of oilsands Peter Zebedee said the agreement could potentially provide the company’s existing operations — including the nearby Fort Hills mine, along with Syncrude’s Aurora operations — with bitumen supply options past 2040.

(Suncor owns 58 per cent of Syncrude and is the operator of the joint venture.)

Zebedee said the company is still in the early stages of assessing the resource and completed its first drilling season, with more work coming up next year. That will provide necessary technical information to the partners by the end of 2025.

“It’s really too early to say what the commercial opportunities are,” Zebedee said.

“But given the proximity of this lease to both the Syncrude Aurora operations, as well as our Fort Hills assets, there are some synergies we would be looking to extract that are promising from an economic standpoint.”

Powder noted Nation members held a referendum on the use of the land as part of its treaty land entitlement settlement in 2003, and they supported it being earmarked for oilsands development.

He said the agreement is a strategic partnership with Suncor, one of the country’s largest oilsands producers.

“Fort McKay would not be able to do this independently because we don’t have the resources, nor the experience. And so we’re utilizing and capitalizing on that relationship we have with Suncor,” he added.

In 2017, Fort McKay and the Mikisew Cree First Nation independently financed $545 million to buy a 49 per cent stake in Suncor’s oilsands storage facilities.

Fort McKay, which has 900 band members, has built up several successful companies that are active in the energy industry.

However, developing an oilsands project would give the Nation direct control over the sector’s development and environmental standards.

“It would leverage the opportunities to actually be in the driver’s position,” Powder said.

“We can have that authority and that sovereignty, asserting our positions with respect to stewardship of the land and the water and the air.”

Greg Stringham, former vice-president of oilsands at the Canadian Association of Petroleum Producers, said the Fort McKay lease has been discussed as a potential development dating back more than a decade.

“I am glad to see this is moving ahead,” he said.

“It would give them a much more detailed level of control over their own mine.”

It won’t be simple, however.

Aside from the huge upfront capital costs to develop a mine and questions about future oil demand in the coming years, the political hurdles appear enormous.

The ill-fated Frontier oilsands mining project was pitched by Vancouver-based Teck Resources and approved by a joint federal-provincial review panel.

After spending more than $1 billion advancing the project, Teck gave up on getting federal approval in 2020, less than one week before the Trudeau government was expected to make a final decision.

The $20.6-billion project had signed support agreements with all 14 Indigenous groups in the area.

Don Lindsay, Teck’s CEO at the time, said it had become clear there was no path forward for the project.

Advancing a new oilsands mine in Canada today would be a “significant uphill battle,” given federal policy, said oilsands expert Ben Brunnen, a partner with Garrison Strategy.

“When Frontier was set to be finalized, it had the best emissions profile and an exceptionally strong First Nations relationship,” he said.

“If Frontier can’t advance, what can? That really is the question here.”

Alvaro Pinto, CEO of the Fort McKay Oilsands Development Project, noted the federal government recently amended the 2007 Fort McKay First Nations oilsands regulations.

The project, if approved, could begin operating by around 2036.

Premier Danielle Smith said the agreement and potential for a new oilsands project is one that the provincial government supports, noting it would generate additional revenues for the Fort McKay First Nation.

“To see a proposal where a band is going to be in on the ground floor of production, it just warms my heart,” Smith told reporters Thursday.

“I would hope that the federal government wouldn’t stand in the way of the aspiration of a First Nation to develop their own source revenue . . . I do hope we do see more of it.”

Chris Varcoe is a Calgary Herald columnist.

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However, don’t expect a major new export pipeline project in Western Canada’s future.

Instead, incremental expansions and plans to tweak existing lines are in the works to bolster the transportation capacity for oil coming out of Canada.

During the company’s investor day on Wednesday, Enbridge indicated it expects to increase the capacity of its Mainline oil pipeline network by 200,000 barrels per day (bpd) — starting in 2026 — as production climbs in the Western Canadian Sedimentary Basin.

According to the Calgary-based company, additional pipeline capacity will be needed as petroleum producers ramp up output by 500,000 bpd by the end of 2025.

Enbridge’s Mainline system, which moved about 3.2 million bpd during the fourth quarter, is already full.

The federally owned Trans Mountain pipeline is expected to start commercial operations of its expansion project in the coming months.

“As has happened in the past, as soon as people think there’s too much pipeline capacity, there’s more production being produced,” Enbridge CEO Greg Ebel told reporters after the meeting.

“There probably won’t be a major pipeline build, but at this point in time, I think with the volumes we’re talking about . . . with low capital and optimization of the current assets that we have, we can add those additional volumes.”

Producers in Western Canada have been cranking up production over the past year as global demand reaches record levels — more than 102 million barrels per day — and with the anticipated completion of the Trans Mountain expansion.

On Tuesday, oilsands producer Cenovus Energy laid out plans to boost its production to about 950,000 barrels of oil equivalent (boe) per day by 2028, up about 150,000 bpd from fourth-quarter volumes.

Canadian Natural Resources pumped out an all-time high of 1.42 million boe per day during the October-to-December period, up 9.6 per cent from a year earlier. And Suncor Energy reported fourth-quarter output climbed to 808,000 boe per day, a six per cent jump from a year earlier.

“Supply growth has surprised,” Colin Gruending, Enbridge’s president of liquids pipelines, said during Wednesday’s meeting. “We are seeing green shoots in the oilsands portfolio.”

Total oil production from Western Canada, which averaged 4.7 million barrels per day last year, could approach five million bpd this year, and get close to 5.4 million bpd by the end of this decade, said Kevin Birn, a vice-president with S&P Global Commodity Insights.

South of the border, production has also set new output records over the past year, averaging 13.3 million bpd in December, according to the U.S. Energy Information Administration.

“Canadian oil and gas is going to grow, U.S. production will hit records and the need for transportation has never been greater,” said Birn.

“A case could be made for a new incremental pipeline, if someone were brave enough to take on that venture.”

For years, that new pipeline was the Trans Mountain expansion (TMX), which was approved by Canadian regulators and the federal government in 2016.

The pipeline is expected to begin commercial operations during the second quarter, transporting oil from Alberta to the B.C. coast for export. The federal Crown corporation that runs the pipeline called for oil from shippers last week.

The expansion will increase the existing pipeline’s capacity by 590,000 barrels per day.

The project has been delayed several times — it was expected at one point to be completed by late 2019 — and its price tag has skyrocketed above $30.9 billion from $5.4 billion.

But given the demise of three other pipeline projects in the past decade — Energy East, Keystone XL and Northern Gateway — experts don’t expect to see another major export project proposed in Canada any time soon.

Chris Bloomer, former CEO of the now-defunct Canadian Energy Pipeline Association and a former oilpatch executive, said oilsands producers are taking projects off the shelf to increase output.

Once the Trans Mountain expansion fills up, more egress out of Western Canada will be needed.

“Everybody will be gun-shy about proposing anything new. They have learned from the past,” Bloomer said in an interview.

“It is going to be very difficult — financially, organizationally, emotionally and politically. I don’t think we will be in a spot to have a major new project come to the table.”

Asked under what scenario the federal government would support additional oil pipelines, Natural Resources Minister Jonathan Wilkinson said it’s important to get TMX into operation. He also pointed to forecasts by the International Energy Agency showing demand for fossil fuels hitting a peak this decade.

“If folks want to bring forward proposals with respect to pipelines that they’re interested in building, obviously we would consider that,” Wilkinson said.

“But I would also say that to build a pipeline is multibillions of dollars, and one has to have some degree of certainty around the projections for demand over decades.”

Optimization and expansion of existing pipelines, along with increasing the amount of crude moved by rail, are potential solutions to allow transportation to keep up with output later in the decade.

Ebel said the company can spend modest amounts of capital on expansions and use drag-reducing agents to boost the capacity of its Mainline system.

“We can continue to be bullish. I think we can continue to be optimistic about the opportunities for the Western Canadian Sedimentary Basin,” he added.

“And I think we can continue to be optimistic about the pipeline capabilities, beyond a big build out, to actually add those volumes.”

Chris Varcoe is a Calgary Herald columnist.

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But feelings of frustration are also growing on the other side.

One of the country’s largest oilsands producers said Tuesday it’s still not seeing enough clarity around promised federal incentives for the Pathways Alliance group to start building its $16.5-billion carbon capture and storage network in northern Alberta.

The proposed development is a foundational part of the sector’s plan to attain net-zero emissions by 2050.

An executive with Cenovus Energy, one of the members of the alliance of oilsands producers, said that policy certainty is also being affected by a series of federal initiatives, such as the incoming emissions cap on the Canadian oil and gas sector.

“These massive projects take a lot of thought and they take a lot of time. That’s why I do get a bit frustrated when I hear some politicians and others publicly state that we should already have shovels in the ground for the Pathways CCS project,” said Cenovus Energy’s chief sustainability officer Rhona DelFrari.

“With what we know today . . . the government funding partnerships in Canada are not enough for large-scale CCS to proceed in the oilsands.”

The remarks were made at the company’s investor day in Toronto, less than a week after leaders with the Pathways Alliance met virtually with federal Natural Resources Minister Jonathan Wilkinson.

The back-and-forth volley between the Trudeau government and the sector is centred on the group’s massive carbon capture, utilization and storage (CCUS) project, and the level of federal incentives that are required to see it proceed.

The proposed development could eventually connect more than 20 oilsands facilities in Alberta through a CO2 pipeline to an underground storage hub near Cold Lake.

A final investment decision hasn’t been made, although planning work continues.

The Pathways Alliance includes Cenovus, Suncor Energy, Imperial Oil, MEG Energy, Canadian Natural Resources and ConocoPhillips Canada.

DelFrari noted significant engineering, environmental fieldwork and consultation with Indigenous communities have already been completed in preparation for “imminent regulatory applications.”

However, there’s a “lack of clarity” around the draft regulations surrounding the federal investment tax credit for carbon capture projects — expected to cover up to 50 per cent of capital costs for equipment on such developments — that may prevent companies from accessing its full value, she said.

The companies also need to understand how promises of federal carbon contracts for difference will work. Such agreements are intended to provide long-term certainty to producers on the future national price of carbon, which is slated to head up to $170 a tonne by 2030.

DelFrari said Canada is adopting a complex “stick-based approach with some carrots thrown in,” unlike the United States, which has a straightforward incentive for CCUS initiatives based on each tonne of stored CO2.

“First of all, we can’t start construction of the CO2 pipeline or sequestration hub without regulatory approval, and that process, as I mentioned, is still underway,” she said.

“Without competitive fiscal incentives, our country risks being left out as large-scale emissions reduction investments are developed and deployed elsewhere where they get the best returns.

“We’re also dealing in Canada with significant policy uncertainty right now . . . The result is a lack of clarity that companies need to make long-term, multi-decade, multibillion-dollar decarbonization investment decisions.”

The blunt talk comes after Wilkinson publicly chastised the oilsands group in an interview last month with the Calgary Herald.

The natural resources minister called out the oilsands group, saying it needed “to start to show actual progress on the ground” and not merely run a public relations campaign about its proposed decarbonization plans.

On Tuesday, the natural resources minister’s press secretary said Wilkinson delivered the same message to the oilsands group last week, and the alliance members know the necessary details of the federal investment tax credit, which has not yet been formally passed.

“He is getting more frustrated as they continue to drag their heels, despite the federal government delivering on everything that is promised,” said Carolyn Svonkin.

“In order for talks to remain more productive, they need to do more of their homework.”

Discussions continue between the oilsands industry and the federal and Alberta governments. The provincial government has previously pledged to provide a 12 per cent grant on eligible capital costs for CCUS projects.

“We need the federal government to do its part and step up with supports for capital and operating costs,” Alberta Energy Minister Brian Jean said Tuesday in a statement.

With the oilpatch the largest emitting sector in the country, and the federal government needing to see progress from all sectors to reach its 2030 and 2050 climate targets, both sides will need to strike a deal in short order.

However, until they’re all are on board, expect the testy negotiations to continue, both in private and in public.

“These CCUS projects are absolutely massive undertakings, in terms of logistics and costs. They’re also absolutely going to be needed,” said Marla Orenstein, director of the Natural Resources Centre at the Canada West Foundation.

“While there has been a lot of goodwill on both these sides . . . when it comes down to the actual details of implementation, the cracks start to show.”

Chris Varcoe is a Calgary Herald columnist.

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One solar developer says it’s awaiting direction from the Alberta Utilities Commission (AUC), but is moving forward with the project “amid a period of considerable policy and regulatory uncertainty.”

As part of its proposed regulations for the renewables sector announced on Feb. 28, the province said it will no longer allow renewable development on Class 1 and 2 lands — though exceptions will be made if developers can show crops or livestock can exist alongside the project.

The AUC estimates seven applications are currently proposed on Class 1 and 2 lands, the commission said in an email to Postmedia. (Class 1 and 2 lands are designated prime agricultural land, meaning they’re optimal for growing high yields of crops.)

Among them are the 300-megawatt Dolcy Solar project in Provost, another 300 MW project by Eastervale Solar Inc., also in Provost, and a 112 MW solar project beside Edmonton International Airport.

The Logic first reported several solar projects could be affected by Alberta’s proposed regulations.

It’s unclear how the projects could be affected by the new regulations because project areas may have a mix of different classes of land, the AUC said, meaning some projects could be on a sliver of Class 2 land and others could be fully sitting on Class 2 land.

Developer forging ahead despite ‘regulatory uncertainty’

Brookfield’s Sunrise Solar Project — a 75 MW, 500-acre development near Pincher Creek in southern Alberta — is among the projects that could be affected.

Evolugen, a subsidiary of Brookfield Renewable Partners, estimates the project will annually generate 180 gigawatt hours (GWh) of renewable energy — enough, it says, to power more than 25,000 homes.

The developer announced several changes to the project last December that would decrease the project’s agricultural footprint by 13 per cent and distance itself from Pincher Creek’s town boundary.

“With the government’s announcement last week, we’re awaiting further direction from the AUC on next steps on our project and any further information required,” Mike Peters, director of public affairs for Evolugen, wrote in a statement to Postmedia. The developer said it’s considering integrating agrivoltaics into its design by using sheep grazing.

“We believe that Sunrise Solar is a high-quality project and are committed to advancing it amid a period of considerable policy and regulatory uncertainty for the renewable sector.”

Combined, the seven projects would bring 843 MW of renewable power generation plus 300 MW of battery storage. For comparison, the Travers Solar Project — Alberta’s largest and one of the biggest in North America — is capable of producing 465 MW of power.

When asked whether the province has metrics on how it expects the proposed regulations will affect renewables development in Alberta, Ashley Stevenson, press secretary to Affordability and Utilities Minister Nathan Neudorf, directed Postmedia to the minister’s comments at a Feb. 28 news conference.

Alberta plans to advance its policies and regulatory changes before the end of 2024, Neudorf wrote to the AUC on Feb. 28. In the meantime, the AUC has implemented temporary requirements for renewable project applications, which include agricultural effects and the potential for co-location activities, such as grazing or haying that can be integrated into projects.

The “agriculture first” approach is included in Alberta’s proposed changes, which would also make developers responsible for reclamation costs through a bond or security.

There were 26 solar projects affected by the renewables pause, according to the AUC’s most recent data, along with one power plant and one wind power plant application. In total, 3,645 MW of renewable generation and 460 MW of storage are in the AUC’s approvals pipeline.

The following projects are the seven applications currently proposed to sit on Class 1 and 2 lands:

• Airport City Solar: Planned for construction at Edmonton International Airport, the 112 MW project at a cost of $169 million is being managed by Alpin Sun, a large German solar developer with a handful of major projects in Texas.
• Dolcy Solar: This 300 MW project slated to be built in Provost, Alta., comes with 100 MW in battery storage. It’s being managed by Calgary-based Westbridge Renewable Energy Corporation.
• Eastervale Solar: The project managed by Eastervale Solar Inc. — a subsidiary of WestBridge — is projected to bring 300 MW of power and 200 MW of battery storage. It’s expected to be built near Provost, Alta. and comes with a $415-million price tag, according to the province.
• Sunrise Solar: The 75 MW project by Evolugen, a subsidiary of Brookfield Renewable Partners, is proposed to occupy about 500 acres near Pincher Creek, Alta.
• Peter Lougheed Solar: The project is owned by PACE Canada and proposed for construction in the Village of Lougheed, located between Camrose and Wainwright in Central Alberta. It would come with 30.8 MW of generation.
• Ponoka Solar: Proposing 23.2 MW of capacity, Acestes Power ULC is seeking approval for the project in Ponoka, located just north of Red Deer.
• Three Hills Solar: The relatively small solar project is applying for residence in Three Hills, Alta., where it would bring an additional 18 MW of capacity. Three Hills Power Corp. last September purchased the project from Abacus Power Ltd.

X: @mattscace67

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One day after the UCP government released a new budget with a narrow $367-million surplus, oilsands producer MEG Energy indicated shippers were given notice to begin putting oil into the Trans Mountain expansion (TMX) development.

The project is designed to almost triple the capacity of the existing Trans Mountain pipeline, which moves oil from Alberta to the B.C. coast.

It’s expected to shrink the price differential between U.S. benchmark West Texas Intermediate crude and Western Canadian Select (WCS) heavy crude, which would bolster energy revenues to the province.

During a call with analysts Friday, MEG chief executive Derek Evans said the company, which has committed to moving oil on TMX, was told to prepare for the export pipeline to begin filling up.

“TMX did issue a call for line-fill yesterday. As a matter of fact, they are looking for 2.1 million barrels in April and another 2.1 million barrels in May. So, we see this as incredibly positive,” Evans said.

It’s “good news for not only us but really everybody in the heavy oil business.”

Include the Alberta treasury in that mix.

The pipeline expansion project has been more than a decade in the making, with the final price tag expected to top $31 billion.

It will help the oilsands sector get more barrels into export markets — including Asia — and allow domestic producers to increase output without overwhelming the existing transportation system.

According to Thursday’s provincial budget, every $1-a-barrel drop in the price discount facing Western Canadian Select crude would add $600 million to government revenues.

The new budget forecasts the price differential for WCS will drop from an average of $17.30 a barrel for the fiscal year ending this month, to $16 in the new budget year — and to $13.60 in 2026-27.

“TMX matters because it will determine, in part, the prices that can be earned by Alberta producers,” said economist Marc Desormeaux with Desjardins.

“If for some reason there are delays . . . that could put pressure on the Western Canadian Select discount and ultimately weaken revenues that the government collects as oil royalties.”

The existing 1,150-kilometre Trans Mountain pipeline ships oil from the Edmonton area to a terminal in Burnaby, B.C. The expansion will increase its capacity to 890,000 barrels per day from 300,000.

Due to surging oilsands output and insufficient pipeline capacity coming out of Western Canada over the past decade, the price discount has soared at times, exceeding US$50 a barrel in 2018.

That prompted the Alberta government to temporarily adopt production quotas.

With the province forecasting a small surplus in the new fiscal year, Premier Danielle Smith said Friday that Alberta’s finance minister “is nervous because we don’t know what oil and gas prices are going to look like over the coming years.”

The premier hailed Evans’ comments, noting she was crossing her fingers the project would be online by the third quarter and increase Alberta’s export capacity.

“That’s good news,” she told reporters.

“If we’re now seeing an increase in our production by 600,000 barrels per day, you can just do the math on that, it’s about $75 a barrel . . . we get about one-third of that in royalties. That’s a pretty significant number.”

Trans Mountain Corp., the federal Crown corporation that operates the pipeline, did not comment Friday on the matter.

In an interview last fall, TMX chief executive Dawn Farrell said the expansion is projected to generate about $40 billion of royalties and taxes to Alberta over two decades.

The project has been grappling with delays due to drilling challenges in the final construction stretch in British Columbia’s Fraser Valley.

Earlier this week, the Crown corporation announced it had made progress and was working toward anticipated commercial operations beginning during the second quarter.

In a recent regulatory filing with the Canada Energy Regulator, the corporation said it expected the price tag to be about 10 per cent higher than last spring’s $30.9-billion cost estimate.

Analyst Phil Skolnick of Eight Capital said the startup of TMX should lower the price differential for WCS and remove the risks of it widening significantly as Canadian oil production continues to set records.

“We are getting close, if we’re not already there, of basically having supply outpacing pipeline capacity out of Western Canada for oil,” he said.

“For Canadian oil in general, it provides room for growth.”

The provincial budget forecasts West Texas Intermediate crude prices will average US$74 a barrel in the new fiscal year.

Adam Hardi, a vice-president with Moody’s Investors Service credit rating agency, called that forecast “relatively conservative,” noting it’s below current oil prices of almost $80 a barrel.

The pending startup of TMX should reduce another potential headwind for an Alberta budget that has little room for error.

“It is certainly a big benefit to the province,” said Pedro Antunes, chief economist with the Conference Board of Canada.

“If we hadn’t seen the (green) light on it coming into production, that would be a downside risk.”

Chris Varcoe is a Calgary Herald columnist.

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