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Crosbie Hydro Energy Action Plan outlines rate mitigation for Muskrat Falls, leveraging Nalcor oil revenues, export sales, Holyrood savings, and potential Hydro-Quebec taxation to keep Newfoundland and Labrador electricity rates near 14.67 cents/kWh.

Key Points

PC plan to cap post-Muskrat rates by using Nalcor revenues, exports, and savings, with optional Accord funds.

✅ $575.4M yearly to hold rates near 14.67 cents/kWh

✅ Sources: Nalcor oil $231M, Holyrood $150M, rates/dividends $123.4M

✅ Options: export sales, restructuring, Atlantic Accord, HQ tax

Newfoundland and Labrador PC Leader Ches Crosbie says Muskrat Falls won't drive up electricity rates, a goal consistent with an agreement to shield ratepayers from cost overruns, if he's elected premier.

According to Crosbie, who presented the party's Crosbie Hydro Energy Action Plan — acronym CHEAP — at a press conference Monday, $575.4 million is needed per year in order to keep rates from ballooning past 14.67 cents per kilowatt hour.

Here's where he thinks the money could come from:

• Hydro rates and dividends — $123.4 million
• Export sales — $40.1 million
• Nalcor restructuring — $30 million
• Holyrood savings — $150  million
• Nalcor oil revenue — $231 million

The oil money, Crosbie said, isn't going into government coffers but being invested into the offshore which, he said, is a good place for it.

"But the plan from the beginning around Muskrat Falls was that if there was need for it — for mitigation for rates — that those revenues and operating cash flows from Nalcor oil and gas would be available to be recycled into rate mitigation, as reflected in a recent financial update on the pandemic's impact. and that's what we're going to have to do," he said.

According to Crosbie, his numbers come from the preliminary stage of the Public Utilities Board process, even as rate mitigation talks have lacked public details.

This is a recent aerial view of the Muskrat Falls project in central Labrador. The project is more than 90 per cent complete, with first power forecast for late 2019, alongside Ottawa's $5.2B support for the project. (Nalcor)

"I'm telling you this is the best information available to anyone outside of government," he said. "We're working on what we can."

The PUB estimated Nalcor restructuring could save between $10 million and $15 million, according to Crosbie, but he figures there's "enough duplication and overpayment involved in the way things are now set up that we can find $30 million there."

Currently, provincial ratepayers pay about 12 cents per kilowatt hour as electricity users have started paying for Muskrat Falls costs.

Crosbie's $575.4-million figure would put rates at 14.67 cents per kilowatt-hour in 2021, where his plan pledges to keep them.

A recent Public Utilities Board Report says there's a potential $10 million to $15 million in savings from Nalcor, but Crosbie says he can find $30 million. (CBC)

"The promise is that Muskrat Falls, when it comes online — comes in service — will not increase your rates. Between now and when that happens there are rate increases already in the pipeline up to that level of [14.67 cents per kilowatt-hour] … so that is the baseline target rate at which rates will be kept.

"In other words, Muskrat will not drive up prices for electricity to consumers beyond that point."

In addition to those savings, Crosbie's plan outlined two further steps.

"We think it could be done out of the resources that I've just identified now, but if there's a problem with that, and as a temporary measure, we can use a modest amount of the Atlantic Accord review, fiscal review, revenues," he said.

Plan 'nothing new'

Premier Dwight Ball slammed the plan at the House of Assembly on Monday, saying it lacked insight.

"It was a copy and paste exercise," he told reporters. "There's nothing new in that plan. Not at all."

"We're not leaving any stone unturned of where the opportunity would be to actually generate revenue," he said.  "We are genuinely concerned about rate mitigation and we've got to get a plan in place."

Potential to tax Hydro-Québec

Crosbie also said there's potential to tax Hydro-Québec.

According to Crosbie, tax exemptions that expired in 2016 allow the province to tax exports from the Upper Churchill, which, he said, could result in "hundreds of millions or billions" in revenue.

"It's not my philosophy to immediately go and do that because that would generate litigation — who needs more of that? — but we do need to let Quebec know that we're very aware of that, and aware of that opportunity, and invite them to come talk about a whole host of issues," Crosbie said.

Crosbie said the tax would also have to be applied to domestic consumption.

"But so massive is the potential revenue from the Upper Churchill export that there would be ways to mitigate that and negate the effect of that on consumers in the province."

Crosbie said with the Atlantic Accord revenue, he could still present a balanced budget by 2022.

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ERCOT Ancillary Services Clawback and VOLL Pricing summarize PUCT and IMM actions on load shed, real-time pricing adders, clawbacks, and settlement corrections after the 2021 winter storm in the Texas power grid market.

Key Points

Policies addressing clawbacks for unprovided AS and correcting VOLL-based price adders after load shed ended in ERCOT.

✅ PUCT ordered clawbacks for ancillary services not delivered.

✅ IMM urged price correction after firm load shed ceased.

✅ ERCOT's VOLL adder raised costs by $16B during 32 hours.

Potomac Economics, the Independent Market Monitor (IMM) for the Electric Reliability Council of Texas (ERCOT), filed a report with the Public Utility Commission of Texas (PUCT) that certain payments were made by ERCOT for Ancillary Services (AS) that were not provided, even as ERCOT later issued a winter reliability RFP to procure capacity during subsequent seasons.

According to the IMM (emphasis added):

There were a number of instances during the operating days outlined above in which AS was not provided in real time because of forced outages or derations. For market participants that are not able to meet their AS responsibility, typically the ERCOT operator marks the short amount in the software. This causes the AS responsibility to be effectively removed and the day-ahead AS payment to be clawed back in settlement. However, the ERCOT operators did not complete this task during the winter event, echoing issues like the Ontario IESO phantom demand that cost customers millions, and therefore the "failure to provide" settlements were not invoked in real time.

Removing the operator intervention step and automating the "failure to provide" settlement was contemplated in NPRR947: Clarification to Ancillary Service Supply Responsibility Definition and Improvements to Determining and Charging for Ancillary Service Failed Quantities; however, the NPRR was withdrawn in August 2020 amid ongoing market reform discussions because of the system cost, some complexities related to AS trades, and the implementation of real-time co-optimization.

Invoking the "failure to provide" settlement for all AS that market participants failed to provide during the operating days outlined above will produce market outcomes and settlements consistent with underlying market principles. In this case, the principle is that market participants should not be paid for services that they do not provide, even as a separate ruling found power plants exempt from providing electricity in emergencies under Texas law, underscoring the distinction between obligations and settlements. Whether ERCOT marked the short amount in real-time or not should not affect the settlement of these ancillary services.

On March 3, 2021, the PUCT ordered (a related press release is here) that:

ERCOT shall claw back all payments for ancillary service that were made to an entity that did not provide its required ancillary service during real time on ERCOT operating days starting February 14, 2021 and ending on February 19,2021.

On March 4, 2021, the IMM filed another report and recommended that:

the [PUCT] direct ERCOT to correct the real-time prices from 0:00 February 18,2021, to 09:00 February 19, 2021, to remove the inappropriate pricing intervention that occurred during that time period.

The IMM approvingly noted the PUCT's February 15, 2021 order, which mandated that real-time energy prices reflect firm load shed by setting prices at the value of lost load (VOLL).1

According to the IMM (emphasis added):

This is essential in an energy-only market, like ERCOT's, where the Texas power grid faces recurring crisis risks, because it provides efficient economic signals to increase the electric generation needed to restore the load and service it reliably over the long term.

Conversely, it is equally important that prices not reflect VOLL when the system is not in shortage and load is being served, and experiences in capacity markets show auction payouts can fall sharply under different conditions. The Commission recognized this principle in its Order, expressly stating it is only ERCOT's out-of-market shedding firm load that is required to be reflected in prices. Unfortunately, ERCOT exceeded the mandate of the Commission by continuing to set process at VOLL long after it ceased the firm load shed.

ERCOT recalled the last of the firm load shed instructions at 23:55 on February 17, 2021. Therefore, in order to comply with the Commission Order, the pricing intervention that raised prices to VOLL should have ended immediately at that time. However, ERCOT continued to hold prices at VOLL by inflating the Real-Time On-Line Reliability Deployment Price Adder for an additional 32 hours through the morning of February 19. This decision resulted in $16 billion in additional costs to ERCOT's market, prompting legislative bailout proposals in Austin, of which roughly $1.5 billion was uplifted to load-serving entities to provide make-whole payments to generators for energy that was not needed or produced.

However, at its March 5, 2021, open meeting (related discussion begins around minute 20), although the PUCT acknowledged the "good points" raised by the IMM, the PUCT was not willing to retrospectively adjust its real-time pricing for this period out of concerns that some related transactions (ICE futures and others) may have already settled and for unintended consequences of such retroactive adjustments.  

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Yukon SMR Feasibility Study examines small modular reactors as low-emissions nuclear power for Yukon's grid and remote communities, comparing costs, safety, waste, and reliability with diesel generation, renewables, and energy efficiency.

Key Points

An official assessment of small modular reactors as low-emission power options for Yukon's grid and remote sites.

✅ Compares SMR costs vs diesel, hydro, wind, and solar

✅ Evaluates safety, waste, fuel logistics, decommissioning

✅ Considers remote community loads and grid integration

The Yukon government is looking for ways to reduce the territory's emissions, and wondering if nuclear power is one way to go.

The territory is undertaking a feasibility study, and, as some developers note, combining multiple energy sources can make better projects, to determine whether there's a future for SMRs — small modular reactors — as a low-emissions alternative to things such as diesel power.

The idea, said John Streicker, Yukon's minister of energy, mines and resources, is to bring the SMRs into the Yukon to generate electricity.

"Even the micro ones, you could consider in our remote communities or wherever you've got a point load of energy demand," Streicker said. "Especially electricity demand."

For remote coastal communities elsewhere in Canada, tidal energy is being explored as a low-emissions option as well.

SMRs are nuclear reactors that use fission to produce energy, similar to existing large reactors, but with a smaller power capacity. The International Atomic Energy Agency (IAEA) defines reactors as "small" if their output is under 300 MW. A traditional nuclear power plant produces about three times as much power or more.

They're "modular" because they're designed to be factory-assembled, and then installed where needed. 

Several provinces have already signed an agreement supporting the development of SMRs, and in Alberta's energy mix that conversation spans both green and fossil power, and Canada's first grid-scale SMRs could be in place in Ontario by 2028 and Saskatchewan by 2032.

A year ago, the government of Yukon endorsed Canada's SMR action plan, at a time when analysts argue that zero-emission electricity by 2035 is practical and profitable, agreeing to "monitor the progress of SMR technologies throughout Canada with the goal of identifying potential for applicability in our northern jurisdiction."

The territory is now following through by hiring someone to look at whether SMRs could make sense as a cleaner-energy alternative in Yukon. 

The territorial government has set a goal of reducing emissions by 45 per cent by 2030, excluding mining emissions, even as some analyses argue that zero-emissions electricity by 2035 is possible, and "future emissions actions for post-2030 have not yet been identified," reads the government's request for proposals to do the SMR study. 

Streicker acknowledges the potential for nuclear power in Yukon is a bit of "long shot" — but says it's one that can't be ignored.

"We need to look at all possible solutions," he said, as countries such as New Zealand's electricity sector debate their future pathways.

"I don't want to give the sense like we're putting all of our emphasis and energy towards nuclear power. We're not."

According to Streicker, it's nothing more than a study at this point.

Don't bother, researcher says
Still, M.V. Ramana, a professor at the School of Public Policy and Global Affairs at the University of British Columbia, said it's a study that's likely a waste of time and money. He says there's been plenty of research already, and to him, SMRs are just not a realistic option for Yukon or anywhere in Canada.

"I would say that, you know, that study can be done in two weeks by a graduate student, essentially, all right? They just have to go look at the literature on SMRs and look at the critical literature on this," Ramana said.

Ramana co-authored a research paper last year, looking at the potential for SMRs in remote communities or mine sites. The conclusion was that SMRs will be too expensive and there won't be enough demand to justify investing in them.

He said nuclear reactors are expensive, which is why their construction has "dried up" in much of the world.

"They generate electricity at very high prices," he said.

'They just have to go look at the literature,' said M.V. Ramana, a professor at the School of Public Policy and Global Affairs at the University of British Columbia. (Paul Joseph)
"[For] smaller reactors, the overall costs go down. But the amount of electricity that they will generate goes down even further."

The environmental case is also shaky, according to a statement signed last year by dozens of Canadian environmental and community groups, including the Sierra Club, Greenpeace, the Council of Canadians and the Canadian Environmental Law Associaton (CELA). The statement calls SMRs a "dirty, dangerous distraction" from tackling climate change and criticized the federal government for investing in the technology.

"We have to remember that the majority of the rhetoric we hear is from nuclear advocates. And so they are promoting what I would call, and other legal scholars and academics have called, a nuclear fantasy," said Kerrie Blaise of CELA.

Blaise describes the nuclear industry as facing an unknown future, with some of North America's larger reactors set to be decommissioned in the coming years. SMRs are therefore touted as the future.

"They're looking for a solution. And so that I would say climate change presents that timely solution for them."

Blaise argues the same safety and environmental questions exist for SMRs as for any nuclear reactors — such as how to produce and transport fuel safely, what to do with waste, and how to decommission them — and those can't be glossed over in a single-minded pursuit of lower carbon emissions.  

Main focus is still renewables, minister says
Yukon's energy minister agrees, and he's eager to emphasize that the territory is not committed to anything right now beyond a study.

"Every government has a responsibility to do diligence around this," Streicker said.

A solar farm in Old Crow, Yukon. The territory's energy minister says Yukon is still primarily focussed on renewables, and energy efficiency. (Caleb Charlie)
He also dismisses the idea that studying nuclear power is any sort of distraction from his government's response to climate change right now. Yukon's main focus is still renewable energy such as solar and wind power, though Canada's solar progress is often criticized as lagging, increasing efficiency, and connecting Yukon's grid to the hydro project in Atlin, B.C., he said.

Streicker has been open to nuclear energy in the past. As a federal Green Party candidate in 2008, Streicker broke with the party line to suggest that nuclear could be a viable energy alternative. 

He acknowledges that nuclear power is always a hot-button issue, and Yukoners will have strong feelings about it. A lot will depend on how any future regulatory process works, he says.

In taking action on climate, this Arctic community wants to be a beacon to the world
Cameco signs agreement with nuclear reactor company
"There's some people that think it's the 'Hail Mary,' and some people that think it's evil incarnate," he said. 

"Buried deep within Our Clean Future [Yukon's climate change strategy], there's a line in there that says we should keep an eye on other technologies, for example, nuclear. That's what this [study] is — it's to keep an eye on it."

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Canada Net-Zero Transition unites energy workers, R&D, and clean tech to decarbonize steel and cement with hydrogen, scale renewables, and build hybrid storage, delivering a just transition that strengthens communities and the economy.

Key Points

A national plan to reach net-zero by 2050 via renewables, hydrogen, decarbonization, and a just transition for workers.

✅ Hydrogen for steel and cement decarbonization

✅ Hybrid energy storage and clean tech R&D

✅ Just transition pathways for energy workers

Except for an isolated pocket of skeptics, there is now an almost universal acceptance that climate change is a global emergency that demands immediate and far-reaching action to defend our home and future generations. Yet in Canada we remain largely focused on how the crisis divides us rather than on the potential for it to unite us, despite nationwide progress in electricity decarbonization efforts.

It’s not a case of fossil-fuel industry workers versus the rest, or Alberta versus British Columbia where bridging the electricity gap could strengthen cooperation. We are all in this together. The challenge now is how to move forward in a way that leaves no one behind.

The fossil fuel industry has been — and continues to be — a key driver of Canada’s economy. Both of us had successful careers in the energy sector, but realized, along with an increasing number of energy workers, that the transition we need to cope with climate change could not be accomplished solely from within the industry.

Even as resource companies innovate to significantly reduce the carbon burden of each barrel, the total emission of greenhouse gases from all sources continues to rise. We must seize the opportunity to harness this innovative potential in alternative and complementary ways, mobilizing research and development, for example, to power carbon-intensive steelmaking and cement manufacture from hydrogen or to advance hybrid energy storage systems and decarbonizing Canada's electricity grid strategies — the potential for cross-over technology is immense.

The bottom line is inescapable: we must reach net-zero emissions by 2050 in order to prevent runaway global warming, which is why we launched Iron & Earth in 2016. Led by oilsands workers committed to increasingly incorporating renewable energy projects into our work scope, our non-partisan membership now includes a range of industrial trades and professions who share a vision for a sustainable energy future for Canada — one that would ensure the health and equity of workers, our families, communities, the economy, and the environment.

Except for an isolated pocket of skeptics, there is now an almost universal acceptance that climate change is a global emergency that demands immediate and far-reaching action, including cleaning up Canada's electricity to meet climate pledges, to defend our home and future generations. Yet in Canada we remain largely focused on how the crisis divides us rather than on the potential for it to unite us.

It’s not a case of fossil-fuel industry workers versus the rest, or Alberta versus British Columbia. We are all in this together. The challenge now is how to move forward in a way that leaves no one behind.

The fossil fuel industry has been — and continues to be — a key driver of Canada’s economy. Both of us had successful careers in the energy sector, but realized, along with an increasing number of energy workers, that the transition we need to cope with climate change could not be accomplished solely from within the industry.

Even as resource companies innovate to significantly reduce the carbon burden of each barrel, the total emission of greenhouse gases from all sources continues to rise, underscoring that Canada will need more electricity to hit net-zero, according to the IEA. We must seize the opportunity to harness this innovative potential in alternative and complementary ways, mobilizing research and development, for example, to power carbon-intensive steelmaking and cement manufacture from hydrogen or to advance hybrid energy storage systems — the potential for cross-over technology is immense.

The bottom line is inescapable: we must reach net-zero emissions by 2050 in order to prevent runaway global warming, which is why we launched Iron & Earth in 2016. Led by oilsands workers committed to increasingly incorporating renewable energy projects into our work scope, as calls for a fully renewable electricity grid by 2030 gain attention, our non-partisan membership now includes a range of industrial trades and professions who share a vision for a sustainable energy future for Canada — one that would ensure the health and equity of workers, our families, communities, the economy, and the environment.

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Central Asia power shortages strain grids across Kazakhstan, Uzbekistan, Kyrgyzstan, Tajikistan, and Turkmenistan, driven by drought-hit hydropower, aging coal and gas plants, rising demand, cryptomining loads, and winter peak consumption risks.

Key Points

Regionwide blackouts from drought, aging plants and grids, rising demand, and winter peaks stressing Central Asia.

✅ Drought slashes hydropower in Kyrgyzstan, Tajikistan, Uzbekistan

✅ Aging coal and gas TPPs and weak grids cause frequent outages

✅ Cryptomining loads and winter heating spike demand and stress supply

Central Asians from western Kazakhstan to southern Tajikistan are suffering from power and energy shortages that have caused hardship and emergency situations affecting the lives of millions of people.

On October 14, several units at three power plants in northeastern Kazakhstan were shut down in an emergency that resulted in a loss of more than 1,000 megawatts (MW) of electricity.

It serves as an example of the kind of power failures that plague the region 30 years after the Central Asian countries gained independence and despite hundreds of millions of dollars being invested in energy infrastructure and power grids, and echo risks seen in other advanced markets such as Japan's near-blackouts during recent cold snaps.

Some of the reasons for these problems are clear, but with all the money these countries have allocated to their energy sectors and financial help they have received from international financial institutions, it is curious the situation is already so desperate with winter officially still weeks away.

The Current Problems
Three power plants were affected in the October 14 shutdowns of units: Ekibastuz-1, Ekibastuz-2, and the Aksu power plant.

Ekibastuz-1 is the largest power plant in Kazakhstan, capable of generating some 4,000 MW, roughly 13 percent of Kazakhstan’s total power output.

The Kazakhstan Electricity Grid Operating Company (KEGOC) explained the problems resulted partially from malfunctions and repair work, but also from overuse of the system that the government would later say was due to cryptominers, a large number of whom have moved to Kazakhstan recently from China after Beijing banned the mining needed by Bitcoin and other cryptocurrencies, amid its own China's power cuts across several provinces in 2021.

But between November 8 and 9, rolling blackouts were reported in the East Kazakhstan, North Kazakhstan, and Kyzylorda provinces, as well as the area around Almaty, Kazakhstan’s biggest city, and Shymkent, its third largest city.

People in Uzbekistan say they, too, are facing blackouts that the Energy Ministry described as “short-term outages,” even as authorities have looked to export electricity to Afghanistan to support regional demand, though it has been clear for several weeks that the country will have problems with natural gas supplies this winter.

Power lines in Uzbekistan
Kyrgyz President Sadyr Japarov continues to say there won't be any power rationing in Kyrgyzstan this winter, but at the end of September the National Energy Holding Company ordered “restrictions on the lighting of secondary streets, advertisements, and facades of shops, cafes, and other nonresidential customers.”

Many parts of Tajikistan are already experiencing intermittent supplies of electricity.

Even in Turkmenistan, a country with the fourth-largest reserves of natural gas in the world, there were reports of problems with electricity and heating in the capital, Ashgabat.

What Is Going On?
The causes of some of these problems are easy to see.

The population of the region has grown significantly, with the population of Central Asia when the Soviet Union collapsed in late 1991 being some 50 million and today about 75 million.

Kyrgyzstan and Tajikistan are mountainous countries that have long been touted for their hydropower potential and some 90 percent of Kyrgyzstan’s domestically produced electricity and 98 percent of Tajikistan’s come from hydropower.

But a severe drought that struck Central Asia this year has resulted in less hydropower and, in general, less energy for the region, similar to constraints seen in Europe's reduced hydro and nuclear output this year.

Tajik authorities have not reported how low the water in the country’s key reservoirs is, but Kyrgyzstan has reported the water level in the reservoir at its Toktogul hydropower plant (HPP) is 11.8 billion cubic meters (bcm), the lowest level in years and far less than the 14.7 bcm of water it had in November 2020.

The Toktogul HPP, with an installed capacity of 1,200 MW, provides some 40 percent of the country's domestically produced electricity, but operating the HPP this winter to generate desperately needed energy brings the risk of leaving water levels at the reservoir critically low next spring and summer when the water is also needed for agricultural purposes.

This year’s drought is something Kyrgyzstan and Tajikistan will have to take into consideration as they plan how to provide power for their growing populations in the future. Hydropower is a desirable option but may be less reliable with the onset of climate change, prompting interest in alternatives such as Ukraine's wind power to diversify generation.

Uzbekistan is also feeling the effects of this year’s drought, and, like the South Caucasus where Georgia's electricity imports have increased, supply shortfalls are testing grids.

According to the International Energy Agency, HPPs account for some 12 percent of Uzbekistan’s generating capacity.

Uzbekistan’s Energy Ministry attributed low water levels at HPPs that have caused a 23 percent decrease in hydropower generation this year.

A reservoir in Kyrgyzstan
Kazakhstan and Uzbekistan are the most populous Central Asian countries, and both depend on thermal power plants (TPP) for generating most of their electricity.

Most of the TPPs in Kazakhstan are coal-fired, while most of the TPPs in Uzbekistan are gas-fired.

Kazakhstan has 68 power plants, 80 percent of which are coal-fired TPPs, and most are in the northern part of the country where the largest deposits of coal are located. Kazakhstan has the world's 10th largest reserves of coal.

About 88 percent of Uzbekistan’s electricity comes from TTPs, most of which use natural gas.

Uzbekistan’s proven reserves are some 800 billion cubic meters, but gas production in Uzbekistan has been decreasing.

In December 2020, Uzbek President Shavkat Mirziyoev ordered a halt to the country’s gas exports and instructed that gas to be redirected for domestic use. Mirziyoev has already given similar instructions for this coming winter.

How Did It Come To This?
The biggest problem with the energy infrastructure in Central Asia is that it is generally very old. Nearly all of its power plants date back to the Soviet era -- and some well back into the Soviet period.

The use of power plants and transmission lines that some describe as “obsolete” and a few call “decrepit” has unfortunately been a necessity in Central Asia, even as regional players pursue new interconnections like Iran's plan to transmit electricity to Europe as a power hub.

Reporting on Kazakhstan in September 2016, the Asian Development Bank (ADB) said, “70 percent of the power generation infrastructure is in need of rehabilitation.”

The Ekibastuz-1 TPP is relatively new by the power-plant standards of Central Asia. The first unit of the eight units of the TPP was commissioned in 1980.

The first unit at the AKSU TPP was commissioned in 1968, and the first unit of the gas- and fuel-fired TPP in southern Kazakhstan’s Zhambyl Province was commissioned in 1967.

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BC-Alberta Transmission Intertie enables clean hydro to balance wind and solar, expanding transmission capacity so Site C hydro can dispatch power, cut emissions, lower costs, and accelerate electrification across provincial grids under federal climate policy.

Key Points

A cross-provincial grid link using BC hydro to firm Alberta wind and solar, cutting emissions and costs.

✅ Balances variable renewables with dispatchable hydro from Site C.

✅ Enables power trade: peak exports, low-cost wind imports.

✅ Lowers decarbonization costs and supports electrification goals.

By Mark Jaccard

Lost in the news and noise of the federal government's newly announced $170-per-tonne carbon tax was a single, critical sentence in Canada's updated climate plan, one that signals a strategy that could serve as the cornerstone for a future free of greenhouse gas emissions.

"The government will work with provinces and territories to connect parts of Canada that have abundant clean hydroelectricity with parts that are currently more dependent on fossil fuels for electricity generation — including by advancing strategic intertie projects."

Why do we think this one sentence is so important? And what has it got to do with the controversial Site C project Site C electricity debate under construction in British Columbia?

The answer lies in the huge amount of electricity we'll need to generate in Canada to achieve our climate goals for 2030 and 2050. Even while we aggressively pursue energy efficiency, our electric cars, buses and perhaps trucks in Canada's net-zero race will need a huge amount of new electricity, as will our buildings and industries. 

Luckily, Canada is blessed with an electricity system that is the envy of the world — already over 80 per cent zero emission, the bulk being from flexible hydro-electricity, with a backbone of nuclear power largely in Ontario, a national electricity success and rapidly growing shares of cheap wind and solar. 

Provincial differences
Yet the story differs significantly from one province to another. While B.C.'s electricity is nearly emissions free, the opposite is true of its neighbour, Alberta, where more than 80 per cent still comes from fossil fuels. This, despite an impressive shift away from coal power in recent years.

Now imagine if B.C. and Alberta were one province.

This might sound like the start of a bad joke, or a horror movie to some, but it's the crux of new research by a trio of energy economists who put a fine point on the value of such co-operation.

The study, by Brett Dolter, Kent Fellows and Nic Rivers, takes a detailed look at the economic case for completing Site C, BC Hydro's controversial large hydro project under construction, and makes three key conclusions.

First, they argue Site C should likely not have been started in the first place. Only a narrow set of assumptions can now justify its total cost. But what's done is done, and absent a time machine, the decision to complete the dam rests on go-forward costs.

On that note, their second conclusion is no more optimistic. Considering the cost to complete the project, even accounting for avoiding termination costs should it be cancelled, they find the economics of completing Site C over-budget status to be weak. If the New York Times had a Site C needle in the style of the newspaper's election visual, it would be "leaning cancel" at this point.

In Alberta, more than 80 per cent of the electricity still comes from fossil fuels, despite an impressive shift away from coal power in recent years. (CBC)
But it is their third conclusion that stands out as worthy of attention. They argue there is a case for completing Site C if the following conditions are met:

B.C. and Alberta reduce their electricity sector emissions by more than 75 per cent (this really means Alberta, given B.C.'s already clean position); and

B.C. and Alberta expand their ability to move electricity between their respective provinces by building new transmission lines.

Let's deal with each of these in turn.

On Condition 1, we give an emphatic: YES! Reducing electricity emissions is an absolute must to meet climate pledges if Canada is to come even close to achieving its net-zero goals. As noted above, a clean electricity grid will be the cornerstone of a decarbonized economy as we generate a great deal more power to electrify everything from industrial processes to heating to transportation and more. 

Condition 2 is more challenging. Talk of increasing transmission connections across Canada, including Hydro-Québec's U.S. strategy has been ongoing for over 50 years, with little success to speak of. But this time might well be different. And the implications for a completed Site C, should the government go that route, are profound.

Wind and solar costs rapidly declining
Somewhat ironically, the case for Site C is made stronger by the rapidly declining costs of two of its apparent renewable competitors: wind and solar.

The cost of wind and solar generation has fallen by 70 per cent and 90 per cent, respectively, a dramatic decline in the past 10 years. No longer can these variable sources of power be derided as high cost; they are unequivocally the cheapest sources of raw energy in electricity systems today.

However, electricity system operators must deal with their "non-dispatchability," a seemingly complicated term that simply means they produce electricity only when the sun shines and the wind blows, which is not necessarily when electricity customers want their electricity delivered (dispatched) to them. And because of this characteristic, the value of dispatchable electricity sources, like a completed Site C, will grow as a complement to wind and solar. 

Thus, as Alberta's generation of cheap wind and solar grows, so too does the value of connecting it with the firm, dispatchable resources available in B.C.

Rather than displacing wind and solar, large hydro facilities with the ability to increase or decrease output on short notice can actually enable more investment in these renewable sources. Expanding the transmission connection, with Site C on one side of that line, becomes even more valuable.

Many in B.C. might read this and rightly ask themselves, why should we foot the bill for this costly project to help out Albertans? The answer is that it won't be charity — B.C. will get paid handsomely for the power it delivers in peak periods and will be able to import wind power at low prices from Alberta in other times. B.C. will benefit greatly from these gains of trade.

Turning to Alberta, why should Albertans support B.C. reaping these gains? The answer is two-fold.

First, Site C will actually enable more low-cost wind and solar to be built in Alberta due to hydro's ability to balance these non-dispatchable renewables. Jobs and economic opportunity will occur in Alberta from this renewable energy growth.

Second, while B.C. imports won't come cheap, they will be less costly than the decarbonization alternatives Alberta would need without B.C.'s flexible hydro, as the economists' study shows. This means lower overall costs to Alberta's power consumers.

A clear role for Ottawa
To be sure, there are challenges to increasing the connectedness of B.C. and Alberta's power systems, not least of which is BC Hydro being a regulated, government-owned monopoly while Alberta is a competitive market amongst private generators. Some significant accommodations in climate policy and grids will be needed to ensure both sides can compete and benefit from trade on an equal footing.

There is also the pesky matter of permitting and constructing thousands of kilometres of power lines. Getting linear energy infrastructure built in Canada has not exactly been our forte of late.

We are not naive to the significant challenges in such an approach, but it's not often that we see such a clear narrative for beneficial climate action that, when considered at the provincial level, is likely to be thwarted, but when considered more broadly can produce a big win.

It's the clearest example yet of a role for the federal government to bridge the gap, to facilitate the needed regulatory conversations, and, let's be frank, to bring money to the table to make the line happen. Neither provincial side is likely to do it on their own, nor, as history has shown, are they likely to do it together. 

For a government committed to reducing emissions, and with a justified emphasis on the electricity sector, the opportunity to expand the Alberta-B.C. transmission intertie, leveraging the flexibility of B.C.'s hydro with the abundance of wind and solar potential on the Prairies, offers a potential massive decarbonization win for Western Canada that is too good to ignore.

Mark Jaccard, a professor at Simon Fraser University, and Blake Shaffer, a professor at the University of Calgary

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