South Korea to launch emissions scheme

Hydro-Quebec NECEC Transmission Line faces Maine PUC scrutiny over clean energy claims, greenhouse gas emissions, spillage capacity, resource shuffling, and Massachusetts contracts, amid opposition from natural gas generators and environmental groups debating public need.

Key Points

A $1B Maine corridor for Quebec hydropower to Massachusetts, debated over emissions, spillage, and public need.

✅ Maine PUC weighing public need and ratepayer benefits

✅ Emissions impact disputed: resource shuffling vs new supply

✅ Hydro-Quebec spillage claims questioned without data

As Maine regulators are deciding whether to approve construction of a $1 billion electricity corridor across much of western Maine, the Canadian hydroelectric utility poised to make billions of dollars from the project has been absent from the process.

This has left both opponents and supporters of the line arguing about how much available energy the utility has to send through a completed line, and whether that energy will help fulfill the mission of the project: fighting climate change.

And while the utility has avoided making its case before regulators, which requires submitting to cross-examination and discovery, it has engaged in a public relations campaign to try and win support from the region's newspapers.

Government-owned Hydro-Quebec controls dams and reservoirs generating hydroelectricity throughout its namesake province. It recently signed agreements to sell electricity across the proposed line, named the New England Clean Energy Connect, to Massachusetts as part of the state's effort to reduce its dependence on fossil fuels, including natural gas.

At the Maine Public Utilities Commission, attorneys for Central Maine Power Co., which would build and maintain the line, have been sparring with the opposition over the line's potential impact on Maine and its electricity consumers. Leading the opposition is a coalition of natural gas electricity generators that stand to lose business should the line be built, as well as the Natural Resources Council of Maine, an environmental group.

That unusual alliance of environmental and business groups wants Hydro-Quebec to answer questions about its hydroelectric system, which they argue can't deliver the amount of electricity promised to Massachusetts without diverting energy from other regions.

In that scenario, critics say the line would not produce the reduction in greenhouse gas emissions that CMP and Hydro-Quebec have made a central part of their pitch for the project. Instead, other markets currently buying energy from Hydro-Quebec, such as New York, Ontario and New Brunswick, would see hydroelectricity imports decrease and have to rely on other sources of energy, including coal or oil, to make up the difference. If that happened, the total amount of clean energy in the world would remain the same.

Opponents call this possibility "greenwashing." Massachusetts regulators have described these circumstances as "resource shuffling."

But CMP spokesperson John Carroll said that if hydropower was diverted from nearby markets to power Massachusetts, those markets would not turn to fossil fuels. Rather they would seek to develop other forms of renewable energy "leading to further reductions in greenhouse gas emissions in the region."

Hydro-Quebec said it has plenty of capacity to increase its electricity exports to Massachusetts without diverting energy from other places.

However, Hydro-Quebec is not required to participate -- and has not voluntarily participated -- in regulatory hearings where it would be subject to cross examinations and have to testify under oath. Some participants wish it would.

At a January hearing at the Maine Public Utilities Commission, hearing examiner Mitchell Tannenbaum had to warn experts giving testimony to "refrain from commentary regarding whether Hydro-Quebec is here or not" after they complained about its absence when trying to predict potential ramifications of the line.

"I would have hoped they would have been visible and available to answer legitimate questions in all of these states through which their power is going to be flowing," said Dot Kelly, a member of the executive committee at the Maine Chapter of the Sierra Club who has participated in the line's regulatory proceedings as an individual. "If you're going to have a full and fair process, they have to be there."

[What you need to know about the CMP transmission line proposed for Maine]

While Hydro-Quebec has not presented data on its system directly to Maine regulators, it has brought its case to the press. Central to that case is the fact that it's "spilling" water from its reservoirs because it is limited by how much electricity it can export. It said that it could send more water through its turbines and lower reservoir levels, eliminating spillage and creating more energy, if only it had a way to get that energy to market. Hydro-Quebec said the line would make that possible, and, in doing so, help lower emissions and fight climate change.

"We have that excess potential that we need to use. Essentially, it's a good problem to have so long as you can find an export market," Hydro-Quebec spokesperson Serge Abergel told the Bangor Daily News.

Hydro-Quebec made its "spillage" case to the editorial boards of The Boston Globe, The Portland Press Herald and the BDN, winning qualified endorsements from the Globe and Press Herald. (The BDN editorial board has not weighed in on the project).

Opponents have questioned why Hydro-Quebec is willing to present their case to the press but not regulators.

"We need a better answer than 'just trust us,'" Natural Resources Council of Maine attorney Sue Ely said. "What's clear is that CMP and HQ are engaging in a full-court publicity tour peddling false transparency in an attempt to sell their claims of greenhouse gas benefits."

Energy generators aren't typically parties to public utility commission proceedings involving the building of transmission lines, but Maine regulators don't typically evaluate projects that will help customers in another state buy energy generated in a foreign country.

"It's a unique case," said Maine Public Advocate and former Democratic Senate Minority Leader Barry Hobbins, who has neither endorsed nor opposed the project. Hobbins noted the project was not proposed to improve reliability for Maine electricity customers, which is typically the point of new transmission line proposals evaluated by the commission. Instead, the project "is a straight shot to Massachusetts," Hobbins said.

Maine Public Utilities Commission spokesperson Harry Lanphear agreed. "The Commission has never considered this type of project before," he said in an email.

In order to proceed with the project, CMP must convince the Maine Public Utilities Commission that the proposed line would fill a "public need" and benefit Mainers. Among other benefits, CMP said it will help lower electricity costs and create jobs in Maine. A decision is expected in the spring.

Given the uniqueness of the case, even the commission seems unsure about how to apply the vague "public need" standard. On Jan. 14, commission staff asked case participants to weigh in on how it should apply Maine law when evaluating the project, including whether the hydroelectricity that would travel over the line should be considered "renewable" and whether Maine's own carbon reduction goals are relevant to the case.

James Speyer, an energy consultant whose firm was hired by natural gas company and project opponent Calpine to analyze the market impacts of the line, said he has testified before roughly 20 state public utility commissions and has never seen a proceeding like this one.

"I've never been in a case where one of the major beneficiaries of the PUC decision is not in the case, never has filed a report, has never had to provide any data to support its assertions, and never has been subject to cross examination," Speyer said. "Hydro-Quebec is like a black box."

Hydro-Quebec would gladly appear before the Maine Public Utilities Commission, but it has not been invited, said spokesperson Abergel.

"The PUC is doing its own process," Abergel said. "If the PUC were to invite us, we'd gladly intervene. We're very willing to collaborate in that sense."

But that's not how the commission process works. Individuals and organizations can intervene in cases, but the commission does not invite them to the proceedings, commission spokesperson Lanphear said.

CMP spokesperson Carroll dismissed concerns over emissions, noting that Hydro-Quebec is near the end of completing a more than 15-year effort to develop its clean energy resources. "They will have capacity to satisfy the contract with Massachusetts in their reservoirs," Carroll said.

While Maine regulators are evaluating the transmission line, Massachusetts' Department of Public Utilities is deciding whether to approve 20-year contracts between Hydro-Quebec and that state's electric utilities. Those contracts, which Hydro-Quebec has estimated could be worth close to $8 billion, govern how the utility sells electricity over the line.

Dean Murphy, a consultant hired by the Massachusetts Attorney General's office to review the contracts, testified before Massachusetts regulators that the agreements do not require a reduction in global greenhouse gas emissions. Murphy also warned the contracts don't actually require Hydro-Quebec to increase the total amount of energy it sends to New England, as energy could be shuffled from established lines to the proposed CMP line to satisfy the contracts.

Parties in the Massachusetts proceeding are also trying to get more information from Hydro-Quebec. Energy giant NextEra is currently trying to convince Massachusetts regulators to issue a subpoena to force Hydro-Quebec to answer questions about how its exports might change with the construction of the transmission line. Hydro-Quebec and CMP have opposed the motion.

Hydro-Quebec has a reputation for guarding its privacy, according to Hobbins.

"It would have been easier to not have to play Sherlock Holmes and try to guess or try to calculate without having a direct 'yes' or 'no' response from the entity itself," Hobbins said.

Ultimately, the burden of proving that Maine needs the line falls on CMP, which is also responsible for making sure regulators have all the information they need to make a decision on the project, said former Maine Public Utilities Commission Chairman Kurt Adams.

"Central Maine Power should provide the PUC with all the info that it needs," Adams said. "If CMP can't, then one might argue that they haven't met their burden."

'They treat HQ with nothing but distrust'

If completed, the line would bring 9.45 terawatt hours of electricity from Quebec to Massachusetts annually, or about a sixth of the total amount of electricity Massachusetts currently uses every year (and roughly 80 percent of Maine's annual load). CMP's parent company Avangrid would make an estimated $60 million a year from the line, according to financial analysts.

As part of its legally mandated efforts to reduce carbon emissions and fight climate change, Massachusetts would pay the $950 million cost of constructing the line. The state currently relies on natural gas, a fossil fuel, for nearly 70 percent of its electricity, a figure that helps explain natural gas companies' opposition to the project.

A panel of experts recently warned that humanity has 12 years to keep global temperatures from rising above 1.5 degrees Celsius and prevent the worst effects of climate change, which include floods, droughts and extreme heat.

The line could lower New England's annual carbon emissions by as much as 3 million metric tons, an amount roughly equal to Washington D.C.'s annual emissions. Opponents worry that reduction could be mostly offset by increases in other markets.

But while both sides have claimed they are fighting for the environment, much of the debate features giant corporations with headquarters outside of New England fighting over the future of the region's electricity market, echoing customer backlash seen in other utility takeovers.

Hydro-Quebec is owned by the people of Quebec, and CMP is owned by Avangrid, which is in turn owned by Spanish energy giant Iberdrola. Leading the charge against the line are several energy companies in the Fortune 500, including Houston-based Calpine and Florida-based NextEra Energy.

However, only one side of the debate counts environmental groups as part of its coalition, and, curiously enough, that's the side with fossil fuel companies.

Some environmental groups, including the Natural Resources Council of Maine and Environment Maine, have come out against the line, while others, including the Acadia Center and the Conservation Law Foundation, are still deciding whether to support or oppose the project. So far, none have endorsed the line.

"It is discouraging that some of the environmental groups are so opposed, but it seems the best is the enemy of the good," said CMP's Carroll in an email. "They seem to have no sense of urgency; and they treat HQ with nothing but distrust."

Much of the environmentally minded opposition to the project focuses on the impact the line would have on local wildlife and tourism.

Sandi Howard administers the Say NO To NECEC Facebook page and lives in Caratunk, one of the communities along the proposed path of the line. She said opposition to the line might change if it was proven to reduce emissions.

"If it were going to truly reduce global CO2 emissions, I think it would be be a different conversation," Howard said.

Not the first choice

Before Maine, New Hampshire had its own debate over whether it should serve as a conduit between Quebec and Massachusetts. The proposed Northern Pass transmission line would have run the length of the state. It was Massachusetts' first choice to bring Quebec hydropower to its residents.

But New Hampshire's Site Evaluation Committee unanimously voted to reject the Northern Pass project in February 2018 on the grounds that the project's sponsor, Eversource, had failed to prove the project would not interfere with local business and tourism. Though it was the source of the electricity that would have traveled over the line, Hydro-Quebec was not a party to the proceedings.

In its decision, the committee noted the project would not reduce emissions if it was not coupled with a "new source of hydropower" and the power delivered across the line was "diverted from Ontario and New York." The committee added that it was unclear if the power would be new or diverted.

The next month, Massachusetts replaced Northern Pass by selecting CMP's proposed line. As the project came before Maine regulators, questions about Hydro-Quebec and emissions persisted. Two different analyses of CMP's proposed line, including one by the Maine Public Utility Commission's independent consultant, found the line would greatly reduce New England's emissions.

But neither of those studies took into account the line's impact on emissions outside of New England. A study by Calpine's consultant, Energyzt, found New England's emissions reduction could be mostly offset by increased emissions in other areas, including New Brunswick and New York, that would see hydroelectricity imports shrink as energy was redirected to fulfill the contract with Massachusetts.

'They failed in any way to back up those spillage claims'

Hydro-Quebec seemed content to let CMP fight for the project alone before regulators for much of 2018. But at the end of the year, the utility took a more proactive approach, meeting with editorial boards and providing a two-page letter detailing its "spillage" issues to CMP, which entered it into the record at the Maine Public Utilities Commission.

The letter provided figures on the amount of water the utility spilled that could have been converted into sellable energy, if only Hydro-Quebec had a way to get it to market. Instead, by "spilling" the water, the company essentially wasted it.

Instead of sending water through turbines or storing it in reservoirs, hydroelectric operators sometimes discharge water held behind dams down spillways. This can be done for environmental reasons. Other times it is done because the operator has so much water it cannot convert it into electricity or store it, which is usually a seasonal issue: Reservoirs often contain the most water in the spring as temperatures warm and ice melts.

Hydro-Quebec said that, in 2017, it spilled water that could have produced 4.5 terawatt hours of electricity, or slightly more than half the energy needed to fulfill the Massachusetts contracts. In 2018, the letter continued, Hydro-Quebec spilled water that could have been converted into 10.4 terawatts worth of energy. The company said it didn't spill at all due to transmission constraints prior to 2017.

The contracts Hydro-Quebec signed with the Massachusetts utilities are for 9.45 terawatt hours annually for 20 years. In its letter, the utility essentially showed it had only one year of data to show it could cover the terms of the contract with "spilled" energy.

"Reservoir levels have been increasing in the last 15 years. Having reached their maximum levels, spillage maneuvers became necessary in 2017 and 2018," said Hydro-Quebec spokesperson Lynn St. Laurent.

By providing the letter through CMP, Hydro-Quebec did not have to subject its spillage figures to cross examination.

Dr. Shaleen Jain, a civil and environmental engineering professor at the University of Maine, said that, while spilled water could be converted into power generation in some circumstances, spills happen for many different reasons. Knowing whether spillage can be translated into energy requires a great deal of analysis.

"Not all of it can be repurposed or used for hydropower," Jain said.

In December, one of the Maine Public Utility Commission's independent consultants, Gabrielle Roumy, told the commission that there's "no way" to "predict how much water would be spilled each and every year." Roumy, who previously worked for Hydro-Quebec, added that even after seeing the utility's spillage figures, he believed it would need to divert energy from other markets to fulfill its commitment to Massachusetts.

"I think at this point we're still comfortable with our assumptions that, you know, energy would generally be redirected from other markets to NECEC if it were built," Roumy said.

In January, Tanya Bodell, the founder and executive director of consultant Energyzt, testified before the commission on behalf of Calpine that it was impossible to know why Hydro-Quebec was spilling without more data.

"There's a lot of details you'd have to look at in order to properly assess what the reason for the spillage is," Bodell said. "And you have to go into an hourly level because the flows vary across the year, within the month, the week, the days. ...And, frankly, it would have been nice if Hydro-Quebec was here and brought their model and allowed us to see how this could help them to sell more."

Even though CMP and Hydro-Quebec's path to securing approval of the project does not go through the Legislature, and despite a Maine court ruling that energized Hydro-Quebec's export bid, lawmakers have taken notice of Hydro-Quebec's absence. Rep. Seth Berry, D-Bowdoinham, the House chairman of the Joint Committee On Energy Utilities and Technology and a frequent critic of CMP, said he would like to see Hydro-Quebec "show up and subject their proposal to examination and full analysis and public examination by the regulators and the people of Maine."

"They're trying to sell an incredibly lucrative proposal, and they failed in any way to back up those spillage claims with defensible numbers and defensible analysis," Berry said.

Berry was part of a bipartisan group of Maine lawmakers that wrote a letter to Massachusetts regulators last year expressing concerns about the project, which included doubts about whether the line would actually reduce global gas emissions. On Monday, he announced legislation that would direct the state to create an independent entity to buy out CMP from its foreign investors.

'No benefit to remaining quiet'

Hydro-Quebec would like to provide answers, but "there is always a commercially sensitive information concern when we do these things," said spokesperson Abergel.

"There might be stuff we can do, having an independent study that looks at all of this. I'm not worried about the conclusion," Abergel said. "I'm worried about how long it takes."

Instead of asking Hydro-Quebec questions directly, participants in both Maine and Massachusetts regulatory proceedings have had to direct questions for Hydro-Quebec to CMP. That arrangement may be part of Hydro-Quebec's strategy to control its information, said former Maine Public Utilities Commissioner David Littell.

"From a tactical point of view, it may be more beneficial for the evidence to be put through Avangrid and CMP, which actually doesn't have that back-up info, so can't provide it," Littell said.

Getting information about the line from CMP, and its parent company Avangrid, has at times been difficult, opponents say.

In August 2018, the commission's staff warned CMP in a legal filing that it was concerned "about what appears to be a lack of completeness and timeliness by CMP/Avangrid in responding to data requests in this proceeding."

The trouble in getting information from Hydro-Quebec and CMP only creates more questions for Hydro-Quebec, said Jeremy Payne, executive director of the Maine Renewable Energy Association, which opposes the line in favor of Maine-based renewables.

"There's a few questions that should have relatively simple answers. But not answering a couple of those questions creates more questions," Payne said. "Why didn't you intervene in the docket? Why are you not a party to the case? Why won't you respond to these concerns? Why wouldn't you open yourself up to discovery?"

"I don't understand why they won't put it to bed," Payne said. "If you've got the proof to back it up, then there's no benefit to remaining quiet."

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Muskrat Falls financial impact highlights a hydro megaproject's cost overruns, rate mitigation challenges, and inquiry findings in Newfoundland and Labrador, with power exports, Churchill River generation, and subsea cables shaping long-term viability.

Key Points

It refers to the project's burden on provincial finances, driven by cost overruns, rate hikes, and debt risks.

✅ Costs rose to $12.7B from $6.2B; inquiry cites suppressed risks.

✅ Rate mitigation needed to offset power bill shocks.

✅ Exports via subsea cables may improve long-term viability.

Newfoundland and Labrador's premier says the Muskrat Falls hydro megaproject is currently too much of a massive financial burden for him to be optimistic about its long-term potential.

"I am probably one of the most optimistic people in this room," Liberal Premier Dwight Ball told the inquiry into the project's runaway cost and scheduling issues, echoing challenges at Manitoba Hydro that have raised similar concerns.

"I believe the future is optimistic for Newfoundland Labrador, of course I do. But I'm not going to sit here today and say we have an optimistic future because of the Muskrat Falls project."

Ball, who was re-elected on May 16, has been critical of the project since he was opposition leader around the time it was sanctioned by the former Tory government.

He said Friday that despite his criticism of the Labrador dam, which has seen costs essentially double to more than $12.7 billion, he didn't set out to celebrate a failed project.

He said he still wants to see Muskrat Falls succeed someday through power sales outside the province, but there are immediate challenges -- including mitigating power-rate hikes once the dam starts providing full power and addressing winter reliability risks for households.

"We were told the project would be $6.2 billion, we're at $12.7 (billion). We were never told this project would be nearly 30 per cent of the net debt of this province just six, seven years later," the premier said.

"I wanted this to be successful, and in the long term I still want it to be successful. But we have to deal with the next 10 years."

The nearly complete dam will harness Labrador's lower Churchill River to provide electricity to the province as well as Nova Scotia and potentially beyond through subsea cables, while the legacy of Churchill Falls continues to shape regional power arrangements.

Ball's testimony wraps up a crucial phase of hearings in the extensive public inquiry.

The inquiry has heard from dozens of witnesses, with current and former politicians, bureaucrats, executives and consultants, amid debates over Quebec's electricity ambitions in the region, shedding long-demanded light on what went on behind closed doors that made the project go sideways.

Some witnesses have suggested that estimates were intentionally suppressed, and many high-ranking officials, including former premiers, have denied seeing key information about risk.

On Thursday, Ball testified to his shock when he began to understand the true financial state of the project after he was elected premier in 2015.

On Friday, Ball said he has more faith in future of the offshore oil and gas industry, and emerging options like small nuclear reactors, for example, than a mismanaged project that has put immense pressure on residents already struggling to make ends meet.

After his testimony, Ball said he takes some responsibility for a missed opportunity to mitigate methylmercury risks downstream from the dam through capping the reservoir, in parallel with debates over biomass power in electricity generation, something he had committed to doing before it is fully flooded this summer.

Still to come is a third phase of hearings on future best practices for issues like managing large-scale projects and independent electricity planning, two public feedback sessions and closing submissions from lawyers.

The final report from the inquiry is due before Dec. 31.

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Atlantic Clean Power Superhighway outlines a federally backed transmission grid upgrade for Atlantic Canada, adding 2,000 MW of renewable energy via interprovincial ties, improved hydro access from Quebec and Newfoundland and Labrador, with utility-regulator funding.

Key Points

A federal-provincial plan upgrading Atlantic Canada's grid to deliver 2,000 MW of renewables via interprovincial links.

✅ $2M technical review to rank priority transmission projects

✅ Target: add 2,000 MW renewable power to Atlantic grid

✅ Cost-sharing by utilities, regulators, and federal-provincial funding

The federal government will spend $2 million on an engineering study to improve the Atlantic region's electricity grid.

The study was announced Friday at a news conference held by 10 federal and provincial politicians at a meeting of the Atlantic Growth Strategy in Halifax, which includes ongoing regulatory reform efforts for cleaner power in Atlantic Canada.

The technical review will identify the most important transmission projects including inter-provincial ties needed to move electricity across the region.

Nova Scotia Premier Stephen McNeil said the results are expected in July.

Provinces will apply to the federal government for federal funding to build the infrastructure. Utilities in each province will be expected to pay some portion of the cost by applying to respective regulators, but what share falls to ratepayers is not known.

​Federal Intergovernmental Affairs Minister Dominic LeBlanc characterized the grid improvements as something that will cost hundreds of millions of dollars.

He said the study was the first step toward "a clean power superhighway across the region.

"We have a historic opportunity to quickly get to work on upgrading ultimately a whole series of transmission links of inter-provincial ties. That's something that the government of Canada would be anxious to work with in terms of collaborating with the provinces on getting that right."

Premier McNeil referred specifically to improving hydro access from Quebec and Newfoundland and Labrador.

For context, a massive cross-border hydropower line to New York is planned, illustrating the scale of projects under consideration.

Goal of 2,000 megawatts

McNeil said the goal was to bring an additional 2,000 megawatts of renewable electricity into the region.

"I can't stress to you enough how critical this will be for the future economic success and stability of Atlantic Canada, especially as Atlantic grids face intensifying storms," he said.

Federal Immigration Minister Ahmed Hussen also announced a pilot project to attract immigrant workers will be extended by two years to the end of 2021.

International graduate students will be given 24 months to apply under the program — a one-year increase.

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Self-healing grid technology automatically reroutes power to reduce outages, speed restoration, and boost reliability during storms like Hurricane Ian in Florida, leveraging smart grid sensors, automation, and grid hardening to support Duke Energy customers.

Key Points

Automated smart grid systems that detect faults and reroute power to minimize outages and accelerate restoration.

✅ Cuts outage duration via automated fault isolation

✅ Reroutes electricity with sensors and distribution automation

✅ Supports storm resilience and faster field crew restoration

As Hurricane Ian made its way across Florida, where restoring power in Florida can take weeks in hard-hit areas, Duke Energy's grid improvements were already on the job helping to combat power outages from the storm.

Smart, self-healing technology, similar to smart grid improvements elsewhere, helped to automatically restore more than 160,000 customer outages and saved nearly 3.3 million hours (nearly 200 million minutes) of total lost outage time.

"Hurricane Ian is a strong reminder of the importance of grid hardening and storm preparedness to help keep the lights on for our customers," said Melissa Seixas, Duke Energy Florida state president. "Self-healing technology is just one of many grid improvements that Duke Energy is making to avoid outages, restore service faster and increase reliability for our customers."

Much like the GPS in your car can identify an accident ahead and reroute you around the incident to keep you on your way, self-healing technology is like a GPS for the grid. The technology can quickly identify power outages and alternate energy pathways to restore service faster for customers when an outage occurs.

Additionally, self-healing technology provides a smart tool to assist crews in the field with power restoration after a major storm like Ian, helping reduce outage impacts and freeing up resources to help restore power in other locations.

Three days after Hurricane Ian exited the state, Duke Energy Florida wrapped up restoration of approximately 1 million customers. This progress enabled the company to deploy more than 550 Duke Energy workers from throughout Florida, as well as contractors from across the country, to help restore power for Lee County Electric Cooperative customers.

Crews worked in Cape Coral and Pine Island, one of the hardest-hit areas in the storm's path, as Canadian power crews have in past storms, and completed power restoration for the majority of customers on Pine Island within approximately one week after arriving to the island.

Prior to Ian in 2022, smart, self-healing technology had helped avoid nearly 250,000 extended customer outages in Florida, similar to Hydro One storm recovery efforts, saving around 285,000 hours (17.1 million minutes) of total lost outage time.

Duke Energy currently serves around 59% of customers in Florida with self-healing capabilities on its main power distribution lines, with a goal of serving around 80% over the next few years.

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Natrium small modular reactor pairs a sodium-cooled fast reactor with molten salt storage to deliver load-following, dispatchable nuclear power, enhancing grid flexibility and peaking capacity as TerraPower and GE Hitachi pursue factory-built, affordable deployment.

Key Points

A TerraPower-GE Hitachi SMR joining a sodium-cooled reactor with molten salt storage for flexible, dispatchable power.

✅ 345 MW base; 500 MW for 5.5 hours via thermal storage

✅ Sodium-cooled coolant and molten salt storage enable load-following

✅ Backed by major utilities; factory-built modules aim lower costs

Nuclear power is the Immovable Object of generation sources. It can take days just to bring a nuclear plant completely online, rendering it useless as a tool to manage the fluctuations in the supply and demand on a modern energy grid.  

Now a firm launched by Bill Gates in 2006, TerraPower, in partnership with GE Hitachi Nuclear Energy, believes it has found a way to make the infamously unwieldy energy source a great deal nimbler, drawing on next-gen nuclear ideas — and for an affordable price. 

The new design, announced by TerraPower on August 27th, is a combination of a "sodium-cooled fast reactor" — a type of small reactor in which liquid sodium is used as a coolant — and an energy storage system. While the reactor could pump out 345 megawatts of electrical power indefinitely, the attached storage system would retain heat in the form of molten salt and could discharge the heat when needed, increasing the plant’s overall power output to 500 megawatts for more than 5.5 hours. 

“This allows for a nuclear design that follows daily electric load changes and helps customers capitalize on peaking opportunities driven by renewable energy fluctuations,” TerraPower said. 

Dubbed Natrium after the Latin name for sodium ('natrium'), the new design will be available in the late 2020s, said Chris Levesque, TerraPower's president and CEO.

TerraPower said it has the support of a handful of top U.S. utilities, including Berkshire Hathaway Energy subsidiary Pacificorp, Energy Northwest, and Duke Energy. 

The reactor's molten salt storage add-on would essentially reprise the role currently played by coal- or gas-fired power stations or grid-scale batteries: each is a dispatchable form of power generation that can quickly ratchet up or down in response to changes in grid demand or supply. As the power demands of modern grids become ever more variable with additions of wind and solar power — which only provide energy when the wind is blowing or the sun shining — low-carbon sources of dispatchable power are needed more and more, and Europe is losing nuclear power at a difficult moment for energy security. California’s rolling blackouts are one example of what can happen when not enough power is available to be dispatched to meet peak demand. 

The use of molten salt, which retains heat at extremely high temperatures, as a storage technology is not new. Concentrated solar power plants also collect energy in the form of molten salt, although such plants have largely been abandoned in the U.S. The technology could enjoy new life alongside nuclear plants: TerraPower and GE Hitachi Nuclear are only two of several private firms working to develop reactor designs that incorporate molten salt storage units, including U.K.- and Canada-based developer Moltex Energy.

The Gates-backed venture and its partner touted the "significant cost savings" that would be achieved by building major portions of their Natrium plants through not a custom but an industrial process — a defining feature of the newest generation of advanced reactors is that their parts can be made in factories and assembled on-site — although more details on cost weren't available. Reuters reported earlier that each plant would cost around $1 billion.

NuScale Power

A day after TerraPower and GE Hitachi's unveiled their new design, another nuclear firm — Portland, Oregon-based NuScale Power — announced that the U.S. Nuclear Regulatory Commission (NRC) had completed its final safety evaluation of NuScale’s new small modular reactor design.

It was the first small modular reactor design ever to receive design approval from the NRC, NuScale said. 

The approval means customers can now pursue plans to develop its reactor design confident that the NRC has signed off on its safety aspects. NuScale said it has signed agreements with interested parties in the U.S., Canada, Romania, the Czech Republic, and Jordan, and is in the process of negotiating more. 

NuScale previously said that construction on one of its plants could begin in Utah in 2023, with the aim of completing the first Power Module in 2026 and the remaining 11 modules in 2027.

NuScale
An artist’s rendering of NuScale Power’s small modular nuclear reactor plant. NUSCALE POWER
NuScale’s reactor is smaller than TerraPower’s. Entirely factory-built, each of its Power Modules would generate 60 megawatts of power. The design, typical of advanced reactors, uses pressurized water reactor technology, with one power plant able to house up to 12 individual Power Modules. 

In a sign of the huge amounts of time and resources it takes to get new nuclear technology to the market’s doorstep, NuScale said it first completed its Design Certification Application in December 2016. NRC officials then spent as many as 115,000 hours reviewing it, NuScale said, in what was only the first of several phases in the review process. 

In January 2019, President Donald Trump signed into law the Nuclear Energy Innovation and Modernization Act (NEIMA), designed to speed the licensing process for advanced nuclear reactors, and the DOE under Secretary Rick Perry moved to advance nuclear development through parallel initiatives. The law had widespread bipartisan support, underscoring Democrats' recent tentative embrace of nuclear power.

An industry eager to turn the page

After a boom in the construction of massive nuclear power plants in the 1960s and 70s, the world's aging fleet of nuclear plants suffers from rising costs and flagging public support. Nuclear advocates have for years heralded so-called small modular reactors or SMRs as the cheaper and more agile successors to the first generation of plants, and policy moves such as the UK's green industrial revolution lay out pathways for successive waves of reactors. But so far a breakthrough on cost has proved elusive, and delays in development timelines have been abundant. 

Edwin Lyman, the director of nuclear power safety at the Union of Concerned Scientists, suggested on Twitter that the nuclear designs used by TerraPower and GE Hitachi had fallen short of a major innovation. “Oh brother. The last thing the world needs is a fleet of sodium-cooled fast reactors,” he wrote.  

Still, climate scientists view nuclear energy as a crucial source of zero-carbon energy, with analyses arguing that net-zero emissions may be impossible without nuclear in many scenarios, if the world stands a chance at limiting global temperature increases to well below 2 degrees Celsius above pre-industrial levels. Nearly all mainstream projections of the world’s path to keeping the temperature increase below those levels feature nuclear energy in a prominent role, including those by the United Nations and the International Energy Agency (IEA). 

According to the IEA: “Achieving the clean energy transition with less nuclear power is possible but would require an extraordinary effort.”

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OEB Hydro One Rate Decision 2023-2027 sets approved transmission and distribution rates in Ontario, with a settlement reducing revenue requirement, modest bill impacts, higher productivity factors, inflation certainty, DVA credits, and First Nations participation measures.

Key Points

OEB-approved Hydro One 2023-2027 transmission and distribution rates settlement, lowering costs and limiting bill impacts.

✅ $482.7M revenue reductions vs. original proposal

✅ Avg bill impact: +$0.69 trans., +$2.43 distr. per month

✅ Faster DVA refunds; productivity and efficiency incentives

The Ontario Energy Board (OEB) issued its Decision and Order on an application filed by Hydro One Networks Inc. (Hydro One) on August 5, 2021 seeking approval for changes to the rates it charges for electricity transmission and distribution, beginning January 1, 2023 and for each subsequent year through to December 31, 2027. 

The proceeding resulted in the filing of a settlement proposal that the OEB has now approved after concluding that it is in the public interest. 

The negotiated reductions in Hydro One's transmission and distribution revenue requirements over the 2023 to 2027 period total $482.7 million compared to the requests made by Hydro One in its application.

The OEB found that the reductions in Hydro One's proposed capital expenditure and operating, maintenance and administration costs were reasonable, and should not compromise the safety and reliability of Hydro One's transmission and distribution systems. It also concluded that the estimated bill impacts for both transmission and distribution customers are reasonable, and that the January 1, 2023 implementation and effective date of the new rates is appropriate.

In the broader Canadian context, pressures on utility finances at other companies, such as Manitoba Hydro's debt provide additional background for stakeholders.

Bill Impacts

This proceeding related to both transmission and distribution operations.

Transmission

The new transmission revenue requirement will affect Ontario electricity consumers across the province because it will be incorporated into updated transmission rates, which are paid by electricity distributors and other large consumers connected directly to the transmission system, and distributors then pass this cost on to their customers.

As a result of the settlement approved on the transmission portion of the application, it is estimated that for a typical Hydro One residential customer with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $0.69 per month or 0.5%, which follows the 2021 electricity rate reductions that affected many businesses.

Distribution

The new OEB-approved distribution rates will affect Hydro One's distribution customers, including areas served through acquisitions such as the Peterborough Distribution sale which expanded its customer base.

As a result of the settlement reached on the distribution portion of the application, it is estimated that for a typical residential distribution customer of Hydro One with a monthly consumption of 750 kWh, the total bill impact averaged over the 2023-2027 period will be an increase of $2.43 per month or 1.5%.
This proceeding included 24 approved intervenors representing a wide variety of customer classes and other interests. Representatives of 18 of those intervenors participated in the settlement conference. Having this diversity of perspective enriches the already thorough examination of evidence and argument that the OEB routinely undertakes when considering an application.

Other features of the settlement proposal include:

• A commitment by Hydro One to include, in future operational and capital investment plans, a discussion of how the proposed spending will directly support the achievement of Hydro One's climate change policy.
• Eliminating further updates to reflect changes to inflation in 2022 and 2023 as originally proposed, to provide Hydro One's customers with greater certainty as to the potential impacts of inflation on their bills.
• Increases in the productivity factors and supplemental stretch factors for both the distribution and transmission business segments which will provide Hydro One with additional incentives to achieve greater efficiencies during the 2023 to 2027 period.
• Undertaking certain measures to seek economic participation or equity investment opportunities from First Nations.
• Disposition of net credit balances in deferral and variance accounts (DVAs) owed to customers will be returned over a shorter period of time:
• Transmission DVA – $22.5M over a one-year period in 2023 (versus five years)
• Distribution DVA – $85.9M over a three-year period – 2023-2025 (versus five years)
• Undertaking certain measures to continue examining cost-effective transmission and distribution line losses
• In the decision, the OEB acknowledged the efforts involved by parties to participate in this entire proceeding, including the settlement conference, considering the number of participants, the complexity of the issues, and the challenging logistics of a "virtual" proceeding. The OEB commended the parties and OEB staff for achieving a comprehensive settlement on all issues.

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