IMO implores for Ontario nuclear investment

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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BC Hydro LNG Load Forecast signals rising electricity demand from LNG Canada, Woodfibre, and Tilbury, aligning Site C dam capacity with BCUC review, hydroelectric supply, and a potential fourth project in feasibility study British Columbia.

Key Points

BC Hydro's projection of LNG-driven power demand, guiding Site C capacity, BCUC review, and grid planning.

✅ Includes LNG Canada, Woodfibre, and Tilbury load requests

✅ Aligns Site C hydroelectric output with industrial electrification

✅ Notes feasibility study for a fourth LNG project

Despite recent project cancellations, such as the Siwash Creek independent power project now in limbo, BC Hydro still expects three LNG projects — and possibly a fourth, which is undergoing a feasibility study — will need power from its controversial and expensive Site C hydroelectric dam.

In a letter sent to the British Columbia Utilities Commission (BCUC) on Oct. 3, BC Hydro’s chief regulatory officer Fred James said the provincially owned utility’s load forecast includes power demand for three proposed liquefied natural gas projects because they continue to ask the company for power.

The letter and attached report provide some detail on which of the LNG projects proposed in B.C. are more likely to be built, given recent project cancellations.

The documents are also an attempt to explain why BC Hydro continues to forecast a surge in electricity demand in the province, as seen in its first call for power in 15 years driven by electrification, even though massive LNG projects proposed by Malaysia’s state owned oil company Petronas and China’s CNOOC Nexen have been cancelled.

An explanation is needed because B.C.’s new NDP government had promised the BCUC would review the need for the $9-billion Site C dam, which was commissioned to provide power for the province’s nascent LNG industry, amid debates over alternatives like going nuclear among residents. The commission had specifically asked for an explanation of BC Hydro’s electric load forecast as it relates to LNG projects by Wednesday.

The three projects that continue to ask BC Hydro for electricity are Shell Canada Ltd.’s LNG Canada project, the Woodfibre LNG project and a future expansion of FortisBC’s Tilbury LNG storage facility.

None of those projects have officially been sanctioned but “service requests from industrial sector customers, including LNG, are generally included in our industrial load forecast,” the report noted, even as Manitoba Hydro warned about energy-intensive customers in a separate notice.

In a redacted section of the report, BC Hydro also raises the possibility of a fourth LNG project, which is exploring the need for power in B.C.

“BC Hydro is currently undertaking feasibility studies for another large LNG project, which is not currently included in its Current Load Forecast,” one section of the report notes, though the remainder of the section is redacted.

The Site C dam, which has become a source of controversy in B.C. and was an important election issue, is currently under construction and, following two new generating stations recently commissioned, is expected to be in service by 2024, a timeline which had been considered to provide LNG projects with power by the time they are operational.

BC Hydro’s letter to the BCUC refers to media and financial industry reports that indicate global LNG markets will require more supply by 2023.

“While there remains significant uncertainty, global LNG demand will continue to grow and there is opportunity for B.C. LNG,” the report notes.

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Electrification Potential Study for Canada evaluates NRCan's decarbonization roadmap, assessing electrification of end uses and replacements for fossil fuels across transportation, buildings, and industry, including propane, diesel, natural gas, and coal, to guide energy policy.

Key Points

An NRCan study assessing electrification to replace fossil fuels across sectors and guide deep decarbonization R&D.

✅ Evaluates non-electric alternatives alongside electrification paths

✅ Covers propane, diesel, natural gas, and coal end uses

✅ Guides NRCan R&D priorities for deep decarbonization

The federal government wants to spend up to $300,000 on a study aimed at understanding whether existing electrical technologies can “reduce or eliminate” fossil fuels used for virtually every purpose other than generating electricity.

The proposal has caused consternation within the Saskatchewan government, whose premier has criticized a 2035 net-zero grid target as shifting the goalposts, and which has spent months attacking federal policies it believes will harm the Western Canadian energy sector without meaningfully addressing climate change.

Procurement documents indicate the “Electrification Potential Study for Canada” will provide “strategic guidance on the need to pursue both electric and non-electric energy research and development to enable deep decarbonisation scenarios.”

“It is critical that (Natural Resources Canada) as a whole have a cross-sectoral, consistent, and comprehensive understanding of the viability of electric technologies as a replacement for fossil fuels,” the documents state.

The study proponent will be asked to examine possible replacements for a range of fuels, including propane, transportation fuel, fuel oil, diesel, natural gas and coal, even as Alberta maps a path to clean electricity for its grid. Only international travel fuel and electricity generation are outside the scope of the study.

“To be clear, the consultant should not answer these questions directly, but should conduct the analysis with them in mind. The goal … is to collate data which can be used by (Natural Resources Canada) to conduct analysis related to these questions,” the documents state.

Natural Resources Canada issued the request for proposals one week before Prime Minister Justin Trudeau officially launched a 40-day election campaign in which climate and energy policy, including debates over Alberta's power market like a Calgary retailer's challenge, is expected to play a defining role.

It also comes as the federal government works to complete the controversial Trans Mountain Pipeline Expansion project through British Columbia, amid tariff threats boosting support for Canadian energy projects, which it bought last year for $4.5 billion and is currently bogged down in the court system.

A Natural Resources Canada spokeswoman said the ministry would not be able to respond to questions until sometime on Thursday.

While the documents make clear that the study aims to answer unresolved questions about what the International Energy Agency calls an increasingly-electric future, with clean grid and storage trends emerging, without a specific timeline, the provincial government is far from thrilled.

Energy and Resources Minister Bronwyn Eyre said the document reflects the federal government’s “hostility” to the energy sector, even as Alberta's electricity sector faces profound change, because government ministries like Natural Resources Canada don’t do anything without political direction.

Asked whether a responsible government should consider every option before taking a decision, Eyre said a government that was not interested in eliminating fossil fuels entirely would not have used such “strong” language in a public document, noting that provinces like Ontario are grappling with hydro system problems as well.

“I think it’s a real wake-up call to what (Ottawa’s) endgame really is here,” she said, adding that the document does not ask the proponent to conduct an economic impact analysis or consider potential job losses in the energy sector.

The study is organized by Natural Resources Canada’s office of energy research and development, which is tasked with accelerating energy technology “in order to produce and use energy in … more clean and efficient ways,” the documents state.

Bidding on the proposal closes Oct. 14, one week before the federal election. The successful proponent must deliver a final report in April 2020, according to the documents.

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Africa Energy Access Funding faces disbursement bottlenecks as SDG 7 goals demand investment in decentralized solar, minigrids, and rural electrification; COVID-19 pressures donors, requiring faster approvals, standardized documentation, and stronger project preparation and due diligence.

Key Points

Financing to expand Africa's electrification, advancing SDG 7 via disbursement to decentralized solar and minigrids.

✅ Accelerates investment for SDG 7 and rural electrification

✅ Prioritizes decentralized solar, minigrids, and utilities

✅ Speeds approvals, standard docs, and project preparation

The time frame from final funding approval to disbursement can be the most painful part of any financing process, and the access-to-electricity sector is not spared.

Amid the global spread of the coronavirus over the last few weeks, there have been several funding pledges to promote access to electricity in Africa. In March, the African Development Bank and other partners committed $160 million for the Facility for Energy Inclusion to boost electricity connectivity in Africa through small-scale solar systems and minigrids. Similarly, the Export-Import Bank of the United States allocated $91.5 million for rural electrification in Senegal.

Rockefeller chief wants to redefine 'energy poverty'

Rajiv Shah, president of The Rockefeller Foundation, believes that SDG 7 on energy access lacks ambition. He hopes to drive an effort to redefine it.

Currently, funding is not being adequately deployed to help achieve universal access to energy. The International Energy Agency’s “Africa Energy Outlook 2019” report estimated that an almost fourfold increase in current annual access-to-electricity investments — approximately $120 billion a year over the next 20 years — is required to provide universal access to electricity for the 530 million people in Africa that still lack it.

While decentralized renewable energy across communities, particularly solar, has been instrumental in serving the hardest-to-reach populations, tracking done by Sustainable Energy for All — in the 20 countries with about 80% of those living without access to sustainable energy — suggests that decentralized solar received only 1.2% of the total electricity funding.

The spread of COVID-19 is contributing significantly to Africa’s electricity challenges across the region, creating a surge in the demand for energy from the very important health facilities, an exponential increase in daytime demand as a result of most people staying and working indoors, and a rise from some food processing companies that have scaled up their business operations to help safeguard food security, among others. Thankfully — and rightly so — access-to-electricity providers are increasingly being recognized as “essential service” providers amid the lockdowns across cities.

To start tackling Africa’s electricity challenges more effectively, “funding-ready” energy providers must be able to access and fulfill the required conditions to draw down on the already pledged funding. What qualifies as “funding readiness” is open to argument, but having a clear, commercially viable business and revenue model that is suitable for the target market is imperative.

Developing the skills required to navigate the due-diligence process and put together relevant project documents is critical and sometimes challenging for companies without prior experience. Typically, the final form of all project-related agreements is a prerequisite for the final funding approval.

In addition, having the right internal structures in place — for example, controls to prevent revenue leakage, an experienced management team, a credible board of directors, and meeting relevant regulatory requirements such as obtaining permits and licenses — are also important indicators of funding readiness.

1. Support for project preparation. Programs — such as the Private Financing Advisory Network and GET.invest’s COVID-19 window — that provide business coaching to energy project developers are key to helping surmount these hurdles and to increasing the chances of these projects securing funding or investment. Donor funding and technical-assistance facilities should target such programs.

2. Project development funds. Equity for project development is crucial but difficult to attract. Special funds to meet this need are essential, such as the $760,000 for the development of small-scale renewable energy projects across sub-Saharan Africa recently approved by the African Development Bank-managed Sustainable Energy Fund for Africa.

3. Standardized investment documentation. Even when funding-ready energy project developers have secured investors, delays in fulfilling the typical preconditions to draw down funds have been a major concern. This is a good time for investors to strengthen their technical assistance by supporting the standardization of approval documents and funding agreements across the energy sector to fast-track the disbursement of funds.

4. Bundled investment approvals and more frequent approval sessions. While we implement mechanisms to hasten the drawdown of already pledged funding, there is no better time to accelerate decision-making for new access-to-electricity funding to ensure we are better prepared to weather the next storm. Donors and investors should review their processes to be more flexible and allow for more frequent meetings of investment committees and boards to approve transactions. Transaction reviews and approvals can also be conducted for bundled projects to reduce transaction costs.

5. Strengthened local capacity. African countries must also commit to strengthening the local manufacturing and technical capacity for access-to-electricity components through fiscal incentives such as extended tax holidays, value-added-tax exemptions, accelerated capital allowances, and increased investment allowances.

The ongoing pandemic and resulting impacts due to lack of electricity have further shown the need to increase the pace of implementation of access-to-electricity projects. We know that some of the required capital exists, and much more is needed to achieve Sustainable Development Goal 7 — about access to affordable and clean energy for all — by 2030.

It is time to accelerate our support for access-to-electricity companies and equip them to draw down on pledged funding, while calling on donors and investors to speed up their funding processes to ensure the electricity gets to those most in need.

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DOE CCUS Funding advances carbon capture, utilization, and storage with FEED studies, regional deployment, and CarbonSAFE site characterization, leveraging 45Q tax credits to scale commercial CO2 reduction across fossil energy sectors.

Key Points

DOE CCUS Funding are federal FOAs for commercial carbon capture, storage, and utilization via FEED and CarbonSAFE.

✅ $110M across FEED, Regional, and CarbonSAFE FOAs

✅ Supports Class VI permits, NEPA, and site characterization

✅ Enables 45Q credits and enhanced oil recovery utilization

The U.S. Department of Energy’s (DOE’s) Office of Fossil Energy (FE) has announced approximately $110 million in federal funding for cost-shared research and development (R&D) projects under three funding opportunity announcements (FOAs), alongside broader carbon-free electricity investments across the power sector.

Approximately $75M is for awards selected under two FOAs announced earlier this fiscal year; $35M is for a new FOA.

These FOAs further the Administration’s commitment to strengthening coal while protecting the environment. Carbon capture, utilization, and storage (CCUS) is increasingly becoming widely accepted as a viable option for fossil-based energy sources—such as coal- or gas-fired power plants under new EPA power plant rules and other industrial sources—to lower their carbon dioxide (CO2) emissions.

DOE’s program has successfully deployed various large-scale CCUS pilot and demonstration projects, and it is imperative to build upon these learnings to test, mature, and prove CCUS technologies at the commercial scale. A recent study by Science of the Total Environment found that DOE is the most productive organization in the world in the carbon capture and storage field.

“This Administration is committed to providing cost-effective technologies to advance CCUS around the world,” said Secretary Perry. “CCUS technologies are vital to ensuring the United States can continue to safely use our vast fossil energy resources, and we are proud to be a global leader in this field.”

“CCUS technologies have transformative potential,” said Assistant Secretary for Fossil Energy Steven Winberg. “Not only will these technologies allow us to utilize our fossil fuel resources in an environmentally friendly manner, but the captured CO2 can also be utilized in enhanced oil recovery and emerging CO2-to-electricity concepts, which would help us maximize our energy production.”

Under the first FOA award, Front-End Engineering Design (FEED) Studies for Carbon Capture Systems on Coal and Natural Gas Power Plants, DOE has selected nine projects to receive $55.4 million in federal funding for cost-shared R&D. The selected projects will support FEED studies for commercial-scale carbon capture systems. Find project descriptions HERE. 

Under the second FOA award, Regional Initiative to Accelerate CCUS Deployment, DOE selected four projects to receive up to $20 million in federal funding for cost-shared R&D. The projects also advance existing research and development by addressing key technical challenges; facilitating data collection, sharing, and analysis; evaluating regional infrastructure, including CO2 storage hubs and pipelines; and promoting regional technology transfer. Additionally, this new regional initiative includes newly proposed regions or advanced efforts undertaken by the previous Regional Carbon Sequestration Partnerships (RCSP) Initiative. Find project descriptions HERE. 

Elsewhere in North America, provincial efforts such as Quebec's and industry partners like Cascades are investing in energy efficiency projects to complement emissions-reduction goals.

Under the new FOA, Carbon Storage Assurance Facility Enterprise (CarbonSAFE): Site Characterization and CO2 Capture Assessment, DOE is announcing up to $35 million in federal funding for cost-shared R&D projects that will accelerate wide-scale deployment of CCUS through assessing and verifying safe and cost-effective anthropogenic CO2 commercial-scale storage sites, and carbon capture and/or purification technologies. These types of projects have the potential to take advantage of the 45Q tax credit, bolstered by historic U.S. climate legislation, which provides a tax credit for each ton of CO2 sequestered or utilized. The credit was recently increased to $35/metric ton for enhanced oil recovery and $50/metric ton for geologic storage.

Projects selected under this new FOA shall perform the following key activities: complete a detailed site characterization of a commercial-scale CO2 storage site (50 million metric tons of captured CO2 within a 30 year period); apply and obtain an underground injection control class VI permit to construct an injection well; complete a CO2capture assessment; and perform all work required to obtain a National Environmental Policy Act determination for the site.

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Minnesota Carbon-Free Power by 2050 aims to shift utilities to renewable energy, wind and solar, boosting efficiency while managing grid reliability, emissions, and costs under a clean energy mandate and statewide climate policy.

Key Points

A statewide goal to deliver 100% carbon-free power by 2050, prioritizing renewables, efficiency, and grid reliability.

✅ Targets 100% carbon-free electricity statewide by 2050

✅ Prioritizes wind, solar, and efficiency before fossil fuels

✅ Faces utility cost, reliability, and legislative challenges

Gov. Tim Walz's plan for Minnesota to get 100 percent of its electricity from carbon-free sources by 2050, similar to California's 100% carbon-free mandate in scope, was criticized Tuesday at its first legislative hearing, with representatives from some of the state's smaller utilities saying they can't meet that goal.

Commerce Commissioner Steve Kelley told the House climate committee that the Democratic governor's plan is ambitious. But he said the state's generating system is "aging and at a critical juncture," with plants that produce 70 percent of the state's electricity coming up for potential retirement over the next two decades. He said it will ensure that utilities replace them with wind, solar and other innovative sources, and increased energy efficiency, before turning to fossil fuels.

"Utilities will simply need to demonstrate why clean energy would not work whenever they propose to replace or add new generating capacity," he said.

Walz's plan, announced last week, seeks to build on the success of a 2007 law that required Minnesota utilities to get at least 25 percent of their electricity from renewable sources by 2025. The state largely achieved that goal in 2017 thanks to the growth of wind and solar power, and the topic of climate change has only grown hotter, with some proposals like a fully renewable grid by 2030 pushing even faster timelines, hence the new goal for 2050.

But Joel Johnson, a lobbyist for the Minnkota Power Cooperative, testified that the governor's plan is "misguided and unrealistic" even with new technology to capture carbon dioxide emissions from power plants. Johnson added that even the big utilities that have set goals of going carbon-free by mid-century, such as Minneapolis-based Xcel Energy, acknowledge they don't know yet how they'll hit the net-zero electricity by mid-century target they have set.

Minnkota serves northwestern Minnesota and eastern North Dakota.

Tim Sullivan, president and CEO of the Wright-Hennepin Cooperative Electric Association in the Twin Cities area, said the plan is a "bad idea" for the 1.7 million state electric consumers served by cooperatives. He said Minnesota is a "minuscule contributor" to total global carbon emissions, even as the EU plans to double electricity use by 2050 to meet electrification demands.

"The bill would have a devastating impact on electric consumers," Sullivan said. "It represents, in our view, nothing short of a first-order threat to the safety and reliability of Minnesota's grid."

Isaac Orr is a policy fellow at the Minnesota-based conservative think tank, the Center for the American Experiment, which released a report critical of the plan Tuesday. Orr said all Minnesota households would face higher energy costs and it would harm energy-intensive industries such as mining, manufacturing and health care, while doing little to reduce global warming.

"This does not pass a proper cost-benefit analysis," he testified.

Environmental groups, including Conservation Minnesota and the Sierra Club, supported the proposal while acknowledging the challenges, noting that cleaning up electricity is critical to climate pledges in many jurisdictions.

"Our governor has called climate change an existential crisis," said Kevin Lee, director of the climate and energy program at the Minnesota Center for Environmental Advocacy. "This problem is the defining challenge of our time, and it can feel overwhelming."

Rep. Jean Wagenius, the committee chairwoman and Minneapolis Democrat who's held several hearings on the threats that climate change poses, said she expected to table the bill for further consideration after taking more testimony in the evening and would not hold a vote Tuesday.

While the bill has support in the Democratic-controlled House, it's not scheduled for action in the Republican-led Senate. Rep. Pat Garofalo, a Farmington Republican, quipped that it "has a worse chance of becoming law than me being named the starting quarterback for the Minnesota Vikings."

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