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Rolls-Royce SMR UK Approval underscores nuclear innovation as regulators review a 470 MW factory-built modular reactor, aiming for grid power by 2029 to boost energy security, cut fossil fuels, and accelerate decarbonization.

Key Points

UK regulatory clearance for Rolls-Royce's 470 MW modular reactor, targeting grid power by 2029 to support clean energy.

✅ UK design approval expected by mid 2024

✅ First 470 MW unit aims for grid power by 2029

✅ Modular, factory-built; est. £1.8b per 10-acre site

A Rolls-Royce (RR.L) design for a small modular nuclear reactor (SMR) will likely receive UK regulatory approval by mid-2024, reflecting progress seen in the US NRC safety evaluation for NuScale as a regulatory benchmark, and be able to produce grid power by 2029, Paul Stein, chairman of Rolls-Royce Small Modular Reactors.

The British government asked its nuclear regulator to start the approval process in March, in line with the UK's green industrial revolution agenda, having backed Rolls-Royce’s $546 million funding round in November to develop the country’s first SMR reactor.

Policymakers hope SMRs will help cut dependence on fossil fuels and lower carbon emissions, as projects like Ontario's first SMR move ahead in Canada, showing momentum.

Speaking to Reuters in an interview conducted virtually, Stein said the regulatory “process has been kicked off, amid broader moves such as a Canadian SMR initiative to coordinate development, and will likely be complete in the middle of 2024.

“We are trying to work with the UK Government, and others to get going now placing orders, echoing expansions like Darlington SMR plans in Ontario, so we can get power on grid by 2029.”

In the meantime, Rolls-Royce will start manufacturing parts of the design that are most unlikely to change, while advancing partnerships like a MoU with Exelon to support deployment, Stein added.

Each 470 megawatt (MW) SMR unit costs 1.8 billion pounds ($2.34 billion) and would be built on a 10-acre site, the size of around 10 football fields, though projects in New Brunswick SMR debate have prompted questions about costs and timelines.

Unlike traditional reactors, SMRs are cheaper and quicker to build and can also be deployed on ships and aircraft. Their “modular” format means they can be shipped by container from the factory and installed relatively quickly on any proposed site.

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CCUS in the U.S. Power Sector drives investments as DOE grants, 45Q tax credits, and EPA carbon rules spur carbon capture, geologic storage, and utilization, while debates persist over costs, transparency, reliability, and emissions safeguards.

Key Points

CCUS captures CO2 from power plants for storage or use, backed by 45Q tax credits, DOE funding, and EPA carbon rules.

✅ DOE grants and 45Q credits aim to de-risk project economics.

✅ EPA rules may require capture rates to meet emissions limits.

✅ Transparency and MRV guard against tax credit abuse.

New public and private funding, including DOE $110M for CCUS announced recently, and expected strong federal power plant emissions reduction standards have accelerated electricity sector investments in carbon capture, utilization and storage,’ or CCUS, projects but some worry it is good money thrown after bad.

CCUS separates carbon from a fossil fuel-burning power plant’s exhaust through carbon capture methods for geologic storage or use in industrial and other applications, according to the Department of Energy. Fossil fuel industry giants like Calpine and Chevron are looking to take advantage of new federal tax credits and grant funding for CCUS to manage potentially high costs in meeting power plant performance requirements, amid growing investor pressure for climate reporting, including new rules, expected from EPA soon, on reducing greenhouse gas emissions from existing power plants.

Power companies have “ambitious plans” to add CCUS to power plants, estimated to cause 25% of U.S. CO2 emissions. As a result, the power sector “needs CCUS in its toolkit,” said DOE Office of Fossil Energy and Carbon Management Assistant Secretary Brad Crabtree. Successful pilots and demonstrations “will add to investor confidence and lead to more deployment” to provide dispatchable clean energy, including emerging CO2-to-electricity approaches for power system reliability after 2030,| he added.

But environmentalists and others insist potentially cost-prohibitive CCUS infrastructure, including CO2 storage hub initiatives, must still prove itself effective under rigorous and transparent federal oversight.

“The vast majority of long-term U.S. power sector needs can be met without fossil generation, and better options are being deployed and in development,” Sierra Club Senior Advisor, Strategic Research and Development, Jeremy Fisher, said, pointing to carbon-free electricity investments gaining momentum in the market. CCUS “may be needed, but without better guardrails, power sector abuses of federal funding could lead to increased emissions and stranded fossil assets,” he added.

New DOE CCUS project grants, an increased $85 per metric ton, or tonne, federal 45Q tax credit, and the forthcoming EPA power plant carbon rules and the federal coal plan will do for CCUS what similar policies did for renewables, advocates and opponents agreed. But controversial past CCUS performance and tax credit abuses must be avoided with transparent reporting requirements for CO2 capture, opponents added.

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NEIMA advances NRC regulatory modernization, creating a licensing framework for advanced reactors, improving uranium permitting, capping reactor fees, and mandating DOE planning for excess uranium, boosting transparency, accountability, and innovation across the US nuclear sector.

Key Points

NEIMA is a US law modernizing NRC rules and enabling advanced reactor licensing while reforming fees.

✅ Modernizes NRC licensing for advanced reactors

✅ Caps annual reactor fees and boosts transparency

✅ Streamlines uranium permitting; directs DOE plans

Bipartisan legislation modernising US nuclear regulation and supporting the establishment of a licensing framework for next-generation advanced reactors has been signed by US President Donald Trump, whose order boosting U.S. uranium and nuclear energy underscored the administration's focus on the sector.

The Nuclear Energy Innovation and Modernisation Act (NEIMA) became law on 14 January.

As well as directing the Nuclear Regulatory Commission (NRC) to modify the licensing process for commercial advanced nuclear reactor facilities, the bill establishes new transparency and accountability measures to the regulator's budget and fee programmes, and caps fees for existing reactors. It also directs the NRC to look at ways of improving the efficiency of uranium licensing, including investigating the safety and feasibility of extending uranium recovery licences from ten to 20 years' duration, and directs the Department of Energy, which oversees nuclear cleanup and related projects, to issue at least every ten years a long-term plan detailing the management of its excess uranium inventories.

Maria Korsnick, president and CEO of the US Nuclear Energy Institute, described NEIMA as a "significant, positive step" toward the reform of the NRC's fee collection process. "This legislation establishes a more equitable and transparent funding structure which will benefit all operating reactors and future licensees," she said. "The bill also reaffirms Congress’s support for nuclear innovation by working to establish an efficient and stable regulatory structure that is prepared to license the advanced reactors of the future."

Marilyn Kray, president-elect of the American Nuclear Society, said the passage of the legislation was a "big win" for the nation and its nuclear community. "By reforming outdated laws, NRC will now be able to invest more freely in advanced nuclear R&D and licensing activities. This in turn will accelerate deployment of cutting-edge American nuclear systems and better prepare the next generation of nuclear engineers and technologists," she said.

The bill was introduced in 2017 by Senator John Barrasso of Wyoming. It was approved by Congress on 21 December by 361 votes to 10, having been passed by the Senate the previous day, even as later Biden's climate law developments produced mixed results.

NEIMA is one of several bipartisan bills that support advanced nuclear innovation considered by the 115th US Congress, which ended on 2 January. These are: the Nuclear Energy Innovation Capabilities Act (NEICA); the Nuclear Energy Leadership Act; the Nuclear Utilisation of Keynote Energy Act; the Advanced Nuclear Fuel Availability Act, a focus sharpened by the U.S. ban on Russian uranium in the fuel market; and legislation to expedite so-called part 810 approvals, which are needed for the export of technology, equipment and components. NEICA, which supports the deployment of advanced reactors and also directs the DOE to develop a reactor-based fast neutron source for the testing of advanced reactor fuels and materials, was signed into law in October.

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V.C. Summer nuclear plant leak update: Dominion Energy repaired a valve in the reactor cooling system; radioactive water stayed within containment, NRC oversight continues as power output ramps toward full operation.

Key Points

A minor valve leak in the reactor cooling system contained onsite; Dominion repaired it as the plant resumes power.

✅ Valve leak in piping to steam generators, not environmental release.

✅ Radioactive water remained in containment, monitored per NRC rules.

✅ Plant ramping from 17% power; full operations may take days.

The V.C. Summer nuclear power plant, which has been shut down since early November because of a pipe leak, is expected to begin producing energy in a few days, a milestone comparable to a new U.S. reactor startup reported recently.

Dominion Energy says it has fixed the small leak in a pipe valve that allowed radioactive water to drip out. The company declined to say when the plant would be fully operational, but spokesman Ken Holt said that can take several days, amid broader discussions about the stakes of early nuclear closures across the industry.

The plant was at 17 percent power Wednesday, he said, as several global nuclear project milestones continue to be reported this year.

Holt, who said Dominion is still investigating the cause, said water that leaked was part of the reactor cooling system. While the water came in contact with nuclear fuel in the reactor, the water never escaped the plant's containment building and into the environment, Holt said.

He characterized the valve leak as '"uncommon" but not unexpected. The nuclear leak occurred in piping that links the nuclear reactor with the power plant's steam generators. Hundreds of pipes are in that part of the nuclear plant, a complexity often cited in the energy debate over struggling nuclear plants nationwide.

"There is always some level of leakage when you are operating, but it is contained and monitored, and when it rises to a certain level, you may take action to stop it," Holt said.

A nuclear safety watchdog has criticized Dominion for not issuing a public notice about the leak, but both the company and the U.S. Nuclear Regulatory Commission say the amount was so small it did not require notice.

The V.C. Summer Nuclear plant is about 25 miles northwest of Columbia in Fairfield County. It was licensed in the early 1980s. At one point, Dominion's predecessor, SCE&G, partnered with state owned Santee Cooper to build two more reactors there, even as new reactors in Georgia were taking shape. But the companies walked away from the project in 2017, citing high costs and troubles with its chief contractor, Westinghouse, even as closures such as Three Mile Island's shutdown continued to influence policy.

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Nova Scotia Power solar charge proposes an $8/kW monthly system access fee on net metering customers, citing grid costs. UARB review, carbon credits, rate hikes, and solar industry impacts fuel political and consumer backlash.

Key Points

A proposed $8/kW monthly grid access fee on net metered solar customers, delayed to Feb 1, 2023, pending UARB review.

✅ $8/kW monthly system access fee on net metering

✅ Delay to Feb 1, 2023 after industry and political pushback

✅ UARB review; debate over grid costs and carbon credits

Nova Scotia Power has pushed back by a year the start date of a proposed new charge for customers who generate electricity and sell it back to the grid, following days of concern from the solar industry and politicians worried that it will damage the sector.

The company applied to the Nova Scotia Utility and Review Board (UARB) last week for various changes, including a "system access charge" of $8 per kilowatt monthly on net metered installations, and the province cannot order the utility to lower rates under current law. The vast majority of the province's 4,100 net metering customers are residential customers with solar power, according to the application. 

The proposed charge would have come into effect Tuesday if approved, but Nova Scotia Power said in a news release Tuesday it will change the date in its filing from Feb. 1, 2022, to Feb. 1, 2023.

"We understand that the solar industry was taken off guard," utility CEO Peter Gregg said in an interview.

"There could have been an opportunity to have more conversations in advance."

Gregg said the utility will meet with members of the solar industry over the next year to work on finding solutions that support the sector's growth, while addressing what NSP sees as an inequity in the net metering system.

NSP recognized that customers who choose solar invest a significant amount and pay for the electricity they use, but they don't pay for costs associated with accessing the electrical grid when they need energy, such as on cold winter evenings when the sun is not shining.

"I know that's hit a nerve, but it doesn't take away the fact that it is an issue," Gregg said.

He said this is an issue utilities are navigating around North America, where seasonal rate designs have sparked consumer backlash in New Brunswick, and NSP is open to hearing ideas for other models of charges or fees.

The utility's suggested system access charge closely resembles one proposed in California, which has also raised major concerns from the solar industry and been criticized by the likes of Elon Musk, and has parallels to Massachusetts solar demand charges as well.

Although the "solar profile" of Nova Scotia and California is very different, with far more solar customers in that state, and in other provinces such as Saskatchewan, NDP criticism of 8% hikes has intensified affordability debates, Gregg said the fundamental issues are the same.

For those with a typical 10-kilowatt solar system, which generates around $1,800 of electricity a year, the new charge would mean those customers would be required to pay $960 back to NSP. That would roughly double the length of time it takes for those customers to pay off their investment for the panels.

David Brushett, chair of Solar Nova Scotia, said he relayed concerns from solar installers and others in the industry to Gregg on Monday. 

Brushett said the year delay is a positive first step, but he is still calling on the province to take a strong stance against the application, which has led to customers cancelling their panel installations and companies considering layoffs.

"There's still an urgency to this situation that hasn't been addressed, and we need to kind of protect the industry," he said Tuesday.

NSP's original application proposed exempting net metering customers who enrolled before Feb. 1, 2022, from the charge for 25 years after they sign up. But any benefit would be lost if those customers sold their home, and the exemption wouldn't extend to the new buyers, said Brushett.

Carbon offsets missing from equation: industry
Brushett said NSP "completely ignored" the fact that it's getting free carbon offset credits from homeowners who use solar energy under the provincial cap and trade program.

If the net metering system continues as is, NSP has said non-solar customers would pay about $55 million between now and 2030. That number assumes about 2,000 people sign up for net metering each year over the next nine years.

When asked whether those carbon emission credits were factored into the calculations for the proposed charge, Gregg said, "I don't believe in the current structure it is, but it's something that certainly we'd be open to hearing about."

Brushett said his group is finalizing a legal response to NSP's proposal and has already filed an official complaint against the company with the UARB.

Base charge on actual electrical output: customer
At least one shareholder in NSP parent company Emera is considering selling his shares in response to the application.

Joe Hood, a shareholder from Middle Sackville, said the proposed charge won't apply to his existing 11.16-kilowatt solar system, but if it did, it would cost him $1,071 a year.

"I am offended that a company I would invest in would do this to the solar industry in Nova Scotia," he said.

According to his meter, Hood said he pushed 9,600 kilowatt hours of solar electricity to the grid last year— some only for a brief period, and all of which was used by his home by the end of the year.

Under the proposed charge, someone with one solar panel who goes away on vacation in the summer would push all their electricity to the grid, and be charged far less than someone with 10 panels who has used all their own power and hasn't pushed anything.

"Nova Scotia Power's argument is that it's an issue with the grid. Well, then it should be based on what touches the grid," Hood said.

Far from actually making the system fair for everyone, Hood said this charge places solar only in the hands of the super-rich or NSP, with projects like its community solar gardens in Amherst, N.S.

Green Party suggests legislation update
Nova Scotia's Green Party also said Tuesday that Gregg's arguments of fairness are misleading, echoing earlier premier opposition to a 14% hike on rates.

The party is calling for an update to the Electricity Act that would "prevent penalizing any activity that helps Nova Scotia reach its emissions target," aligning with calls to make the electricity system more accountable to residents.

In its application, NSP has also asked to increase electricity rates for residential customers by at least 10 per cent over the next three years, amid debate that culminated in a 14% rate hike approval by regulators. 

The company wants to maintain its nine per cent rate of return.

NSP expects to earn $153 million this year, $192 million in 2023, and $213 million in 2024 from its rate of return. 

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Canada Oil Recession Outlook analyzes the Russia-Saudi price war, OPEC discord, COVID-19 demand shock, WTI and WCS collapse, Alberta oilsands exposure, U.S. shale stress, and GDP risks from blockades and fiscal responses.

Key Points

An outlook on how the oil price war and COVID-19 demand shock could tip Canada into recession and strain producers.

✅ WTI and WCS prices plunge on OPEC-Russia discord

✅ Alberta oilsands face break-even pressure near 30 USD WTI

✅ RBC flags global recession; GDP hit from blockades, virus

A war between Russia and Saudi Arabia for market share for oil may have been triggered by the COVID-19 pandemic in China, but the oil price crash contagion that it will spread could have impacts that last longer than the virus.

The prospects for Canada are not good.

Plunging oil prices, reduced economic activity from virus containment, and the fallout from weeks of railway blockades over the Coastal GasLink pipeline all add up to “a one-two-three punch that I think is almost inevitably going to put Canada in a position where its growth has to be negative,” said Dan McTeague, a former Liberal MP and current president of Canadians for Affordable Energy. The situation “certainly has the makings” of a recession, said Ken Peacock, chief economist for the Business Council of British Columbia.

“At a minimum, it’s going to be very disruptive and we’re going to have maybe one negative quarter,” Peacock said. “Whether there’s a second one, where it gets labeled a recession, is a different question. But it’s going to generate some turmoil and challenges over the next two quarters – there’s no doubt about that.”

RBC Economics on March 13 announced it now predicts a global recession and cut its growth projections for Canada's economy in 2020 by half a per cent.

Oil price futures plunged 30% last week, dragging stock markets and currencies, including the Canadian dollar, down with them, even as a deep freeze strained U.S. energy systems. That drop came on top of a 17% decline in February, due to falling demand for oil due to the virus.

The latest price plunge – the worst since the 1991 Gulf War – was the result of Russia and the Organization of Petroleum Exporting Countries (OPEC), led by Saudi Arabia, failing to agree on oil production cuts.

The COVID-19 outbreak in China – the world’s second-largest oil consumer – had resulted in a dramatic drop in oil demand in that country, and a sudden glut of oil, with the U.S. energy crisis affecting electricity, gas and EV markets.

OPEC has historically been able to moderate global oil prices by controlling output. But when Russia refused to co-operate with OPEC and agree to production cuts, Saudi Arabia’s state-owned company, Aramco, announced it plans to boost its oil output from 9.7 million barrels per day (bpd) to 12.3 million bpd in April.

In response to that announcement, West Texas Intermediate (WTI) prices dropped 18% to below US$34 per barrel while the Canadian Crude Index fell 24% to US$21. Western Canadian Select dropped 39% to US$15.73.

The effect on Alberta oilsands producers was severe and immediate. Cenovus Energy Inc. (TSX:CVE) saw roughly $2 billion in market cap erased on March 9, when its stock dropped by 52%, which came on top of a 12% drop March 6.

The company responded the very next day by announcing it would cut spending by 32% in 2020, suspend its oil-by-rail program and defer expansion projects.

MEG Energy Corp. (TSX:MEG), which suffered a 56% share price drop on March 9, also announced a 20% reduction in its 2020 capital spending plan.

Peter Tertzakian, chief economist for ARC Energy Research Institute, wrote last week that Russia’s plan is to try to hurt U.S. shale oil producers, who have more than doubled U.S. oil production over the past decade.

Anas Alhajji, a global oil analyst, expects that plan could work. Even before the oil price shock, he had predicted the great shale boom in the U.S. was coming to an end.

“Shale production will decline, and the myth of ‘explosive growth’ will end,” he told Business in Vancouver. “The impact is global and Canadian producers might suffer even more if the oil that Saudi Arabia sends to the U.S. is medium and heavy. This might last longer than what people think.”

The question for Alberta is how Canadian producers can continue to operate through a period of cheap oil. Alberta producers do not compete on the global market. They serve a niche market of U.S. heavy oil refiners, and Biden-era policy is seen as potentially more favourable for Canada’s energy sector than alternatives.

“On the positive side, the industry is battle-hardened,” Tertzakian wrote. “Over the past five years, innovative companies have already learned to endure some of the lowest prices in the world.”

But he added that they need WTI prices of US$30 per barrel just to break even.

“But that’s an average break-even threshold for an industry with a wide variation in costs. That means at that level about half the companies can’t pay their bills and half are treading water.”

Just prior to the oil price plunge, the International Energy Agency (IEA) updated its 2020 forecast for global oil consumption from an 825,000 bpd increase in oil consumption to a 90,000 bpd decrease, due to the COVID-19 virus and consequent economic contraction and reduction in travel.

The IEA predicts global oil demand won’t return to “normal” until the second half of 2020. But even if demand does return to pre-virus levels, that doesn’t mean oil prices will – not if Saudi Arabia can sustain increased oil production at low prices, and evolving clean grid priorities could influence the trajectory too.

The oil plunge was greeted in Alberta with alarm. Alberta Premier Jason Kenney warned Alberta is in “uncharted territory” as consumers are urged to lock in rates and said his government might have to review its balanced budget and resort to emergency deficit spending.

While British Columbians – who pay some of the highest gasoline prices in North America – will enjoy lower gasoline prices at a time when prices are usually starting a seasonal spike, B.C.’s economy could feel knock-on effects from a recession in Alberta.

“We sell a lot of inputs, do a lot of trade with Alberta, so it’s important for B.C., Alberta’s economic health,” Peacock said, “and recent tensions over electricity purchase talks underscore that.”

Last week, the Trudeau government announced $1 billion in emergency funding to cope with the virus and waived a one-week waiting period for unemployment insurance.

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