The power station operates two nuclear reactors in Louisa County, Va. Dominion Energy’s Surry Power Station previously received NRC approval in 2021 to extend its operating license through 2053. Combined, Surry and North Anna generate 40% of Virginia’s electricity and account for about 90% of the carbon-free power in the state.

“For more than 50 years, nuclear power has been the most reliable workhorse of our fleet and the largest source of carbon-free power in Virginia,” said Eric Carr, Dominion Energy’s chief nuclear officer. “North Anna operates around the clock and generates the reliable, clean energy that powers our customers’ homes and businesses every day. With this 20-year extension, our customers can continue counting on North Anna for reliable, carbon-free power for another generation to come.”

Dominion Energy said it is conducting numerous upgrades at the station, including replacing the reactors’ main generators and condensers, refurbishing reactor coolant pumps, and converting instrument and control systems from analog to digital. The company is also implementing 80 enhancements to station procedures, such as additional inspections and equipment testing.

The North Anna units were originally licensed to operate for 40 years in 1978 and 1980. Their licenses were renewed for an additional 20 years in 2003, after a federal review process. Under its current licenses, North Anna reactors 1 and 2 could have operated through 2038 and 2040, respectively. With the renewed licenses, the units can operate through 2058 and 2060, respectively. 

Dominion Energy said it plans to seek recovery of the costs associated with the license extension from the Virginia State Corporation Commission later this year.

The nuclear units at North Anna Power Station are both three-loop Westinghouse pressurized water reactors – capable of providing nearly 2,000 MW at peak capacity, or about 17% of the electricity delivered to Dominion Energy Virginia customers.

Dominion Energy’s affiliated companies also plan to seek NRC approval to extend to 80 years the operating licenses of the V.C. Summer Power Station in South Carolina and Millstone Power Station in Connecticut.

Earlier this year, Dominion Energy Virginia issued a Request for Proposals (RFP) from nuclear technology companies to evaluate the feasibility of developing a small modular reactor (SMR) at the North Anna Power Station. While Dominion stressed the RFP is not a commitment to build this SMR, the company said it is an important first step in evaluating the technology and the North Anna site.

A major expansion of battery storage may be the most economical and environmentally beneficial way for Illinois to maintain grid reliability as it phases out fossil fuel generation, a new study finds.

The analysis was commissioned by the nonprofit Clean Grid Alliance and solar organizations as state lawmakers consider proposed incentives for private developers to build battery storage.

“The outlook is not great for bringing on major amounts of new capacity to replace the retiring capacity,” said Mark Pruitt, former head of the Illinois Power Agency and author of the study, which suggests batteries will be a more realistic path forward than a massive buildout of new generation and transmission infrastructure. 

The proposed legislation — SB 3959 and HB 5856 — would require the Illinois Power Agency to procure energy storage capacity for deployment by utilities ComEd and Ameren. Payments would be based on the difference between energy market prices and the costs of charging batteries off-peak, to ensure the storage would be profitable. The need for incentives would theoretically ratchet down over time. 

“As market prices for power go up, your incentive goes down,” Pruit said. “The idea is to provide an incentive that bridges the gap between the cost of battery technology and the value in the market. Over time, those will equalize and level out.” 

The bills, introduced in May at the end of the legislature’s spring session, would amend existing energy law to add energy storage incentives to state policy, along with existing incentives for nuclear and renewables. 

The study noted that Illinois will need at least 8,500 new megawatts of capacity and possibly as much as 15,000 new megawatts between 2030 and 2049, with increased demand driven in part by the growth of data centers. Twenty-five data centers being proposed in Illinois would use as much energy as the state’s five nuclear plants generate, according to nuclear plant owner Exelon’s CEO Calvin Butler Jr., quoted by Bloomberg. 

The North American Electric Reliability Corporation (NERC) found in its summer and winter 2024 assessments that within MISO and PJM regional grids, Wisconsin, Michigan, Minnesota, Illinois and Indiana are all at “elevated” risk of insufficient capacity. 

“NERC, PJM, MISO and the Illinois Commerce Commission have all identified the potential for capacity shortfalls,” said Pruitt. “You do have some options for alleviating that. You can build transmission and bring in capacity from outside the state. You can maintain your current domestic generating capacity [without retiring fossil fuel plants]. You could expand your domestic generating capacity. And an independent variable is your growth rate. All these have to work together, there’s no silver bullet. We know there are major challenges on each of those fronts.” 

Gloomy numbers 

The latest PJM capacity auction results showed capacity prices increasing from $28.92/MW-Day for the 2024/25 period to $269.92/MW-Day — a nearly 10-fold increase — for the following year. That “translates into an annual cost increase of about $350 for a typical single-family household served by ComEd,” Pruitt said. “The increase in costs indicates that more capacity supply is required to meet capacity demand in the future.” 

There are many new generation projects in the queue for interconnection by MISO and PJM, but many of them drop out before ever being deployed because of unviable economics, long delays, regulatory challenges and other issues. A recent study by Lawrence Berkeley National Laboratory noted that while interconnection requests for renewables have skyrocketed since the Inflation Reduction Act, only 15% of interconnected capacity was actually completed in PJM and MISO between 2000 and 2018, and experts say similar completion rates persist. 

“This finding indicates that deploying sufficient new capacity resources to offset [fossil fuel] retirements is not likely to occur in the near term,” said Pruitt. “Just because something is planned doesn’t mean it gets built.” 

Meanwhile the state is running out of funds for the purchase of renewable energy credits (RECs) that are crucial to driving wind and solar development. The 2024 long-term renewable resources procurement plan by the IPA shows the state’s fund for renewables reaching a deficit in 2028, so that spending on RECs from renewables will have to be scaled back by as much as 60%. 

Long-distance transmission lines could bring wind energy or other electricity from out of state. But planned transmission lines have faced hurdles. The Grain Belt Express transmission line, in the works for a decade, was in August denied needed approval from an Illinois appellate court. The transmission line, proposed by Invenergy, would have brought wind power from Kansas to load centers to the east. 

“That sets it back years,” Pruitt said. “Transmission is a very long-term solution. I’m sure people are working diligently on it, but it’s five to 10 years before you get something approved and built.” 

Value proposition, solar benefits 

Pruitt’s study found that if 8,500 MW of energy storage were deployed between 2030 and 2049, Illinois customers could see up to $3 billion in savings compared to if they had to foot the bill for increased capacity without new storage. The savings would come because of lower market prices in capacity auctions, as well as investment in new transmission and generation that would be avoided. 

Pruitt found that $11 billion to $28 billion in macro-level economic benefits could also result, with blackouts avoided, reduced fossil fuel emissions and jobs and economic stimulus created. 

Pruitt’s analysis indicates that the incentives proposed in the legislation would cost $6.4 billion to customers. But the storage would result in $9.4 billion in savings compared to the status quo, hence a $3 billion overall savings between 2030 and 2049. 

“Solar is great, but solar is an intermittent resource; battery storage when paired with solar allows it to be far more reliable,” said Andrew Linhares, Central Region senior manager for the Solar Energy Industry Association. “Battery storage is not as cheap as solar, but its reliability is its hallmark. Combining the resources gives you a cheap and reliable resource.” 

“Solar and storage is this powerful tool that can help reduce costs for consumers and create new jobs and economic activity,” he continued. “I don’t believe that same picture is there for building out new natural gas resources. Anything that helps storage, helps solar and vice versa. CEJA sees these two technologies as being joined at the hip for the future, they are being seen more and more as a single resource.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

COLUMBIA, S.C. (AP) — The South Carolina Senate on Thursday started its homework assignment of coming up with a comprehensive bill to guide energy policy in a rapidly growing state and amid a quickly changing power- generation world.

The Special Committee on South Carolina’s Energy Future plans several meetings through October. On Thursday, the committee heard from the leaders of the state’s three major utilities. Future meetings will bring in regular ratepayers, environmentalists, business leaders and experts on the latest technology to make electricity,

The Senate took this task upon itself. They put the brakes a massive 80-plus page energy overhaul bill that passed the House in March in less than six weeks, and the bill died at the end of the session.

Many senators said the process earlier this year was rushed. They remembered the last time they trusted an overhaul bill backed by utilities.

State-owned Santee Cooper and private South Carolina Electric & Gas used those rules passed 15 years ago to put ratepayers on the hook for billions of dollars spent on two new nuclear reactors that never generated a watt of power before construction was abandoned because of rising costs.

But those dire memories are being mixed with dire predictions of a state running out of power.

Unusually cold weather on Christmas Eve 2022 along with problems at a generating facility nearly led to rolling blackouts in South Carolina. Demand from advanced manufacturing and data centers is rising. If electric cars grow in popularity, more power is needed. And a state that added 1.3 million people since 2000 has a lot more air conditioners, washing machines and charges for devices, the utility leaders said.

Senators stopped Duke Energy’s president in South Carolina, Mike Callahan, in middle of his presentation after he told them his utility’s most recent predictions for growth in electricity usage over the rest of this decade were eight times more than they were just two years ago.

“Growth is here, and much more is coming. We need clear energy policy to plan for that growth,” Callahan said,

The utility leaders told senators their companies need to know what kind of sources of power — natural gas, solar, nuclear, wind or others — the state wants to emphasize. They would like to have a stable rules from regulators on how they operate.

“A quick no is a lot better to us than a long-term maybe,” Santee Cooper CEO Jimmy Staton said.

Another complicating factor are federal rules that may require utilities to shut down power plants that use coal before there are replacements with different sources online, Staton said.

Others aren’t so sure the state needs a rapid increase in power generation. Environmentalists have suggested the 2022 problems that led to blackouts were made worse because power plants were nowhere near capacity and better cooperation in the grid would allow electricity to get to where its needed easier.

Those less bullish on the overhaul also are urging the state not to lock in on one source of power over another because technology could leave South Carolina with too much power generation in inefficient ways.

There will likely be plenty of discussion of data centers that use a lot of electricity without the number of jobs, property taxes or other benefits a manufacturer provides.

Staton estimated about 70% of Santee Cooper’s increased demand is from data centers.

“We clearly need them. I don’t want to go back in time,” committee chairman Republican Senate Majority Leader Shane Massey said. “What I’m trying to get at is a better understanding, a better handle on how much of the projected growth is based on data centers or on everything else.”

Massey has been hard on Dominion Energy, which bought South Carolina Electric & Gas after the abandoned nuclear project at the V.C. Summer Nuclear Station. But Dominion Energy South Carolina President Keller Kissam said it is important that all options, including a new nuclear plant, remain on the table.

“Everybody thinks if we build anything that we’re going to absolutely repeat what we did with V.C. Summer” Kissam said. “Well, I promise you, that ain’t gonna happen. OK? I’ll pack up and leave.”

Massey said he appreciated Kissam’s candor and felt he was a straight shooter, but there are a lot of other people involved in the failed project who lied and hid problems.

“I can’t put that behind me. And I don’t think a lot of people can put that behind them,” Massey said.

Massey’s goal is to have a bill ready by the time the 2025 session starts in January.

TVA has now approved a total of $350 million in nuclear funding for the SMR project. The federal utility approved an initial $200 million at its February 2022 board meeting.

TVA is among the investors in GE Hitachi’s BWRX-300 SMR, a 300 MWe water-cooled, natural circulation reactor with passive safety systems that leverage the design and licensing basis of GEH’s ESBWR boiling water reactor.

The BWRX-300 leverages a unique combination of existing fuel that is currently used in operating reactors (and does not require HALEU), plant simplifications, proven components and a design based on already licensed reactor technology. 

TVA is currently preparing a construction permit application for a BWRX-300 at the Clinch River Site. The utility is also exploring additional sites in the TVA service area for potential SMR deployments.

“We believe advanced nuclear technologies will play a critical role in our region and nation’s drive toward a clean energy future,” said Jeff Lyash, TVA President and CEO. “Small modular reactors are an energy innovation technology that America must dominate – for our energy security, which is really our national security.”

The TVA Board also took action to accelerate the agency’s deployment of clean technologies, including 10,000 MW of solar by 2035. The Board approved TVA’s FY25 budget, which includes a rate increase to support sustained growth and ongoing construction of nearly 3,500 MW of additional generation.

Utilities everywhere are projecting increased demand, and TVA is no exception. According to TVA, the region’s population is growing three times faster than the national average. To address the need for more electricity, TVA is investing nearly $16 billion through FY27 to build new generation and infrastructure and enhance the reliability of existing assets.

That seemed entirely doable until those dang data centers became such an energy suck (shaking my fist like I just got caught by the Scooby Doo crew).

Google’s greenhouse gas emissions are headed in the wrong direction, fast- they’ve increased nearly 48% since 2019.

“This result was primarily due to increases in data center energy consumption and supply chain emissions,” an annual Google environmental report read. In 2023, Google’s data centers consumed about 24 terawatt hours (TWh) of electricity.

Goldman Sachs Research estimates that data center power demand will grow 160% by 2030. A single ChatGPT query uses 2.9 watt-hours of electricity, nearly 10 times as much as a classic Google search (.3 watt-hours). As consulting firm Slalom’s Tim Stafford put it recently: think before you check the Yankees score on ChatGPT.

Now Google more or less admits the uncertainty around an AI arms race for more and more computational power may make achieving such targets… difficult.

But the company that allows you to type drivel like “Boyband 90’s not NSYNC or Backstreet or 98 Degrees” and find the O-Town song you’re looking for is coming out of the corner swinging.

Google’s new renewables

This week, Google announced a 1.5 GWp solar development contract with Energix Renewables and closed on a tax equity investment with Swift Current Energy on the massive 800 MWdc Double Black Diamond project in southern Illinois.

In the first deal, Energix will supply electricity and Renewable Energy Credits (RECs) generated from its solar projects to Google and the agreement includes an option for future expansion. The parties have already signed the first two Power Purchase Agreements (PPAs) under this agreement. That’s some much-needed good news in PJM territory, as expressed by Asa (Asi) Levinger, CEO of the Energix Group.

“This joint effort with Google not only strengthens our position in the PJM market but also opens up opportunities for future expansion into other power markets, we expect to deliver the 1.5 GW in the next 2-3 years,” he said.

“There is no one-size-fits-all solution when it comes to decarbonizing our electricity grids and no one company can do it on their own. We are proud of our work with Energix Renewables to unlock new clean energy in PJM,” added Amanda Peterson Corio, Google’s global head of data center energy. “This type of collaboration is essential as we continue to progress towards our ambition to run on 24/7 carbon-free energy on every grid where we operate every hour of every day.”

Google’s tax equity financing of Double Black Diamond Solar, expected to be the largest solar project east of the Mississippi when it reaches commercial operations in early 2025, utilizes Energy Communities and domestic content adders in the Inflation Reduction Act. That project is expected to reduce regional carbon dioxide emissions by about one million tons per year.

“As we work to responsibly grow our infrastructure, we need to partner with companies like Swift Current who understand the nuances of the energy markets where we operate and can help unlock new clean energy at a rate that matches the pace and scale of demand growth on electric grids today,” said Google’s Amanda Peterson Corio, pulling double duty in the press release statement department.

Constellation NewEnergy will purchase a portion of the energy and RECs generated by Double Black Diamond Solar to serve seven big customers: The City of Chicago (O’Hare International Airport and Midway International Airport), Cook County Illinois, CVS Health, Loyola University of Chicago, PPG, State Farm, and TransUnion.

In June, Google entered into an agreement with Berkshire Hathaway electric utility NV Energy to power some of its Nevada data centers with about 115 MW of geothermal energy. A little further back in 2022, Google teamed up with ENGIE on a 100 MW PPA to provide more than 5 TWh of renewable energy from Scotland’s Moray West wind farm.

Google reports more than 7 GW of renewable energy projects worldwide, as colorfully displayed on the site tracking Google’s carbon-free energy progress.

But what about the other guys?

Google’s data center growth-driven compatriots are finding themselves in similar predicaments, and a couple of the big ones, notably Microsoft and Amazon, are amping up their commitments to renewable energy in kind.

Microsoft’s total carbon emissions have risen by nearly 30% since 2020, according to its latest Environmental Sustainability Report. That is bad news bears for a company aiming to be carbon-negative by 2030, removing more carbon from the atmosphere than Microsoft and its supply chain emits. By 2050, the company wants to have removed as much carbon as it ever emitted since it was founded in 1975.

Fittingly, this year there has been a flurry of announcements tying Microsoft to renewable energy development.

This month, Pivot Energy announced an ambitious five-year framework agreement with Microsoft to develop up to 500 megawatts (MWac) of community-scale solar energy projects across the United States between 2025 and 2029. The agreement will enable Pivot to develop approximately 150 U.S. solar projects in roughly 100 communities across 20 states. Microsoft will purchase the project Renewable Energy Credits for a 20-year term, and the first projects are expected to come online before the end of this year.

In May, Microsoft inked two 15-year PPAs with developer RWE for two new onshore wind farms in Texas with a combined capacity of 446 MW and shook hands with Canada’s Brookfield Asset Management on the largest single corporate PPA ever, agreeing to develop more than 10.5 gigawatts of new renewable energy capacity.

Microsoft is partnering with Google and Nucor Corporation to develop new business models and aggregate their demand for advanced clean electricity technologies, intending to accelerate the development of “first-of-a-kind” and early commercial projects, including advanced nuclear, next-generation geothermal, clean hydrogen, long-duration energy storage (LDES), and more.

Microsoft also recently announced a partnership with the Department of Energy’s Pacific Northwest National Laboratory (PNNL) to use high-performance computing in the cloud and artificial intelligence to accelerate scientific discovery, with an initial focus on chemistry and materials science for battery solutions.

Amazon aims to reach net-zero across its operations by 2040, co-founding The Climate Pledge in 2019 and investing more than $2 billion in support of sustainable technologies. Last year, Amazon claimed 100% of the electricity it consumed globally was matched with renewable energy, initially a 2030 goal for the company.

Some recent Amazon PPAs include a 98.4 MW wind project with Avangrid, a couple of solar farms in Ohio, one in Japan, and a 473 MW deal with ENGIE on the Moray West offshore windfarm Google signed with back in 2022.

According to BloombergNEF, in 2023 Amazon purchased more solar and wind power than the next three companies combined, announcing 74 PPAs totaling 8.8 GW of capacity. The other top PPA purchasers: Meta (3 GW), LyondellBasell Industries (1.3 GW), and the aforementioned Google (1 GW). More than 200 corporations announced PPAs in 2023, highlighting how the agreements are being used to promote decarbonization efforts, per BloombergNEF.

Is this “matching” or actual matching matching?

How much of an impact PPAs actually make is a more complex question that deserves digging into. Offsetting carbon in bulk doesn’t necessarily belay the larger impact of that carbon.

In some cases, there’s an opportunity to go beyond a PPA and more effectively decarbonize the grid through hourly load matching, or 24/7 matching, according to an analysis by RMI. RMI defines hourly load matching as “where a buyer attempts to procure sufficient carbon-free energy to match a given facility’s load in every hour.” RMI’s Clean Power by the Hour determined that costs increased with the level of hourly load matching compared to costs for meeting annual procurement targets, near-term emissions reductions for hourly load matching depend on the regional grid mix, and hourly procurement strategies can create new markets for emerging technologies.

Google has been carbon-neutral since 2007 through carbon offsets, and was one of the first companies to purchase renewable energy directly through PPAs in 2017. The company is now in the process of transitioning from 100% annual renewable energy matching to 24/7 matching as part of its 2030 goals.

Microsoft has been signing 24/7 hourly matching agreements with projects fueling its data centers, including one with Powerex Corp and another with ENGIE in Texas. 100s of global companies have signed the 24/7 Carbon-Free Energy Compact, including Google and Microsoft but notably not Amazon, which has yet to announce plans for 24/7 matching.

TOKYO (AP) — An attempt to use an extendable robot to remove a fragment of melted fuel from a wrecked reactor at Japan’s tsunami-hit Fukushima Daiichi nuclear power plant was suspended Thursday due to a technical issue.

The collection of a tiny sample of the debris inside the Unit 2 reactor’s primary containment vessel would start the fuel debris removal phase, the most challenging part of the decades-long decommissioning of the plant where three reactors were destroyed in the March 11, 2011, magnitude 9.0 earthquake and tsunami disaster.

The work was stopped when workers noticed that five 1.5-meter (5-foot) pipes used to maneuver the robot were placed in the wrong order and could not be corrected within the time limit for their radiation exposure, the plant operator Tokyo Electric Power Company Holdings said.

The pipes were to be used to push the robot inside and pull it back out when it finished. Once inside the vessel, the robot is operated remotely from a safer location.

The robot can extend up to about 22 meters (72 feet) to reach its target area to collect a fragment from the surface of the melted fuel mound using a device equipped with tongs that hang from the tip of the robot.

The mission to obtain the fragment and return with it is to last two weeks. TEPCO said a new start date is undecided.

“It seems to me a basic mistake,” TEPCO spokesperson Kenichi Takahara said of the pipe setup problem. He said officials are investigating and the retrieval mission will resume only after they find the cause and have preventive measures “so a problem like this should never be repeated.”

TEPCO President Tomoaki Kobayakawa said the priority was safety rather than rushing the process.
The goal of the operation was to bring back less than 3 grams (0.1 ounce) of an estimated 880 tons of fatally radioactive molten fuel. The small sample will provide key data to develop future decommissioning methods and necessary technology and robots, experts say.

Better understanding of the melted fuel debris is key to decommissioning the three wrecked reactors and the entire plant.

The government and TEPCO are sticking to a 30 to 40-year cleanup target set soon after the meltdown, despite criticism it is unrealistic. No specific plans for the full removal of the melted fuel debris or its storage have been decided.

ATLANTA (AP) — Utility regulators on Tuesday approved a plan for Georgia Power Co. to expand a power plant southwest of Atlanta.

The Georgia Public Service Commission voted 5-0 for the unit of Atlanta-based Southern Co. to build three new fossil-fuel burning units at Plant Yates, near Newnan.

The company has declined to say how much it will spend on the plants, which will burn either natural gas or diesel fuel to generate electricity, but commission staff members have said similar recent plants in other states have cost $800 million or more.

The commission greenlighted building the plants in April, when it approved a special plan to add generating capacity because the utility said demand was increasing more rapidly than previous projections, driven in part by a boom in computer data centers locating in Georgia. The company won permission to build the units itself, without seeking outside bids for electrical generation, because its projections show it needs more electricity by the end 2026.

“Simply put, we need to build these units and we need to build them now,” Georgia Power lawyer Steve Hewitson told commissioners Thursday during a committee meeting.

Normally, commissioners approve long-term generating and rate plans for Georgia Power once every three years, but this approval came mid-cycle. Because the regular generating and rate plans will be up for consideration next year, customers will see no change in bills because of Plant Yates until 2026.

Georgia Power customers have seen their bills rise sharply in recent years because of higher natural gas costs, the cost of construction projects, including two new nuclear reactors at Plant Vogtle near Augusta, and other factors. A typical Georgia Power residential customer now pays more than $173 a month, including taxes.

Environmentalists and customer advocates questioned letting Georgia Power build new fossil fuel plants without going through a competitive process. Using those sources would mean Georgia Power emits more climate-altering carbon dioxide than using solar generation, other renewable sources and conservation.

They also argue that it leaves customers more exposed to the risk of rising natural gas costs, which have been a big ingredient in recent bill increases. The units would mostly run on natural gas but would switch to diesel when electrical demand is at peak and more natural gas can’t be purchased or delivered by pipeline.

Curt Thompson, a lawyer representing the Sierra Club and the Southern Alliance for Clean Energy, argued Thursday that Georgia Power should bear some of the risks of rising natural gas costs. In Georgia, the company has been allowed to pass through the entire costs of fuel for its plants, including the combustion turbines it wants to build at Yates.

“The utility industry in general and Georgia Power, in particular, have become increasingly reliant on gas,” Thompson said. “The Yates CTs would only deepen that gas addiction.”

Opponents had again asked the commission to wait until it could examine bids to provide generation, even though commissioners had approved the Yates plan in April.

“Those resources may well be cheaper, cleaner, and a better fit for Georgia Power customers,” Thompson said.

Georgia Power agreed it wouldn’t charge for cost overruns for the turbines unless they are caused by factors outside the company’s “reasonable control.” It’s supposed to submit reports on construction progress every six months.

As we’ve reported, OPG is planning to build a total of four SMRs at the Darlington nuclear site and would use GE Hitachi’s BWRX-300 reactor technology. The four units once deployed would produce a total 1,200 MW of electricity.

In its latest filings, the provincial utility said it completed early-phase site preparation work for the first SMR and site clearing activities for the three planned additional SMRs in March 2024. Now, the project has commenced main site preparation activities.

OPG said the project completed the tunnel boring machine launch shaft retaining wall for the condenser cooling water system in June 2024. The company has now begun to drill for the reactor building shaft retaining wall. OPG is also planning for the procurement of long-lead items such as the fabrication of the reactor pressure vessel (RPV).

In October 2022, OPG submitted the License to Construct application to the Canadian Nuclear Safety Commission (CNSC) for the first SMR. In April 2024, Canadian regulators announced that the existing environmental assessment for the project is applicable to the BWRX-300 technology. The CNSC will hold a two-part second public hearing in October 2024 and January 2025 to consider OPG’s application.

Darlington refurbishment update

OPG also provided updates on the Darlington Refurbishment project, which began in 2016 to extend the lives of the station’s four units by at least 30 years. Refurbishment of Unit 2 was completed in June 2020, with Unit 3 completed in July 2023.

Work on Unit 1 began February 2022. In April 2024, OPG completed the lower feeder installation series and the lower body supports installation series for the Unit 1 refurbishment, signaling the end of reassembly. The loading of new fuel into the reactor was completed in May 2024.

The project is currently working to restore the reactor vault, which includes removing the bulkheads to reconnect Unit 1 back to the operating units. Vault restoration is on track for completion in August 2024. OPG said this would represent the completion of construction work and transition of the unit to start-up activities.

OPG said Unit 1 is expected to be returned to service by late 2024, ahead of its original schedule set for the second quarter of 2025.

Unit 4 refurbishment activities are currently in disassembly. The removal of the fuel channel assemblies is expected finished in the third quarter of 2024 with the removal of pressure tubes and calandria tubes. Refurbishment of Unit 4 is scheduled to be complete by the end of 2026.

OPG said the refurbishments of Units 1 and 4 incorporate the learnings from Units 2 and 3. The utility said it continues to assess the impact of the COVID-19 pandemic on the project’s total cost, which is tracking toward its $12.8 billion budget.

In May 2024, OPG applied to renew the operating license for the Darlington GS for a period of 30 years beyond November 2025. The two-part public hearing is scheduled to be held by the CNSC in March 2025 and June 2025.

That’s according to the latest reporting from the U.S. Energy Information Administration (EIA). For perspective, the 40.4 GW of generating capacity added in 2023 was the most in a year since 2003.

EIA said 20.2 GW came online during the first half of 2024, 3.6 GW (or 21%) more than the capacity added during the first six months of 2023.

Solar continued to lead all U.S. generating capacity additions in the first half of 2024, representing 12 GW (or 59% of all additions). Texas and Florida made up 38% of U.S. solar additions. The largest new projects included the 690 MW solar and storage Gemini facility in Nevada and the 653 MW Lumina Solar Project in Texas.

Nearly 60% of the planned capacity (25 GW) for the second half of 2024 is from solar. If this planned capacity comes online, solar additions will total 37 GW in 2024, a record in any one year and almost double last year’s 18.8 GW.

Battery storage made up the second-most capacity added so far this year, according to EIA. Battery additions made up 21% of new additions and were concentrated in four states: California, Texas, Arizona and Nevada.

10.8 GW of battery storage is planned for the latter half of 2024. If it all comes online, the 2024 total (15 GW) would be a record. Plans for storage capacity in Texas and California currently account for 81% of new battery storage capacity in the second half.

Wind power made up 12% (2.5 GW) of U.S. capacity additions. Canyon Wind (309 MW) and Goodnight (266 MW), both located in Texas, were the largest wind projects that came online in the first half of 2024.

Nuclear power also increased in the U.S. during the first half of 2024, with Vogtle Unit 4 in Georgia coming online in April.

Retirements slow

Retirements of U.S. electric generating capacity has slowed so far in 2024. Operators retired 5.1 GW of generating capacity in the first half of the year, compared to 9.2 GW retired during the same period in 2023.

Natural gas units represented more than half (53%) of the capacity retired in in the first half of 2024, followed by coal (41%).

According to EIA, about 2.4 GW of capacity is scheduled to retire during the second half, including 700 MW of coal and 1.1 GW of natural gas.

Westinghouse said this development allows better nuclear fuel efficiency, longer times between reactor refuels and lower operating costs.

U.S. pressurized water reactors currently operate on 18-month fuel cycles, and Westinghouse said this new higher burnup fuel will enable reductions in feed batch size, thereby improving fuel cycle economics. This is the first time nuclear fuel batch reloads in the United States will be able to exceed a burnup limit of 62 GWd/MTU.

“We are very pleased to receive approval from the Nuclear Regulatory Commission for incremental burnup in our nuclear fuel,” said Tarik Choho, Westinghouse President of Nuclear Fuel. “This milestone marks the start of production of nuclear fuel with increased capacity for Pressurized Water Reactors, vastly improving fuel costs for U.S. utility customers.”

The incremental burnup approval also represents a milestone for the Encore Accident Tolerant Fuel Program, an initiative started in 2012 and funded by the Department of Energy, aimed at increasing performance and safety of nuclear reactors in support of U.S. energy security and climate goals.