WASHINGTON - U.S. Senator Jim Risch (R-Idaho) today introduced the Accelerating Reliable Capacity (ARC) Act to accelerate investment in new commercial nuclear projects by minimizing cost overrun risk.
“We are at the cusp of unlocking a host of advanced reactor technologies, which are essential to meet growing domestic energy demands and strengthening our national security. While the U.S. has made significant investments in developing new nuclear reactors, the financial risk in moving from demonstration to commercialization is so significant, it impedes industry growth,” said Risch. “The ARC Act aims to mitigate that risk and ensure the U.S. remains the global leader in nuclear energy.”
Building new nuclear reactor technologies for the first time creates significant upfront cost and timing uncertainties,
Senator Risch is a long-time advocate for nuclear energy. He has spearheaded legislation to increase domestic energy production, enhance national security, and keep the United States at the forefront of nuclear advancement. He is the founder and co-chair of the Senate Advanced Nuclear Caucus, which amplifies the critical role nuclear energy plays in the U.S. and explores emerging nuclear technologies.
"I commend Senator Risch for his longstanding support of nuclear energy and his commitment to our nation’s energy security and prosperity,” said John Wagner, Director of the Idaho National Lab. “The near-term expansion of nuclear energy is essential to meeting the dramatic demand growth for clean, reliable power necessary for our industrial sector and economic competitiveness. Providing additional certainty to early adopters will help mitigate risks for nuclear projects and encourage the investment needed to accelerate the deployment of new reactors."
"The Accelerating Reliable Capacity Act of 2024 is a pivotal step in addressing the financial barriers that have hindered the deployment of new nuclear reactors. With essential financing solutions, this legislation will accelerate the development of advanced nuclear technology, enhance U.S. energy independence, and strengthen our global leadership in clean energy innovation," said Maria Korsnick, president and CEO of the Nuclear Energy Institute. "We commend Senator Risch's leadership on this critical issue and look forward to working with Congress to advance this important bill."
"The demand for clean, reliable energy is driving renewed interest in nuclear energy," said ClearPath Action CEO Jeremy Harrell. "The faster nuclear projects get off the ground the faster the U.S. can build critical technologies like data centers and new manufacturing facilities. The ARC Act seeks to supercharge the deployment of new nuclear projects to meet this need."
Thanks to Bob Schaeffer for finding this. Nov 2024 report from Kerrisdale Capital on Oklo. References IEEFA's SMR/new reactors cost chart (page 10) and even hyperlinks on page 1 to the term "Nuclear Bros." to Dr. Ed Lyman's great blog.
Excerpt: We believe investors should be wary of unsubstantiated claims spouted by these "Nuclear Bros.” Recent SMR projects have experienced dramatic cost escalation, Oklo does not have the long-term supply of enriched uranium fuel it needs (and won’t well into the 2030s), and sodium-cooled reactors have well-documented reliability problems.
https://www.kerrisdalecap.com/
TMI-2 SOLUTIONS, LLC, THREE MILE ISLAND NUCLEAR STATION, UNIT 2 - NRC INSPECTION REPORT NO. 05000320/2024003
On July 30, PJM announced the results of its capacity auction for 2025-2026, which showed total costs of nearly $14.7 billion, compared to last year’s $2.2 billion. There are two major causes for blame: fossil fuel un-reliability and PJM’s failure to speedily connect thousands of megawatts of wind, solar, and storage to the grid. This was foreseeable and preventable, and PJM’s failure to allow for new clean energy to come online and plan for more transmission has forced the bill onto ratepayers.
In this blog, we’ll break down what happened, and show that solutions are within reach.
PJM’s capacity market is set up to ensure that there is enough electricity to meet demand on the hottest and coldest days of the year. Capacity auctions, which happen annually, occur when power plants are paid to commit to be available, or customers are paid to conserve during emergencies.
For years, PJM has over-relied on fossil fuel power plants, even while affordable new power sources are coming online. Gas plants are prone to fail during extreme weather, such as winter storm Elliott in 2022 – when we need them the most. Since PJM did not account for fossil resource weaknesses in its previous capacity market auctions, customers paid for these plants as if they were reliable. That’s like buying a house at full price only to realize the foundation is crumbling. It now turns out that the repairs are quite expensive.
Last year, PJM took the first step in remedying this problem by changing the way all resources are evaluated for reliability, resulting in a more accurate process known as “marginal capacity accreditation.” According to S&P Global, the result was that roughly 26 gigawatts (GW) of gas and coal resources were shown to be unreliable, and thus could no longer claim to benefit PJM at their assumed full output during all weather conditions.
This chart shows the drivers for the change in PJM’s capacity prices between the last auction (for the 2024-5 year) and the most recent auction (2025-6). Both supply and demand changes drove the price increase. Negative values indicate reductions in capacity in PJM’s system, while positive values indicate additional available capacity. Market changes to better evaluate the reliability of all resources caused the shift in risk periods and resulting additional capacity (far left orange bar), the gas derates, the coal derates, the solar derates, and the changes to the Installed Reserve Margin (IRM). We can see that the reduction in gas capacity is the largest driver for the “tightening” of PJM’s system. Retirements and load growth, while significant, contributed less to the overall price. Only 110 MW (0.1 GW) of new resources came online to help provide capacity; the low number is due mostly to slow interconnection queues.
Credit: NRDCAs with most markets, when supply falls, prices rise. With 26 GW of gas and coal resources now deemed to be unreliable and therefore not counted in its capacity market, the price of capacity in PJM spiked. Affordability, but not reliability, is now at risk.
We need not have come to this place. Why? There are over 286 GW of new resources waiting to come online in the interconnection queue. That is far more than the 135 GW of resources that cleared in the PJM auction. Even a fraction of these queued resources could significantly improve reliability and affordability if they were able to come online.
Unfortunately, PJM has slow-walked interconnection reforms to connect these resources to the grid. This sticker shock is a direct result of delays in getting new energy online, together with the transmission to support it. Many of these resources would have absorbed and buffered the price increases by increasing supply.
Fewer new resources and imports participated in the 2025/26 auction than ever before, showing a clear downward trend.
Credit:PJM Interconnection, “2025/2026 Base Residual Auction Report,” July 30, 2024.
This doesn’t mean we need more gas – on the contrary, it shows that fossil fuels are expensive and unreliable, and a diverse resource mix will benefit the region far into the future. These high prices are sending a signal to build, and PJM shouldn’t stand in the way of progress. Instead, PJM seems more interested in keeping aging and expensive fossil plants alive, such as Brandon Shores in Maryland, rather than expediting the interconnection of new resources to the PJM power system.
Around 6 GW of fossil plants retired since the last auction. The fossil lobby will say this is due to draconian regulations that are forcing power plants to retire before their time, but the truth is that most of these plants are no longer economically viable. Most of the retiring resources are decades-old coal plants, built in the 1960s, and some are facing bankruptcy. Lower-cost, reliable clean energy can replace even more of them, but only if they can get online – which requires PJM to accelerate the interconnection process.
Projected load growth of 3.2 GW further strained the system, which is a 2.2% increase over the last planning year. Planning for load growth and retirements is important, but the principal driver of the capacity market price increase was PJM derating the gas plants to reflect their lower reliability value. The gas and coal derating (26 GW) was nearly three times as much as the combination of retirements and load growth.
PJM needs new resources, and quickly. The good news is that there are currently 268 GW of new resources patiently waiting to come online in PJM, and 95% of those resources are clean. Adding even a fraction of this capacity would dramatically reduce prices.
To estimate the potential cost savings, we constructed a “no backlog” scenario in which 30% of renewable projects that have been stuck in the queue for at least five years were instead assumed to be operational and had bid into the capacity market. The capacity value of these new resources would amount to an additional 7 GW of supply in the most recent auction. Adding just 7 GW of new entry could have lowered the market clearing price from $269.92/MW-day to as low as $98, or by as much as 63%. PJM delays in implementing interconnection queue reforms have effectively blocked new entry, driving up capacity costs and failing to mitigate the price impact for consumers.
The 2025/2026 BRA cleared 135 GW of capacity at a price of $269.92/MW-day. This graph reconstructs the supply curve that produced actual clearing results compared to a “no backlog” supply scenario that includes 7 GW of capacity value from new renewable entry. Additional capacity from backlogged resources could have lowered the market clearing price to under $100/MW-day.
Credit:NRDC
There are three things PJM can do to bring down prices.
First, PJM must comply with FERC’s interconnection Order 2023 as soon as possible. PJM has refused to comply with the order so far, but after this auction it should be able to see the urgency of meaningful interconnection reform and comply as soon as possible.
Second, the region needs new, well-planned transmission. A new report from Americans for a Clean Energy Grid shows that the rate of building new transmission lines is at an all-time low. If PJM’s transmission planning had a grade, it would get a D-. FERC Order 1920 charts a path toward the grid of the future and requires that RTOs, like PJM, create a process to plan for new transmission that provides regional benefits. Doing so will help to add many gigawatts of clean capacity to the power grid.
Third, PJM should examine market barriers that could be quickly fixed before the next capacity market auction in December. For example, customers in PJM currently pay hundreds of millions of dollars to keep at least two coal plants on-line for reliability reasons. Remarkably, neither of these plants bid into the capacity market this year, significantly tightening the supply in the region. PJM should require these plants, and another other future plants in such circumstances, to bid into the capacity market. If they did, customers in Maryland would have saved up to $18 per month, and the PJM region as a whole would have saved $5 billion.
PJM has the tools in its toolbox to bring down prices and ensure a reliable, clean supply of electricity for years to come. If it acts now, these price increases can just be a bump in the road to a more affordable, resilient grid.
By Reuters
Russia said the temporary restrictions were a response to Washington's ban on imports of Russian uranium, which was signed into law earlier this year, but contained waivers allowing for shipments to continue in case of supply concerns through 2027.
Russia is the world's sixth largest uranium producer and controls about 44% of global uranium enrichment capacity. In 2023, the U.S. and China topped the list of Russian uranium importers, followed by South Korea and France.
President Vladimir Putin told a government meeting on Sept. 11 that Moscow should consider limiting exports of uranium, titanium and nickel in retaliation for Western sanctions.
The government's decree on Friday was the first follow up action to Putin's statement in September.
Russia accounted for 27% of the enriched uranium supplied to U.S. commercial nuclear reactors last year. Imports to the U.S. from Russia through July this year stood at 313,050 kilograms (690,160 lb), down 30% from last year.
The U.S. is probing a surge in imports of enriched uranium from China since late 2023 amid concerns the shipments are helping Moscow sidestep a U.S. ban on imports of the power plant fuel from Russia.
Beaver Valley: MSIV FAILED TO CLOSE DURING SURVEILLANCE
| Unit | SCRAM Code | RX Crit | Initial PWR | Initial RX Mode | Current PWR | Current RX Mode |
|---|---|---|---|---|---|---|
| 2 | N | N | 0 | Hot Standby | 0 | Hot Standby |
https://www.powermag.com/
Oct 16, 2024
The power generation sector is looking at numerous ways to provide enough electricity to satisfy demand from data centers. Bloomberg Intelligence recently said its research shows data centers, buildings filled with servers and other computing equipment for data storage and networking that supports operations and artificial intelligence (AI), could be responsible for as much as 17% of all U.S. electricity consumption by 2030. The U.S. Dept. of Energy (DOE) has said one data center can require 50 times the electricity of a typical office building.
Several technology groups are looking at nuclear power, including the use of small modular reactors (SMRs), to meet their electricity needs. Energy analysts have said natural gas, whether burned in large-scale facilities or peaker plants, also will be important.
Power consumption from data centers, though, also is benefiting coal-fired power plants, some of which may be kept running longer than expected in order to meet the increased demand for electricity from companies such as Google, Meta, Amazon Web Services (AWS), and others. Some coal-fired plants already have gotten a reprieve in areas where more energy is needed as data centers come online, or are in the planning stages.
The topic reportedly was discussed when C-suite executives from Alphabet (Google), AWS, Microsoft, Meta, Nvidia, and OpenAI met with government officials in Washington, D.C., last month to discuss ways to support U.S. infrastructure for AI, including data centers. Part of the discussion was about repurposing old coal sites as data center campuses. The DOE has said it will share resources with data center developers about how to repurpose former coal mines, or coal-fired power plants, to be home to data centers. Energy DELTA Lab, a collaborative effort that includes Dominion Energy Virginia and Appalachian Power, already is working on the Data Center Ridge project at a former mining site in Wise County, Virginia.
Life Extension
Maksim Sonin, an energy expert who has collaborated with several companies, including Chevron and Shell, and is a Sloan Fellow at the Stanford University Graduate School of Business, said, “Driven by recent trends in AI development, projected power consumption by data centers in the U.S. is expected to increase in the range from 8% to 17% by 2030—or potentially even higher, as progress in AI technologies is not linear but exponential, as seen in Silicon Valley today.” Sonin told POWER, “With this sharp upward trend, it is highly likely that coal-fired power plants will remain a part of the U.S. energy system for longer, although their role is expected to diminish,” as more renewable and other energy resources come online.
“Coal plants will have an extension of their life due to data center demand,” said Tim Echols, a commissioner and vice-chair of the Georgia Public Service Commission. Echols’ home state is actively recruiting data centers and manufacturing facilities to provide jobs and boost local economies. It already added a significant new source of power when two nuclear reactors entered service at Plant Vogtle last year and this year, providing about 2,200 MW of new electricity output in the state. Plant Vogtle, where two other reactors have operated since the 1980s, is now the nation’s largest nuclear power plant, with more than 4,600 MW of generation capacity.
Echols told POWER in an Oct. 16 interview that Georgia is preparing for a large increase in power demand. “There could be a massive increase of capacity approved next year. Data centers will account for most of it,” he said.
How to satisfy data center power demand is being discussed by utilities and energy officials nationwide. Allan Schurr, chief commercial officer with Texas-based Enchanted Rock, which provides microgrid backup power solutions to data centers and other critical infrastructure, said the debate also should include onsite generation.
“AI data centers require more generating capacity—that’s a given,” said Schurr. “While we are waiting for nuclear power to bring substantial additional baseload to the grid, we don’t want to needlessly ‘recarbonize’ our energy resources by extending the life of older, less-efficient fossil generation plants like coal.
Schurr told POWER, “Today’s grid has significant available capacity with the exception of about 500 hours per year that can be mitigated with dispatchable generation. And the grid needs those 500 hours of additional capacity so we can continue to add solar and wind resources into the energy mix. Data centers can facilitate this dispatchable generation from their own onsite generation, making them assets to the grid instead of liabilities.”
The utilities and grid operators arguing to keep coal-fired plants online say it makes sense to keep existing baseload power sources operating, at least until more nuclear or renewable energy is available. That’s why states including Nebraska, Virginia, and Utah among others, have plans to keep coal-fired units running to support the supply of electricity.
Virginia is World Data Center Leader
DC Byte, a UK-based research group that tracks data centers worldwide, has said the U.S. is the world leader in the buildout of data centers. The group said Virginia—home to about half of all U.S. data centers—is the largest data center market worldwide. Loudoun County in Virginia is known as “Data Center Alley.”
PJM Interconnection, the grid operator that serves Virginia, the District of Columbia, and 12 other states, has conceded some coal-fired power plants will need to continue operating, and miles of new transmission lines must be built, to satisfy ever-increasing demand for electricity. Other power sources will help—Japan’s Sumitomo Corp. on Tuesday announced it will partner with CEP Solar (based in Richmond, Virginia) to add 1.5 GW of solar and battery energy storage to support data center growth in the region.
“The system is in a major transition right now, and it’s going to continue to evolve,” Ken Seiler, PJM’s senior vice president in charge of planning, said in a December stakeholders’ meeting about how the grid operator can supply more power as it waits for more renewable energy resources to come online. “And we’ll look for opportunities to do everything we can to keep the lights on as it goes through this transition.”
DC Byte in its 2024 Global Data Center Index wrote, “Virginia currently has over 6 GW in the development pipeline including projects under active construction as well as Committed and Early Stage campuses.” The group noted, “Cloud is the greatest driver of growth in Virginia. AWS [Amazon Web Services] operates over 40 facilities in the state and Microsoft operates a massive campus in Boydton as well as a smaller facility in Loudoun County. Both companies have more self-build campuses in the pipeline and are also major colocation tenants across the market.”
DC Byte added, “In 2022, Loudoun County’s primary power supplier Dominion Energy announced that it would not be able to meet power demand in the market. Delays in power delivery are expected until 2025 or 2026 while new power infrastructure is built. In the meantime, Dominion Energy would be providing power incrementally.” Dominion officials have said they project that power demand in the utility’s territory will increase by 85% over the next 15 years.
PJM is backing a $5.2 billion plan for new transmission lines across several states to bring power to Virginia. The lines would carry electricity produced at several coal-fired power plants that have been slated for closure, including the Longview, Fort Martin, and Harrison stations in West Virginia.
In Maryland, meanwhile, PJM has asked Texas-based Talen Energy Corp. to keep Brandon Shores and Herbert A. Wagner—two other coal-fired facilities located near Baltimore—online at least through 2028. The plants had been scheduled to close by June 2025.
Operating Extension for Omaha Coal Plant
The 644-MW North Omaha Station in Nebraska was scheduled to close in 2023. Instead, Google and Meta data centers caused the area’s power demand to spike, which led the Omaha Public Power District to decide that the two coal-fired units at North Omaha were needed to maintain reliability of the local power grid. The utility has said it will keep the coal-burning units online at least through 2026.
One Google data center is in Papillon, a town about 12 miles southwest of Omaha. DC Byte said the Google facility uses more power than the Meta office, and added that its data shows Google uses more electricity in Nebraska than it uses elsewhere in the U.S. The company also is planning more data centers in the state.
Data from Meta and other groups shows that the company’s data center in Sarpy County, about 25 miles southwest of Omaha, last year used almost as much power as the North Omaha station produced. The Meta campus includes nine separate complexes, encompassing about 4 million square feet.
The Omaha Public Power District has estimated that as much as two-thirds of the projected growth in power demand around Omaha will come from data centers, which are being built on what used to be farmland. Local officials have said opposition to wind and solar farms in rural areas has curtailed additional renewable energy resources that could supply power. The utility has been developing a 2,800-acre solar power project in rural York County, about 100 miles from Omaha, but area residents have voiced concerns about the installation. The utility also has said regulatory issues have slowed plans to replace coal-fired generation with natural gas-fired units.
Meta’s presence in Omaha was sought by state and local officials; a special electricity rate for industrial customers was created in 2017. That rate was then marketed to Google to entice the search engine giant to build in the area.
Georgia Courting Data Center Operators
Georgia Power is buying electricity from a sister company, Mississippi Power (both are part of Southern Co.), to help meet power demand in Georgia. The deal came after Georgia Power officials reportedly told state regulators that growing demand for electricity would overrun supply by year-end 2025. Georgia officials have been actively looking to bring data centers and manufacturing plants to that state, and Gov. Brian Kemp earlier this year vetoed a bill that would have suspended a tax break for data centers (the bill had bipartisan opposition). Had the bill become law, the tax break would have been under the review of a special commission on data center energy planning.
Kemp in a statement said, “The bill’s language would prevent the issuance of exemption certificates after an abrupt July 1, 2024 deadline for many customers of projects that are already in development—undermining the investments made by high-technology data center operators, customers, and other stakeholders in reliance on the recent extension, and inhibiting important infrastructure and job development.”
Georgia Power has a deal with Mississippi Power to buy 750 MW of electricity through 2028. Mississippi Power is providing the energy from its Victor J. Daniel Electric Generating Plant, better known as Plant Daniel, where two coal-fired units have operated for the past 50 years. The plant also has two natural gas combined-cycle units. It is the state’s largest power plant, with nearly 1.6 GW of generation capacity, including 500 MW from its two coal-fired units.
Mississippi Power had planned to retire the coal-burning steam turbines in 2027. The deal with Georgia Power, though, could extend that lifecycle. Jeffrey Grubb, the utility’s director of resource planning, reportedly was asked by Georgia Power’s lawyers about the agreement, and said, “Because those units would have been either retired or sold off-system and we needed certainty that they would be there to serve our customers.”
Echols, the PUC co-chair, on Wednesday told POWER the contract with Mississippi Power is open to any kind of generation source.
“Our contract with Mississippi Power calls for 750 MW, and it doesn’t matter where it comes from. That may mean an [operating] extension for the coal plant, or it may not,” he said. “Mississippi could do 750 MW of solar plus storage, they could bring in 750 MW of wind power from a neighboring state.”
Echols noted that a move by regulators in 2022 extended operations for two coal-fired units at Georgia Power’s Plant Bowen, one of the nation’s largest coal-burning power plants, with about 3.4 GW of generation capacity. Echols said, “In the 2022 IRP [integrated resource plan] … our commissioners delayed the closure of units 1 and 2 at Plant Bowen. I imagine as we evaluate that in next year’s IRP, we will also delay the closure for another three years. We’ll have to wait and see what the utility is asking for and how the commissioners feel we need to move forward.”
Echols told POWER, “There could be a massive increase of capacity approved next year. Data centers will account for most of it.” Echols also offered, “I think there is a scenario where we approve two more AP1000 [reactors] at Plant Vogtle if the federal government provides bankruptcy insurance or overrun insurance” for another expansion at the site.
Other Efforts
DC Byte has identified Salt Lake City, Utah, as a growing market for data centers. Meta already operates a 4.5-million-square foot complex in Eagle Mountain, Utah, south of Salt Lake City.
State lawmakers have pushed legislation to keep the Intermountain Power Project, a coal-fired station near Delta, Utah, open past the facility’s scheduled 2025 closure date. Officials have looked at ways to have the state take over the plant. Lawmakers this year did pass legislation intended to extend the life of Rocky Mountain Power’s coal-fired stations in Emery County.
Stuart Adams, president of the Utah Senate, during the legislative session this summer said, “The United States has a real problem. We do not have enough power for our data centers. AI development is technology that we have to embrace, and power is the key to it.”
Building more infrastructure to support that AI development was among the reasons those tech company execs met last month on Capitol Hill. Reports said the discussion included repurposing former coal sites to house data center campuses, in part because those sites usually have access to power lines, water, and a local workforce.
The DOE’s Pacific Northwest National Lab, which is leading the “coal-to-X” redevelopment campaign, in a guide to the program wrote, “A retired coal site could even be redeveloped to combine a data center with new clean energy on the same site.”
As Schurr of Enchanted Rock noted, generating onsite power via a microgrid, or through a renewable energy resource, could be preferable to using coal-fired generation. That’s of particular importance for data center operators looking to build in remote areas where they need plenty of land, and where there’s a lack of transmission infrastructure.
Sonin reiterated that coal will play a role in satisfying power demand from data centers, but like Schurr, noted other fuels could work with coal to reduce the environmental impact of keeping coal-fired power plants online.
Sonin told POWER, “Emerging technologies that, for instance, allow for substituting some of the coal with ammonia, a carbon-free hydrogen derivative, through a process known as co-firing, may help address public environmental concerns. Current advancements, particularly the potential for upscaling production trains, could reduce the cost of ammonia facilities by 30% and more, making this chemical a viable solution for cutting emissions from coal plants.”
—Darrell Proctor is a senior editor for POWER
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USA, Pennsylvania: Constellation Energy has ordered a main power transformer for the Three Mile Island nuclear reactor in Pennsylvania. The company is attempting to restart the reactor, pushing ahead with work critical to the plant’s revival.
The transformer will be the biggest single piece of equipment which will need to be replaced for restart of the plant, and it will cost about $100 million. The owner of the plant Constellation is investing $1.6 billion to revive the operation over the next four years.
When deciding whether to move forward with a restart, Constellation surveyed the site to determine the condition of essential infrastructure and equipment, much of which has sat idle since the plant shut in 2019. Constellation Vice President of Generation Bryan Hanson said that the plant is in great condition.
Constellation signed a 20-year power contract with Microsoft to help restart the plant. The nuclear reactor, located on an island in the Susquehanna River in Pennsylvania, could supply 835 MW of power to offset Microsoft’s data center electricity consumption.
No modern US nuclear power plant has been restarted after fully shutting down. Three Mile Island is known as the site of the worst nuclear power accident in US history, as in 1979, a unit experienced a partial meltdown which caused no deaths but released small amounts of radioactive gases and raised concerns about the potential health effects on surrounding communities. That unit will not be restarted.
Separate Unit 1, which Constellation wants to resurrect, shut in 2019 for economic reasons. Unit 1 could begin producing power in 2028, but there is a series of physical hurdles and US and local regulations that must be completed first. Among other investments in resuming operations at the plant are work on the reactor’s turbine, generator, and cooling systems.
Source: Reuters
