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December 17, 2024

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DOE Environmental Justice Pilot Paves Way for Implementation

A pilot effort in 24 communities nationwide yielded important insight for environmental justice initiatives, the U.S. Department of Energy said.

DOE issued its final report Dec. 4 on the Communities Local Energy Action Program (LEAP) pilot, part of the Biden administration’s Justice40 Initiative to direct 40% of clean energy investments to disadvantaged communities.

Communities LEAP targets low-income, energy-burdened communities where environmental injustice exists or where the transition away from fossil fuels faces economic challenges. The first cohort of 24 communities began the process in spring of 2022.

The pilot, funded with $16 million, sought to identify each community’s energy-related priorities, opportunities and challenges; provide resources and analysis to aid with energy planning; and enable long-term economic and environmental benefits.

The National Renewable Energy, Sandia, Lawrence Livermore and National Energy Technology laboratories provided technical assistance, along with subcontractors.

Key points included working with the unique characteristics of each of the 24 communities; identifying priorities and building consensus; establishing trust and enabling local leadership; and maintaining contact between the community and its designated technical assistance providers after the initial round of assistance was complete.

In its report, DOE said many of the coalitions emerged from the process ready to move from planning their energy transition to implementing it. Some already have secured funding.

DOE said there was learning in both directions — the technical assistance providers took away lessons that will inform their work with the 30 communities in the second cohort of Communities LEAP, which began in the spring of 2024, and their efforts in other programs with a similar mission.

Among the changes in the second cohort: Direct funding will be provided because residents of disadvantaged communities may lack the time and capital needed to consistently engage; program staff will incorporate the potential for future uncertainty and change into their planning; staff will look for ways to streamline technical assistance to meet needs that are similar across dissimilar communities; and more training will be offered to community coalitions so they can continue the work after the program itself ends.

The future shape of Justice40 and similar initiatives remains to be seen. There has been widespread speculation that federal environmental justice initiatives will lapse under President Trump.

But Communities LEAP also was about helping communities help themselves.

Among the reported results of the pilot project:

    • Alachua County, Fla., created a Green Jobs Advisory Council, a weatherization toolkit for residents and a potential solar leasing scheme supporting home energy efficiency upgrades.
    • Louisville, Ky., will identify energy-efficiency investments to reduce emissions and lower the energy burden for low- and moderate-income households.
    • Jackson County, Ill., developed the knowledge to approach developers, plan residential interconnection and explain benefits to residential subscribers with help of Illinois Solar for All.
    • Duluth, Minn., developed a clean energy action plan prioritizing building efficiency, transportation and industrial decarbonization.
    • North Birmingham, Ala., analyzed residents’ housing and transportation priorities to inform future strategies and decision making.
    • The Iowa Tribe of Kansas and Nebraska received assistance with development of a microgrid that will improve reliability of energy systems while creating green jobs and job training for the local workforce.
    • The Beacon Hill neighborhood of Seattle received support to meet energy-related goals ranging from improved air quality and better climate impact resilience to reduced resident displacement and lower greenhouse gas emissions.
    • The Columbia (S.C.) Housing Authority developed the technical knowledge and best practices to spearhead weatherization efforts across the city, creating business and job opportunities along the way.
    • Questa, N.M., is better able to decide whether and how it should pursue development of an electrolytic hydrogen plant on the site of a former molybdenum mine, thanks to a feasibility study and economic analysis.
    • Mingo and Logan counties, W.Va., received assistance to evaluate the economic viability of developing infrastructure to separate rare earth elements and other critical minerals from coal waste feedstocks.
    • Bridgeport, Conn., sought help creating a model community benefit/community engagement framework for renewables projects; partly because of this, a manufacturer chose to site a battery electrode factory employing 200 people there.
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BPA Hit FY24 Reliability Targets Despite Wildfires, Peak Load Records

The Bonneville Power Administration hit all its reliability goals in fiscal 2024 despite massive wildfires, peak load records and public safety power shutoffs, agency staff said during a stakeholder workshop Dec. 4. 

The agency managed to meet its reliability targets, which are determined under two indexes: system average interruption duration index and system average interruption frequency index, Richard Shaheen, BPA senior vice president of transmission services, told participants during the agency’s Evolving Grid stakeholder workshop. 

But hitting the targets was challenging, as customers set simultaneous peak load records in both summer and winter, Shaheen said. 

Loads reached 11,396 MW in early January, setting a demand record not seen “since the time of the aluminum smelters in our territory,” according to Shaheen.  

Similarly, loads reached a new summer record of 9,179 MW on July 8. However, that record only lasted one day as BPA saw summer load levels going up to 9,365 MW on July 9. 

Shaheen emphasized that BPA tries to meet this new demand by upgrading and expanding the grid. He noted that weather threats continue to pose significant challenges. 

“One of the biggest challenges we have from Mother Nature is wildfires,” Shaheen said. “Really a significant threat to our system and [a] significant threat to all of Pacific Northwest.” 

The burn area during FY24 increased five times from 2023 within BPA’s service area, Shaheen said. 

The burn area in BPA’s service territory equaled 40.8% of the national burn area, according to Shaheen. More than 3.2 million acres burned by the end of FY24, an almost three-fold increase over the 10-year average, BPA stated in its 2024 annual report. 

“Really a staggering number and staggering challenge,” Shaheen added. 

A recent report from WECC shows wildfires burned 2 million acres in Oregon this summer, breaking the record set in 2020, while the 288,000 acres burned in Washington more than doubled the 10-year average for that state. Idaho and Montana both experienced above-average fire seasons, WECC said. 

The agency issued public safety power shutoffs four times in the past year, which impacted five lines. In one of those instances, BPA had to drop load because of a fire threat to infrastructure, Shaheen noted. 

However, tools like fire wraps, which are placed around wood poles, have protected infrastructure. Shaheen added that BPA also continuously assesses how to boost wildfire mitigation by using data from the National Oceanic and Atmospheric Administration and in conversations with industry leaders and organizations. 

“We continue to advance the analytics and our plans to try to navigate through that wildfire threat,” Shaheen said. “I’d like to say we’ve been pretty successful so far. We don’t want to be the cause of the fire. We don’t want damage to be caused to our infrastructure due to fire.” 

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Voltus Hires Its 2nd Former FERC Chair in Chatterjee

Former FERC Chair Neil Chatterjee is joining virtual power plant operator Voltus, the company announced Dec. 5. 

Chatterjee, who as chair shepherded Order 2222 to passage — requiring ISOs and RTOs to allow DER aggregations to participate in their markets — and joins former FERC Chairman Jon Wellinghoff, who is chief regulatory officer at Voltus. 

“With 2222, Chairman Chatterjee set in motion the next chapter of the VPP industry’s growth,” Voltus CEO Dana Guernsey said in a statement. “We are proving that empowering customers to deliver grid services produces significant grid reliability, affordability and decarbonization outcomes. 2222 allows more households and businesses in more states and markets to deliver value to the grid and to be compensated for it. Neil’s experience, knowledge of energy markets and influence among regulators and utilities are invaluable assets for Voltus’ mission.” 

Order 2222 was one of Chatterjee’s prouder achievements when he chaired the commission, and he said in an interview that the new role with Voltus would let him keep working on those issues. 

“I’m committed to seeing the groundbreaking order succeed,” Chatterjee said. “Voltus is a leading virtual power plant operator and distributed energy resource platform, and helping them realize the market opportunities enabled by 2222 was really exciting to me.” 

Wellinghoff also oversaw major orders on the demand side during his chairmanship, most notably Order 745. 

“With Chairman Chatterjee coming aboard, Voltus possesses even greater capability to work with public service commissions, grid operators, utilities and other industry decision-makers to remove the remaining barriers hindering the full realization of DERs’ capabilities,” Wellinghoff said in a statement. 

Chatterjee noted that so far, only CAISO has gotten the work done on implementing Order 2222. 

“The fallout from the last PJM capacity auction this summer … just illustrates the growing need for kind of flexible, quick-to-scale resources,” Chatterjee said. “And so, to the extent that PJM and the other regions can integrate distributed power plants into their system to help with some of these steep price hikes and the mismatch between supply and demand, I would think it’s in a grid operator’s interest.” FERC could help move that along by focusing on implementation of Order 2222, he said. 

Another area that FERC could move forward on would be to remove the opt-out it granted to states over demand response in 2008’s Order 719, he added.  

Court rulings on DR and similar areas where end-use customers can participate in wholesale markets have chipped away at the need for the opt-out since then, Chatterjee argued. A Notice of Inquiry that FERC launched in 2021 on the issue remains pending (RM21-14). 

VPPs’ ability to help optimize grid infrastructure can help maintain reliability at the lowest cost, especially with growing demand needed to support the ongoing development of artificial intelligence, Chatterjee said. 

President-elect Donald Trump “has made a commitment to both win the AI race against China by ensuring that we have power to win that AI race, but simultaneously … has pledged to bring down electricity bills and curb inflation,” Chatterjee said. “And in order to do that, we’re going to not only need every available electron, we’re also going to need to find greater optimization and efficiencies of our existing infrastructure.” 

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Calif. Report Examines Deep Potential for Wave Energy

Waves off the California coast could provide as much as 140 TWh of electricity a year with today’s technology, but the state faces several obstacles to achieving that potential, according to a new report.

The California Energy Commission report, released in draft form Nov. 26, said that wave and tidal energy could diversify the state’s electricity portfolio, complementing intermittent renewable resources such as solar and wind, and help California meet its renewable energy targets.

Wave energy systems could be deployed as distributed energy resources to serve local demand, such as at ports, remote communities, military installations or marine research stations, the report said.

Wave energy systems also could be located with floating offshore wind.

“Colocation of wave energy and offshore wind energy can reduce project development costs through shared expenses of infrastructure, operations and maintenance, and licensing, and could provide enhanced energy yield and better predictability,” the CEC said in its draft report.

But barriers to wave energy projects are many, the report noted. Because the industry is at an early stage, a single technology or device has yet to emerge as the preferred solution. Costs remain high, and environmental impacts may vary depending on the technology type and location.

There are also grid integration challenges, including connection costs, grid stability and regulatory frameworks.

The report recommends promoting further research on the potential value of wave and tidal energy devices as clean, firm resources as well as the devices’ environmental impacts.

Exploring market incentives to support investment in wave and tidal energy technology is another recommendation, as is developing a clear regulatory process for projects.

The report on wave and tidal energy resources is included in the CEC’s 2024 Integrated Energy Policy Report (IEPR) update.

The evaluation is the result of California Senate Bill 605 of 2023, which directed the CEC to evaluate the feasibility, costs, and benefits of wave and tidal energy and to submit a report to the legislature by Jan. 1, 2025.

CEC said it will follow up with a report on suitable sea space for offshore wave and tidal energy — another requirement of SB 605.

Resource Size

The CEC report assesses both wave and tidal energy — two types of marine energy resources.

It cites the findings of a 2021 report from the National Renewable Energy Laboratory (NREL) that looked at the size of marine energy resources across the U.S. NREL focused on the size of the “technical resource,” which is the amount of energy that could potentially be harnessed using existing technology.

The technical resource is a portion of the total energy resource that’s theoretically available; NREL also noted that the technical resource is greater than the “practical resource,” which considers environmental and regulatory constraints and other barriers.

The wave energy technical resource off California’s coast is 140 TWh/year, NREL said, which equals 69% of the state’s 2019 net electricity generation and is enough to power 13 million homes.

The state’s technical resource for tidal energy is comparatively small, at 0.89 TWh/year, and is concentrated at the entrance to San Francisco Bay, where the resource is 0.78 TWh/year.

“Commercial-scale marine energy projects in California would likely use wave energy instead of tidal energy because of more abundant wave energy resources,” the CEC said in its report.

Elsewhere on the West Coast, Oregon’s wave resource is 93 TWh/year. That’s 1.5 times the state’s 2019 net electricity generation and “could allow Oregon to be a net exporter of wave-powered electricity,” NREL said in its report.

Technology Types

Many different types of technology have been developed to convert wave energy to electricity.

One type of system is an overtopping converter, in which waves spill over the crest of the device and into an above-sea-level reservoir. The controlled release of water from the reservoir drives turbines to generate energy.

A Danish company called Wave Dragon makes one well-known overtopping device. The company says its platform “is highly suitable as a floating foundation for wind turbines.”

Point absorbers are a type of wave energy converter that uses a floating buoy or platform that moves up and down or back and forth as waves pass by. The movement, relative to a fixed object such as an anchor, is converted into mechanical energy and then into electricity.

The advantages of point absorbers are that they are small and easy to move, and can be deployed individually or assembled in arrays, according to Aspen Environmental Group, which performed an analysis of wave and tidal energy for the CEC.

A California-based company, CalWave, completed a 10-month demonstration of its xWave point absorber technology off the coast of San Diego in July 2022. The power and data generated by the x1 pilot device was exported via subsea cable to the Scripps Institute of Oceanography research pier.

“As offshore wind development is growing rapidly in the U.S. and globally, we recognize the significant opportunities for wind and wave farm co-location,” CalWave CEO Marcus Lehmann said in a statement upon completion of the pilot project.

CalWave has now been contracted by the Department of Energy to deploy its first utility grid-connected system at the 20 MW PacWave test site off the central Oregon coast. The test site is expected to be in operation in mid-2025.

CalWave submitted its own recommendations to the CEC on how to move forward with marine energy.

Those include setting statewide marine energy deployment targets of 100 MW by 2030, 500 MW by 2035 and 2,500 MW by 2040.

The company also recommended the CEC consider providing matching funds for DOE awards, clarify state regulatory processes and quantify potential savings to ratepayers from integrating marine energy into the grid.

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NC Town Sues Duke Energy over Alleged Climate Deception

The town of Carrboro filed a lawsuit against Duke Energy on Dec. 4 in North Carolina, alleging its inaction and deception on climate change has cost the municipality millions. 

While similar lawsuits have been filed against oil and gas firms — including one against the utility NW Natural Gas — Carrboro’s is the first suit by a municipality against an electric utility for its contribution to climate change. 

“The town of Carrboro is seeking compensation for damages we’ve suffered and will continue to suffer because of Duke Energy’s climate deception campaign, which has spanned several decades,” Mayor Barbara Foushee said at a press conference. “The corporation has disregarded the immense harm it has imposed on our town and other communities across North Carolina and the country by working against reducing the use of fossil fuels.” 

Foushee was flanked by other town officials, including members of the Town Council that voted unanimously Dec. 3 to file the lawsuit. Carrboro is in the Raleigh-Durham area, and it filed its lawsuit in Orange County Superior Court, with nonprofit NC WARN paying the legal fees. 

With the U.S. and other wealthy countries failing to meaningfully address climate change, it is important to hold their corporate polluters to account, NC WARN Executive Director Jim Warren said. 

“We all hope this lawsuit can help the many communities … that have been hurt already by climate disasters,” Warren said. “As the lawsuit shows, it was Duke Energy’s top bosses that are the culprits. They used denial, confusion [and] greenwashing, and even claimed global warming is good for us. They did all this to keep their profits rolling along.” 

The lawsuit alleges Duke misled the public to believe it is committed to renewable energy and that this has delayed the transition away from fossil fuels, materially worsening the climate crisis. As evidence that the company has known about climate risks for decades, it cites a 1968 Edison Electric Institute conference Duke executives attended, where they heard a presentation from a scientist who said carbon dioxide’s concentration in the atmosphere was growing and would lead to major consequences. 

The lawsuit also cites work from the Electric Power Research Institute, which included Duke executives on its board from its earliest days, that flagged carbon emissions and their impact on average temperatures in the 1970s. 

Despite the knowledge of climate change, Duke and its corporate predecessors continued to cast doubt on it publicly for decades, the lawsuit alleges. While in more recent times the utility has claimed to be a leader in green energy, those claims clash with its continued fossil emissions and plans to keep building natural gas-fired power plants, it says. 

“Although Carrboro is working to mitigate the impacts of climate change, as a result of the ever-worsening impacts of the climate crisis, the town is incurring, and will continue to incur, millions of dollars in damages,” the lawsuit says. Those include repairing town roads more frequently, building improved protections against more regular and devastating storms, and paying bigger bills to Duke itself as town buildings need to run air conditioners more often. 

The lawsuit does not seek any limits on Duke’s emissions or operations, just its liability for damages associated with its overall greenhouse gas emissions. 

Duke supported new coal plants as recently as 2007, when it was planning to add new capacity that could be retrofitted with carbon capture and storage, a still-nascent technology. 

“Over the next decade or more following these statements, Duke and its proxies would repeatedly and publicly support continued reliance upon fossil fuels by misrepresenting that CCS could prevent the problems associated with the emission of carbon due to the use of coal,” the lawsuit says. 

In comments to EPA on its power plant rule last summer, Duke said CCS would not even be ready by the agency’s proposed 2035 deadline, the lawsuit notes. 

More recently, Duke has been shutting down coal plants, but it has replaced much of the capacity with natural gas-fired units, which the lawsuit argues are no better for the climate. 

“Duke is currently engaged in one of the largest natural gas buildouts among any utility or energy company in the United States,” the lawsuit says. “Duke’s deceptions concerning natural gas have materially delayed the transition away from fossil fuels and toward renewable energy, including because these deceptions have caused the public to falsely believe that Duke is an environmentally conscientious corporation and thereby incentivized the public to continue to transact business with Duke.” 

Duke said in a statement that it is reviewing the town’s complaint. 

“Duke Energy is committed to its customers and communities and will continue working with policymakers and regulators to deliver reliable and increasingly clean energy while keeping rates as low as possible,” it said. 

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ISO-NE Stakeholders Respond to Potential Long-term Transmission RFP

Regional stakeholders widely support the New England States Committee on Electricity’s (NESCOE’s) proposed procurement of transmission solutions in Maine and New Hampshire but have differing views on the scope and format of the solicitation, according to public comments published Dec. 2

The proposed transmission solicitation would be the first to emerge from the longer-term transmission planning (LTTP) process, which NESCOE developed in collaboration with ISO-NE and FERC approved in July. (See FERC Approves New Pathway for New England Transmission Projects.)

The process allows NESCOE to identify a transmission need and direct ISO-NE to issue a request for proposals. It also includes a default cost allocation method in which the costs of a selected project would be regionalized by load, while NESCOE also could provide an alternative cost structure or opt to terminate the process.

In October, NESCOE told stakeholders it plans to focus the first LTTP solicitation on increasing the capacity of two interfaces in Maine and New Hampshire, which ISO-NE estimates will be overloaded by the mid-2030s. In a letter to ISO-NE, the states also expressed interest in projects that would help “facilitate the integration of additional generation resources located in northern Maine.” (See New England States Seeking Increase of North-South Tx Capacity.)

NESCOE asked for feedback on how to successfully achieve these goals, and said it still is considering whether it should expand the RFP to include “a requirement for solutions that extend farther north into Maine.”

“While such a requirement would further facilitate the transfer of cost-effective power across these interfaces, NESCOE seeks to avoid an overly prescriptive scope that may hinder the success of a potential RFP,” NESCOE added.

Clean Energy Groups

In joint comments, RENEW Northeast, the American Council on Renewable Energy and American Clean Power said NESCOE’s October memo is “an important first step … that will unlock additional renewable energy sources in Maine and reduce curtailment of existing resources.”

The clean energy groups said the RFP should be structured to encourage competition and be open to a range of technologies, “including the use of grid-enhancing technologies and high-performance conductors, as well as storage that performs a transmission function.”

Because the RFP will not allow partial solutions to the identified needs, “NESCOE should carefully consider the minimum requirements it identifies,” the groups wrote, adding that “allowing for a comprehensive solution to be comprised of discrete segments or sections could provide additional flexibility for meeting transmission needs.”

For future iterations of the LTTP process, the groups recommended ISO-NE and NESCOE adopt “a forward-looking solicitation schedule to provide project developers with longer-term market visibility.”

Advanced Energy United advocated for adequate flexibility to enable non-incumbent transmission developers to meaningfully participate in the process. The trade association said breaking the solicitation into multiple RFPs may enable more participation, but said a multi-RFP format should be pursued only if it does not hurt the timeline or the likelihood of success.

Hydro-Québec said the solicitation will be essential for reducing congestion and wrote that the “resulting transmission solutions will optimize the use of existing and future resources.”

The company touted the potential of its hydro resources to help balance renewables in New England and urged the region to consider “market reforms to complement and optimize future transmission solutions,” including the elimination of exit fees on electricity exported from New England to Québec.

“Market structures should be created and implemented that properly compensate clean and dispatchable resources and long-duration storage to support the integration of significant volumes of renewable generation into the New England system,” Hydro-Québec wrote.

Multi-day energy storage developer Form Energy said its batteries could help address constraints on the interfaces by absorbing energy when the interfaces are constrained and discharging when capacity is available.

Incumbent Transmission Owners

Eversource and Central Maine Power (CMP) both advocated for a defined, clear RFP scope to maximize the likelihood of success.

“A broad RFP seeking large, complex projects may limit the quality of the solutions proposed because bidders may be hesitant to dedicate significant resources to sufficiently developing very large projects,” Eversource wrote. “A targeted RFP is more likely to be successful and would not foreclose the possibility of pursuing a larger transmission expansion program via a sequence of several additional RFPs over time.”

CMP expressed concern that allowing projects to address needs in Northern Maine could overlap with a separate upcoming transmission procurement by the state of Maine and could delay Maine’s solicitation.

National Grid asked for more clarity around how projects will be evaluated and urged the RTO to “adopt and make known a relative weighting of evaluation criteria.”

The company also recommended “that NESCOE define the need to focus on renewable energy deliverability rather than interface limits to give participants greater flexibility in solution development and provide customers with the optimal solution.”

In contrast to CMP and Eversource, Vermont Electric Power Co. (VELCO) and Grid United submitted joint comments advocating for “flexible definitions to encourage a diverse range of innovative responses.”

VELCO and Grid United have proposed a $2.5 billion transmission project connecting New England, Québec and potentially New York, which is intended to increase interregional transmission capacity, reduce congestion and enable the interconnection of new renewables.

“We would respectfully request that NESCOE give strong consideration to this project for its second LTTP solicitation,” the companies wrote.

Non-incumbent Transmission Developers

Non-incumbent transmission developers, including NextEra Energy Transmission (NEET), LS Power and Con Edison Transmission (CET), stressed the need to allow bidders to include upgrades within an existing right of way.

“Allowing bidders to submit transmission solutions that include new or upgraded incumbent-owned transmission facilities and that solve for discrete needs will eliminate unnecessary obstacles to the development of competitive, innovative and cost-effective transmission solutions,” NEET wrote.

To make this RFP a competitive success, it should be clear that the need for new infrastructure defined in the RFP is outside of the [right of first refusal] rights of incumbent transmission owners,” CET wrote.

CET called for “an ample window” for developers to submit proposals, while LS Power advocated for shorter application and evaluation periods. ISO-NE has outlined a six-month application window, followed by a yearlong review process. LS recommended a 60‐ to 90-day application window and a 6-month evaluation period.

Consumer and Environmental Advocates

A coalition of environmental nonprofits said the RFP should explicitly consider potential interconnections of offshore wind upstream of the selected interfaces.

“Focusing solely on the potential integration of 3,000 MW of new onshore generation from northern Maine could result in a lack of grid transfer capacity for offshore wind and other resources that interconnect in Maine,” the coalition wrote.

The groups also stressed the need to move the process as quickly as possible and said NESCOE “should consider the possibility of initiating a second solicitation before the completion of the first.”

The Acadia Center submitted additional comments advocating for flexibility in potential solutions, a priority for using existing rights of way, and consideration of benefits related to increased interregional transmission capacity and offshore wind compatibility.

The Massachusetts Office of the Attorney General and the New Hampshire Office of the Consumer Advocate submitted joint comments advocating for a greater role for consumer advocates in the process.

“The Consumer Advocates seek to enhance our ability to participate more proactively in the LTTP process and to be included in critical discussions at key decision points to assure ratepayer interests are effectively represented and meaningfully considered,” the offices wrote.

Synapse Energy Economics, representing the Maine Office of the Public Advocate and nonprofit energy buying consortium PowerOptions, echoed the calls for a “flexible approach” to maximize competition.

“Synapse encourages NESCOE to include a recommendation that bids utilize alternative transmission technologies and particularly storage options when demonstrated to be cost-effective,” the company wrote.

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Meta Seeks Nuclear Partners; AWS Boosts Efficiency

Meta and Amazon Web Services continue to search for ways to meet their data centers’ growing power demand, requesting proposals for nuclear reactor construction and announcing new efficiency measures. 

Meta said Dec. 3 it wants to add 1 GW to 4 GW of new U.S. nuclear generation capacity by the early 2030s to help meet its AI innovation goals and sustainability objectives. It said it is taking an open approach with its RFP so it can partner with others in the industry to bring new nuclear generation online. 

AWS said Dec. 2 it has designed new data center components to support innovation with artificial intelligence and boost the energy efficiency of its facilities. It said this simultaneously will support the next wave of generative AI, increase computing power 12% and improve the availability and efficiency of the data centers. 

Meta’s announcement is Big Tech’s latest embrace of nuclear power, which holds the potential to supply large amounts of baseload emissions-free electricity — if new reactors can be built quickly, affordably and in large numbers. 

Microsoft, Google and Amazon earlier in 2024 announced deals to run their facilities on nuclear power. In November, media outlets were abuzz about a report that Meta’s plan to build an AI data center next to an existing nuclear plant was thwarted by the presence on-site of a population of rare bees that could be disrupted by the construction. 

So Meta is looking elsewhere to meet its parallel goals of reducing its carbon footprint and increasing its computing power, an effort that already has yielded more than 12 GW of renewable energy contracts for its operations. 

“Supporting the development of clean energy must continue to be a priority as electric grids expand to accommodate growing energy needs,” it said in its announcement. “At Meta, we believe nuclear energy will play a pivotal role in the transition to a cleaner, more reliable and diversified electric grid.” 

Meta explained it is engaging projects earlier in the process because nuclear generation is more expensive, takes longer to build, faces more regulatory oversight and has a longer operating lifespan than other generation technologies. 

It said: “We are looking to identify developers that can help accelerate the availability of new nuclear generators and create sufficient scale to achieve material cost reductions by deploying multiple units, both to provide for Meta’s future energy needs and to advance broader industry decarbonization.” 

The growth of power-intensive AI and the data centers in which it exists has been presented as a seismic change, and one the U.S. power industry is not prepared to meet. 

In the past several months, for example, Goldman Sachs predicted a 160% increase in data center demand by 2030. EPRI predicted data center demand could more than double to as much as 9% of U.S. electricity generation by 2030. The U.S. Department of Energy predicted total U.S. demand could grow 15 to 20% in the next decade. S&P Global predicted a need for 50 GW of new generation capacity by 2030, with accompanying upgrades in transmission — total cost $75 billion. 

Not everyone is convinced the increase in electric demand from data centers will be so steep, however — the sector may not grow as expected, or technology improvements could reduce the power consumption of the hardware. 

This latter scenario is the focus of the AWS initiative. 

The new data center components announced Dec. 2 incorporate improvements in power, cooling and hardware design. They will be used in new U.S. data centers starting in early 2025; some existing facilities already have been retrofitted. 

The upgrades include: 

    • Simplified electrical and mechanical designs reduce the required number of conversion and distribution processes, each of which is a point of inefficiency, energy loss and potential failure. 
    • Backup power is moved closer to the server racks, reducing the number of cooling fans needed. 
    • Novel liquid-to-chip mechanical cooling solutions are integrated with air cooling systems to maximize performance and efficiency while minimizing cost. 
    • AI is used to predict the most efficient way to position racks, reducing the amount of power that is stranded, unused or underused. 
    • In-house innovations in power delivery are expected to yield a 6X increase in rack power density within two years and an additional 3X increase further in the future. 
    • Telemetry tools provide real-time diagnostics and troubleshooting to optimize operating conditions. 

Prasad Kalyanaraman, vice president of infrastructure services at AWS, said in the news release: “These data center capabilities represent an important step forward with increased energy efficiency and flexible support for emerging workloads. But what is even more exciting is that they are designed to be modular, so that we are able to retrofit our existing infrastructure for liquid cooling and energy efficiency to power generative AI applications and lower our carbon footprint.” 

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NYISO Energy Costs up in Q3 2024

The NYISO energy market performed competitively in the third quarter of 2024, with all-in prices ranging from $42/MWh in the North Zone to $72/MWh in New York City, a decline of 4 to 14% from the same period in 2023, according to the Market Monitoring Unit’s third-quarter State of the Market report.

Presenting to the NYISO Installed Capacity Working Group, Pallas LeeVanSchaick, vice president of MMU Potomac Economics, said that even though all-in prices were slightly down, energy costs generally were up by 4 to 26% in most areas, despite relatively flat natural gas prices compared to 2023. The MMU found that the driver was higher emissions costs: Regional Greenhouse Gas Initiative carbon prices rose by 78% between 2023 and 2024, adding $4 to $5/MWh to energy prices.

The exception to this was in the Long Island zone, which benefited from additional offshore wind and imports across the Cross Sound Cables.

A graph of all-in prices by region comparing Q3 of 2022-2024. There was a sharp decline in energy prices (light blue) caused by a decrease in natural gas prices. Overall prices are still much lower than they were two years ago. | NYISO

“There was an outage of one of the 354-kV circuits into Long Island which would tend to make prices higher,” said LeeVanSchaick. “But on the other hand, imports over the Cross Sound Cable increased a lot due to higher availability in 2024 … so you actually saw a drop in prices on Long Island despite a significant outage there.”

Capacity costs fell by 29 to 39%, depending on the zone, because of lower demand curve reference points, reduced locational capacity requirements and a lower peak load forecast.

“Congestion rose modestly from the previous year but remained low, marking the second-lowest level for a third quarter since 2014,” the report says.

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MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup

MISO has officially decided it will forgo acceptance of a 2024 queue cycle of projects while it works with Pearl Street to automate interconnection studies.

MISO announced during a Dec. 3 Interconnection Process Working Group teleconference that it will close its currently open queue application window sometime in the third quarter of 2025 to begin a freshly automated study process on submitted projects.

MISO’s Ryan Westphal said staff and Pittsburgh-based Pearl Street Technologies have worked diligently on standing up an automated study process, paying attention to how the program selects network upgrades and estimates upgrade costs.

“Determining the network upgrade is one of the most time consuming pieces of the queue. We’re trying to distill that down into something that’s workable, reasonable and fast,” he explained.

Westphal said MISO will introduce Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software to “finish off” studies beginning with the 2022 cycle of project entrants. He said MISO will not rebuild its study models using SUGAR for the 2022 cycle, leaving that to subsequent queue classes. Instead, Westphal said the software will help finalize network upgrades and associated cost estimates.

MISO plans to begin using the software in earnest and “start from scratch” on model-building, Westphal said, in the first quarter of 2025, when it kicks off studies on the 123 GW of submittals that entered under the 2023 cycle. He predicted a busy January for MISO.

“We do have a pretty robust I would say, first draft of what will work,” Westphal told stakeholders. “With everyone’s participation and help, we can make this even better than what we have today.”

The grid operator originally said it would postpone a possible 2024 cycle while it waits on FERC approval of an annual megawatt cap on its queue. (See 2023 Queue Cycle Delayed into 2025 as MISO Seeks Software Help on Studies.)

MISO filed Nov. 21 to implement a 50% peak demand cap on the project submittals it will accept into its interconnection queue annually (ER25-507). The RTO has said it needs the cap to limit project proposals year to year, making for more realistic study outcomes and potentially reducing network upgrade costs.

MISO also promises to debut a special brand of faster interconnection processing for projects needed for resource adequacy. (See MISO Outlines Plan on Fast-track Queue for Resource Adequacy.)

For the 2025 cycle, MISO will use SUGAR to conduct pre-queue, “quality assurance” technical checks of applicants to test whether projects are feasible, Westphal said.

“Right now, the technical work is done sort of manually, by an engineer,” he said, adding that SUGAR should allow for “near instantaneous” checks.

Westphal also said MISO likely could accommodate stakeholders’ requests to provide a primer on how files and supporting documents should be submitted under the new automated study process.

He said under SUGAR, MISO’s input files still would be available to interconnection customers so they’re able to conduct their own analyses and look for alternative mitigations to upgrades.

Westphal predicted the SUGAR software will be in use in MISO for years and evolve over time with improvements.

“We’re hopeful that it’s a long-term partnership on this tool,” he said.

Pearl Street has said it is “thrilled” to partner with MISO and explained that a pause while MISO incorporates the software is regrettable but necessary.

“Any delay in the schedule is always unfortunate, but we see this as an investment to enable a truly transformative payoff: a fast, repeatable and transparent process that all interconnection stakeholders will ultimately benefit from. Let’s move some projects through the queue!” the company said in a statement in September.

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FERC Upholds MISO Sloped Demand Curve, Lets Opt-out Provision Stand

FERC was not persuaded by environmental nonprofits, utilities or Mississippi regulators to order MISO to rework the sloped demand curve it’s been cleared to use in the spring capacity auction.  

The commission issued a Dec. 3 order, refusing all rehearing requests tied to the demand curve’s opt-out provision, elimination of a clearing price cap and the curvature itself (ER23-2977).  

Starting in 2025, LSEs that decide to opt out of the auction and sloped demand curve must obtain more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The rule is a feature of the new curve and applies an “X% adder” — which changes yearly — beyond strictly necessary load obligations in an attempt to create congruence between LSEs that participate in the auction and are subject to the sloped demand curve and LSEs that opt out of the auction by assigning them similar reserve requirements. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.)  

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project argued over the summer that it’s unfair for the RTO to require utilities that opt out to procure capacity beyond resource adequacy needs. (See Environmental Groups Seek Rehearing of MISO Sloped Demand Curve.)  

But FERC said it’s appropriate for MISO’s sloped demand curve plan to place a value on incremental capacity above a loss of load requirement. As such, the commission said LSEs that choose to opt out shouldn’t “be exempt from contributing to these incremental reliability benefits.”  

“LSEs that opt out of the auction are not also opting out of the overall resource adequacy construct, which, as MISO notes, is crafted as a ‘risk-sharing pool across all LSEs, regardless of the LSE’s choice of participation model,’” FERC decided.  

The commission pointed to a previous finding that “a downward-sloping demand curve provides a good indication of the incremental value of capacity at different capacity levels” and that “incremental capacity above the [reserve margin] is likely to provide additional reliability benefits.”  

FERC said MISO’s opt-out as its stands neither motivates LSEs to participate in MISO’s voluntary capacity auctions nor incentivizes bowing out.   

FERC disagreed with the nonprofits that MISO is obliged to offer a “truly compelling justification” before it forces LSEs to buy more capacity than necessary to meet its reliability targets. The commission also said it is not MISO’s concern if incremental capacity procured outside the auction is more expensive than incremental capacity procured within the auction — a theoretical argument of the nonprofits.  

“While public interest organizations would prefer an opt-out mechanism that considers parity of cost of incremental procurement rather than parity of quantity, we do not need to evaluate the relative reasonableness of such a mechanism, given that we continue to find MISO’s proposed design to be just and reasonable,” FERC explained.  

The commission also decided MISO remains free to terminate its current 1.75-times-the-cost-of-new-entry (CONE) annual price cap for local resource zones. Transmission-dependent utilities in the Midwest had argued that MISO should have preserved the annual cap to discourage excessive prices and protect consumers. 

FERC’s refusal leaves MISO using a setup where the total annual price for a local resource zone could reach as high as four times the CONE, depending on whether capacity shortages occur in all four seasons of the auction.  

FERC said the annual cap was necessary under the previous vertical demand curve because even an “extremely small,” 1-MW shortage could have prices shooting up to CONE in all four seasons. Conversely, FERC said the sloped curve should return more gradual increases in shortage pricing that are commensurate with the missing capacity quantities.  

FERC said it’s “extremely unlikely” MISO would experience shortages in all four seasons, and if it did occur, the four-times-CONE clearing prices would properly reflect “unprecedented and severe capacity shortages.” The commission also dismissed as speculative the utilities’ argument that price protections are needed because a sloped curve would introduce the potential for more erroneous market results.  

Finally, FERC rebuffed arguments from the Mississippi Public Service Commission that it shouldn’t have accepted the sloped curve because it supported MISO’s vertical demand curve in past dockets.  

FERC said it never foreclosed MISO’s ability to adopt a sloped curve just because it found a vertical curve reasonable at the time and it “expressly left open the possibility that MISO could adopt a different market design if it so desired.”  

FERC noted that in the past, it has found both sloped and vertical demand curves practical and said it did not “change course” from its precedent regarding a sloped versus vertical curve, as the Mississippi PSC suggested.  

“Rather, this was the first instance in which MISO proposed a shift to a sloped demand curve design,” FERC said.