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December 13, 2025

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CESA Report Examines State Approaches to Meet Rising Power Demand

The Clean Energy States Alliance released a report July 2 highlighting how states are tackling the rise in electricity demand, which varies based on factors such as the scale of demand growth they face and their geography.

About 80% of national data center load in 2023 was in 15 states, but the growth is concentrated in Virginia, with the largest collection of data centers in the world that account for a quarter of statewide electricity consumption. Other states expecting to see significant demand growth from data centers in the coming years are Georgia, Texas, Pennsylvania, Indiana, Ohio and the Carolinas.

Demand from manufacturing is expected to rise in the Midwest (both PJM and MISO), Southeast and West, while electrification is going to drive demand growth in California, New York and New England.

“A big challenge facing states is uncertainty around load forecast projections,” the report said. “The future of artificial intelligence and cryptomining, changes in state policy around electrification and clean energy, and the impact of federal policies on domestic industry and manufacturing all contribute to uncertainty. Additionally, big data centers often scout multiple potential locations for potential development, thereby making it unclear to state regulators and utility planners if and where a particular data center will ultimately be built.”

Most states, especially those with strong climate goals, continue to expand renewable energy, efficiency and demand response, but those facing near-term growth are backing new natural gas capacity and delaying the retirements of older fossil plants. Many states are exploring nuclear generation, with utilities including it in their long-term plans.

Concerns about rising costs from higher demand have led legislatures, regulators and utilities to develop large-load tariffs, promote data center efficiency and limit cost shifts among different customer classes.

The different drivers of load growth have their own demand profiles, which affects how they impact the grid and how state regulators and others need to address them.

Data centers generally are less flexible than most demand, but tech firms can shift computing demand around to different locations, and cryptomining facilities are price sensitive. But their usage is unpredictable, leading to forecasting challenges.

Industrial load tends to be higher during the workday, but process heat electrification and industrial-scale storage could help some facilities become more flexible.

Electrification load will tend to peak in the morning before people go to work and then again in the late afternoon/evening. In northern climates, such as New York and New England, electrification will shift the grid to having its overall peak in the winter.

“Transportation electrification’s load shape will also vary to some degree,” the report said. “Residential or commercial overnight charging will peak at night, while public fast EV chargers will likely peak during the day.”

An analysis from RMI estimates that to meet the growing demand, about 94 GW of new natural gas capacity is being planned to come online by 2035, 34 GW more than had been planned at the end of 2023. Renewables also are expected to grow, but the utility sector now plans to build 40 GW more natural gas than wind and solar by 2035, when just a couple years ago the planned new capacity for both was even.

Dominion Energy plans to build 5.9 GW of new gas by the end of the 2030s; Duke Energy has been approved to add 3.6 GW; and Southern Co.’s Georgia Power won approval for another 1.4 GW of gas this decade. Lawmakers in Maryland passed legislation to fast track a new gas plant, and those in Texas identified 17 gas-fired projects for state-backed loans.

About 9,100 MW of older capacity is expected to see its life extended because of demand growth, which includes two coal plants in West Virginia benefiting from new transmission planned to serve data centers in Virginia.

“Even New York, a state deeply committed to climate action, delayed the retirement of gas peaker plants in late 2023 due to reliability concerns and growing demand,” the report said.

The federal government also has started to issue orders keeping coal plants open, which was anticipated by some in the industry: Duke Energy said it would revisit its plans to retire its coal plants just days after President Donald Trump won the 2024 election.

Using fossil plants to deal with the higher load clashes with climate policies in some states, such as Virginia and North Carolina, the report noted.

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FERC Again Rejects SDG&E Bid for RTO Adder

FERC has denied San Diego Gas & Electric’s challenge of a commission order rejecting the utility’s request for an RTO adder to its transmission rates based on its participation in CAISO, saying SDG&E is ineligible for the adder under California law. 

FERC found that SDG&E failed to show its participation in CAISO is voluntary, a condition for receiving the RTO adder, stating a 2022 California law requires electric utilities to join and remain members of CAISO, allowing them to leave only with the California Public Utility Commission’s approval (ER25-270). 

Investor-owned utilities Pacific Gas and Electric and Southern California Edison joined SDG&E in challenging FERC’s order. 

“We continue to find that SDG&E’s participation in CAISO is not voluntary,” FERC’s July 2 order stated. “Section 362(c) of the California Public Utilities Code provides that, ‘[c]onsistent with Section 851 and the [CPUC’s] regulation of transfers of operational control of electric facilities, an electric corporation subject to [the transfer order] … shall participate in [CAISO].’ California IOUs do not dispute that SDG&E is subject to the transfer order. Therefore, the plain meaning of section 362(c) requires SDG&E to participate in CAISO.” 

In a separate but related order, FERC also affirmed a previous decision that SDG&E must refund adders with an effective date of June 1, 2019. 

The decisions stem from a broader FERC order issued in December 2024 in which the commission partly accepted SDG&E’s proposed formula rate and recovery of costs associated with transmission facilities. But FERC also rejected the utility’s request for an adder and affirmed that decision July 2. 

SDG&E proposed a base return on equity of 11.75% and an adder of 50 basis points for participating in CAISO — for a total ROE of 12.25%.  

RTO adders are provided through federal ratemaking as a way for FERC to incentivize utilities to join RTOs or ISOs. However, to be eligible for the adder, utilities must show that participation in an RTO or ISO is voluntary and not mandated by state law. 

Disputes around whether to allow California investor-owned utilities to recover an incentive for participating in the ISO have been ongoing. (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) 

In a 2020 case involving PG&E, FERC rejected CPUC’s argument that PG&E was ineligible for the RTO adder because participation in CAISO was mandatory. FERC ruled that, based on California law, the utility’s participation in the ISO was voluntary and that it could decide unilaterally to leave. (See FERC Rejects RTO Incentive Adder Rehearing.) 

But in September 2022, California amended its public utilities code to mandate participation in CAISO, with the ability to leave only with CPUC approval. Following this, FERC in December 2023 issued a decision holding that PG&E no longer was eligible for the RTO adder. 

In the underlying case involving SDG&E, the San Diego-based utility told the commission it believed FERC wrongly ruled against PG&E in 2023 and had appealed the decision to the U.S. Court of Appeals for the Ninth Circuit. 

According to the FERC July 2 order, the IOUs argue the CPUC code contains ambiguous language that allows them to leave CAISO, making their participation voluntary. 

But FERC disagreed, instead finding “Contrary to California IOUs’ view, Section 362(c) mandates participation and does not address withdrawal at all.” 

“While California IOUs argue that passages in the formula rate order and PG&E adder order suggest otherwise, the commission clarified in the PG&E adder rehearing order that Section 362(c) does not provide for withdrawal subject to CPUC approval,” the order stated. “To the extent the formula rate order leaves any ambiguity, we clarify that Section 362(c) does not provide for withdrawal.” 

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Google Data Center Electricity Consumption Up 27% in 2024

Google is reporting another sharp annual jump in electricity consumption at its data centers but says greenhouse gas emissions were lower in 2024 than 2023 by some measures. 

The company in its 2025 Environmental Report said it bought 32.11 million MWh worldwide in 2024 — 0.83% as much as the total electricity consumption in the 50 states in 2023 and 499% more than Vermont, the state that used the least electricity. 

Electricity use by data centers, particularly with the advent of energy-intensive artificial intelligence, is the focus of much debate and consternation among grid operators and policymakers. Some maintain the dire predictions are overblown, others say the demand is real, and there is a looming crisis on which the nation’s future rides. 

Google is a giant — its soaring power consumption may or may not be a bellwether of the tech sector as a whole. But its purchased electricity use in 2024 was 27% higher than in 2023 and 112% higher than in 2020. 

For perspective, fellow tech giant Microsoft reported 29.83 million MWh consumed in its fiscal 2024 — 26% more than in fiscal 2023 and 177% more than in fiscal 2020.  

Both companies reported small additional amounts of energy purchased in the form of fuel, heat, steam and chilled water, or generated by on-site renewables. 

A potentially huge environmental footprint accompanies all those gigawatt hours and all those data computations. 

In the annual report issued June 27, Google frames its power consumption within efforts to reduce that footprint and increase sustainability. 

“In 2024, we made our largest-ever procurement of clean energy, adding 8 GW to our portfolio, more than we’ve ever done in a single year,” Google Chief Sustainability Officer Kate Brandt said in announcing the Environmental Report.

Google nearly doubled its on-site renewable electricity from 10,700 MWh in 2023 to 20,500 MWh in 2024, for example. More than two dozen clean power projects contracted over the previous five years came online in 2024, raising Google’s carbon-free energy use from 64% in 2023 to 66% in 2024, even as total energy use soared. 

More broadly, Google said, energy-intensive AI data crunching is saving electricity beyond the data centers, through company products such as fuel-efficient routing, solar API, traffic signal management and machine learning-enabled thermostats. 

Google says those five products alone enabled an estimated 2024 emissions reduction of 26 million metric tons. The company’s goal is to reduce clients’ carbon-equivalent emissions by 1 gigaton per year by 2030. 

Google also has made headlines with its partnerships in advanced nuclear and geothermal development. 

An entire school of climate activism is dedicated to calling out corporate greenwashing, and five days after Google issued its 120-page report, Kairos Fellowship issued a 53-page report criticizing its emissions reporting as misleading and its conclusions as wrongly self-congratulatory. 

In the tenth annual report, Google acknowledges the gray areas within some decarbonization metrics. 

It set out in 2012 to match its global energy use with renewable energy purchases; it reached 100% in 2017 and every year since, but a 100% match is not what it considers carbon-free. 

“Even if a company buys clean energy in bulk and applies it to match its total usage over the course of the year, its real-time energy mix likely includes electricity generated from fossil fuels,” the authors write. 

Google continues to pursue its 24/7 carbon-free energy goal — a real-time match of electricity used with clean energy generated locally on the same grid in the same hour. On that measure, it claimed 66% success in 2024. 

In the final tally, Google reported its Scope 1 emissions and certain Scope 2 emissions were lower in 2024 than 2023, while Scope 3 emissions were higher. Combined, they are 6.3% higher, but Google does not include in that equation another type of Scope 2 emissions that showed the biggest year-over-year increase of all.  

Carbon intensity per unit of revenue, per full-time employee equivalent and per megawatt hour of energy consumed all were significantly reduced year over year. 

The hurdles Google sees to further progress are the same ones that face everyone else: interconnection delays, regulatory bottlenecks, logistical and economic constraints, limited local supply, permitting challenges and regional variations. 

The company reached only 12% carbon-free energy in the Asia-Pacific region in 2024, for example, compared with 70% in the U.S., 5% in the Middle East/Africa and 92% in Latin America. 

Google is pursuing multiple strategies for further progress but acknowledges the scale of the task, saying, “The path ahead is anything but simple.” 

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SPP Stakeholders Reject Urgent Dispatch Change

SPP stakeholders have rejected a proposed tariff revision (RR687) that would help the grid operator connect generation more quickly. 

Staff said the change would improve the definitive integration system impact study (DISIS) process by modifying the RTO’s dispatch method to ensure the added generation’s reliability and also lower exports to a realistic level. The proposal failed with only 36% of the vote during the Markets and Operations Policy Committee’s June 30 virtual special meeting. 

Natasha Henderson, SPP’s senior director of grid asset use, said during a June 26 education session that the large amount of generation in the queue, combined with the dispatch method, is causing unrealistic generation exports. That assigns noncommercial viable upgrades to generators. 

The 2023 DISIS includes 28 GW of capacity from 127 projects, about half of which are wind and solar resources. Like all SPP study clusters, staff analyze them in five groups: North, Nebraska, Central, Southeast and Southwest. 

Henderson said SPP is seeing dropout rates between 67 and 100% in the study clusters that are causing further downstream issues. 

“What happened in the 2022 DISIS is after all of this generation dropped out, $22 billion of associated upgrades also went away,” she said. “So, when we finish the 2023 DISIS Phase 2, it’s likely those generators are now going to see that same $22 billion of upgrades assigned to them. The proposed dispatch changes will mitigate that. It will not completely eliminate it, but it will help a little bit.” 

Oklahoma Gas & Electric’s Adam Snapp, a member of the Transmission Working Group (TWG), cautioned against the proposal, saying no one knows the full effect the modified dispatch will have on the 2023 DISIS. The TWG twice rejected RR687 in June, 0-13 with five abstentions, and 6-14 with three abstentions. 

“There are still a large number of resources that are in the 2023 queue that are benefiting from billions of dollars of upgrades that are currently assigned to the 2022 cluster,” Snapp said. “Once those 2022 cluster resources withdraw, those costs will shift to the 2023 resources that will trigger a lot of resource withdrawals from the 2023 cluster. What we’re effectively doing here is asking the policy to overrule TWG on a very technical matter without understanding the whole impact of … that decision.” 

SPP had hoped to receive an expedited approval from MOPC so it could apply RR687 to the DISIS 2023 Phase 2 clusters that hadn’t been completed before July 1. That study will conclude before the committee’s regularly scheduled July 15-16 meeting. 

“We do think that this needs to be ported over in future generation interconnection processes,” said SPP’s Casey Cathey, vice president of engineering. 

The issue will be sent back to the TWG for further consideration and discussion. The group next meets July 29 in Kansas City. 

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FERC Denies MISO, SPP Waiver of Joint Study Process

FERC has denied a waiver request by MISO and SPP to make changes to the Coordinated System Plan (CSP) under their joint operating agreement, saying it is not the “appropriate vehicle” to improve the process.  

The July 2 finding was made without prejudice, allowing the RTOs to submit proposed revisions to their CSP in a future Section 205 filing under the Federal Power Act (ER25-943). 

The grid operators filed the request in January, asking the commission to allow them to incorporate multiple scenarios in a single 10-year model instead of the multiyear analysis required by their JOA. They also asked to use multiple benefit metrics to evaluate reliability and public policy interregional transmission projects rather than the agreement’s narrowly defined “cost avoidance of pre-existing regional projects.” (See MISO, SPP Ask FERC for JOA Waiver to Conduct More Meticulous Interregional Study.) 

MISO and SPP contended that previous CSP studies were unsuccessful in “developing solutions where both RTOs benefit” and “have not yielded any interregional projects” for more than a decade. 

FERC said the request did not meet the commission’s criteria for granting tariff waivers that: the applicant acted in good faith; the waiver is of limited scope; the waiver addresses a concrete problem; and the waiver does not harm third parties or have other undesirable consequences. 

The commission found the request was not limited in scope because waiving a multiyear analysis “would appear to relieve them of a discrete tariff obligation.” It said waiving the RTOs’ tariff obligation to evaluate the benefits of reliability and public policy interregional projects as the avoided cost of regional projects that address the same reliability or public policy issue is “a significant change to the CSP study scope.” 

FERC said the waiver request does not address a concrete problem because the grid operators did not show that expanding the study scope would address the problem they identified. “That is, the proposed expanded CSP study might not identify transmission solutions that meet [the RTOs’] selection criteria,” FERC said. 

The commission said it was unpersuaded by the grid operators’ claim that their waiver request is consistent with FERC precedent granting “waivers modifying transmission planning study requirements and timelines and addressing inefficient market outcomes.” The commissioners said those proceedings involved waiver requests of tariff deadlines to allow the applicant additional time to comply with a tariff requirement, not to change the requirement outright. 

Commissioner David Rosner dissented from the 2-1 vote. Commissioner Judy Chang did not participate. 

Rosner said he believed MISO and SPP satisfied the commission’s waiver criteria. Noting the CSP study has not yielded a project in more than 10 years, he said the proposal to waive two JOA provisions related to technical planning assumptions will “better tailor the study to their regional needs, making it more likely to yield useful results.” 

“The commission should not stand in the way of simple solutions that give MISO, SPP and their stakeholders flexibility to improve the accuracy of their study,” Rosner wrote. “The alternative compels MISO and SPP to commit resources towards an inefficient study and prevents the regions from identifying needed interregional transmission projects.” 

“As the dissent rightfully points out, the CSP studies have not yielded any interregional transmission solutions for more than a decade,” Chair Mark Christie and Commissioner Lindsay See said. “In other words, the current situation is not a surprise to either MISO or SPP, and the circumstances that led to this situation are not outside of their control. While we appreciate MISO’s and SPP’s desire to improve their CSP process, a waiver request is not the appropriate vehicle to achieve such an outcome.” 

The American Council on Renewable Energy (ACORE) and International Transmission Co. filed comments supporting the MISO-SPP application. They said the waiver request would have yielded an expanded CSP study that would identify interregional projects that benefit both the MISO and SPP regions and would support a more reliable and efficient transmission system. 

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WRAP Participants Find Value in Program’s Nonbinding Phase

Even in its nonbinding phase, the Western Power Pool’s Western Resource Adequacy Program (WRAP) has been a valuable tool for working toward resource adequacy goals, program participants said. 

“We are really finding that the nonbinding phase is increasing our likelihood of success in the future,” said Camille Christen, resource acquisition, planning and coordination manager at Idaho Power. 

Christen’s comments came during an Oregon Public Utility Commission summer readiness workshop June 24 in which WRAP was one topic of discussion. 

Idaho Power’s WRAP capacity requirement, which consists of a load forecast plus planning reserve margin, was about 4,100 MW for summer 2025. 

Idaho Power did not meet the forward-showing requirement, Christen said, despite its combination of existing and new resources and demand response programs. The utility is now working to resolve the deficiency. 

Idaho Power fared better in meeting its internal 1-in-20 forecast of peak summer demand, which is about 4,000 MW. The utility has sufficient firm resources and contracts, including market purchases, to serve load. Idaho Power hit its all-time system peak of 3,793 MW in summer 2024. 

Christen noted differences between Idaho Power’s internal modeling and the WRAP model, which is based on regional inputs. Assumptions also vary regarding resource contributions, and the timing of the two analyses differs. 

WRAP’s nonbinding phase has provided transparency into regional planning and aggregated resource position, she said. Participants are also gaining experience on the operational side of the program. 

In a separate presentation at the OPUC meeting, Dee Outama, senior director of power operation at Portland General Electric, said the utility has enough resources to meet an internal target: a 1-in-2 peak plus a 9% planning reserve margin and 3% contingency. PGE is also in compliance with WRAP metrics for the summer, he said. 

In response to a request from RTO Insider, WPP declined to provide details on how many WRAP participants have been meeting forward-showing requirements during the nonbinding phase. 

Binding Phase Penalties

Western Power Pool launched the WRAP in response to industry concerns about resource adequacy in the West. 

Under the program’s forward-showing requirement, participants must demonstrate that they have secured their share of regional capacity needed for the upcoming season. Once WRAP enters its binding phase, participants with surplus must help those with a deficit in the hours of highest need. 

The binding phase also includes penalties for participants that enter a binding season with capacity deficiencies compared with their forward showing of resources promised for that season. 

In 2024, the binding phase was postponed by one year at the request of participants, who said they were facing challenges including supply chain issues, faster-than-expected load growth and extreme weather events that would make it difficult for them to secure enough resources and avoid penalties. The binding phase is now expected to start in summer 2027. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.) 

“What’s fascinating about the challenges that the WRAP is facing in going binding is they sort of prove out that there is a reliability challenge — that in fact folks are short,” OPUC Chair Letha Tawney said during the meeting. “And it’s hard to dig out of that hole in a time frame in the face of all the other headwinds.” 

The WRAP’s first nonbinding forward showing season was winter 2023/24; the program’s fifth forward showing, for winter 2025/26, is now underway. 

And plenty is happening during the nonbinding phase, according to Michael O’Brien, WPP’s senior policy engagement manager for the WRAP, who gave a presentation during the OPUC meeting. 

“[Participants] are giving data to SPP, the program operator,” O’Brien said. “They are going through the forward showing. They are being let know … where they are deficient in their planning.” 

Building Consensus

Another WRAP participant that has found the program beneficial thus far is Arizona-based Salt River Project. 

“SRP sees significant value in WRAP, as it has provided a regional forum to discuss resource adequacy in the West and how to best address the adequacy challenges posed by load growth and changes to the resource mix,” SRP spokesperson Jennifer Schuricht told RTO Insider. 

In addition, WRAP has built consensus around a set of reliability metrics for the region, “which will be increasingly important as the resource mix changes,” Schuricht said in an email. 

SRP is on track to fully meet WRAP forward-showing requirements when the program becomes binding, she said. 

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Trump to Sign Big Beautiful Bill into Law on Independence Day

After it took Republican leadership most of the previous day cajoling its members, the House of Representatives on July 3 voted 218-214 to pass the Senate version of its budget reconciliation package, the One Big Beautiful Bill Act, just in time for President Donald Trump to sign it into law by his imposed deadline.

“The House has passed generational legislation that permanently lowers taxes for families and job creators, secures the border, unleashes American energy dominance, restores peace through strength, reduces spending more than any other bill has, and makes government more efficient and effective for all Americans,” Speaker Mike Johnson (R-La.) and other Republican leaders said in a joint statement.

The bill makes permanent tax cuts enacted during Trump’s first term and slashes federal funding, including on tax credits for renewable energy and other programs Democrats passed in the Inflation Reduction Act of 2022. (See related story, Senate Passes Trump’s Big Bill that Slashes Clean Energy Tax Credits.)

Republicans kept the voting open for hours to secure passage, which was delayed by a record-long speech on the floor by Minority Leader Hakeem Jeffries (D-N.Y.). The entire Democratic caucus voted against the bill, as well as two Republicans.

“Our House Republican colleagues, Mr. Speaker, have one last opportunity to join us … to stand up and protect the health care of the American people; stand up and protect the nutritional assistance of the American people; stand up and protect our farmers; stand up and protect our veterans; stand up and protect the clean energy economy; stand up to protect our public schools,” Jeffries said.

The clean energy provisions were highly criticized by trade groups representing developers and environmentalists, but the investor-owned utility trade group Edison Electric Institute said the bill had some benefits for its members, including lower corporate tax rates and interest deductibility, and supported some energy tax provisions.

“Our top priority is delivering affordable, reliable energy to hundreds of millions of Americans. We support the many provisions in the bill that help us achieve this goal and grow our economy,” EEI President Drew Maloney said in a statement. “We will continue to work with the administration and lawmakers to implement and develop policies to support energy infrastructure investment and keep customer bills as low as possible.”

Clean energy supporters said that with rising demand, the bill’s changes and cuts to tax credits for renewable resources will only raise prices for consumers.

“While the new policies are a step backward, the combination of surging demand for electric power and economic benefits of renewable energy technologies ensure that clean power will continue to play a significant and growing role in our nation’s energy mix,” American Clean Power Association CEO Jason Grumet said in a statement. “America’s electricity demand is projected to surge by as much as 50% by 2040. That growth requires every available source of reliable power, including the clean energy technologies that are the only shovel-ready sources of additional power and the low-cost option across much of the nation.”

While the two parties have now used reconciliation in recent years to enact major swings in clean energy funding, one area they have so far failed to move on is permitting reform, despite both sides of the aisle having support for the concept.

“Permitting reform can and should be a bipartisan focus for members in the coming weeks and months that remain in this Congress,” Americans for a Clean Energy Grid Executive Director Christina Hayes said in a statement. “America’s transmission grid is at a crossroads. No matter your politics, the reality is clear: Demand for electricity is rising. Whether that power comes from natural gas, coal, nuclear, wind or solar, none of it will reach homes, businesses or data centers without a modern, reliable and expanded transmission network. As technology advances, we must ensure our grid can keep up — or risk losing America’s dominance in the global competition for advanced manufacturing and artificial intelligence.”

The Clean Energy Buyers Association represents many of the big tech firms behind the surge in data centers and other large energy users whose total demand is bigger than any U.S. state. CEO Rich Powell saw mixed results in the bill and seconded the call for “fundamental reforms to our national permitting system.”

“We regret that the tax credits for solar and wind are being sunset at a difficult time when we need all energy options to support unprecedented electricity growth in America,” Powell said. “We do acknowledge and appreciate the work of President Trump and Congress in expanding the critical policies needed for clean firm energy, such as nuclear, batteries and geothermal, to support the next generation of carbon emissions-free energy resources. America’s energy dominance depends on our ability to lead in the technologies of the future and to continue to invest in all forms of clean energy.”

The Business Council for Sustainable Energy said the bill will hold the U.S. energy industry back, though renewables and efficiency should continue to grow in spite of it.

“Compared to earlier proposals, the final legislation provides a more workable transition for some energy businesses currently utilizing federal energy tax credits,” BCSE President Lisa Jacobson said in a statement. “However, it imposes many rapid changes to various energy credits that will cause uncertainty and increase energy costs. These provisions include consumer credits for energy efficiency and clean energy that help lower energy costs for families and businesses, make the grid more resilient, protect good American jobs and provide certainty for vital investments in the energy sector.”

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NERC Posts CIP Survey, IBR Registration Updates

NERC is calling on industry to help the ERO identify the top security risks facing the North American electric grid in a new survey, while also providing guidance for newly registered owners of inverter-based resources ahead of next year’s deadline. 

The 2025 Emerging Security Risks and CIP Standards Roadmap Survey of Industry, released July 2, is intended to satisfy one of the ERO’s 2025 Work Plan Priorities approved by NERC’s Board of Trustees at its Dec. 10 meeting. (See “Organizational Items Endorsed,” NERC Board of Trustees Briefs: Dec. 10, 2024.) One of the priorities was to “create a road map for ensuring CIP [critical infrastructure protection] standards provide baseline protection for an evolving risk environment.”  

The survey provides participants with a list of 34 emerging physical and cybersecurity risks, to be ranked according to “their likelihood of occurrence and potential impact on [grid] reliability.” Topics included in the list range from broad issues such as supply chain, ransomware and malware attacks, and physical attacks on infrastructure, to more focused areas like targeting of distributed energy resource aggregator control systems, targeting of artificial intelligence tools and capabilities, compromising of metering infrastructure, weaponization of drones and unusable data backups. 

To prevent confusion among stakeholders, NERC also provided a supplemental information document outlining the risk statement and one or more hypothetical risk scenarios for each risk. The survey form also includes spaces for comments on the risk ranking and security risks not included on the list, along with their ranking. 

Survey responses are due by July 22. NERC said in an announcement it would “assess responses from the survey participants and use the collected insights in further developing” the CIP road map. The ERO then will develop a report with an overview of the risks prioritized in the survey, current applicable CIP standards, ongoing risk mitigation activities addressing each risk and recommendations for addressing identified gaps. 

IBR Materials Posted

The ERO’s IBR registration guidance, comprising two infographics also released July 2, are aimed at owners of IBRs that will need to be registered with NERC by May 2026. The deadline is based on the work plan approved by FERC in May 2023, which laid out a three-year process for registering IBRs that were not previously required to register but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation. 

Earlier in 2025, NERC told FERC it estimated there were 863 IBRs whose owners will need to be registered under the new classification “Category 2 generator owners.” This includes entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.” 

NERC prepared one infographic for GOs that already are registered with the ERO and will need to update their registration to include relevant facilities, and another for entities that are new to the ERO Enterprise. For the latter, NERC included explanations of the ERO and its mission, along with a brief outline of the registration process. 

The release of the new infographics is part of the third and final step of the IBR registration initiative, which NERC called an effort to welcome new participants into the ERO Enterprise.” NERC and the regional entities have events planned to further assist entities with the transition. 

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IESO Seeking Feedback on Commercial HVAC Demand Response Program

IESO plans to introduce its first electricity demand-side management (eDSM) program in 2026, focused on commercial HVAC systems during summer to lower peak demand as load grows in Ontario.

“HVAC loads in the commercial sector presents a significant opportunity for demand response,” the ISO said in a presentation to stakeholders June 24. “Large commercial buildings, including offices, retail spaces and institutional facilities, account for a substantial portion of Ontario’s peak demand, largely driven by HVAC loads during summer cooling season.”

The ISO has numerous energy efficiency programs that mostly are focused on retrofitting buildings, collectively known as Save on Energy. It also allows DR resources to participate in its capacity market. The new program would be part of Save on Energy, and any aggregated loads participating would be barred from bidding into the market.

That’s because capacity resources are expected to perform for at least half the year. (The “summer” half of the capacity year is defined as May 1 to Oct. 31.) However, certain large commercial facilities have capacity value only during the height of summer. The ISO is targeting 100 MW of curtailment in 2026 and 230 MW in 2027 from “resources” such as large retailers, office buildings, shopping centers, universities and municipal premises.

IESO plans to begin registering participants at the beginning of 2026 with a goal of beginning operation June 1 and running until Sept. 30. DR events would last up to three hours on business days only. Participants would be compensated by the end of the year based on the average megawatts curtailed and capacity prices for those four months.

The program is part of a larger eDSM framework funded through Ontario’s Affordable Energy Act of 2024, which granted IESO $10.9 billion for the new program as well as expanding existing Save on Energy programs. As part of the initiative, the ISO also is considering programs to support distributed energy resource installation and additional incentives for new energy-efficient buildings.

IESO has allocated $1.8 billion for the first three years of the framework with goals of 900 MW in peak demand savings and 4.6 TWh in electricity savings.

The ISO used the June 24 presentation to go over aspects of the commercial DR program on which it is seeking feedback from stakeholders. IESO’s Mohammed Yousif highlighted the ISO’s proposed incentive structure: the summer capacity price ($/MW-day) multiplied by 92 (representing the 23 business days in each of the four months), with the resulting figure multiplied by the average demand reduction.

A stakeholder representing the University of Western Ontario, which participates in the capacity market as part of an aggregation, asked how compensation through the program would compare. Noting that “the HVAC program is not meant to compete with the capacity auction,” Yousif said, “I think what we are leaning towards is … for the [program’s] price to be aligned with the [auction] clearing price, but not more.”

Another stakeholder asked why the program was limited to HVAC. “I’m a bit confused … if the intention is to alleviate demand on the grid, why are we limiting it to HVAC loads when a lot of these buildings have good capabilities [such as] light dimming?”

Yousif answered that “there has been a lot of discussion” about widening the scope of the program after the first one or two years.

But others were not satisfied with this, with one saying, “It seems like you’re adding a lot of rules … for something that doesn’t really make any sense. You should just let people openly select their demand response technologies.”

Yousif urged attendees to submit this feedback in writing and again suggested the program could open to other technologies if the ISO sees enough potential.

Feedback is due July 8. IESO will provide its response July 29 and consult with potential aggregators and other commercial customers over August and September, with a goal of issuing rules for the program before the end of October.

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NRC Makes Series of Streamlining Changes

The Nuclear Regulatory Commission has taken multiple steps to speed and smooth the path forward for the U.S. nuclear power industry. 

In two weeks, the NRC announced it has: 

    • changed policies to accommodate factory-built microreactors;  
    • reduced the hourly rate charged to advanced nuclear reactor applicants and pre-applicants; 
    • accelerated its review of a construction permit for an advanced reactor planned in Wyoming; and 
    • finalized a rule extending design certifications from 15 to 40 years. 
  • NRC also extended the expiration date of the operating license of a South Carolina nuclear reactor from 2042 to 2062, giving it a potential 80-year lifespan. 

President Donald Trump on May 23 issued a series of orders intended to ease and expedite development of new nuclear power generation. Among these was a strongly worded directive for reform of the NRC, its structure, its personnel, its regulations and its basic operations. 

On July 2, NRC published the design certification (DC) rule in the Federal Register. It is using the direct final rule procedure because it considers the action to be non-controversial. The rule will take effect Sept. 15 unless “significant adverse comments” are received by Aug. 1. 

The change pertains to the five reactor DCs now in effect, as well as future DCs and renewals. The 15-year period dates to 1989; NRC said time has shown too little operating experience accumulates in 15 years for review at time of renewal. Extending the window to 40 years will allow this to happen, NRC wrote, adding, “it will reduce unnecessary burdens with no reduction in safety or security.” 

Also on July 2, NRC said it had moved forward to no later than Dec. 31 its target date for completion of review of TerraPower’s construction permit request for its Kemmerer Power Station Unit 1. 

TerraPower subsidiary US SFR Owner submitted the application in March 2024. Before adopting the “more aggressive schedule,” NRC had expected completion of its review no later than June 30, 2026. 

The company seeks to build TerraPower’s Natrium design near an existing coal-fired power plant in Kemmerer, Wyo. The facility would be rated at 345 MW; an energy storage system would boost maximum temporary output to 500 MWe. If it is built, it will need an operating license through a separate NRC application procedure. 

On June 30, NRC announced renewal of Dominion Energy South Carolina’s operating license for V.C. Summer Nuclear Station Unit 1. 

The 966-MW pressurized water reactor in Jenkinsville, S.C., first was licensed to operate from 1982 through 2022. In 2004, NRC approved a renewal to 2042. This latest renewal will extend its license through Aug. 6, 2062. 

The Nuclear Energy Institute’s database indicates this is the furthest-reaching license of any U.S. reactor other than the brand-new Plant Vogtle Unit 4, whose initial 40-year license extends to July 28, 2063. 

There is widespread interest in expanding the aging U.S. nuclear fleet, but given the high cost and long time frame of new construction, operators are keen to keep existing facilities in service, uprate their capacity and even bring retired units back online. 

Dominion said July 1 it has been conducting upgrades at V.C. Summer to ensure its longevity, including the recent replacement of the main transformer. 

On June 24, NRC amended the fees it will charge applicants and licensees for fiscal 2025, as required by the ADVANCE Act of 2025. The hourly rate will be reduced from $318 to $148 effective Oct. 1. 

The NRC is required to recover as much of its operating budget through fees as possible. Its fiscal 2025 budget authority is $944.1 million; it expects to recover $205.4 million through service fees and $603.4 million through annual fees. 

On June 18, NRC announced three policy decisions to expedite deployment of microreactors — reactors built, fueled and tested at a factory that would generate 1% or less of the output of a large plant such as V.C. Summer. Under the changes: 

    • A factory-fabricated microreactor can be loaded with fuel at the factory under NRC license if it has features to prevent a nuclear chain reaction. 
    • Also, such a reactor can be excluded from “in operation” status. 
    • Finally, NRC staff can authorize testing of a microreactor at the factory before it is shipped to its operating site. 

NRC said it had directed staff to continue other efforts focused on microreactors in compliance with the ADVANCE Act and the executive orders.