Reliability

The U.S. House of Representatives passed a bill Sept. 18 that could give dispatchable power plants priority in interconnection queues.

“The interconnection queue is overwhelmed and bogged down, leaving shovel-ready power projects waiting for years while demand continues to climb,” Rep. Troy Balderson, R-Ohio and the bill’s sponsor, said in a press release.

Under the GRID Power Act, FERC would have 60 days to review proposals from regional transmission organizations and independent system operators for specific projects that would be pushed to the head of interconnection queues.

The RTOs and ISOs would have to show the proposed projects would bolster grid reliability and resilience, according to the legislation. The bill defines dispatchable power as “an electric energy generation resource capable of providing known and forecastable electric supply in time intervals necessary to ensure grid reliability.”

The bill requires FERC to start a rulemaking process to implement the legislation within 90 days after the bill becomes law and to complete the rulemaking within 180 days.

Sens. John Hoeven, R-N.D., and Todd Young, R-Ind., have introduced a companion bill in the Senate.

The Electric Power Supply Association, a trade group for power producers, supports the bill.

“It has been surprising to hear that opponents of the GRID [Power] Act believe that this process will become chronic or habit-forming for grid operators or somehow represents a permanent barrier or level of discrimination against non-dispatchable projects,” EPSA President and CEO Todd Snitcher said in a “backgrounder” on the bill. “If the immediate reliability need doesn’t exist or can’t be explained, and FERC isn’t convinced both to the urgency and efficiency of the proposal, then queue prioritization doesn’t take place.”

The Sierra Club said the bill — along with two other energy bills that passed the House Thursday — would hamper efforts to build cleaner, more reliable energy sources, like wind and solar, that can be built more quickly than fossil-fueled power plants.

“House Republicans have continued the claim they want abundant, affordable, American-sourced energy while doing everything in their power to block clean energy progress and prop up dirty, expensive energy sources of the past,” Beyond Fossil Fuels Policy Director Mahyar Sorour said in a statement. “Energy prices continue to skyrocket as Trump blocks clean energy investment, and these bills will only ensure that rates continue to climb.”

The U.S. Department of Energy on Sept. 18 announced a “Speed to Power” initiative aimed at accelerating development of large-scale generation and transmission projects needed to power AI data centers and other emerging loads.

“DOE analysis shows that the current rate of project development is inadequate to support the country’s rapidly expanding manufacturing needs and the reindustrialization of the U.S. economy,” the agency said. It kicked off the initiative with a request for information on near-term investment opportunities, project readiness, load growth expectations and infrastructure constraints.

After years of flatlining, U.S. appetite for electricity is growing rapidly.

The North American Electric Reliability Corp. said it expected summer peak demand to rise by 15% and winter peak demand by nearly 18% over the next decade. The reliability watchdog said in its most recent 10-year forecast that demand growth is now higher than at any point in the past two decades, with more large commercial and industrial loads as well as the continued electrification of the transportation and building sectors. 

Analysts also expect aggressive growth. Consulting firm ICF said in May that demand could grow 25% from 2023 to 2030 and 78% by 2050. Bank of America Institute believes electricity demand will grow at a 2.5% compound annual growth rate through 2035, compared with an anemic 0.5% CAGR from 2014-2024.

“DOE is requesting stakeholder input on how to best leverage its funding programs and authorities to rapidly expand energy generation and transmission grid capacity,” the agency said. Utilities, state energy offices, regulators, grid operators, infrastructure developers, large energy users, and other stakeholders are invited to respond by Nov. 21.

The power system needs new resources quickly and if it is technology-agnostic then Speed to Power is “exactly the kind of action that DOE should be undertaking,” John Moore, director of the Sustainable FERC Project, housed at the Natural Resources Defense Council, said.

But “there is some irony to it, as the administration is moving to block clean energy projects onshore and offshore,” he added.

The Trump administration has declared an energy emergency and DOE has used its authorities to keep aging fossil fuel plants online. But at the same time, the White House has sought tighter restrictions for onshore wind and solar development and has tried to halt offshore wind projects.

The administration has also canceled previously-approved funding for some transmission projects, including a $4.9 billion loan for the 800-mile Grain Belt Express planned from Kansas to Illinois. 

DOE says the Speed to Power initiative will help achieve the aims of President Trump’s executive orders on “energy dominance” and winning the “artificial intelligence race.” The agency did not immediately respond to questions about how the need for rapid energy infrastructure deployment balances against the clean energy restrictions.

“If this is really the goal, then working with the Department of Interior on unblocking some permit approvals for offshore wind projects, or developing clean energy on federal lands, would serve the executive orders,” Moore said.

DOE could take steps to improve port infrastructure to speed development of offshore wind, or work with FERC to accelerate the interconnection of energy storage, Moore said. DOE’s initiative also noted the need for more interregional transfer capacity and “that’s something folks across the policy spectrum can agree on,” he said.

In the first year of Trump’s term, his administration has largely focused on the development of fossil fuel and nuclear resources, however.

“The bottom line is, you can’t meet the need with one hand tied behind your back,” Moore said. Some of the “anti-energy positions” coming out of the administration “will just drive up costs.”

A DOE spokesperson said the U.S. needs all energy sources that are “affordable, reliable, and secure.”

The country “cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” the spokesperson said in an email. “In the coming years, America’s reindustrialization and the AI race will require a significantly larger supply of around-the-clock, reliable, and uninterrupted power.”

A spokesperson for the Natural Gas Supply Association noted that while the RFI did not directly speak to the need for gas infrastructure to support AI, “natural gas investment is an integral component of this race.”

“It is imperative for DOE to use both its technical tools and funding strategies to ensure that sufficient natural gas infrastructure, including both pipeline expansions and storage, are readily available to manage demand growth from data centers and to ensure that grid reliability for other power uses are maintained,” the group said.

The National Association of Regulatory Utility Commissioners said its members will be discussing DOE’s initiative and RFI in the coming weeks, and the group will be “providing the insights of the state regulatory community to our federal colleagues.

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By Honeywell

Utilities face relentless threats from cybercriminals and nation-states capable of sophisticated cyberattacks that can disrupt operations, damage critical assets and interrupt the vital flow of energy services that enable our modern lifestyles. A cybersecurity strategy based on building taller walls and stronger locks alone can’t keep attackers at bay in a world where the grid has become more digital, interconnected and vulnerable.

This requires the utility sector – particularly energy services companies – to continue to evolve how it addresses and mitigates threats to better protect the grid.

The best approach combines prevention, detection and resilience response planning and recovery with a cohesive strategy to help block as many threats as possible and mitigate effects if intruders do get through. Cyber resilience is about containing breaches, maintaining critical operations and recovering quickly from adverse events.

Start Small to Build Resilience

Improving resilience takes time as utilities conform to regulatory requirements by identifying and upgrading assets, integrating new technologies, strengthening partnerships and adapting to evolving threats. The key is to start with achievable steps while moving toward a more adaptive, future-ready grid.

It can often be challenging for in-house security specialists to keep up with regulatory requirements and changing threat dynamics, so utilities of all sizes need to work with trusted, qualified cybersecurity partners to audit and inventory connected devices, identify vulnerabilities and assess response readiness.

To improve cyber resilience, utilities must first identify all assets on their network, including devices, systems and applications to understand what needs to be protected. They must assess each asset for its security level and operational criticality to focus resources where they are most needed.

Building and Executing Incident Response Plans

Trusted cybersecurity partners can help utilities develop and test comprehensive response plans for cyber incidents. Utilities need to continuously audit and refresh response plans to keep pace with changing assets, regulations and threats. These plans should also be tested yearly for effectiveness through tabletop exercises based on real incidents that the industry has experienced.

Advanced monitoring tools, powered by machine learning, can provide utilities with real-time visibility across their networks, enabling faster detection of anomalies and potential threats. By analyzing patterns and alerting operators to unusual activity, these tools allow utilities to respond quickly, contain attacks and prevent disruptions from spreading. They also support compliance and provide insights that strengthen long-term resilience.

Cybersecurity is not just the responsibility of a single person or group. It requires an ownership mentality that empowers all employees to embrace cybersecurity as their collective responsibility. It’s also important to continually test and update plans to demonstrate effectiveness.

With digitalization expanding and threats from cybercriminals and nation-states on the rise, utilities must go beyond compliance and fortress thinking. By prioritizing critical assets, deploying advanced monitoring and ensuring rapid recovery, they can turn resilience into a continuous commitment that protects people, assets and trust in the grid’s dependability.

Learn how Honeywell can help you strengthen your defenses and build resilience into your operations. Explore our utility industry solutions online and connect with an expert today.

California lawmakers approved a sweeping energy package at the end of the legislative session that does not include funding to continue two grid reliability programs, including a virtual power plant advocates believe is the largest in the world. 

Earlier this year, the state faced a $12 billion budget shortfall, and the two programs were in limbo for months as legislators negotiated down to the wire. The bills awaiting Gov. Gavin Newsom’s signature after the session closed Sept. 13 include proposals aimed at bringing down energy costs, expanding the Western grid and codifying virtual power plants in longterm planning.

Advocates say gutting the Demand Side Grid Support and Distributed Electricity Backup Assets programs threatens to undermine the state’s progress toward a more resilient grid that can respond to system stress by calling on batteries, electric vehicles, rooftop solar panels, smart thermostats and other energy resources that are increasingly common in homes, businesses and institutions. 

Legislators created DSGS and DEBA in 2022 to try to improve reliability and avoid blackouts during emergencies. At one time, they were slated to receive nearly a billion dollars in state funds. 

Kate Unger, senior policy advisor for the California Solar and Storage Association, said the DSGS program alone has more than one gigawatt of enrolled capacity, of which about 750 MW is batteries. The program is run by the California Energy Commission and offers customers, utilities and/or aggregators compensation in exchange for allowing their resources to be dispatched at times of grid stress. 

A test event in July saw more than 500 MW of battery energy dispatched to the grid for two hours.

“I think we’re at a point now where I can actually see the program come to a grinding halt,” said Unger. “There appears to be a risk that DSGS providers and customers could participate in 2026 and not get paid.”

A study by The Brattle Group, commissioned by Sunrun and Tesla Energy, both of which participate in the DSGS program, concluded that the taxpayer-funded virtual power plant could reduce the need for gas peaker plants and has the potential to save ratepayers $206 million between 2025 and 2028. 

After several rounds of appropriations and clawbacks, the programs had been expected to receive more than $400 million through at least 2028, funded primarily from California’s Greenhouse Gas Reduction Fund, which is funded by its cap and trade program.

Their fate, however, rested on the reauthorization of the cap and trade program, which was the centerpiece of a sprawling energy package that Newsom pushed through. The legislature passed a bill reauthorizing cap and trade and rebranding it as “cap and invest,” but without the grid reliability funding. 

Edson Perez, senior principal at Advanced Energy United, expressed disappointment that the programs seemed to have been left on the cutting room floor amid intense negotiations and budget constraints. 

“It just went into the black box of negotiations,” he said. “It is a huge missed opportunity.”

Perez said overall, reauthorizing cap and trade was a “great achievement” and he expressed hope that legislators would find another way to fund the grid reliability programs early next year. 

“The Governor is steadfast in his commitment to building a more reliable, affordable, clean and safe power grid that can serve the evolving needs of millions of Californians in a hotter, drier climate,” a spokesperson for Newsom wrote in an email. “The reality is that California has rapidly deployed thousands of new megawatts in recent years meaning our grid is more resilient than it’s ever been.”

The PJM Interconnection faces a possible multi-year “energy emergency,” according to the U.S. Department of Energy.

“The emergency conditions resulting from increasing demand and accelerated retirements of generation facilities supporting the issuance of [an emergency order issued in May] will continue in the near term and are also likely to continue in subsequent years,” DOE said in its August 27 order.

Given the possibility of hot weather in the next several months, DOE ordered Constellation Energy to continue operating two 380-MW gas- and oil-fired units at its Eddystone power plant near Philadelphia until Nov. 26. Constellation planned to retire the units on May 31, 2025, but kept them online in response to an initial emergency order from DOE.

DOE issued a similar second emergency order on Aug. 20 for Consumers Energy’s majority-owned, 1,420-MW J.H. Campbell power plant in West Olive, Michigan.

Under the Federal Power Act, DOE can order power plants to operate for 90 days during emergencies. So far, DOE has issued emergency orders for the Campbell and Eddystone power plants, but industry observers expect others will be issued as part of the Trump administration’s effort to support fossil-fueled power plants. At the same time, the administration is making it harder to build wind and solar power supplies.

In justifying the need for the Constellation units to keep running, DOE cited statements from PJM officials and reports that the grid operator faces resource adequacy concerns as its supply-demand balance tightens.

Also, the two units produced 17,000 MWh in June, including during a heat wave from June 23 to June 26 when the Eddystone units ran for a combined 124 hours, DOE said.

However, during the three-day hot spell in June, PJM exported a net of 273,062 MWh, according to a group of state consumer advocates who are challenging DOE’s initial Eddystone order. “Exporting megawatt-hours to others is inconsistent with the order’s finding that PJM is in the throes of a resource adequacy ‘emergency,’” they said in a June 27 appeal to DOE.

DOE failed to show that PJM faces an immediate energy emergency, according to the Maryland Office of People’s Counsel, the Delaware Division of the Public Advocate, New Jersey Division of Rate Counsel, the Illinois attorney general and the Citizens Utility Board of Illinois.

“On its face a ‘growing … concern’ is not an emergency,” the consumer advocates said. “While we think PJM needs to do more to address both resource adequacy and related affordability concerns, that does not include keeping an aging power plant online at ratepayer subsidy that even its owner would prefer to retire.”

The Natural Resources Defense Council, Citizens for Pennsylvania’s Future, the Environmental Defense Fund, the Sierra Club and Public Citizen also asked DOE to reconsider its initial emergency order.

DOE’s denial of the rehearing requests tees up a possible appeals court challenge by the groups. Michigan’s attorney general and a coalition of groups, led by the Sierra Club and Earthjustice, in July sued to overturn DOE’s emergency order on the Campbell plant.

PJM runs the grid and wholesale power markets in 13 Mid-Atlantic states and the District of Columbia.

The Public Utility Commission of Texas on Aug. 21 approved a slimmed-down version of CenterPoint Energy’s system resiliency plan, ultimately approving about $2.7 billion for strategic hardening investments over the next three years.

Texas lawmakers in 2023 required electric utilities to submit resiliency plans to improve grid reliability. Oncor Electric’s $3 billion plan was the first to be approved, in November, and Entergy’s $137 million plan was approved in January.

CenterPoint’s original resiliency plan, filed in January, came in with a price tag of $5.75 billion. A June settlement cut the ask to $3.2 billion, and at the PUCT open meeting last week more was removed by commissioners.

Commissioner Courtney Hjaltman said she wanted to “remove a few measures that ... seem more about replacing materials that have come to the end of their useful life,” and make changes to how the cost of some vegetation management is recovered.

Hjaltman filed a memo discussing her proposed reductions to the plan. She raised concerns about the level of detail in CenterPoint’s vegetation management plan and how the costs to transition from a five-year to a three-year tree-trimming cycle would be recovered. She said the utility’s proposal looked more like an “augment” to its base vegetation management budget and that “the lack of verifiable details for the individual programs leaves us unable to sufficiently distinguish the resiliency investment.”

“To be clear, I am supportive of [the vegetation management projects] but consumers deserve transparency between increased base budgeting and the unique investments made through these resiliency plans,” Hjaltman said in her memo.

The day of the open meeting, CenterPoint filed a memo responding that “increasing the regulatory asset threshold as suggested would leave the Company unable to collect $30.67 million per year in incremental vegetation management expenses required to transition to a 3-year cycle” during the resiliency plan period.

At the meeting, Hjaltman said she was unconvinced.

“I still feel that CenterPoint is using base rates to cover the cost of implementing the resiliency plan, and to me that blurs the lines of what should already be done and what is the purpose of the resiliency plan, which is the ‘above and beyond,’” she said.

The PUCT voted 3-0 to approve the plan, in line with Hjaltman’s proposed changes. It includes more than two dozen resiliency projects for the 2026-2028 period, the utility said.

”These programs will benefit our customers and communities by avoiding more than 755 million outage minutes and increasing our system's ability to take a punch from extreme weather events and get back up more quickly after storms,” CenterPoint said in an emailed statement. “We look forward to beginning work this fall.”

A July report in which the U.S. Department of Energy warned of widespread blackouts if coal and gas plants are allowed to retire “falls far short of a serious assessment of reliability and resource adequacy,” three clean energy organizations said in a formal rehearing request.

The Aug. 6 filing submitted by Advanced Energy United, the American Clean Power Association and the American Council on Renewable Energy says the resource adequacy document, though styled as a “report,” is in fact an “arbitrary and capricious” rule intended to bolster interventions by DOE under the Federal Power Act.

At least one federal agency — the Department of the Interior — has already cited the DOE resource adequacy protocol in an official action. It referred to the protocol in an Aug. 1 order that staff consider the capacity density of energy projects proposed on federal lands, singling out wind and solar as “inefficient.” 

DOE has 30 days to deny or respond to the rehearing request, Advanced Energy United Managing Director Caitlin Marquis said in an interview. If DOE denies the request, the groups would then have 60 days to file a judicial appeal, she said.

“We’ve provided some compelling counterpoints, so we hope they engage with our concerns,” Marquis said.

The report based its analysis on incomplete or unrealistic assumptions about load growth, net generation additions and individual resources’ contributions to overall system reliability through 2030, said Kent Chandler, former chairman of the Kentucky Public Service Commission and resident senior fellow at the R Street Institute, a free-market think tank.

“My takeaway from the report was that it’s an interesting … scenario, but it’s not the end-all, be-all of where we are and where we’re going to be on resource adequacy moving forward,” he said, calling DOE’s assumptions “near-extreme.”

Marquis and Chandler noted that the report assumes scheduled coal, gas and oil power plant retirements continue apace and that only new resources in the most advanced stages of development today actually come online by 2030. 

And its survey of generator additions appears incomplete, omitting resources — such as the 800-MW nuclear plant expected to resume operations in Michigan later this year — that are very likely to hit the grid before 2030, Marquis said.

On the demand side, the DOE report’s load growth expectations are plausible but well above some other credible estimates, she added. The report sees about 50 GW of U.S. data center capacity added from 2025 to 2030.

DOE also uses simplistic, unrealistic assumptions when modeling resource types’ reliability contributions, Chandler said. Its analysis of gas-fired power plants’ reliability, for example, appears not to account for the possibility of cascading fossil power plant failures due to pipeline outages, frozen coal piles and other fuel-related disruptions during extreme weather events, such as those that happened when Winter Storm Elliott hit the East Coast in 2022.

Grid operators like the PJM Interconnection recognize “the increasing probability that in the riskiest hours of winter, those generators may not be able to meet the need” and have given them “a significant [capacity accreditation] haircut” as a result, Chandler said. 

These and other reliability issues are known to utility regulators and grid operators, Marquis said, but DOE nevertheless discounts their ability to ensure resource adequacy and shore up reliability over the next five years. 

The result of acting on the report could be a grid that’s more expensive to operate and maintain. A DOE mandate to prevent uneconomic fossil power plants from retiring could cost U.S. ratepayers $3.1 billion annually by 2028, according to a Thursday report from the energy consulting group Grid Strategies.

“A utility rate case is a better-tailored tool to take all the available solutions and costs into account and make measured decisions rather than [deploying] this blunt instrument that has a really high ratepayer cost,” Marquis said.

As electricity demand rises and the power system grows more complex, six major themes are driving grid risk in 2025, according to the North American Electric Reliability Corp.:

• New large loads adding demand while the resource mix evolves.
• Reliability events are becoming larger and more widespread.
• Growing interdependence of the gas and power sectors.
• Increasing complexity of cyber and physical security.
• Persistent supply chain challenges.
• And “volatile” energy policy.

“Substantive simultaneous change in all system dimensions (resource, grid, load), along with increasing complexity in the interactions between them, requires rethinking traditional system planning and operating approaches,” the reliability watchdog said in its 2025 “Reliability Risk Priorities” report. 

NERC first added energy policy to the risk report’s “critical risk profiles” in the 2023 edition. Grid transformation, extreme events, security and critical infrastructure interdependencies were listed in the 2021 report.

NERC says its risk report differs from other analysis it creates and is intended to provide industry with “strategic direction to plan for imminent risks and their mitigation.”

Grid transformation “remains an overarching driver of new reliability risks,” according to the report. “Grid impacts emerging from the transformations underway are very different from traditional power system behavioral assumptions, challenging the existing grid’s resilience to extreme events.”

In its annual State of Reliability report, published in June, NERC found the grid is being challenged by the proliferation of large loads, such as data centers, and the operating profile of inverter-based resources. But “reliability improvements were observed in areas with high concentrations of battery energy storage systems.”

Though there is uncertainty surrounding how much data center capacity will be built, experts agree that data centers are increasing electricity demand. Data centers could account for 44% of U.S. electricity load growth from 2023 to 2028, Bain & Co. said in an October analysis.

NERC’s risk report contains dozens of recommendations, specific and broad, including for the industry to rethink reliability constructs, update planning and operating models and improve resource diversity, including energy and fuel storage facilities.

The industry should “add additional on-line and responsive sources of essential reliability services,” NERC said, and “assess the potential impacts through transmission enhancements.” Grid operators should also “enhance event response mitigation and recovery plans, as system impacting events cannot be completely avoided. Actively incorporate consideration of persistent supply chain challenges.”

The Federal Energy Regulatory Commission in July approved fast-track interconnection processes proposed by the Midcontinent Independent System Operator and the Southwest Power Pool.

The two temporary processes, which are similar, aim to bring power supplies online quickly to meet near-term grid needs. In SPP, utilities and other “load responsible entities,” or LREs, will select potential projects for fast-track interconnection reviews. State utility commissions or other “relevant electric retail regulatory authorities,” or RERRA, would vet potential projects for being considered in MISO’s review process.

Generally, state utility regulators supported the proposals. They were opposed by renewable energy companies and public interest groups which argued, in part, that they violated FERC’s principle of providing nondiscriminatory access to the grid.

FERC’s approval of the MISO and SPP plans is a “dangerous misstep" that could disrupt the development of projects that are waiting in interconnection queues, according to the American Clean Power Association.

“The fastest growing sources of energy — solar, wind, and energy storage technologies — are the ones ready to deploy to help keep costs lower and power reliable” in MISO and SPP, Carrie Zalewski, ACP vice president of markets and transmission, said in a statement. “Maintaining reliable and affordable power requires a diversified grid and predictable measures to bring new resources online.”

In its decisions on MISO’s Expedited Resource Addition Study process and SPP’s Expedited Resource Adequacy Study process, FERC rejected arguments that the plans violated the agency’s open access principles and that they discriminated against certain types of resources.

FERC said, for example, that SPP’s proposal was resource, ownership and technology neutral, and applied the same eligibility criteria across all potential interconnection requests. “In this way, we find that SPP’s proposal ensures that all interconnection customers will have comparable ability to seek to participate in the ERAS process,” FERC said.

The approved processes will allow planned resources that meet eligibility criteria to sidestep MISO’s and SPP’s standard interconnection queue reviews. Gas-fired power plants will likely be the main beneficiary of the fast-track processes, with standalone batteries also potentially being included in the fast-track reviews, according to ClearView Energy Partners.

However, depending on the energy policy preferences of utility regulators and LREs, the fast-track processes could result in the selection of some renewable resources, particularly projects with onsite battery storage. ClearView, a research firm, said Tuesday.

In May, the PJM Interconnection selected about 11.8 GW for a fast-track review process, with gas-fired generation making up nearly 70% of that capacity. ClearView said Tuesday that it expects a similar outcome for MISO and SPP.

The Sierra Club was one of the groups opposing the MISO and SPP proposals. “FERC’s decisions make it possible for gas plants to cut in line at the expense of thousands of clean energy projects that have been waiting for years to interconnect, projects that are well qualified to meet MISO’s and SPP’s energy needs,” Greg Wannier, a senior attorney with the Sierra Club, said in a statement.

MISO has 63 gas-fired projects in its interconnection queue totaling about 33.4 GW of summer-rated capacity. SPP has 69 “thermal” projects in its interconnection queue totaling about 30 GW.

MISO will accept ERAS interconnection requests from Aug. 6-11, the grid operator said. They will be studied on a first-come, first-served basis, with the first quarterly study beginning on Sept. 2.

SPP plans to issue a 30-day notice that it will open a one-time 30-day window for accepting ERAS applications. ERAS applicants must attest that their projects have a 2030 commercial operation date.

As the eastern half of the United States baked under record heat this summer and electricity demand reached multi-year peaks, it looked like the grid might succumb. 

Grid operators and public officials scrambled to avoid a disaster, ordering generators to defer maintenance and customers to conserve energy. The PJM Interconnection served about 161 GW of load on June 24, its highest demand since 2011 and not far off its all-time high of 165.6 GW.

But aside from scattered outages caused by heat-damaged electrical delivery equipment in parts of the New York City area, Eastern U.S. grids largely weathered the heatwave. 

Grid experts — and at least one grid operator — say at least some of the credit goes to distributed energy resource aggregations and flexible loads dispatching at higher rates than ever before. Those “virtual” or distributed power plants helped keep the lights on as generator reserve margins plummeted.

“PJM said that demand response was essential,” Federal Energy Regulatory Commission Chair Mark Christie said in a June 30 press conference focused on the need for resource adequacy amid rising load forecasts. “That 161-GW peak would have been higher without DR, so DR is an important part of the mix too.”

Major virtual power plant operators matched near-record peak loads with unprecedented dispatch activity. Sunrun dispatched more than 340 MW from customer-sited batteries on the evening of June 24. The same day, EnergyHub shed 900 MW of peak load and shifted 3.5 GWh of energy away from the highest-demand periods. Uplight managed about 350 MW of flexible load in 45 dispatch events across 16 utility programs over the course of the heat dome week. 

Supportive state policy, expectations for rising power demand and simple economics are pushing once-skeptical utilities to embrace VPPs, said Hannah Bascom, chief growth officer at Uplight.

“You're seeing [utility] folks on the supply side saying, ‘Wait, how many megawatts do we have lying around?’ And the light bulbs are starting to go off,” Bascom said in an interview.

Quicker and cheaper than traditional generation

It helps that it costs far less — and takes less time — to aggregate existing customer-sited resources than it does to build new dispatchable generation or storage, Bascom added. 

A new, 400-MW VPP has a net cost of $43/kW-year, compared with $69/kW-year for a utility-scale battery and $99/kW-year for a gas-fired peaker plant, the U.S. Department of Energy said in a January update to its virtual power plant liftoff report. An RMI report released last July said VPPs could be deployed in six to 12 months, quicker than any form of utility-scale generation. 

RMI’s report made a point of saying utilities eyeing VPPs in mid-2024 could have them ready in time for this summer’s heat. 

It’s clear many utilities and other load-serving entities have launched or expanded VPP offerings recently, said Kevin Brehm, a manager in RMI’s carbon-free electricity practice. 

“We’re definitely seeing progress in terms of the number of utility [VPP] programs, and in regulation and policy being implemented to advance VPPs,” he said in an interview.

Last year, RMI and the VPP Partnership published a flipbook featuring 75 U.S. VPPs with 3.9 million enrolled customers and 1.5 GW of capacity. That’s a small fraction of DOE’s 30 GW estimate of total U.S. VPP capacity in 2024.

Brehm cautioned that because VPPs can be deployed so quickly, published figures may underestimate capacity and thus the potential for utilities and aggregators to dispatch it during extreme weather events.

“Actual VPP capacity is what ultimately determines the level of response,” he said. “And [public reports] don’t tell the whole story because there’s a lag.”

Residential smart thermostats are already central to hot-climate VPP programs like Arizona Public Service Cool Rewards, whose 140 MW of thermostat capacity accounted for most of the utility’s 190-MW VPP as of last September. They’ll become even more important as smart thermostat adoption increases from today’s relatively low levels, Brehm said.

Commercial and industrial participation has room to grow

But much of the country’s VPP capacity still comes from manual commercial and industrial demand response programs, where power-hungry facilities agree to curtail load during peak periods, Wood Mackenzie said last year in a report. Another report by Energy Systems Integration Group showed C&I enrollments in wholesale demand response programs ranging from 4% to 10% of total potential capacity in most grid operator territories.

“Given how much capacity prices have risen recently, we’re going to see a lot more [C&I] demand response, and the potential is on the [multi] gigawatt scale,” Brehm said.

With the notable exception of the California Independent System Operator’s territory, C&I demand response enrollment has recently flatlined or declined in most regions due to limited customer awareness, weak financial incentives and barriers to wholesale market participation, according to ESIG. 

Brehm is hopeful that better technology and program design will turn the tide. Some VPP operators, like Voltus and CPower, coordinate multiple customer-sited resources, rather than interrupting power at a facility’s meter and shutting down production lines, he said. During the June heatwave, CPower says it dispatched 18.5 GWh across 120 events in PJM, ISO-New England and the New York Independent System Operator’s territory.

Small and midsize commercial facilities can also provide meaningful support during extreme weather events, said Thomas Flynn, chief administrative officer and general counsel at Budderfly, a commercial energy management provider serving more than 7,000 restaurants, medical clinics, convenience stores, hotels, gyms and other commercial sites nationwide.

Budderfly activated its first VPP on June 1, just in time for the heatwave. Flynn said the initial deployment included capacity in PJM, ISO-New England and the Southwest Power Pool — all hit hard last month — as well as CAISO. Enrollment could expand to NYISO and the Electric Reliability Council of Texas soon.

“We ran events across all of our programs during the week of the heat dome, activating programs from coast to coast,” Flynn said. “The events went well.”

For now, Budderfly’s VPP mainly dispatches HVAC systems via smart thermostats, but Flynn said it will soon expand to include onsite refrigeration systems, lighting, rooftop solar, electric vehicle chargers and onsite battery storage.

Because Budderfly owns those resources, dispatch is simpler than for customer-owned equipment, Flynn said. For local utilities, that simplicity — and the fact that commercial sites generally have larger and more consistent power loads — means more reliable and predictable VPP capacity.  

“Utilities see this model as a more reliable and scalable solution for flexible load capacity, particularly in regions where traditional demand response has been underutilized,” Flynn said. Budderfly can target dispatch in grid nodes without big industrial customers to provide load flexibility on a larger scale, he added.

Like Budderfly, Sunrun generally owns customer-sited resources. Its rapidly growing arsenal of batteries allows it to play a meaningful role in responding to extreme weather events, said Chris Rauscher, its head of grid services.

“We’ve fully embraced a storage-first strategy over the last few years,” Rauscher said. “Nearly 70% of our new installations include battery storage, up from just 10% a few years ago.”

Republican attack on renewables could help VPPs

Despite the recent U-turn in federal policy around renewables, the Trump administration’s preference for dispatchable power and declaration of an energy emergency create an opening for distributed asset owners like Sunrun, Rauscher said.

“Dispatchable energy is a top priority for this administration, and critical for grid stability,” he said. 

At the same time, Rauscher added, utilities are waking up to the fact that they need more electrons as fast as possible. Sunrun operates 17 VPP programs across the U.S., including utility-run programs like ConnectedSolutions in the Northeast and state programs like Demand Side Grid Support in California.

“The narrative is shifting [and] utilities are starting to see VPPs not just as pilots, but as core infrastructure,” Rauscher said.

Uplight’s Bascom agreed. While the rollback of clean energy tax credits will likely slow the deployment of distributed energy resources, that will also make it more expensive to build utility-scale generation, likely netting out to a boost for VPPs, she said.

“We still haven’t hit mass-market penetration,” she said. “We think there’s a lot of opportunity to leverage these resources for way, way cheaper than any type of new generation.”

Blackouts could increase by 100 times in 2030, relative to today’s averages, if the United States continues to shutter power plants and fails to add additional firm capacity amid rising demand, the U.S. Department of Energy said in a July report.

The report includes a uniform methodology to identify regions at risk of power outages and guide federal reliability “interventions,” DOE said. The report was required by President Donald Trump’s April executive order which directed the agency to respond to an “energy emergency” he declared in January.

But clean energy advocates say the report appears to exaggerate the risks, and undercount the contributions of wind, solar and battery storage resources. “If the analysis is overly pessimistic about advanced energy technologies and the future of the grid, consumers will end up paying too much for resources we no longer need,” Caitlin Marquis, managing director at Advanced Energy United, said in an email.

DOE’s report assumes 104 GW of plant retirements by 2030, alongside the addition of 210 GW of new generation — but only 22 GW of the additions will be “firm, reliable, dispatchable generation.”

“Modeling shows annual outage hours could increase from single digits today to more than 800 hours per year. Such a surge would leave millions of households and businesses vulnerable,” the report said. “We must renew a focus on firm generation and continue to reverse radical green ideology in order to address this risk.”

Average Loss of Load Hours could jump from 8.1 annually to 817.7 under some scenarios, the report said. It estimated an additional 100 GW of new peak capacity is needed by 2030 — of which, 50 GW is attributable to data centers.

“Data centers can be built in 18 months, but it takes more than three times as long to add new generation required to service those data centers,” DOE said in a fact sheet accompanying the report.

Even assuming no retirements, DOE said its model found outage risks in several regions rise more than 30-fold, “proving the queue alone cannot close the dependable-capacity deficit.”

“This report affirms what we already know: The United States cannot afford to continue down the unstable and dangerous path of energy subtraction previous leaders pursued, forcing the closure of baseload power sources like coal and natural gas,” Energy Secretary Chris Wright said in a statement.

America’s Power, which represents the coal sector, praised the report.

The analysis “is further proof that the premature retirement of coal plants is putting the reliability of the U.S. electricity grid at risk,” America’s Power President and CEO Michelle Bloodworth said in a statement. “Baseload power sources like coal are being replaced by less reliable sources like wind and solar. These renewables are not capable of meeting the constant 24/7 electricity demands required for AI, data centers, and other advanced technologies.”

The report includes a methodology that DOE says it will use to identify which generation resources within a region are critical to system reliability. The methodology uses hourly datasets for load, generation and interregional transfer capabilities for the 23 U.S. electric subregions.

DOE said it developed its outage risk estimates by running simulations using 12 different years of historical weather, with every hour based on actual data for wind, solar, load and thermal availability.

Clean energy advocates say they have doubts about the agency’s methodology.

DOE’s study “appears to exaggerate the risk of blackouts and undervalue the contributions of entire resource classes, like wind, solar, and battery storage,” AEU’s Marquis said.

“We are working quickly to dig into the numbers to unpack how DOE reached its conclusions,” Marquis said. “But it’s troubling that the report was not subject to public input and scrutiny, especially since the Executive Order that mandated it calls for it to be used to identify power plants that should be retained for reliability.”

The methodology “is another attempt to push the false narrative that our country’s energy future depends upon decades-old coal- and gas-plants, rather than clean renewables,” Sierra Club Senior Attorney Greg Wannier said in an email.

The Federal Energy Regulatory Commission and the states “are already well equipped to meet any projected resource needs through the existing regulatory process, which ensures that electricity demand is reliably met at the least public cost,” Wannier said. “Any effort by DOE to override this process to forcibly keep coal plants online past their planned retirements  would be an extraordinary and unlawful overreach of its regulatory authority.”

In May, DOE issued an emergency order under section 202(c) of the Federal Power Act, directing Consumers Energy to delay, by about three months, shutting down a 1,560-MW, coal-fired power plant in Michigan. Earthjustice and other groups have asked the agency for rehearing, and said they may go to the courts to challenge the order.

“Determining the reserve margin and ‘critical’ resources are complex decisions with severe health and economic consequences that Congress rightly entrusted FERC to oversee using a robust public adjudication process,” said Christine Powell, deputy managing attorney for Earthjustice’s clean energy program. DOE’s methodology “attempts to usurp that process, and would impose billions of dollars and harmful pollutants on consumers without any corresponding benefits for anyone except for the coal industry.”

DOE’s analysis “doesn’t support President Trump’s strategy of using emergency declarations to stop power plants from carrying through with their plans to retire,” said Jennifer Danis, federal energy policy director at the Institute for Policy Integrity.  

“The Trump administration’s own study has found that no present emergency exists in the two regions where it already issued 202(c) orders,” Danis said. “Reforms may be needed to ensure better planning for future resource adequacy to power AI, but they should focus on improving existing markets and planning standards, as well as speeding up new resource interconnection, rather than forcing customers to pay to keep old, inefficient plants online.”