The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released its vision for the future of the 26-year-old Common Vulnerabilities and Exposures (CVE) Program, pledging financial support and stability for the framework as it transitions from a “growth” to a “quality” focus.
Begun in 1999 as a research project at MITRE, the CVE Program has been sponsored by DHS since 2003 and by CISA since the agency’s establishment in 2018. Users have access to “a common lexicon of real, exploitable vulnerabilities,” CISA Executive Assistant Director for Cybersecurity Nick Andersen said in a blog post. Since its inception, the program has enrolled more than 460 partners across 40 countries.
The period until now represents the program’s “growth” era, CISA staff said in the CVE Quality for a Cyber Secure Future document, released Sept. 10. The document’s authors called the program “one of the world’s most enduring and trusted cybersecurity public goods” that “has contributed to exponential growth in the cybersecurity community’s capacity to identify, define and catalog hundreds of thousands of vulnerabilities.”
“If you’re a cybersecurity practitioner, you already rely on the CVE Program — whether you realize it or not,” Andersen said.
However, the future of the program was called into question earlier in 2025 when MITRE reportedly informed program managers that the federal government’s contract for the corporation to maintain the CVE program had been cut and the program would have to shut down by April 16.
Matt Hartman, CISA’s then-acting executive assistant director for cybersecurity, said in a release that the problem was “a contract administration issue” and that CISA had stepped in to resolve the issue before the contract lapse. But Andersen acknowledged in his Sept. 10 post that “significant debate” about the program’s future had occurred in recent months amid reporting that federal funding for the program was in jeopardy.
Andersen laid claim for CISA to “the mandate, mission and momentum to lead [the CVE Program] into the future,” saying the agency’s accountability to the American people made it a crucial independent voice in the program’s decision-making. CISA staff echoed this argument in their document, saying that alternate arrangements like privatization had been considered but found wanting.
“Privatizing the CVE Program would dilute its value as a public good,” CISA staff wrote. “The incentive structure in the software industry creates tension for private industry, who often face a difficult choice: promote transparency to downstream users through vulnerability disclosure or minimize the disclosure of vulnerabilities to avoid potential economic or reputational harm. These built-in conflicts could have a detrimental impact on program transparency.”
The authors also said alternate stewardship models might lack stability, leaving the program open to “undue financial pressures or contribution-driven influence.” As a result, they said CISA needs to take a more active role in the management of the CVE Program.
Staff identified several areas in addition to funding through which CISA can support the program. The first is for the agency to use its connections with its international counterparts, academic institutions, security researchers, operational technology developers and operators, and others to grant them more representation in the program that can “yield valuable insights and innovations.”
CISA also will support infrastructure modernization and the implementation of services including automation to improve services, while incorporating community feedback into road map decisions to expand transparency and communication. Data quality is another area for investment, with plans “to find creative ways to achieve quality, improve the CVE schema and forge ahead with innovative solutions,” the authors wrote.
“CISA is reaffirming our leadership role and seizing the opportunity to modernize the CVE Program, solidifying it as the cornerstone of global cybersecurity defense,” Andersen said. “In collaboration with the global cybersecurity community, CISA is committed to delivering a well-governed, trusted and responsive CVE Program aimed to enhance the quality of vulnerability data and global cybersecurity resilience.”
DETROIT — MISO’s generator interconnection queue has fallen to 215 GW as developers cut back on projects in response to the federal phaseout of renewable energy tax incentives, RTO leadership said Sept. 16 during Board Week.
The queue currently contains 1,127 projects at 215 GW. That’s down from more than 300 GW earlier in 2025.
“We’re starting to see significant withdrawals,” MISO Vice President of System Planning Aubrey Johnson told the System Planning Committee of the Board of Directors.
Johnson said projects that entered the queue in 2023 would be hard-pressed to be online in time to meet a 2028 phaseout of federal tax incentives. He said developers are making decisions to trim projects based on the changing economics.
MISO’s tariff expects that generation projects can scale the regular interconnection queue within 373 days; however, the actual average timeline is 1,511 days. The RTO is working to get to a 365-day completion rate with the help of automated studies from tech startup company Pearl Street Technologies. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)
Johnson said resource changes are showing up in the next set of members’ integrated resource plans. Currently, MISO’s 2023 cycle is down to 102 GW from the 123 GW of projects that entered.
“We expect to see significantly more withdrawals in the 2023 cycle,” Johnson said.
Meanwhile, 75 GW are all that remains of MISO’s jumbo, 171-GW 2022 cycle, and 38 GW still are standing from MISO’s 77-GW 2021 cycle.
MISO said it processed 100 generator interconnection agreements totaling 17 GW from November 2024 to August 2025. Historically, only about 20% of generation proposals ever make it to interconnection agreements. The RTO expects to add 10.9 GW in nameplate capacity (6.2 GW on an accredited basis) over the rest of 2025.
Johnson said the clampdown on MISO’s penalty-free withdrawals for projects in the queue also could play a supporting role in the project drop-offs.
Executive Director of Transmission Planning Laura Rauch said that although MISO members are tweaking the near-term resource plans they previously communicated, their emissions targets and renewable energy goals remain unchanged in the long term. She said there’s an “acceptance that it will take longer to get to the endpoint, but no changes in those endpoints as of yet.”
Finally, Johnson said the first 10 generation projects MISO selected for its first interconnection queue fast lane all seem viable, and MISO would begin official studies within days. Half of the first class admitted into MISO’s interconnection queue fast lane are natural gas units and account for 4.3 of the 5.3-GW lot. (See MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class.)
“We showed only one constraint, and the network upgrades look like they’re going to be in the couple hundred-thousand-dollar range,” Johnson said of transmission needed to accommodate the new generation. He credited MISO’s previous long-range transmission planning for making expedited generator interconnections possible.
DETROIT — MISO will start evaluating its South region for long-term transmission needs in 2026, beginning with Louisiana and possibly a lighter touch than used in the Midwest, the RTO announced before its Board of Directors on Sept. 16.
RTO planners told the board’s System Planning Committee they will approach the South with a “collaborative, investigative approach” and an eye on reliability and load growth.
MISO South never has had a successful, regionally cost-shared transmission project. MISO’s approximately $32 billion of long-range transmission projects approved over two portfolios in 2022 and 2024 have been confined to its Midwest region.
“We strongly suspect that while MISO South long-range planning will rely on the same tariff framework, it will have different viewpoints and different requirements,” Executive Director of Transmission Planning Laura Rauch told the committee.
MISO plans to start with modeling and what it calls the “South Load Pocket Risk Assessment” to inform planning. The RTO said it will use its updated, 20-year transmission planning futures in South planning once it’s done reformulating them. The transmission futures are due to be completed in early 2026. (See MISO Seeking Realistic Gen Buildout for Tx Planning Futures.)
Rauch said MISO will focus first on Louisiana’s needs “knowing that there are challenges” with load pockets and large load additions in the state. She said the RTO would develop a detailed scope of work for the South with stakeholders.
MISO said the load pocket assessment would estimate the risk of load shedding, with an initial focus on the Downstream of Gypsy load pocket in southeastern Louisiana, where load shedding occurred in late May.
Louisiana Public Service Commissioner Davante Lewis has said the Memorial Day weekend load shed event in New Orleans demonstrates the state needs more transmission capacity in and around the Downstream of Gypsy load pocket, which predates Entergy’s inclusion into MISO. (See MISO Debates What-ifs, Vows Improvements in Front of La. PSC After Load Shed.)
MISO South contains four major load pockets: Western, in East Texas; West of the Atchafalaya Basin, in East Texas and southwestern Louisiana; and Amite South and Downstream of Gypsy, in southeastern Louisiana.
Rauch said MISO’s early modeling could uncover issues where generation solutions — not new transmission — would be more appropriate. She said the RTO aims for solutions that South members “could pick up on and run with.”
MISO also said it plans to discontinue use of the word “tranche” to refer to the series of long-term portfolios. “Tranche 1” and “Tranche 2” referred to the first, $10.4 billion long-range portfolio and the second, $21.8 billion portfolio, respectively.
The Alliance for Affordable Energy’s Yvonne Cappel-Vickery said she hoped the phaseout of the word doesn’t mean that MISO South long-range planning would be “less robust” than in the Midwest.
At a Sept. 17 meeting of the Advisory Committee, Wisconsin Public Service Commissioner Marcus Hawkins asked when MISO might address its Midwest-South transfer constraint. The RTO originally said it would concentrate on the constraint in a fourth long-range transmission portfolio.
“Today, there certainly is some congestion on the North-South boundary,” said Jennifer Curran, senior vice president of planning and operations. But she added that as issues evolve in MISO, adding capacity on the constraint has decreased in urgency.
“I don’t think it’s a near-term priority economically or for reliability. But certainly, we will keep an eye on it.”
PJM has revised elements of its proposal to create a non-capacity backed load (NCBL) product for large loads as the Critical Issue Fast Path (CIFP) embarks on determining how to address the reliability challenges posed by accelerating data center load growth. (See PJM Board Initiates CIFP Addressing RA, Large Loads.)
The proposal would create a new form of interconnection service in which customers would not receive, or pay, for capacity in a set delivery year, and the amount of load procured in the corresponding capacity auctions would diminish accordingly. It would be triggered in delivery years where forecasted supply for a Base Residual Auction (BRA) is less than the reliability requirement. In nearly 200 pages of comments submitted to PJM in response to its initial proposal, many stakeholders argued it would undermine investment signals for new generation and lead data center developers to look to other regions. They also said PJM proposed a solution without taking the time to fully understand the scope of the issue.
The core change PJM made to the proposal is how large load customers might receive a mandatory NCBL designation. Under the version of the proposal PJM presented at a CIFP meeting Sept. 15, the RTO would calculate the amount of NCBL that would be needed across its footprint and allocate a share of that to electric distribution companies and load-serving entities based on the amount of planned, unbuilt large loads expected to come into service in their service area during a delivery year in which a shortfall has been identified. It would then fall to each EDC and LSE to determine how to assign their NCBL allotment to customers.
When first presented, the proposal had a voluntary pathway for customers to request NCBL status when PJM determined there might be a capacity shortfall in an auction, followed by the RTO making mandatory NCBL assignments if the deficiency persisted. Much of the criticism in the subsequent comments argued that PJM lacks jurisdiction to assert how retail customers receive service.
PJM’s approach to determining how much NCBL would be distributed to each zone would exclude existing load and planned large loads that intend to participate in demand response or bring-your-own-generation (BYOG) programs. Because the final NCBL designation would be left to retail service providers, however, Senior Director of Market Operations Tim Horger said it is possible that EDCs and LSEs, with direction from state regulators, could opt to include large loads already in operation or planning to enroll in DR or BYOG.
Horger told RTO Insider in an email that if a planned large load’s DR or BYOG participation does not cover its expected load, the remainder would be added to the NCBL area calculation.
Data center representatives said the proposal appears to force customers to take flexible or inferior service unless they enroll in BYOG or DR, and even then there would be no certainty that they could entirely mitigate the risk of being required to take NCBL service. That uncertainty around who is subject to the proposal would impact the prospect of making investments in PJM for those in need of large amounts of energy, they said.
Horger said concern that large loads could face unreliable service would be present even if PJM does nothing because of the heightened risk of manual load shedding being needed. The proposal would at least provide customers with savings on capacity and possibly more advance notice on when they would need to curtail in real time. He characterized NCBL as changing the prioritization of the load-shedding procedures.
Denise Foster Cronin, vice president of federal and RTO regulatory affairs for the East Kentucky Power Cooperative, said the proposal could result in scenarios where retail service providers bilaterally contract capacity for expected large customers, only for that load to be subject to NCBL and pulled out of the capacity market, while the self-supplied generation would remain on the supply side of the ledger. She argued that would effectively offer that paid-for capacity to other customers participating in BRAs.
“Additionally, despite having secured capacity to meet the totality of the load obligation, PJM would require its assessed amount of NCBL to be curtailed prior to emergencies. Since we are one of the transmission owners that PJM will require to execute the NCBL curtailment, that presents us with a Hobson’s choice, as none of our load should be curtailed,” Cronin told RTO Insider.
Responding to stakeholder inquiries on whether the NCBL proposal is being envisioned as a permanent addition to PJM’s capacity market or a temporary measure, Horger said it’s viewed as a way to bridge a gap across a reliability shortfall expected to last a few years. While a firm retirement for the product has not been included, he said the RTO is open to including a trigger to eliminate the process, such as after the reliability requirement has been cleared for a certain number of years.
PJM Associate General Counsel Mark Stanisz said the CIFP discussion demonstrates that the proposal impacts wholesale rates and supports the position that it falls under federal jurisdiction. He said PJM states have chosen to rely on the RTO’s markets and the courts have routinely determined that FERC and the Federal Power Act have jurisdiction over the rates, practices and mechanics behind RTO capacity constructs. He added that the federal energy policy ecosystem is rapidly evolving, with several executive orders since the start of 2025 and an artificial intelligence action plan in place.
PJM presented its non-capacity backed load proposal, which would create a new product for curtailable load that would be exempted from capacity payments. | PJM
In a statement responding to the proposal, the Natural Resources Defense Council recommended an approach requiring all new large loads to procure their own generation to avoid disruptions to the capacity market from individual customers. It argued that the proposal would leave data center load in the capacity market, causing customers to pay significantly higher costs and push data centers to install inefficient backup generation to cover periods where they are curtailed.
“PJM is creating rules for how to manage the reliability risk, essentially by proposing to shut off new data centers during any hour of the year when there is insufficient electricity. While this approach would preserve reliability in a draconian way, it will do little to protect residents from rising bills and require highly polluting backup generators to run many more hours each year,” the NRDC wrote.
Additional Package Details
PJM presented additional information on how it envisions the proposal being implemented, including specifying that NCBL curtailments would fall before pre-emergency load management deployments in the stack of emergency procedures.
Customers assigned NCBL status would be exempt from capacity payments by removing their load from the corresponding zone’s forecast peak load when determining how much capacity must be procured in each zone. The relevant EDC or LSE would be responsible for reducing its obligation peak load to reflect the reduced capacity requirement. PJM would shift the resource requirement and variable resource requirement curve, which determines the amount of capacity procured in a BRA, to reflect the RTO-wide NCBL designation.
The definition of a large load would be set at 50 MW, with a case-by-case review for including smaller customers.
PJM staff acknowledged many areas of the proposal require further refining, including what would happen if a customer or retail service provider failed to curtail NCBL.
PJM Broaches Alternative Proposals
PJM presented additional concepts that could develop into alternative CIFP proposals, including an alternate NCBL with only voluntary participation.
Eliminating the mandatory designation would grant states and retail service providers more ability to balance reliability risk against costs on their own, the RTO said. If participation is low, that could mean higher risk of manual load shedding, however.
Ongoing discussions around expanding provisional interconnection service could also be shifted from the Planning Committee to the CIFP. The changes being considered aim to identify resources that could enter partial operations before their full transmission network upgrades have been complete, making more energy available to dispatchers during emergency conditions. (See PJM Stakeholders Endorse Expansion of Provisional Interconnection Service.)
Another concept would require planned large loads to bid into capacity auctions for the year in which they intend to enter service, with a cost commitment that would hold even if they do not come online. Doing so would improve the certainty of the load forecast. Bids would be submitted either through the customer’s retail service provider, or the customer could become its own LSE, though PJM said both present jurisdictional quandaries. The proposal could be paired with a voluntary NCBL model, though the risk of manual load shed could still be high if many customers do not opt to participate.
The changes could be limited to how shed load is allocated, or they could be paired with other proposals, though PJM cautioned that if no other market design changes are made, the auction could repeatedly clear short of the reliability requirement, triggering the Reliability Pricing Model backstop auction.
An expedited interconnection option could create a parallel queue for a select number of resources with strict eligibility requirements, including being operational within three years. PJM’s Jason Shoemaker said it could deliver interconnection agreements in 10 months with minimal impacts to the overall queue. Because implementation would fall after the completion of Transition Cycles 1 and 2, he said there would be no disruption to projects already in the queue.
PJM could also develop more transparency for planned generation and large loads and assist in identifying opportunities to create partnerships between the two.
RA Scenarios Highlight Capacity Shortfall in 2030
PJM Senior Manager of Policy Initiatives Susan McGill presented five scenarios looking at how different levels of supply growth could impact a capacity deficiency PJM has projected in 2030. Each built off the 2025 Load Forecast, which estimated that net energy load growth will increase by about 4.8% annually over the following decade.
The first scenario assumed new resources would come on at the historically slow rate, bringing 6.6 GW of unforced capacity online, while policy-driven deactivations would take 8.1 GW of supply offline. Paired with 22.9 GW of load growth, that would result in a 24.1-GW UCAP deficiency.
The direst scenario assumed a 25% faster rate in resources interconnecting, offset by 29.2 GW of load growth from requests to co-locate load with new resources, resulting in a 24.7-GW shortfall.
Removing the co-located load requests and holding generation deactivations flat would result in a 10.4-GW shortfall, while adding the highest DR participation seen in the last five years to the equation would add 3.3 GW of supply and shrink the gap to 7.1 GW.
The final scenario assumed additional load flexibility would participate, resulting in the market clearing with no surplus.
Wide-ranging Comments Submitted on CIFP
Dozens of organizations and individuals submitted comments to PJM, many of which debated the merits of the NCBL proposal or urged the RTO to extend its focus to load forecasting, DR and the interconnection queue.
The governors of Pennsylvania, New Jersey, Maryland and Illinois jointly wrote that a CIFP process is needed to address rising load growth and correspondingly high capacity prices while stating that the impact of the NCBL proposal is difficult to model and could carry unintended consequences. If it were to be implemented, they recommended limiting it to the 2028/29 and following auction.
“An explicitly temporary and more broadly applicable NCBL methodology that is mandatory for only the next two BRA performance periods … could provide a partial and short-term solution. However, we feel strongly that this temporary solution must be accompanied by additional measures that address more fundamental issues and will not risk artificially perpetuating extremely high capacity prices through a potentially flawed trigger mechanism,” they wrote.
They said the CIFP scope should explore overhauling load forecasting, creating incentives for large loads to bring their own generation, using regional transmission planning to create new interconnection opportunities and speeding the interconnection of energy-only resources.
Exelon said the original iteration of PJM’s proposal would infringe on state jurisdiction and create a compliance trap for utilities stuck between the RTO imposing civil penalties if they fail to curtail NCBL customers and state regulators that might object to that curtailment.
“The proposal establishes a new category of retail service for certain large loads whereby those customers would receive service on an interruptible basis subject to curtailment in emergencies and would be exempted from paying capacity charges. This is not simply a tweak to PJM’s wholesale market rules; it is the creation of a novel form of retail electric service, with specified terms and conditions set on a regionwide basis by PJM,” the utility wrote.
Rather than rushing to a solution without understanding the problem, Exelon said that PJM should more thoroughly study the resource adequacy threats and hold education on the load shed risk in the Mid-Atlantic.
“Ultimately, we owe it to our customers, current and future, and our state policymakers and regulators to begin informing them of the real and increasing possibility of load shedding in the not-to-distant future, even as we continue efforts to build both the transmission and generation needed to address and mitigate that risk,” Exelon said. “Doing so may also result in additional creative solutions that would further mitigate and address this risk. Without being informed of the imminent need, we may lack the collective alignment amongst policymakers, regulators and operators to more aggressively tackle these issues.”
Advanced Energy United argued that PJM should focus its efforts on a BYOG pathway, which it said is likely the only way for significant amounts of supply to interconnect in time to make an impact, and address the load forecast to avoid mismatching transmission and generation development against load growth.
United argued the proposal would suppress capacity prices and hold back new investment in a manner that would make it hard to backtrack from.
The Digital Power Network said data centers lend themselves to load flexibility, which is underutilized because of outdated programming and inaccurate modeling of load-shedding events. Rules around when data centers could be curtailed must be clear and transparent, but PJM’s proposal would leave them in the dark, it argued.
“Flexible digital loads should be incentivized to participate in resource adequacy initiatives rather than be excluded from them. A framework that encourages voluntary participation through programs such as demand response while rewarding flexibility would strengthen adequacy and preserve reliability,” it wrote.
Ontario environmental groups panned the Canadian government’s inclusion of small modular reactors (SMRs) on its list of infrastructure projects to receive fast-track regulatory treatment, saying renewables would be a far cheaper way to expand generation capacity.
Prime Minister Mark Carney on Sept. 11 identified four SMRs planned at Ontario’s Darlington nuclear power plant as one of five “nation building” projects he said are needed to bolster the country’s economy in response to U.S. President Donald Trump’s escalating tariffs.
Speaking at a union training facility in Edmonton, Carney called Trump’s actions “not a transition [but] a rupture.”
“They are closing markets, disrupting supply chains, halting investments and pushing up unemployment. Canadians are over the shock, but we must always remember the lessons,” said Carney, who took office in March. “From now on, Canada’s new government starts by asking ourselves, for major projects, ‘how?’ How can we do it bigger? How can we do it faster?”
The Canadian and Ontario governments have leapt ahead of other regions in embracing SMRs, touting their zero emissions and economic development potential. But environmentalists say the province would be better served by building more renewables and storage to fill electricity demand projected to grow by 75% by 2050.
“Ontario risks being left behind by failing to embrace the faster, cheaper, cleaner alternatives already powering economies around the world,” Ontario Green Party Leader Mike Schreiner said in response to Carney’s announcement. “Right now we could create good-paying jobs using Ontario steel to build steel racking for solar and wind turbines and generate low-cost power.”
Tim Gray, executive director of Environmental Defence, and Jack Gibbons, chair of the Ontario Clean Air Alliance, were also critical.
Gibbons cited a recent analysis by IESO that he said showed that renewables and storage can meet the province’s peaking and baseload demands at a far lower cost than SMRs.
Wind and solar power, combined with four-, six-, eight- and 10-hour lithium-ion batteries can meet up to 99.98% of the province’s peaking electricity needs and up to 99.9% of its baseload needs under all weather scenarios, the alliance said in a briefing note. “Demand response resources and/or our existing gas-fired power plants could meet our remaining electricity needs,” it added.
It concluded that a hybrid portfolio plus natural gas was the least-cost resource option to meet the 5.1-TWh Peaky Need Scenario, with a cost of $25 billion to $34 billion (net present value in 2024 Canadian dollars), depending on the weather year used. The gas-only option was estimated at $31 billion in seven of the 10 weather years. The Peaky Need Scenario is based on production cost modeling for the 2025 Annual Planning Outlook without capacity expansion, which resulted in unserved energy of about 5.1 TWh in the medium term and a peak need of about 7,300 MW.
The Peaky Need Scenario is based on production cost modeling for the 2025 Annual Planning Outlook without capacity expansion, which resulted in unserved energy of about 5.1 TWh in the medium term and a peak need of about 7,300 MW. The Baseload Need Scenario assumes the addition of 2,000 MW of capacity, akin to a baseload generation facility, or 11,300 to 15,000 MW of installed capacity for the hybrid resource portfolio. | IESO
The analysis found dispatchable resources were the best solution for the Baseload Need Scenario. “Both SMR-only and gas-only resource options have similar cost profiles when acting as a baseload generator,” it said. The SMR-only option ranged from $27.6 billion to $33.8 billion, with the gas-only option estimated at $28 billion. The renewables-BESS option ranged from $37 billion to $47 billion depending on the weather year, a levelized cost of energy range of $140 to $175/MWh.
The Baseload Need Scenario assumes the addition of 2,000 MW of capacity, akin to a baseload generation facility, or 11,300 to 15,000 MW of installed capacity for the hybrid resource portfolio.
Hybrid Premium ‘Smaller than Expected’
To capture the geographic and temporal ranges in wind speed and solar intensity, IESO’s report considered 13 potential wind sites and 10 potential solar sites across 10 different weather years, assuming no transmission constraints.
“The premium on installed capacity and costs of hybrid resource portfolio solutions required to achieve load served up to 99.98% was smaller than expected,” IESO said in the report. “As performance of VG and BESS technologies improves and costs continue to decline, a non-emitting, hybrid resource portfolio, in theory, shows significant promise. It can provide both baseload and peak nuclear generation.”
‘Excess Generation’ Impact
The IESO analysis noted that wind and solar generation often need to be “overbuilt” to meet system adequacy needs and said that the value of the excess energy should “be considered in any planning study when comparing resource portfolios to meet a specific need.”
The energy that would be curtailed as a result of the overbuild “could potentially provide tens of billions of dollars in system value” by displacing higher-cost resources, IESO said.
Canadian Prime Minister Mark Carney announces Ontario’s small modular reactors will receive fast-track regulatory treatment. | CPAC
The Clean Air Alliance said that when the excess wind and solar energy is included ($17.8 billion in baseload scenarios, $28.4 billion in peaking scenarios), those sources and energy storage can meet peaking needs at a cost of $15.7 billion to $24.5 billion versus $97.1 billion to $120 billion for SMRs. Baseload electricity needs would be $19.5 billion to $29 billion for renewables and storage versus $27.6 billion to $33.8 billion for SMRs.
Questioning SMR Assumptions
The Alliance said IESO’s analysis understated the cost difference because of overly optimistic assumptions regarding SMRs:
IESO’s capital cost estimates for new SMRs ($11,804 to $16,711/kW in 2024 Canadian dollars) are 25 to 50% lower than the cost of Plant Vogtle Units 3 and 4 in Georgia, which went into service in 2023 and 2024, respectively ($22,628/kW).
IESO assumed the SMRs will have annual capacity utilization factors of 90.9%, well above the historical rates of Ontario’s Pickering (71.4%) and Darlington Nuclear Stations (78.6%).
Although Ontario Power Generation is spending $12.8 billion to refurbish Darlington Nuclear Station after 26 years of service, IESO assumes the SMRs will operate for 60 years without major refurbishments.
IESO’s report used the U.S. National Renewable Energy Laboratory’s 2024 Electricity Annual Technology Baseline for the low end of the cost range and the Tennessee Valley Authority’s 2025 Integrated Resource Plan’s estimate of an “nth-of-a kind” light-water SMR for the high end.
OPG did not respond to a request for comment.
Not a Recommendation
IESO cautioned that its paper was a modeling exercise and did not consider any “resource build limits” such as supply chain issues that would impact the feasibility of building the resulting resource portfolios.
“It should be emphasized that this document is not a plan, nor does it constitute a recommendation or endorsement of any resource, resource portfolio or technology.”
It also noted that to provide “high temporal granularity,” its modeling used deterministic, hourly profiles that did not fully capture the dispatchability (e.g., gas turbines) and storage capability (e.g., hydroelectric reservoirs) of existing resources.
“The study also shows that Ontario would need to build more than five times the baseload need in total capacity in the hybrid scenario, and even then may still not be able to meet the full need,” IESO said in response to questions from RTO Insider.
The ISO also noted that the paper did not consider the land use implications of the alternate portfolios. “A buildout of that scale would have considerable development and transmission costs that have not been factored into the paper.”
Nonetheless, the ISO said the role of renewables and storage will increase, noting that it recently completed the largest battery storage procurement ever in Canada, and that renewables are eligible in its second long-term energy and capacity procurement. (See IESO Officials Deny Favoring Gas Resources in Upcoming Procurement.)
“Ultimately, Ontario’s electricity grid benefits from a diverse supply mix that includes wind, solar, hydro, natural gas, nuclear and energy storage to keep the lights on,” IESO said. “These different resources have different characteristics and responses to weather, and maintaining a diverse supply mix means we always have resources to draw on that are right for the moment.”
The ISO said it plans to seek feedback on the study and rerun the simulation based on updated need profiles.
Ontario Pols Tout Economic Development Potential of New Nuclear
Ontario Premier Doug Ford in May approved OPG’s plan to start construction on the first of four SMRs.
The initial 300-MW SMR, targeted for commercial operation in 2030, would be the first grid-scale SMR in the Group of Seven countries. OPG says building all four SMRs, a total of 1,200 MW, will cost $20.9 billion. (See Ontario Greenlights OPG to Build Small Modular Reactor.)
The Ontario government also is supporting the addition of up to 4,800 MW of additional nuclear capacity at the Bruce Nuclear Generating Station.
In a high electrification scenario, IESO says, the province could need up to 17,800 MW of new nuclear generation in addition to its current 12,000 MW, which generates more than half of the province’s electricity.
Canadian Prime Minister Mark Carney (center) and President Donald Trump (right), at a G7 meeting on June 16. | Prime Minister Mark Carney (Photo: Lars Hagberg)
Carney said the SMR in Clarington will “sustain” 3,700 jobs annually, including 18,000 during construction.
Officials also see their leadership on SMRs having additional economic impact, citing agreements to work with Saskatchewan, New Brunswick and Alberta on the technology.
“We are already seeing results,” Clarington Mayor Adrian Foster told the Toronto Star. “Today, we have a Dutch delegation in town. [Other countries] are coming to see the SMRs. The world is paying attention to what is happening right here, right now.”
Major Projects Office
In addition to the Ontario SMRs, Carney’s five “nation building” projects include one to double the export capacity of the LNG Canada facility in Kitimat, B.C.; an expansion of the Contrecoeur Terminal at the Port of Montreal; a copper mine in Saskatchewan; and the expansion of the Red Chris copper and gold mine in northwestern British Columbia.
Carney said the office also will help other, less advanced projects, including the 60-GW Wind West Atlantic Energy Project off Nova Scotia and the Pathways carbon capture project in Alberta.
Environmental Defence’s Gray panned Carney’s selection of the Kitimat LNG facility and the mining projects.
“The federal government promised Canadians that nation building projects would align with our climate goals. This announcement, which begins with the expansion of LNG Canada that will increase climate pollution, is completely inconsistent with this commitment and will threaten Canada’s ability to meet its climate pollution-reduction targets,” Gray said.
He called the carbon capture and storage project “deeply flawed and regressive.”
“Carbon capture and storage has a decadeslong record of failure, delivering only a fraction of promised production emission reductions while locking Canada into higher overall oil emissions and draining public funds,” he said.
With California lawmakers passing the bill designed to transition the governance of CAISO’s markets to an independent “regional organization” (RO), new challenges await the West-Wide Governance Pathways Initiative as the coalition seeks to turn a once-elusive goal into reality.
In an interview with RTO Insider, Kathleen Staks, co-chair of the Pathways Initiative’s Launch Committee and executive director of Western Freedom, discussed the future of the multistate RO that will oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the latter set to launch in 2026.
Nine state utility commissioners and energy officials launched the Pathways Initiative in a July 2023 letter outlining their desire for increased coordination and expansion of electricity markets in the West. (See Regulators Propose New Independent Western RTO.)
The primary obstacle to realizing that goal has been California’s oversight of CAISO, which operates the markets and whose Board of Governors is appointed by the state’s governor.
“Nobody wants to participate in something where one state has the ability to choose the governing body members,” Staks said.
Previous legislative efforts to regionalize CAISO have failed because those asked California to completely relinquish control of CAISO’s balancing authority and transmission functions, Staks explained.
Pathways took a different approach. Over the course of 18 months, Staks and her team designed the RO to only oversee CAISO’s markets while preserving the ISO’s role in planning California’s grid.
The California legislature voted to approve the initiative’s “Step 2” plan on Sept. 13, authorizing the ISO and California’s investor-owned utilities to participate in the RO. (See Pathways Bill Passes Calif. Legislature in Lopsided Votes.)
But the work is far from over.
“It’s one thing to get the bill passed,” Staks said. “It’s another thing to actually get the thing off the ground. The implementation part still has to happen as well.”
For example, the RO has yet to be incorporated, and the Launch Committee is still drafting the bylaws and policies that will guide the organization. Additionally, FERC must approve the tariff change, and the committee must seat a board and find an executive director.
All those tasks will take time and money.
The group, which has estimated a $7.1 million budget for all three of its phases, hit a financing snare early in 2025 when the Trump administration paused nearly $1 million in funding as part of a larger spending freeze on projects previously promised support by the Biden administration.
There is enough money in the bank to cover expenses through the end of 2025, but the committee needs roughly $2 million for 2026 and about $4.8 million for 2027, staff said during an Aug. 29 meeting.
The group has issued an updated pledge form and a draft funding agreement to solicit additional funding, and it also is considering debt financing as an option.
“Fundraising is not going to be easy,” Staks said. “But I also think that, again, the economic benefits of getting this done and having one large, independently governed market for the West are good enough that we will be able to overcome that hurdle.”
Keeping the Door Open
However, the West will, at least for now, have two day-ahead markets. Because in tandem with CAISO’s EDAM, SPP is developing an alternative day-ahead market for the region — Markets+. SPP is also developing a Western version of its Eastern RTO called RTO West.
Major utilities like PacifiCorp, Portland General Electric and the Los Angeles Department of Water and Power have committed to EDAM.
Meanwhile, entities such as Xcel Energy subsidiary Public Service Company of Colorado, El Paso Electric, Tacoma Power and the Bonneville Power Administration have agreed to join Markets+. (See BPA Chooses Markets+ over EDAM.)
Despite utilities committing to either EDAM or Markets+, Staks said there is still a possibility for a unified market in the West. Utilities could decide to leave the SPP option and instead join EDAM, which has a larger market footprint, Staks noted.
The success of AB 825 “keeps the door open” for creating a larger market in the West, and ultimately an RTO, she said.
The bill “crosses off one of the barriers that have existed for so long … for utilities to decide to join and to go further with a market that is governed by California,” Staks added.
Supporters of EDAM have pointed to production cost studies by The Brattle Group and Energy and Environmental Economics that have found that CAISO’s market option would save ratepayers millions of dollars more than Markets+. (See Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW.)
For example, an October Brattle study found that BPA would earn $65 million in annual benefits from EDAM but face $83 million in increased yearly costs from participating in Markets+.
BPA and other Markets+ supporters have argued the production cost models have limitations and cannot capture the full economic picture. Additionally, BPA staff have pointed to Markets+’s resource adequacy requirements, greenhouse gas accounting mechanisms and especially its independent governance model. (See Western Utilities Set Sights on RTO After DAM Choice.)
After AB 825 passed, BPA told RTO Insider that the bill is a “positive development toward a more equitable market landscape in the West,” but maintained that Markets+ will provide greater benefits for its customers.
“While Bonneville participated in the development of several important provisions in the Pathways Initiative — like broader stakeholder engagement and the assurances for public purposes — BPA has been and remains clear in its desire to participate in a market wholly separate from the authority of any single state or entity,” BPA said.
However, Staks noted that U.S. senators from Oregon and Washington, along with stakeholders in the region, urged BPA to wait for the Pathways Initiative to play out, which the agency did not do.
Citing stakeholder comments, Staks said, “If governance is such a problem, why wouldn’t you wait for the Pathways Initiative, for the California legislative process to happen?” (See BPA Flooded with Comments on Draft Day-ahead Market Decision.)
“I think the response from BPA has generally been, ‘yeah, we don’t even think that the Step 2 proposal goes far enough, it’s not independent enough,’” according to Staks. “I’m not even sure what to say to that.”
“The new RO has sole authority over the EIM and EDAM,” Staks contended. “I don’t know how you get more independent than that.”
She acknowledged the RO will initially be under CAISO’s tariff, “and so there are some challenges inherent in that.”
“But that does not mean that the governance over the market is not … fully independent, because it is, and that was the design,” Staks said.
“We have that [independence] in Markets+, BPA spokesperson Kevin Wingert told RTO Insider. “Markets+ continues to demonstrate the effectiveness of its Western participant-led governance.”
Scott Simms, executive director of the Portland, Ore.-based Public Power Council, which strongly urged BPA to join Markets+ throughout the agency’s decision process, said the passage of AB 825 did not address the organization’s concerns about EDAM’s governance or affect its evaluation of the two options.
“PPC, and other Western entities including BPA, have been very clear about our concerns with the continued relationship between the future regional organization and CAISO under the Step 2 proposal, which prevents establishing truly independent governance over EDAM,” Simms said in an email.
‘Erosion of Trust’
The next steps for the Launch Committee include continuing to support the development of the RO until an independent board is brought on around July 2026. The board will not have power over markets until FERC approves the tariff, but it will assume authority over the RO to pick an executive director, negotiate the service agreement between CAISO and the RO and design the overall strategic plan for the RO moving forward.
The committee will continue to exist to support the board and make recommendations, “but ultimately, those decisions will be made by this independent entity starting next summer,” according to Staks.
“Once we have the RO set up and it has the market authority, then the Pathways Initiative has been successful,” Staks said. “And then we take a victory lap and see what else needs to be worked on.”
The committee consists of representatives from all sectors in the Western power industry that have an interest in developing electricity markets in the region. Staks said the effort is a testament to the importance of collaboration.
She said the debate over EDAM and Markets+ has created an “erosion of trust” and forced people into camps.
“We have an opportunity now, and we have a mandate now to rebuild those relationships,” Staks said. “Because whether we have one market or two, we’re going to have to find a way to work together, because the challenges are too big for us to be divided.”
The country faces “almost existential” challenges, Staks said. She pointed to difficulties of building new infrastructure, the changing generation mix, load growth and “inconsistent policies” coming out at the federal level that are targeting the renewable energy sector along with tariffs impacting supply chains. (See IRS Guidance on Wind and Solar Credits Not as Bad as Feared.)
“We have not just common ground, but universal agreement that we must be able to provide affordable, reliable energy to our consumers,” Staks said. “Those are fundamental tenets for every state in the West. Those are not political issues. Affordability and reliability are imperatives. And if we can peel away the rest of this noise and come back to those two fundamental tenets, I think we’ve got a good platform to rebuild trust and relationships again.”
DETROIT — MISO’s Independent Market Monitor said the recently uncovered, eight-year-old repeat error in the RTO’s capacity market that caused a $280 million impact in this year’s auction alone is unfortunate but insisted the resulting prices were efficient.
Monitor David Patton said he thought the MISO tariff’s requirement that loss-of-load expectation (LOLE) only be contemplated during daily peak hours was outdated in the first place. He said renewable resources have shifted loss-of-load risk to MISO’s non-peak hours.
MISO discovered in summer that an unnamed vendor since 2017 has miscalculated the RTO’s LOLE using an “all-hours” methodology, rather than the tariff-defined “daily peak hour” methodology, leading this year’s auction to clear more capacity than intended. As currently defined, a day with a loss-of-load event is counted in MISO’s LOLE calculations only if the event happens during the hour with daily peak load. The coding error caused a $280 million impact on market participants in this year’s auction, with some owing more money and some getting refunds. (See MISO Discloses $280M Error, Over-procurement in 2025/26 Capacity Auction.)
Patton said that despite the mistake, MISO’s clearing prices denoted the true reliability value of capacity resources in the footprint.
“The prices are actually right from a reliability standard; they represent a true one-day-in-10 standard,” Patton told the Markets Committee of the Board of Directors, meeting during MISO Board Week on Sept. 16. “Unfortunately, the tariff is actually flawed.”
MISO entered summer with a $666.50/MW-day capacity price across all zones. (See MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction.) The RTO experienced average real-time prices of $48.55/MWh over the summer, a 56% increase over summer 2024. The Monitor said energy prices rose largely from a 49% increase in gas prices and a 2% increase in load.
Patton said having an LOLE limited to peak hours “made sense six to seven years ago” when MISO had fewer intermittent resources and risk hours. He said the RTO’s performance since then clearly shows that emergencies now crop up outside of the peak hour.
If MISO had set reserve margin targets and procured capacity according to a “daily peak hour” methodology, it would have only achieved a less than one-day-in-five-years loss-of-load standard, under half of the target, Patton said.
“I don’t think it’s the right answer, and MISO doesn’t think it’s the right answer either, as they have already filed to fix this,” Patton said of the existing tariff language.
MISO said it plans to adopt an all-hours calculation in its LOLE because of its more volatile risk profile and emergency conditions popping up at non-peak times. However, the RTO did not mean to impose the switch beginning in the 2018/19 planning year.
Patton said that he was encouraged to see that MISO already filed to “fix the LOLE definition in the tariff with little opposition from participants.”
Senior Vice President of Markets Todd Ramey agreed with the Monitor that the mistake resulted in a “more accurate representation” of day-to-day risk in MISO, though it “slightly overstated” risk according to tariff definitions. He explained to the board that the error affected a parameter in MISO’s LOLE calculation, which “had an effect of being at odds” with the tariff-defined LOLE calculation.
Patton said that while the resettlements may be legally required, they “undermine the integrity of the competitive markets.” He said resettlements will be “inconsistent with the information posted prior to the auction,” which market participants used to make decisions regarding supply contracts and resource retirements. “From a market standpoint, this is really unfortunate,” he said. He emphasized that it is critical that market participants can rely on the data MISO posts ahead of the auction.
Considering the tariff requirement that the RTO limit corrections on long-term errors to the past year, Ramey said MISO determined that the most “appropriate adjustment” was to resettle market participants’ positions at lower estimated capacity prices in the 2025/26 auction.
MISO has said it will not rerun or completely resettle the 2025/26 auction. It has called the process “settlement adjustments.”
Ramey said that because the auction clearing prices were the highest in summer ($666.50/MW-day), the “bulk” of financial impacts involve the summer. He said MISO would issue three separate settlement batches for the summer.
The RTO has held one-on-one meetings with affected market participants, he said.
Patton said MISO should consider tariff changes that would allow it to “avoid retroactively resettling markets in the future” when errors occur. He said he would be in favor of doing “the least destructive thing to the market.”
“I think MISO is in an impossible position, balancing its legal obligations under the tariff with the market concerns,” Patton said in summarizing the situation.
Director Nancy Lange asked about stakeholders’ reactions, as the mistake resulted in some “winners and losers” among market participants. “Do you feel like there’s grace and understanding, or some consternation?” she asked.
“No one is happy in a circumstance like this,” Ramey said. “At the end of the day, it’s an unfortunate situation we’re working through.”
Ramey said MISO had to strike a balance between mitigating the impacts of the mistake and protecting the integrity of its markets. He said the saving grace is that market participants self-supplied about 90% of their capacity needs and weren’t affected by the prices in the voluntary capacity auction. However, he said, a few market participants relied heavily on the auction for capacity.
Ramey said MISO aims to cut down on overlooked mistakes going forward by initiating reapproval of authorizations for software and “changing the approach” to testing software.
Director Robert Lurie asked for a follow-up report on MISO’s efforts to strengthen software validation.
Public Utility Commission of Texas economist Werner Roth, who is also the chair of MISO’s Resource Adequacy Subcommittee, said the loss-of-load model “exists in a black box.” He said little is known about the important calculations that planners in MISO count on to make resource decisions.
“We need more data transparency,” Roth said. “Confidence in the LOLE model results are critical, and [MISO] could benefit from additional eyes.”
President Donald Trump is poised to have more than one of his own nominees on FERC for the first time in his second term, and, coupled with ongoing cases working their way through the courts, that has raised questions about the future of its independence.
When asked about FERC’s independence during their confirmation hearing in early September, both Laura Swett and David LaCerte gave the standard answer of following the law and FERC’s internal rules and regulations. But depending on the results of several cases, the laws governing the commission and other federal agencies could go through some major, radical changes. (See Senators Focus on FERC’s Independence at Swett, LaCerte Confirmation Hearing.)
The argument against independent agencies comes from subscribers of the “unitary executive theory” which, as Project 2025 said, finds them “constitutionally problematic” because in their view, the opening line of Article II of the Constitution vests executive power solely in the president.
While they exercise executive authority, independent agencies are largely free from White House influence, in part because of laws limiting the president’s ability to fire their members to certain circumstances. These laws were deemed constitutional in 1935 in Humphrey’s Executor v. United States, a case that proponents of the unitary executive have made a target for the Supreme Court revisiting. The precedent is being tested by Trump firing members of several independent agencies and the resulting wrongful termination lawsuits, and many observers see Humphrey’s Executor on the chopping block before the current justices.
“What [Humphrey’s Executor] says is that Congress, when enacting statutes, creating or regulating agencies, can condition or limit the president’s ability to fire certain officials for things like misuse of office,” Yale Law School associate professor Joshua Macey said in an interview. “It’s called ‘for cause removal.’ And, so, the sort of recent trend by the Supreme Court is towards the unitary executive thesis, which says that the president can fire any agency official for any reason whatsoever.”
Beyond the legal issues are “norms-based arguments” about whether a president should be able to control everything an agency does. “The president has shown that he’s willing to basically use all the tools at his disposal to control agencies,” Macey said. “With FERC, he’s been a little bit more reluctant.”
But the Department of Energy’s use of Section 202(c) of the Federal Power Act to keep two old fossil-fired power plants running this summer (and extending both orders this fall) was unprecedented. Macey also cited recent efforts to unseat Federal Reserve Governor Lisa Cook over allegations of mortgage fraud as another example of the White House trying to effectuate the unitary executive theory.
And while naming Democratic FERC Commissioner David Rosner as chair appeared bipartisan on its face, sources told RTO Insider they saw it as Trump exerting control over the agency. Under the precedent of the chair being of the same party as the president, Commissioner Lindsay See, the lone Republican on FERC, would be expected to be chair. (See FERC Independence Likely Coming to an End with Christie’s Exit.)
Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, pointed to the department’s Notice of Proposed Rulemaking during Trump’s first term as the kind of policy that the administration might try to impose if the unitary executive theory prevails at the Supreme Court. The proposed rule, rejected unanimously by a FERC comprising a majority of Trump’s nominees, would have paid power plants with on-site fuel their full operating costs.
“Congress designed agencies like FERC to operate somewhat independently from the White House,” Peskoe said. “I think part of the reason for that is for the stability of these industries. And particularly for energy industries regulated by FERC, that are making such large investments … unstable policies like we’ve seen at some politically controlled agencies would I think be disastrous for the development of energy infrastructure.”
So far, the Supreme Court has only dealt with the issue by overruling injunctions against firings from lower courts, Peskoe said. In one such decision in May, in a case involving the National Labor Relations Board and the Merit Systems Protection Board, Chief Justice John Roberts wrote that the government was likely to show both agencies “exercise considerable executive power.”
The court said it would benefit from full briefing and argument on the case, which is currently awaiting a final decision from the D.C. Circuit Court of Appeals.
“I’ve been reloading the D.C. Circuit opinion page every day to see whether it will rule on the merits, and that’s the case that I think would be the vehicle for getting this issue on the merits to the Supreme Court,” Peskoe said.
‘Distinct Historical Tradition’
The only case that has brought the Humphrey’s Executor issue as applied to FERC directly before the Supreme Court is an appeal of an enforcement action the agency issued against energy efficiency provider American Efficient, which has challenged the legality of the commission itself. (See FERC Seeks Nearly $1 Billion in Penalties from EE Provider in MISO, PJM.)
“We’ll see what the Supreme Court ultimately says,” Peskoe said. “There’s a lot of ways this could go that maybe would not impact FERC directly. What the Supreme Court has suggested is that somehow the Federal Reserve may be different than other agencies. Maybe there’s a way that FERC could also be different from other agencies.”
In that May decision, Roberts wrote that the Federal Reserve “follows in the distinct historical tradition of the First and Second Banks of the United States.”
Peskoe argued that FERC has its own “distinct historical tradition” in the form of ratemaking commissions, most notably the Interstate Commerce Commission (ICC), a federal railroad regulatory agency created in 1887 that had the same “for cause” removal conditions for commissioners.
“Congress’ goal there was to create deliberative bodies — not political bodies — that were going to handle the sensitive issue of regulating the railroads and setting their rates in terms of service,” he added. “That’s a ratemaking model that persisted as Congress regulated numerous industries under basically the same law over the next 50 or so years, and many of those issues don’t really exist anymore. But FERC is kind of the descendant of the ICC, and when the courts look at these separation-of-powers issues, that history may very well be relevant.”
Ratemaking is a legislative function, not an executive function, and that could help to distinguish FERC, assuming underlying legal precedents change, Peskoe said.
“Congress and state legislatures were completely incapable of doing this, and there were two basic reasons for this,” Macey said. “The first was rate cases. The question of ‘Can Congress review investment and then approve rates that will be passed on to captive ratepayers?’ is an enormously complex and time-consuming endeavor, and no Congress or state legislature had any interest in doing it.
“The second thing is, there’s a time lag. You need to consistently review these things. It’s not really possible to say we’re going to come in once a year, once every two years, and regulate. You need to look at investments in a dynamic fashion over time. That requires expertise, but it also requires a built-out staff whose full-time job is to do this.”
The Federal Reserve is likely to get an exemption from the end of Humphrey’s Executor, Macey said, but it is much less likely that FERC would get one. That leaves two questions, he said: whether there is any value to FERC independence, and whether adjudicatory agencies are exempt.
“FERC does a lot of adjudication,” Macey said. “Utilities file tariffs with FERC, and FERC either approves or rejects those tariffs; that looks less like rulemaking than like adjudication. And typically, we think adjudicator judges need to have some amount of independence because of due process reasons. We have to decide adjudication on the law, not based on political considerations.”
The Supreme Court has not touched that issue, but it will be forced to once the “for cause” protections are removed from FERC and other adjudicatory agencies, Macey said.
Ex Parte Communications
FERC’s ex parte rules already distinguish between its adjudicatory function and its rulemaking function: Commissioners cannot discuss pending rates, but commission chairs have often discussed rulemakings with the White House in past administrations.
Whether the Trump administration would want to intervene in adjudications before the agency in an open question, but the anti-wind policies at other agencies show that the White House cares about certain electricity issues more than others.
“My own view is that probably the primary justification for agency independence is that some matters involve significant expertise, and there is a real benefit to having to not completely immunizing them from political trends but at least limiting the kind of whipsaw reaction that comes in with a policy change every four years,” Macey said.
Presidents will always influence FERC policy, Macey noted, even if that remains solely through the power to nominate commissioners and appoint the chair. While drastic actions like freezing permits for clean energy resources might seem like they favor an administration’s interest, they lead to unintended consequences, he said.
“I think they are pretty bad for capital markets and investment because investors like stability much more than they like a policy that slightly favors their own interests,” Macey said.
FERC would have to change its ex parte rules, or at least how they are interpreted, to start talking about ratemaking cases with the White House, Paul Wight, a partner at DLA Piper and a former FERC staffer, said in an interview.
“There’s a couple of positions where there could be changes in the way it’s currently interpreted,” Wight said. “One position could be it’s not obvious that White House communications with FERC would always be prohibited by these ex parte rules. That’s a legal question.”
FERC ex parte regulations are arguably stronger than what the law requires, he added. But allowing for White House communications “would be a big change.”
“If they wanted to change the regulations, they would have to go through a process, and there would have to be comments from parties on whether or not this is a good policy to allow more direct communication,” Wight said.
The industry wants transparency around the commission’s regulations and, with its need to manage long-term, major investments, it also values certainty.
“You want to know what the process is and [whether] it’s fair,” Wight said. “There’s a lot of strong policy points to be made, [but] if you went to a less independent commission with more direct White House control, it would definitely be a change in the industry. It would be something that folks would have to adapt to. And, you know, I could see pros and cons, perhaps.
“We haven’t lived in that regime, but I think the history of FERC independence [has] been a hallmark of FERC, and I think it served the industry very well.”
Summer’s officially over, white shoes have been relegated to the back of the closet, and pumpkin spice everything is back. Now that the worst of the hot weather is most likely behind us for the year, it’s a good time to reflect on the pressure that extreme heat puts on the electric system.
Extreme weather has earned its way onto the short list of life’s certainties. Whether it’s heat waves, excessive precipitation, storms or freezes, there’s a higher chance than ever that where you live or where your company does business will be affected by extreme weather in ways that are as varied as the biblical plagues.
Heat affects the full length of the electric supply chain, from generation, through the grid, to utilities’ customers. In the first of a series on the impacts of climate extremes, this column will dig into the many ways hotter weather challenges the electric system.
Hot Town, Summer in the City
Extreme heat drives demand spikes. On July 28, 2025, peak demand in the lower 48 states broke the record set in July 2024, only to surpass it the next day. The peak demand of 759,180 MW between 6 and 7 p.m. July 29, adjusted for time zones, was nearly 2% higher than the July 2024 record.
| EIA
The demand is driven largely by an increase in the cooling load, though there probably were some AI servers churning out answers to heat-related questions: How can I cool my home? Will a blended margarita cool me down more than one on the rocks?
It’s not a surprise that demand spikes with heat: Who doesn’t want to walk into a cool home at the end of a hot commute? But heat waves are changing what these demand spikes look like. It’s not just that it takes more energy to cool a home when outdoor temperatures are higher than usual, but also that those with air conditioning are using it longer.
Heat waves can show no mercy at night. Earlier in 2025, some areas in the Southwest saw overnight lows as high as 95°F. This means household cooling loads extended well beyond the typical peak hours from 4 p.m. to 8 or 9 p.m.
Cooling a home becomes more challenging as the heat wave lingers. A home’s thermal mass—dense building materials such as brick, concrete or stone — absorbs heat and radiates it out during cooler periods. Usually, the thermal mass protects a home from heat (that’s why it’s cool inside a building with thick stone walls), but exposure to multiple days of extreme temperatures can slow down how a home cools at night and result in heat continuing to radiate after the heat wave ends.
Growing home sizes and increasing adoption of home cooling systems also increase demand. The results can be a capacity deficiency as demand spikes in areas not known for extreme heat, such as the spike ISO-NE dealt with in June.
The biggest change is happening in what the Building America program calls the marine climate region, which extends from the San Francisco Bay Area along the coast all the way to Canada. After record-breaking heat waves in the Pacific Northwest — in June 2021, Portland hit a record 116°F while Seattle hit 108°F, and then in late August 2025, Portland again recorded temperatures over 100°F — installing air conditioning in new homes is becoming common.
The bottom line: The grid will need to plan for ever-higher and longer demand spikes if it wants to maintain reliability.
Heat Strains Supply on Many Fronts
If the only challenge were meeting those demand spikes, the electric system probably would be in good shape. But generation and the grid itself are less efficient during extreme heat, sometimes dramatically so.
The first challenge comes from hot air being less dense: Combined cycle and gas combustion plants are less efficient when the air mixed with the gas to combust in the turbines is less dense.
Efficiency losses vary based on technology, but almost all are affected by heat, according to the Union of Concerned Scientists: “Many types of power plants become less efficient at higher temperatures. A gas turbine rated at 60° F might be able to generate only 85% of that capacity when ambient temperatures reach 100° F, for example.”
Similarly, power plants that use dry cooling, which works like a giant car radiator, have difficulty when the air needed for cooling already is heated.
The bigger challenge comes from hot water: All generation plants that involve combustion require cooling, regardless of whether they burn fossil fuels or split atoms. Most use water for cooling, which means drawing from seas and the like. If that water is hotter than usual before the cooling process, it will be less efficient at cooling, and there usually are limits on discharging hot water.
For example, nuclear reactors in Switzerland and France were throttled after heat waves warmed the water coming in so much that it couldn’t effectively cool the plants and environmental restrictions prevented them from discharging hot water into already overly warm rivers.
While most of these losses can be anticipated, extreme heat can cause extreme outcomes.
Attack of the Overheated Jellyfish
Not once, but twice this summer, the European grid had to cope with unplanned supply shocks because of [checks notes] jellyfish…?
It’s a story that sounds straight out of the eco-thriller “The Swarm”: The warming planet leads to a hotter English Channel, causing jellyfish to thrive, resulting in a “massive and unpredictable” horde of them in a French nuclear plant’s seawater cooling system. It happened in August, and closed four of six reactors, cutting output by 3.6 GW. Less than a month later, and only 165 miles up the road, another jellyfish swarm led to the shutdown of one reactor and the throttling of another, taking 2.4 GW offline.
While jellyfish swarms may be unpredictable, what we can predict is that heat waves will have widespread and varied consequences.
Renewables also are Challenged by Heat
Certain types of heat can make wind farms less efficient too. Heat lowers air density, and wind turbines produce less power when the air’s easier for the blades to pass through, so any hot day will cut production. However, when a stagnant high-pressure weather pattern settles in and creates a heat dome, the problems multiply: Low winds and less variation in wind speeds at different heights from the ground both cut output. A research paper in Europe found the impact varies by location, but one heat wave cut wind power output by more than 30%.
Hydroelectric output’s not immune either. Early heat waves in 2023 melted snowpack in the Pacific Northwest, leaving less water flow for the summer. Overall, the May heat wave decreased output 23% in Washington state across the 2022/23 water year. (Like the school year, the water year is not aligned with the calendar: It starts on Oct. 1.) Of course, heat often is associated with drought, which also limits hydroelectric output.
What about solar? More sun is good, right? Not if it comes with heat. There’s a reason Chile’s Atacama Desert is a prime location for utility-scale solar: It’s cool and sunny. Electronics are more efficient as temperatures drop, and every degree of extra heat lowers the output of a solar module.
Solar module datasheets include a measure called Pmax: the peak power the module can produce at standard operating conditions of 25°C (77°F). Right after that number, there’s always a temperature coefficient: the percentage drop in efficiency for every degree Celsius above 25°C.
While newer solar modules are less temperature sensitive, most still lose around 0.35 to 0.40% efficiency for each degree. This means that back in May, when Texas hit an early heat wave, exceeding 100°F (38C) in Austin — more than 7°C above the average high of 87°F (30.5°C) — the solar farms were delivering at least 2.6% less peak power than they would have on a normal summer day.
That sounds like a small amount of loss, but it was significant, as ERCOT recorded peak usage of over 78 GW, setting a record in May and again pushing the grid to its limits in July. And who wants their utility asking them to limit the use of air conditioning when the nights get down only to the 80s?
Even the Grid Wilts in the Heat
Like all of us, the grid is saggy and inefficient during heat waves. The power lines not only stretch, but also are less efficient conductors as the heat vibrates the conductive material and slows the flow of electrons. So, line losses, which typically consume 5% of electricity across the grid, increase during heat waves, meaning more generation is required to deliver the same amount of electricity where it’s needed.
As heat waves get longer and hotter, generation asset construction and grid upgrades and maintenance also are at risk. Heat accounts for about $100 billion in lost productivity nationally, and any industry where labor works outside is affected.
Some states are instituting worker protections that require breaks, shade and other cooling for outdoor workers (as someone who’s at high risk of heat stroke, I have to give a shout-out to Heat Relief Depot’s phase-changing vests). Some of those regulations have followed heat-related deaths. Other states, such as Florida, are doing the opposite: banning worker protections. But with or without protection, it’s reasonable to assume outdoor worker productivity will decline during excessive heat.
Upstream is not Immune
While we’ve looked from generation to end user, extreme heat has effects all the way upstream in the fossil industry.
In the ultimate irony, melting permafrost puts pipeline foundations at risk of sinking and causing a rupture in the pipeline. It’s a problem in Alaska and other arctic regions, and often is managed using passive thermosyphons (think of vertical radiators around pilings). However, hotter ambient air renders them less effective, and refreezing the permafrost under pipeline footings may require running fossil fuel-powered chillers.
A Hot Take on the Markets
The industry already knows how to manage hot weather. However, to think of extreme heat events as just extra hot weather is a mistake. Excessive and persistent heat, with little nighttime relief, creates challenges that are more diverse and harder to model. So, how should the electricity markets plan for extreme heat?
First, it means that the RTOs are on the right path as they aim to raise installed reserve margins and encourage demand response programs. And utilities should incentivize anything that can temper those peaks, from distributed energy storage to more efficient cooling technologies, such as rebates for mini-splits.
Second, as extreme heat events become more common, the industry needs to plan for them in a nuanced way. It’s critical to understand the wide and varied impact on generation assets. Gas and nuclear? Keep an eye on how they keep cool. Wind? Beware of the heat domes. And given that solar’s decline in efficiency in extreme heat events is easy to calculate (and has zero jellyfish-related risk), it may be time for RTOs to reconsider how they think of solar’s reliability. It’s not just about generation assets: The industry’s ultimate asset is its people, so thinking about worker safety also is critical.
Finally, extreme heat risk reinforces the need to diversify generation and consider where energy storage assets can best act as a shock absorber for the grid. They are, of course, useful sited next to intermittent generation assets, but there’s a strong argument to think of all generation assets as intermittent when extreme heat events are concerned.
Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience.
The California legislature has passed a bill that would create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects.
Senate Bill 254, by Sen. Josh Becker (D), would also establish an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. Contributions to the fund would be split between ratepayers and shareholders.
Lawmakers passed the bill Sept. 13 in the final hours of the 2025 legislative session. If signed by Gov. Gavin Newsom, the urgency measure would take effect immediately.
Becker said the bill, which was 361 pages, was the culmination of three processes. Elements of his initial bill were combined with consumer affordability measures developed in the state Assembly, as well as Gov. Gavin Newsom’s proposal to shore up the state’s wildfire fund.
During the Sept. 13 floor session, Senate President Pro Tem Mike McGuire thanked Becker for his perseverance on what he called one of the largest energy reform bills in state history.
“This bill has died about 10 times, and you’ve stuck through it,” McGuire said.
Becker pitched his bill as a way to rein in rising electric bills.
California investor-owned utilities’ electric rates traditionally have been higher than the national average and are rising rapidly, a legislative analyst said in reviewing SB 254. Electric rates charged by Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) have risen by 127, 91 and 72%, respectively, over the last decade, the analyst said.
SB 254 “will save ratepayers billions, stabilize our utilities and make sure the grid can support housing, clean energy and economic growth,” Becker said in a release.
One way the bill aims to save money is through a California Transmission Accelerator within the Governor’s Office of Business and Economic Development. Eligible transmission projects could receive low-cost public financing through the California Infrastructure and Economic Development Bank.
The bill gives the accelerator a Dec. 31, 2026, deadline to coordinate transmission planning activity in the state “in order to minimize duplicative efforts” and increase efficiency.
The accelerator would review results of CAISO’s transmission planning process and choose projects to be eligible for public financing. Projects must be consistent with the state’s reliability and greenhouse gas policy objectives.
The applicant must have successfully completed a previous California transmission project.
Recipients would repay the loans to an accelerator revolving fund so the money could be used for other transmission projects.
California launched its wildfire fund in 2019; utilities may tap into it to pay claims for damages resulting from a wildfire caused by utility equipment. PG&E, SCE and SDG&E contribute to the fund, as do electric ratepayers.
Without the proposed continuation account, the state’s wildfire fund could run dry due to claims from the 2025 Eaton fire in Southern California, a legislative analyst said.
Under SB 254, electric customers would pay into the continuation account through an existing charge on their bills, which is set to expire in 2035 but would be extended for 10 years.
Without the wildfire fund, Becker said, “ratepayers are on the hook for everything because of inverse condemnation,” which holds utilities liable for all damage caused by their equipment regardless of a finding of negligence.
If the wildfire fund runs out, SB 254 would allow utilities to use ratepayer financing to cover any settled wildfire claims between Jan. 1, 2025, and the time the bill takes effect.
Becker said the bill would add “teeth” to existing law regarding timelines for utilities to energize new customers.
Under current law, the California Public Utilities Commission sets reasonable average and maximum energization timelines. Customers may report delays.
SB 254 would require CPUC to draw up an enforcement policy for those timelines, including penalties, by Jan. 1, 2027. CPUC would also consider requiring utilities to have executive compensation incentives based on whether the utility is meeting energization timelines.
CPUC would also require utilities to hire a third-party auditor to review their energization practices.
In other provisions, the bill would block utilities from earning a profit on $6 billion in fire risk mitigation projects starting Jan. 1, 2026. It would also require more transparency into utility profits, so that consumer advocates and others can better gauge whether the profits are just and reasonable.
