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December 14, 2025

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CAISO Looks to Improve Visibility of Distributed Battery Storage

CAISO is working on an initiative to improve the visibility of distributed battery storage resources on the grid, especially for when they are needed for resource adequacy purposes.

The additional information will allow operators to see potential real-time operational limitations of the resources on the distribution system, CAISO said in a June 30 presentation.

Part of the challenge is that distributed batteries are often operated by a local utility, which might request placing certain charging and discharging restrictions on them. Sometimes that request conflicts with CAISO’s request for the same resource. When this happens, a battery resource should follow CAISO’s request, unless human safety or electric facilities would be knowingly put at risk, the ISO said in a discussion paper.

Another challenge for CAISO is figuring out how charging constraints are affecting distributed batteries during dispatch times. For example, if a storage resource is restricted from charging in the afternoon, then it might not be able to discharge to its full capacity in the evening, the paper says.

To address this problem, CAISO could identify distributed units in its master data file using a specific flag, the paper says. This approach would provide a good first step in providing needed transparency and was supported by two stakeholders in the initiative, the paper says. However, six stakeholders preferred updating CAISO’s resource modeling tools, such as its real-time telemetered capabilities, and extending the dynamic limit tool, the paper says.

In California, distributed battery storage capacity has grown from about 330 MW in 2022 to about 420 MW in 2023 and nearly 1,400 MW in 2025. It has not grown much over the past year, however: Capacity was about 1,250 MW in 2024.

As part of the same initiative, CAISO is studying the availability of mixed-fuel resources, such as solar and battery storage facilities, on the grid. Currently, the ISO is struggling to obtain accurate and reliable data from mixed-fuel resources, specifically about a resource’s high sustainable limit (HSL). The HSL is an estimate of the instantaneous generating capacity of a variable energy resource. For this problem, CAISO proposed to evaluate how HSLs are developed in its Business Practice Manuals. Doing so could improve short-term forecasts of co-located and standalone variable resources, the paper says.

Comments on the paper are due July 16.

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PJM Monitor Calls for Bidding Limits on NRG Generation, DR in LS Deal

PJM’s Independent Market Monitor told FERC on July 7 that NRG Energy’s proposed purchase of power plants and demand response from LS Power would increase structural market power in the RTO (EC25-102).

The Monitor asked for the commission to impose behavioral constraints on the proposed merger, which includes assets in other markets, though the biggest overlap is PJM. (See NRG Energy Seeks FERC Approval for LS Power Deal.)

“The transaction would increase structural market power in PJM markets,” the Monitor said. “The significant increase in the concentration of ownership of emergency and pre-emergency demand resources is especially noteworthy given the newly pivotal role of these resources and the absence of any applicable market power mitigation rules.”

DR does not have a must-offer obligation, which allows for physical withholding and no offer caps, allowing for economic withholding, according to the IMM.

“This absence of market power mitigation rules is much more significant now than ever before in the history of the PJM capacity market as a result of the fact that demand resources are included in the reserve margin for the first time ever in the 2025/2026 delivery year,” the Monitor said. “The PJM capacity market would have been short of meeting the reliability requirement in the [Base Residual Auction] for 2025/2026 but for these demand resources.”

The behavioral commitments would ensure competitive behavior on behalf of NRG and be applied uniquely to the firm’s portfolio of emergency and pre-emergency demand resources. The Monitor said the conditions were warranted because of their “extreme increase in concentration.”

The IMM listed nine commitments in its filing that NRG should follow to ensure its bids are competitive even with the higher market power once the deal closes.

    • All resources should develop cost-based offers using a fuel-cost policy that passes the IMM’s review and are limited to just $1/MWh of markup.
    • All resources should be required to refrain from using crossing price and cost-based energy market offer curves to ensure no price-based offers with high markups will be dispatched by PJM.
    • All operating parameters should be based on physical limits as defined in PJM’s tariff.
    • NRG should have to agree to only retire power plants when they become uneconomic, meaning avoided costs are expected to exceed projected revenues.
    • The company should have to bid into the capacity market at prices that do not exceed net avoidable costs to ensure that market offers stay competitive, even if PJM changes its rules.
    • It should have to bid all supply at its full installed capacity of all its cleared unforced capacity megawatts into the day-ahead and real-time markets.
    • NRG should be required to base its energy offers, including the pre-emergency and emergency DR strike price, on the documented cost of dispatch and all its capacity offers on the net avoidable cost of the resources’ participation in DR programs.
    • All emergency and pre-emergency demand resources should be offered in the capacity market following the transaction.
    • NRG should commit to not removing resources from PJM’s markets for co-location deals until final rules are developed by FERC to ensure continued competitive results in the wholesale markets.
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N.J. Mulls PJM Withdrawal amid Energy Shortfall Predictions

Anger over a recent dramatic rate hike and fears of energy shortfalls because of a predicted future rise in demand have prompted New Jersey to look anew at whether the state should consider pulling out of PJM or otherwise reorganize the relationship with the RTO. 

A bill introduced by three Assembly Democrats, A5902, would require the New Jersey Board of Public Utilities to “work in collaboration with other states to explore alternative options to PJM’s capacity auction for securing the capacity necessary for grid reliability.” 

Specifically, the states would study whether they should withdraw from PJM’s Reliability Pricing Model and develop a multistate compact to engage in the fixed resource requirement (FRR) alternative to secure electric capacity through contracts with private entities, competitive capacity auctions or some combination. 

The group also would look at whether they should “withdraw from the regional, high-voltage electric transmission grid operated or managed by PJM Interconnection.” And the group would look at the merits of creating an independent electric transmission grid or joining “an existing electric transmission grid that operates within another state or region.” 

In an unrelated move, the BPU has organized a technical conference Aug. 5 to focus on “concerns over resource adequacy.” Among the conference goals is to “evaluate alternatives to the PJM capacity market” and to “identify potential paths forward in achieving long-term resource adequacy within the state of New Jersey.”  

Protecting Ratepayers

The two initiatives spotlight a concern New Jersey has voiced or studied several times in the past decade: that it does not get the energy quantity or quality — mainly enough clean energy — it wants from its partnership with PJM. Past efforts have not resulted in significant changes, but this time the severity of the situation — dramatic electricity rate hikes and a potential future power shortage — could have an impact. 

Assemblyman Robert Karabinchak (D), a bill co-sponsor, said in a release announcing the bill’s introduction that it will “start the tough but necessary conversation about PJM’s future.” 

The RTO has “for far too long” operated in a way that “ignores the needs of the states in our region and saddles our residents with higher utility bills,” he said. “Their inability to adapt has become harmful to families and businesses across the Northeast, and it’s time we push for a system that works for us.” 

Assemblywoman Lisa Swain (D), in the same release, said it is “time we explore our options to find an energy partner that is better aligned to serve our communities.” 

“We have heard from our constituents, and we are committed to finding the most effective solution, whether or not PJM is a part of it,” she said. 

But PJM dismissed the suggestion that New Jersey would be better off if it departed from PJM. 

“New Jersey needs new electricity supply; a ‘leave PJM’ bill is not going to solve that problem,” said Jeff Shields, a spokesman for PJM. “Actually, it will make the investment climate for new supply in New Jersey far worse by creating uncertainty for private developers seeking to earn a return on their investments in New Jersey through PJM’s markets.” 

He rejected the suggestion that PJM is at fault for the rate hike, calling it a “red herring.” PJM has reformed its interconnection process and has approved 46,000 MW worth of power projects that are not getting built “due to industry challenges that have nothing to do with PJM,” Shields said. “Of these, about 1,500 MW are in New Jersey, and another 1,800 MW are in the transition queue,” he said. 

“Even if you get both of these categories to build out in full, New Jersey is still very short of creating a balanced supply portfolio,” Shields said. 

Past Studies

The legislation follows a similar study launched in March 2020 by the BPU after FERC expanded its minimum offer price rule (MOPR) to include “all resources receiving state support,” which effectively made clean energy resources more expensive in the auction, according to the order setting up the study. New Jersey considered the move a “direct attack” on the state’s clean energy programs and feared it might disrupt state efforts “to shape its electric generation” and hinder clean energy development in favor of fossil fuel generation. (See FERC Extends PJM MOPR to State Subsidies.) 

The BPU study was conceived to look at whether New Jersey could achieve its clean energy objectives “under the current resource adequacy paradigm” at PJM. If not, the order said, the study should “recommend how best to meet New Jersey’s resource adequacy needs.” 

The BPU updated that report in 2022. But friction with PJM had erupted before: Then-BPU President Joseph Fiordaliso in 2018 threatened to pull the state out of PJM over frustration at a lack of coordination between the RTO and member states.  

The recent proposals were triggered by the events that led to the 20% increase in the average electricity bill on June 1, levels that were set by the state’s basic generation services (BGS) auction in February. State officials say the hike was shaped by PJM’s capacity auction in July 2024, in which prices were 10 times higher than in the previous auction.  

PJM says the sudden hike stemmed in large part from an unforeseeable rise in demand — mainly due to heavy energy-using data centers — and a looming energy shortfall, as the rapid closure of old fossil-fuel generators outpaces the much slower introduction of new clean energy facilities. 

New Jersey officials, however, say the PJM capacity auction was flawed, with prices driven up by an inaccurate count of the impact of new clean energy sources. New Jersey Gov. Phil Murphy (D) has asked FERC to investigate “potential market manipulations” in the PJM Base Residual Auction (BRA). (See N.J. Gov. Urges FERC to Investigate PJM; Christie and Phillips Defend PJM.) 

BPU President Christine Guhl-Sadovy, in a written statement to FERC on May 28, as the agency prepared to hold a June hearing on the issues, said states like New Jersey “must be allowed to play a significantly greater role in ensuring resource adequacy at the lowest cost to ratepayers than is currently allowed by PJM.”  

“This includes being free to procure some or all of states’ capacity needs outside of PJM’s Reliability Pricing Model, commonly referred to as the PJM capacity market,” she said. Guhl-Sadovy also called for “significant reforms to PJM governance” to give states a greater role in resource adequacy planning. 

Starting Anew

Yet the previous study, completed by BPU staff and the Brattle Group, showed that changing the status quo would be far from simple. An unrelated study also concluded it could be expensive. 

“Incorporating New Jersey’s clean energy goals in the regional market is the most efficient way to provide New Jersey consumers with reliable, affordable and carbon-free electricity,” the Brattle report concluded, saying it would be “premature to consider leaving the regional market structure.” 

Project researchers studied several “resource adequacy alternatives that involved leaving the regional market and adopting a New Jersey-centric resource adequacy model under the fixed resource requirement alternative,” the report said. Under such a plan, New Jersey — and perhaps other states — would set up their own capacity auction, for developers to commit to developing future capacity, while remaining inside PJM for the energy market. 

But the report concluded the state should wait while “important market reforms are being considered at the regional and federal level that could facilitate the rapid decarbonization of the electricity sector.” The report found that customer costs under MOPR were the highest, but if it were removed, customer costs under the existing system would be cheaper than other options studied. 

However, the report also said that “New Jersey should continue to explore the option to implement a New Jersey or multistate ICCM [integrated clean capacity market] under the FRR structure.”  

The 2022 update report, largely echoing the previous report, said New Jersey could meet its “clean energy targets at substantially lower costs by participating in a regional clean energy ‘buying pool,’ such as an ICCM, to purchase clean energy attributes.” 

Development Costs

The BPU eventually did not pursue any of the discussed changes, in part because PJM largely dropped the MOPR, removing the state’s main concern. In addition, the election of President Biden created a more friendly environment to renewable energy. 

Observers of the situation said one difficulty with New Jersey departing PJM would be the sheer logistics of setting up a new system, coupled with coordination issues associated with adding other states to the mix that would be needed to make the venture viable. Another challenge would be attracting energy suppliers in an environment in which energy supply is expected to be scarce, putting New Jersey’s venture in competition with PJM’s own auction. 

Furthermore, the cost of setting up the system could be hefty. A report by the Independent Market Monitor for PJM, titled “Potential Impacts of the Creation of New Jersey FRRs” and released in May 2020, concluded that net load charges for an FRR that covered all of New Jersey would cost between $32 million and $386.4 million, depending on the way it was calculated. 

The monitor also questioned the efficiency of such a system. 

“Creation of an FRR creates market power for the small number of local generation owners from whom generation must be purchased in order to meet the reliability requirements of the FRR entities,” the report concluded, emphasizing that it is a “non-market approach” that excludes competition. “In the FRR approach, there is no PJM market monitoring of offer behavior by generation owners, there are no market rules governing offers, and there are no market rules requiring competitive behavior.” 

Given the challenges, the suggestion that the state could leave PJM may be more of a negotiating strategy. 

Alex Ambrose, a researcher for New Jersey Policy Perspective, a liberal-leaning think tank, said the main impact of the bill may be to refocus PJM. 

“What would happen with this bill is that then BPU would study it,” she said. “PJM will feel that pressure and New Jersey gains some leverage, and PJM implements the reforms that we want,” such as improved governance and greater transparency in the RTO’s decision-making, she said.  

Another possibility is that the BPU concludes that the state is better off leaving PJM, she said. 

“What will end up coming out of this bill is better governance, more supply and better market rules for New Jersey,” she said. 

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Trump Executive Order Targets Renewable Energy Tax Credits

President Donald Trump issued an executive order July 7 targeting renewable energy tax credits as strongly as possible under the One Big Beautiful Bill Act. 

The law accelerates to 2026 the phaseout of the large tax credits created by the Inflation Reduction Act of 2022 in line with Trump’s strong opposition to renewables and support for fossil fuel. He signed it at a July 4 ceremony. (See related story, Trump Signs Big Beautiful Bill into Law on Independence Day.) 

The order, “Ending Market Distorting Subsidies for Unreliable, Foreign-controlled Energy Sources,” directs Treasury Secretary Scott Bessent to determine and then take all actions needed to terminate 45Y and 48E clean energy production and tax credits for wind and solar facilities. 

The OBBBA specifies construction start dates and safe-harbor provisions for the remaining period of eligibility for these tax credits, and Trump’s order directs that these rules not be circumvented by eligibility manipulation. 

Trump also directed prompt implementation of the bill’s enhanced restrictions on foreign entities of concern. And he directed Interior Secretary Doug Burgum to look for and eliminate any codified forms of preferential treatment for wind and solar over dispatchable energy sources. 

The reasons stated in a White House fact sheet are familiar speaking points for Trump and some of his Republican allies: 

    • Wind and solar are unreliable, denigrate the natural beauty of the American landscape and displace dispatchable energy, compromising the grid.
    • Reliance on green subsidies threatens national security by making the U.S. dependent on supply chains controlled by foreign adversaries. 
    • Ending these massive taxpayer subsidies is vital to energy dominance, national security, economic growth and the fiscal health of the country. 

Trump specifies that his order be implemented consistent with applicable laws. However, there may be some room for interpretation of the energy-related provisions of the 870-page OBBBA. 

Investment analysis firm Jefferies in a note to clients earlier July 7 said the House Freedom Caucus sought a strict interpretation by the administration of the “beginning of construction” provisions during negotiations as a condition for support. It said the concern now is whether the Trump administration will attempt to “change the goal posts” for these safe harbor provisions. 

The order directs the Interior and Treasury departments to report back within 45 days on their findings and the actions they have taken or planned. 

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NYISO Management Committee Briefs: June 30, 2025

The NYISO Management Committee passed two motions at its brief June 30 meeting, unanimously recommending that the Board of Directors approve them.

The committee recommended revisions to the ISO’s Joint Operating Agreement with PJM for the upcoming activation of a phase angle regulator at a new 345-kV Dover substation for approval. The project is part of the AC Transmission Segment B public policy transmission project, which is intended to reduce congestion between the Capital District and downstate. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The committee also passed revisions to the NYISO tariff to implement transmission owners’ right of first refusal over upgrades in the reliability and economic planning processes. (See “Committees Approve Updates to ROFR Implementation,” NYISO BIC & OC Briefs: Week of June 16, 2025.)

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DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030

The U.S. Department of Energy released a report July 7 saying that retirements and delays in new firm capacity “will lead to a surge in power outages and a growing mismatch between electricity demand and supply,” especially from growth driven by data centers. 

The Report on Evaluating U.S. Grid Reliability and Security responds to President Trump’s executive order from April, which DOE used to keep open power plants in MISO and PJM that were set to retire in May. Trump’s order directed DOE to come up with a uniform method of studying resource adequacy. (See Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies.) 

“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. “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. 

The report argues that “absent decisive intervention,” the grid will be unable to meet projected demand for manufacturing, re-industrialization and data centers, which make adversary nations control the future development of artificial intelligence, thus jeopardizing economic and national security. 

The status quo of additional generator retirements and “less dependable replacement generation” is not consistent with winning the AI race or maintaining reliability, the report said. “Absent intervention, it is impossible for the nation’s bulk power system to meet the AI growth requirements while maintaining a reliable power grid and keeping energy costs low for our citizens.” 

The report estimates an additional 104 GW are set for retirement by 2030, which is planned to be replaced by 209 GW, though only 22 GW of that is from “baseload sources.” Retirements and load growth combined could lead to 100 times greater risk in power outages by the end of the decade, the report said. 

“Antiquated approaches to evaluating resource adequacy do not sufficiently account for the realities of planning and operating modern power grids,” the report said. “At a minimum, modern methods of evaluating resource adequacy need to incorporate frequency, magnitude and duration of power outages; move beyond exclusively analyzing peak load time periods; and develop integrated models to enable proper analysis of increasing reliance on neighboring grids.” 

The report said it used a model based on NERC’s Interregional Transfer Capability Study, which uses time-correlated generation and outages based on historical data. It looked at a range of projections for data center demand by 2030 from major projects and picked a midpoint of 50 GW, allocating it regionally based on a forecast from Standard & Poor’s. 

The report includes several models, including one with the 104 GW of retirements that are in line with NERC and Energy Information Administration projections, another without power plant closures and a scenario with replacement capacity. 

The only regions that did not fail to meet reliability thresholds in the power plant retirement category were ISO-NE and NYISO, which are not expected to see additional data center growth. But every other region saw higher risks of outages in the closed power plant case. Even if all the power plants were to stay open, the report still found shortfalls in PJM, SPP and the Southeastern Electric Reliability Council. 

The report found that at least 23 GW of new “perfect capacity” is needed to meet future demand, especially in ERCOT and PJM (particularly in Virginia and Maryland). 

The report calculates unserved energy (USE) for different regions of the country based on its forecast supply and demand and found troublingly high levels of the metric in some regions for 2030. 

“It should be noted that USE is not an indication that reliability coordinators would allow this level of load growth to jeopardize the reliability of the system,” the report said. “Rather, it represents the unrealizable AI and data center load growth under the given assumptions for generator build outs by 2030, generator retirements by 2030, reserve requirements and potential load growth. These numbers are used as indicators to determine where it may be beneficial to encourage increased generation and transmission capacity to meet an expected need.” 

The report does not use common probabilistic measurements of resource, such as expected unserved energy (EUE) or loss of load expectation (LOLE), instead using deterministic equivalents. 

The report was released midafternoon July 7, so most people had limited time to review it. Advanced Energy United Managing Director Caitlin Marquis said it appears to exaggerate the risk of blackouts and undervalues the reliability contributions of wind, solar and battery storage. 

“We are working quickly to dig into the numbers to unpack how DOE reached its conclusions, 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,” Marquis said in a statement. “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.” 

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NYISO Proposes ICAP Changes for New Entry Ahead of CHPE

NYISO on July 2 released its proposed changes to certain capacity market parameters to accommodate the Champlain Hudson Power Express transmission project, as well as facilitate the new entry of resources.

The changes, presented to the Installed Capacity Working Group, would see NYISO developing two sets of market parameters for capability years where “triggering resources” did not enter the market by May, the first month of the ISO’s capability year.

This would mean that NYISO would use an alternative set of market parameters as the foundation of the market until the resource begins participating. The ISO would run two installed reserve margin (IRM) studies: one assuming the new resource (in this case CHPE) is in service, and one assuming it is not. This would create two sets of transmission security limit (TSL) floors, locational capacity requirements, capacity accreditation factors, system translation factors, unforced capacity demand curve parameters and load-serving entity minimum capacity requirements.

CHPE is a 1,250-MW HVDC line that will run between Quebec and New York City and is expected to go into service in 2026 — but the exact date is unknown. NYISO is keeping an eye on its progress, but it is worried it will be mistimed with the beginning of the capability year. Most of the ICAP market is predicated on annual inputs, with limited seasonality. CHPE’s entry would have major implications for the reliability parameters in the New York City zone.

While NYISO does not anticipate CHPE to shift the IRM, it does anticipate the TSL floor to increase by about 4%, which would impact “downstream” parameters.

NYISO is also proposing that notice requirements for new capacity resources be changed so they must achieve commercial operation prior to notifying the ISO that they intend to participate in the market. The ISO must receive the notification by the first business day of the month before the month the resource wants to qualify for participation. This would only apply to resources whose entry would change contingencies evaluating the transfer capability into a zone.

Stakeholders questioned the rigidity of the timing NYISO laid out, saying that it could possibly create a situation where the market parameters were acting under the assumption that a new resource was not participating when it was.

“If commercial operations start during the middle of June, that means that the resource wouldn’t be able to provide capacity until September,” one stakeholder said. “I’m having trouble understanding why you think this is an improvement.”

There was also some back and forth with Zach Smith, senior manager of capacity and resource integration for NYISO, about why changing the ICAP market parameters could not be moved more swiftly. Smith said that he would look into whether it was possible to increase the flexibility of the proposal.

Another stakeholder asked NYISO to make the forecasted commercial operation dates of resources like CHPE available to the market so they could plan for the shift in market parameters.

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IESO to Expand Synchrophasor Data Requirements to Storage

IESO proposes to update its synchrophasor data requirements to include storage resources as part of its effort to expand the use of phasor measurement units (PMUs) in Ontario. 

Storage units rated at least 20 MVA, including aggregations, would be required to provide their voltage and current phasor measurements and frequency for all three phases. The same requirement would apply to units that are associated with or have the potential to impact a NERC interconnection reliability operating limit, regardless of size. 

The data required would be the same as those provided by generators and transmission owners, but the ISO also proposes doubling the reporting rate — 60 samples per second — for all resources. Storage units also would need to provide phasor measurements for each phase sequence, unlike generation and transmission, which must provide data for only the positive sequence. 

The number of PMUs grew exponentially in North America after the 2003 Northeast blackout. The American Recovery and Reinvestment Act of 2009 (the so-called “stimulus package”) provided $4.5 billion for grid operators to deploy smart grid technologies, including PMUs. Utilities and RTOs installed more than 1,000 production-grade PMUs over the following five years. 

But Ontario has lagged behind the U.S. The IESO proposal is part of a larger initiative to increase PMU usage throughout the province to more than 200. The requirements for generation and transmission went into effect at the end of 2024. 

“This project will enable us to finally begin closing the gap between what our neighbors have been doing for some years before us and also adopt some new applications for our control room folks,” Dame Jankuloski, IESO’s lead power system engineer, said during a webinar June 26 to present the proposal. 

Feedback on the proposal is due July 10, with the goal of Technical Panel approval by the end of the year and PMU registration beginning in early 2026. 

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Behind-the-meter Solar Shines in ISO-NE Capacity Deficiency Event

Amid the rapid growth of behind-the-meter (BTM) solar in New England, a capacity deficiency event demonstrated the significant benefits of solar resources, along with their limits in displacing fossil resources during peak load periods.

On June 24, extreme heat and humidity caused ISO-NE peak demand to surpass 26,000 MW at about 7 p.m., marking the region’s highest peak load since summer 2013. (See Extreme Heat Triggers Capacity Deficiency in New England.)

Without the contributions of BTM solar, ISO-NE estimates the peak would have reached over 28,400 MW at about 3:40 p.m. The 2,400-MW reduction in the region’s peak provided significant cost and reliability benefits to the grid. According to an analysis by the Acadia Center, “BTM solar avoided as much as roughly $19.4 million in costs on this single day by suppressing the overall price of wholesale electricity.”

In recent years, New England has seen annual additions of about 700 MW of BTM solar capacity, largely driven by state policy in Massachusetts and Connecticut. This has helped prevent load growth, pushed peaks later in the day and contributed to a growing duck curve and evening ramping requirements in the region. (See Growth of BTM Solar Drives Record-low Demand in ISO-NE.)

While BTM solar made a significant contribution to lowering the peak load, fossil resources continue to dominate the generation mix during the peak hour. ISO-NE estimates that carbon-emitting generation “provided about 74% of total energy consumed in the region during the peak” on June 24, including over 12,000 MW of natural gas generation, over 3,000 MW of oil generation and about 300 MW of coal generation.

The region’s reliance on fossil generation to keep the grid running was not without challenges — outages of large fossil units appear to have played a major role in triggering the deficiency event. Natural gas generation declined by about 1,000 MW immediately prior to ISO-NE’s declaration of a capacity deficiency, and the RTO estimates there were about 2,550 MW of generator outages and reductions at the time of the declaration.

The performance of BTM solar, coupled with fossil unit outages, has drawn attention from solar advocates. At a Massachusetts legislative hearing on June 25, several representatives of solar companies pointed to the benefits of solar during the deficiency when arguing against a proposal from Gov. Maura Healey (D) to reduce net metering compensation for new large solar facilities. (See Mass. Gov. Healey Introduces Energy Affordability Bill.)

“Solar … is the reason we didn’t have backouts and we didn’t have even higher prices and even higher emissions over the last few days,” said Jessica Robertson of New Leaf Energy.

However, incremental standalone solar capacity likely will have diminishing effects on peak loads in the coming years, as BTM solar has pushed peak periods into the evening, when solar production declines rapidly. ISO-NE’s 2025 Capacity, Energy, Loads and Transmission report estimates that increasing BTM solar will reduce the region’s gross summer peak by only an additional 144 MW by 2034.

In the wake of the capacity deficiency event, clean energy advocates made the case that increased energy storage capacity would have provided significant benefits during the peak.

“Had we had even more behind-the-meter solar paired with storage online, we could have potentially completely avoided that absurd price spike later in the evening,” said Kyle Murray of the Acadia Center at the June 25 hearing.

The Acadia Center wrote in its analysis of the event that there is “clear evidence that additional BTM battery energy storage would have been able to further reduce the overall cost to consumers by increasing flexibility and shifting the solar production later in the day, dampening the early evening peak prices.”

Consulting firm Power Advisory estimated that 1,000 MW of battery storage capacity could have reduced real-time LMPs by an average of over $100/MWh during the event, saving up to $17/kW. The firm also estimated that offshore wind would have reduced LMPs by $47/MWh, assuming a capacity factor of nearly 50% based on prevailing wind speeds.

While battery storage is in its infancy in the region, it is poised to grow quickly in the coming years, which would help to balance the production profile of storage. About 1,800 MW of energy storage cleared in ISO-NE’s capacity auction for the 2027/28 capacity commitment period, including 700 MW of new storage. Storage resources also account for 45% of the active projects in ISO-NE’s interconnection queue, totaling 18.4 GW in capacity.

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Texas Supreme Court Dismisses Bulk of Winter Storm Uri Claims

The Texas Supreme Court has ruled against residents and businesses who sued utilities after the deadly February 2021 winter storm known as Uri, saying they did not adequately prove the companies were intentionally negligent in causing widespread power blackouts.

In a June 27 order, the high court ruled the plaintiffs did not provide enough evidence to show Oncor, CenterPoint Energy and AEP Texas were “purposely negligent” or caused a nuisance when they were ordered to cut power as ERCOT struggled to meet overwhelming demand following Winter Storm Uri (24-0424).

Writing for the court’s unanimous decision, Justice Debra Lehrmann dismissed the claims of intentional nuisance, saying the plaintiffs did not allege sufficient facts to survive a motion to dismiss. She held that the plaintiffs, “as a matter of law, cannot allege” that the utilities “created” or “maintained” a nuisance.

“The alleged ‘nuisance’ here is prolonged freezing temperatures during Winter Storm Uri,” Lehrmann wrote. “The allegations do not suggest that the utilities created or exacerbated the cold temperatures or affirmatively maintained them. Rather, the plaintiffs complain that the utilities failed to adequately respond to and mitigate the harm caused by those temperatures. That is not a basis for an intentional-nuisance claim.”

Lehrmann also held that the plaintiffs’ arguments “do not sufficiently allege gross negligence.” However, she wrote they should “have an opportunity to replead the gross-negligence claims.”

The court ordered the Harris County multidistrict litigation (MDL) court to dismiss the intentional-nuisance claims with prejudice and to provide the plaintiffs an opportunity to replead their gross-negligence claims in an amended petition.

Thousands of customers filed hundreds of lawsuits against electricity companies in the wake of Uri’s outages, which lasted up to 80 hours for some Texans. The cases, alleging negligence, gross negligence, nuisance and other claims, were consolidated into an MDL proceeding.

The storm’s freezing temperatures knocked more than 34 GW of generation offline, bringing the Texas Interconnection within minutes of total collapse. The ensuing outages caused billions of dollars in damages, bankrupted electric companies and killed hundreds of Texans.

The 14th Court of Appeals dismissed the negligence and strict-liability nuisance claims but allowed the gross negligence and intentional nuisance claims to proceed. The Texas Supreme Court heard arguments on appeal in February. (See Texas Supremes Hear Arguments in Last Uri Case.)

Oncor spokesperson Roxana Rubio said the company was pleased with the ruling in that it barred plaintiffs from pursuing six of the seven original causes of action alleged against it. She said the utility is confident the case will “ultimately be fully dismissed should the plaintiffs attempt to pursue an allegation of gross negligence under the strict limitations of this ruling.”

“We continue to maintain that every action Oncor took during Winter Storm Uri was for the purpose of successfully preventing the collapse of the Texas grid,” Rubio said in an email. “We recognize this does not lessen the anguish experienced by our customers and by Texans across the state during that time.”

CenterPoint said it takes seriously “the privilege it has of providing safe and reliable electric service to its customers and communities.” It said it implemented ERCOT’s load-shed orders and “acted quickly to save the electric grid when demand exceeded supply.”

“CenterPoint is confident that plaintiffs will be unable to support any claim for gross negligence,” the utility said in a statement. “If plaintiffs replead, CenterPoint will continue to vigorously defend against plaintiffs’ remaining claim in the trial and appellate courts.”

AEP Texas declined to comment.