Search
December 16, 2025

Posted on

NEPGA Seeks Relief for ‘Improper’ Pay-for-Performance Costs in ISO-NE

The New England Power Generators Association (NEPGA) is seeking immediate action from FERC to address what it calls “serious flaws” in the design of ISO-NE’s Pay-for-Performance (PFP) mechanism, which the group says caused capacity resources to face $51 million in “improper charges” incurred during a capacity shortfall event June 24. 

In a complaint filed with FERC in late June, NEPGA wrote that resources with capacity supply obligations (CSOs) were required to provide power above their obligations and that capacity resources that performed during the event were charged millions to make up for the under-collection of penalties on resources that failed to perform (EL25-106). 

The association argued that imposing expensive PFP charges on resources that fulfill their capacity supply obligations undermines performance incentives and could dissuade resources from participating in future capacity auctions. 

ISO-NE’s PFP mechanism is intended to incentivize resource performance during capacity shortfall events. Resources that provide more than their CSO receive PFP credits, while resources that receive less than their obligation face PFP charges. Resources that lack CSOs can also receive payments by providing power during shortfall events.  

The system is intended to insulate ratepayers from the direct effects of charges and credits, with the charges for under-performers directly correlating with the payments to over-performers. To prevent resources from facing excessive penalties due to an outage, the PFP mechanism includes stop-loss provisions capping the total cost of penalties a capacity resource can incur each month. 

ISO-NE’s PFP rules have undergone multiple changes in recent years, and on June 1, the RTO increased the PFP rate from $5,455/MWh to $9,337/MW-hour. 

NEPGA wrote in its complaint that the PFP balancing ratio — which sets the portion of each CSO that resources are required to meet in an event — surpassed 1.0 on June 24 due to higher-than-expected load that exceeded the amount of obligated capacity. (See Extreme Heat Triggers Capacity Deficiency in New England.) 

The association noted that the balancing ratio averaged 1.031 over the three-hour emergency period June 24. NEPGA said this rate would have cost a perfectly performing 500-MW resource nearly $500,000 over the three-hour period and estimated the elevated balancing ratio “caused $25 million in improper charges to capacity resources” during the event. 

“Even suppliers that had delivered 100% of their promised supply obligation now faced charges under ISO-NE’s rules and a large number of resources reached their monthly stop-limit,” NEPGA wrote.  

Quoting from the movie “This Is Spinal Tap,” NEPGA stressed that “generators cannot give 110%. It is as certain as amplifiers not being capable of ‘one louder’ even if ‘these go to 11.’”

NEPGA also wrote that the RTO’s stop-loss rules led to the significant under-collection of PFP payments, which was charged to capacity resources which had not hit the stop-loss limit.  

“Capacity resources that did not reach their monthly stop-loss limit were charged an additional $26 million to make up the negative net surplus of capacity performance payments,” NEPGA said. It noted the PFP balancing fund also included $9 million in excess revenue caused by reserve shortages, which partly offset the under-collection of charges, reducing the balancing fund’s deficit to $17 million. 

When accounting for the offsetting costs, “the ISO-NE tariff charged capacity resources — including fully performing capacity resources — to recover this $42 million to provide maximum $9,337/MWh bonuses to resources performing above their capacity supply obligation,” the association wrote.  

‘Careful Evaluation’

To address the issue, NEPGA proposed to “cap the balancing ratio at 1.0 and split the bonus pool that gets collected to pay over-performers, with no post-hoc secondary charges imposed on capacity supply obligation holders to make up for any under-collection.” 

NEPGA wrote that these changes would mirror the PFP rules at PJM and noted that FERC in 2015 required PJM to impose a cap on its balancing ratio. 

The proposed changes would “adjust bonus payments to performing resources while still sending very strong financial incentives to perform during emergencies,” NEPGA wrote, adding that the changes would “ensure that the capacity market sends incentives to take on a capacity supply obligation.”  

NEPGA requested that FERC “set an immediate refund effective date” on the date of the complaint, noting that similar issues could occur before the end of the summer.  

In a filed response to NEPGA’s complaint, ISO-NE opposed NEPGA’s request for fast-track processing of the complaint, arguing the association failed to justify the need for immediate action. The RTO wrote that the complaint raises “complex questions” about the design of the PFP mechanism that are not well suited for fast-track processing. 

The RTO did not substantively comment on NEPGA’s proposed remedies, but wrote it is “misleading” to say the issues could be easily and quickly resolved by the proposed changes. 

“PJM’s version of pay-for-performance differs from New England’s version in important ways,” ISO-NE wrote, noting that PJM uses separate PFP rates for payments and charges, while ISO-NE uses a single rate. 

“A single performance payment rate that provides the same marginal incentive to perform is central to [ISO-NE’s] two-settlement, pay-for-performance market design,” ISO-NE wrote. “Transitioning to separate payment rates requires careful evaluation to ensure that it does not produce gaming opportunities.” 

ISO-NE also asked FERC to extend the deadline for responses to the complaint from Aug. 14 to Aug. 21, which the commission granted Aug. 5. The RTO said the extension is necessary to “provide the commission with a clearer indication of the full range of issues that are implicated.” 

Posted on

Duke Highlights Legislative Wins in Q2 Earnings Call

Duke Energy reported earnings of $1.25/share for the second quarter, and CEO Harry Sideris told analysts Aug. 5 the company also came out ahead with state and federal legislation.

With Republicans in control of both houses, the North Carolina legislature overrode a veto from Gov. Josh Stein (D) on July 29 and made the Power Bill Reduction Act (SB266) law, which cuts the state’s greenhouse gas emission-reduction commitments.

“As we ramp up generation investments to meet accelerating load growth, this legislation allows for annual recovery of financing costs for new baseload generation, supporting our credit profile and minimizing costs to customers,” Sideris said.

Stein’s veto statement argued that the bill would lead to higher costs for customers, as Duke and other load-serving entities have to burn more expensive fuel to generate power in the coming decades.

“Recent independent analysis of Senate Bill 266 shows that this bill could cost North Carolina ratepayers up to $23 billion through 2050 due to higher fuel costs,” Stein said. “This bill not only makes everyone’s utility bills more expensive, but it also shifts the cost of electricity from large industrial users onto the backs of regular people — families will pay more so that industry pays less. Additionally, this bill walks back our state’s commitment to reduce carbon emissions, sending the wrong signal to businesses that want to be a part of our clean energy economy.”

The law eliminates a requirement for Duke and other generators to cut emissions by 70% from 2005 levels by 2030. Sideris highlighted language that authorizes Duke to recover generation investments using construction work in progress (CWIP) adders, meaning it can collect money from ratepayers when plants are being built.

But Sideris said the law will make the state more attractive for growth and help Duke meet the higher demand that comes with new customers, including new data center investment of $10 billion by Amazon Web Services.

“It gives us some credit help with CWIP being able to recover annually,” he added. “But … our plan is still along the same lines as the all-of-the-above [approach] that we filed in the multiple [requests for proposals] that we’ve done. We’ll be … really looking at all resources that can support the growth that we’re seeing in North Carolina, and this bill just helps us manage that but also manage the customer affordability portion.”

On the company’s previous earnings call, Sideris was critical of a draft of the One Big Beautiful Bill Act that would have stripped tax credits for nuclear plants, but that language did not make it into the final law. (See Budget Bills Would End Energy Tax Credits Early, Claw Back Other Funding.)

“On the federal side, the preservation of nuclear production tax credits in the final budget reconciliation bill was a significant win for our customers,” Sideris said. “Only well-run, cost-efficient reactors are eligible to receive the credit. Our 11-GW nuclear fleet is the largest regulated fleet in the nation and earned $500 million of PTCs last year.”

In Ohio, Duke counts the enactment of House Bill 15 as a victory because it eliminates the electric security plans, which had governed utilities there for more than a decade, Sideris said. (See Ohio Governor Signs Utility Law Aimed at Enhancing Competition.)

In Florida, Duke announced a deal with Brookfield Asset Management, which will acquire a 19.7% share of Duke Energy Florida for $6 billion that will support a $4 billion increase in the utility’s five-year capital plan.

Duke is also preparing some regulatory filings that will seek to combine its utilities in the Carolinas, which have maintained some separation since the company bought Progress Energy more than a decade ago. It plans to file requests with FERC and both the North Carolina and South Carolina commissions this month.

In addition to large customers, the Carolinas are seeing demand grow as more people move there, and the company has plans to build 8 GW of new dispatchable supply by 2031 at all of its utilities, including 1 GW of uprates at existing plants and new generators, Sideris said.

“With turbines secured under our framework agreement with GE Vernova and gas supply contracted, we are confident in meeting the in-service timelines we have laid out for these new units,” Sideris said.

While uprates at existing nuclear plants are a firm part of its plan, Sideris said Duke would not commit to building new units until the risks, supply chains and workforces are addressed for both traditional and small modular reactors.

“We’re also going to have to have overrun protection from the federal government or others to be able to protect our customers and our investors from any overruns on these projects,” Sideris said. “And then lastly, we’re going to have to have a means to make sure that we’re protecting the balance sheet as we’re building these facilities. So, until we get those items resolved, we’re still looking at solar, gas, and upgrading and getting everything that we can out of our current assets.”

Posted on

Google Strikes Demand Response Deals with I&M, TVA

Google has reached agreements with Indiana Michigan Power (I&M) and the Tennessee Valley Authority to reduce power use by its data centers during critical periods. 

The company said Aug. 4 that it has been working to bring demand flexibility to its data center fleet but the new demand response agreements are the first time it is targeting machine-learning workloads to accomplish this. 

In a demonstration project with Omaha Public Power District, Google reduced the power demands of its machine-learning workloads during three grid events in 2024. This set the stage for similar efforts in other regions. 

The rise of data centers, with their 24/7 demand for large amounts of electricity, has left the electricity sector and policymakers excited about the lucrative potential they represent and anxious about the challenge of realizing that potential: There appears not to be enough capacity to meet the highest projections of peak demand and no way to add capacity quickly and inexpensively. 

A Duke University study released earlier in 2025 addressed this quandary by looking at the kind of arrangement Google is announcing with the two utilities: temporary curtailment of load. 

As much as 126 GW of new demand could be handled with existing generation, the authors concluded, if data centers cut their energy use by as little as 1% during peak periods. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.) 

Google said it is working to develop this ability to reduce or shift power demand during certain hours and certain times of the year. 

Along with the benefits to the grid and to grid operators, DR has the advantage of speeding up the interconnection process and bridging the gap to long-term clean energy solutions, Google said. 

The company said its first such efforts involved shifting non-urgent computing tasks such as processing videos for YouTube, and it sees significant further opportunity through development of DR for machine-learning workloads. This will let it grow artificial intelligence capabilities even in regions where generation and transmission are constrained, it said. 

Google said demand flexibility will be possible only in certain locations in these early stages and faces a finite potential, given the high level of reliability the company needs for some of its services. It expects DR to be part of a portfolio of solutions that includes new generation and transmission. 

Contract Details

I&M submitted the Google contract to the Indiana Utility Regulatory Commission on July 30 (46276). 

It pertains to Google’s new data center in Fort Wayne and is similar to programs currently available to the utility’s residential and commercial/industrial customers, I&M President Steve Baker said in a news release. Google announced the $2 billion Fort Wayne project in April 2024; I&M energized it seven months later. 

“Google’s ability to leverage load flexibility will be a highly valuable tool to meet their future energy needs,” Baker said. 

It would also help I&M. The utility said that if the IURC approves the contract, “this agreement will reduce I&M’s long-term generation requirements and financial commitments to benefit all I&M customers.” 

In its petition to the IURC, I&M said the contract has two key aspects: a clean capacity agreement by which Google will transfer to I&M long-term accredited capacity from clean energy resources that the utility will use to meet a portion of its state retail capacity obligations as part of its PJM fixed resource requirement plan, and “a custom demand response offering” to reduce I&M’s peak load in times of high demand, thereby reducing the utility’s capacity obligation and transmission requirements to serve its customers.  

Because the clean capacity agreement will be used to meet its load obligation for all Indiana customers, I&M proposes to recover associated costs in the same way it recovers capacity-related purchase costs: through its Resource Adequacy Rider. It also proposes to recover through the rider any demand response credits provided to Google. 

Two days after I&M submitted the petition, the Citizens Action Coalition of Indiana petitioned to intervene, citing the potential impact on rates charged to residential customers and services provided to them. 

Posted on

Home Batteries Provide 535 MW to CAISO Grid on VPP Test Day

An aggregation of more than 100,000 residential batteries provided an average 535 MW of support to California’s electricity grid during a July 29 test to prepare for the hot summer period ahead. 

The sea of home batteries formed a virtual power plant, comprising a group of customer-owned battery storage systems that are typically paired with solar panels. Local utilities, CAISO, the California Energy Commission and other energy companies, such as Sunrun, released charge from the fleet of batteries onto the grid for two hours, from 7 p.m. to 9 p.m. 

The VPP visibly reduced CAISO’s net load during those peak demand hours, said representatives of The Brattle Group, which studied the results of the test. 

“Performance was consistent across the event, without major fluctuations or any attrition,” said Ryan Hledik, a Brattle principal. “Residential batteries — and other sources of distributed flexibility — can serve CAISO’s net peak, reduce the need to invest in new generation capacity, and relieve strain on the system associated with the evening load ramp.” 

Most of the 535 MW would not have been available had the test not been initiated, according to Brattle. 

“On peak days, using VPPs to serve CAISO’s net peak could reduce the need to invest in new generation capacity and/or relieve strain on the system associated with the evening load ramp,” Brattle said, adding that would help address challenges with California’s “duck curve.” 

“Optimized VPP program design and coordination with the system operator could further maximize the value of the battery output to the system,” Brattle noted. 

Pacific Gas and Electric customers made up about 50% of test participants, Southern California Edison about 38%, and San Diego Gas & Electric about 12%. 

Most of the batteries in the test are part of the CEC’s Demand Side Grid Support (DSGS) program, which rewards customers who support the electric grid during extreme events. Rewards include payment for demonstrated capacity at varying monthly rates based on VPP capacity and duration, according to the CEC. 

As of October 2024, the DSGS program had 515 MW of capacity and more than 265,000 participants. The program, which began in 2022, operates from May to October and is intended to help reduce the risk of rotating power outages during peak demand months. In 2024, the DSGS program turned on its VPP system 16 times. 

The test on July 29 was not the first of its kind this summer: On June 24, Sunrun participated in a similar event in which its power resources provided 325 MW to the grid from 7 to 9 p.m, according to Sunrun. Participating Sunrun customers can receive up to $150 per battery per dispatching season, while Sunrun is paid for dispatching the batteries, the company said.

The CEC on Aug. 14 is holding a workshop on the performance of the DSGS program in 2024, specifically on VPP performance. 

Posted on

PSEG Sees Data Centers Surge amid Rising Demand Forecasts

The Public Service Enterprise Group is waiting for New Jersey to address the region’s predicted energy shortage as the utility sees a dramatic rise in potential demand from data centers, said CEO Ralph LaRossa.

Developer inquiries for large load projects seeking new service connections jumped by 47% between March and June to 9,400 MW, LaRossa said Aug. 5 during the company’s second-quarter earnings conference call.

There’s growing concern in New Jersey and in other states that the PJM region is facing a chronic future energy shortage. Rapid demand growth is happening while aging fossil fuel plants are closing faster than new generators, mostly renewable energy, can open.

“The resource adequacy challenges in New Jersey and across the entire 13-state PJM region are becoming more acute,” LaRossa said. “Recent reports reflect an increasing amount of new large load applications that are quickly eroding existing reserve margins. Within the confines of PJM, it’s hard to see the path to new generation through existing market signals, which may require the consideration of a new approach to procuring capacity and resource planning.”

Underscoring the seriousness of the situation, LaRossa said the utility hit a peak load of 10,229 MW during the three-day heat wave in June, the highest level since 2013. New Jersey, a net importer of power, imported about half its energy during the heat wave, LaRossa said. But while the state in the past could rely on energy imports from other PJM members that generate excess power, such as Pennsylvania, that “convenient option is quickly being absorbed by rapid growth of native load in those states,” he said.

Much of the new demand is for large-load projects, mainly data centers used for artificial intelligence and other projects. LaRossa said about 90% of the 9,400 MW in large load projects — which include mature applications, feasibility studies and initial leads — comes from planned data centers. He said he expects 10 to 20% of the total to be completed eventually.

One of the projects included in the large load figure is a data center that AI cloud computing company CoreWeave plans to build on a 107-acre campus in Kenilworth, N.J., LaRossa said. CoreWeave announced on Aug. 4 it has completed the land purchase.

Capacity Auction Concerns

The earnings call was PSEG’s first since PJM completed its capacity auction and announced on July 22 the outcome price of $329.17/MW-day (UCAP) RTO-wide for delivery year 2026/27. The price would have been $388.57/MW-day without a price cap put in place by PJM in agreement with Pennsylvania Gov. Josh Shapiro (D). He filed suit seeking changes in the system after the auction in 2024 raised prices about tenfold to $269.92/MW-day, the result of load growth, generation deactivations and changes to risk modeling that shrank reserve margins. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

The dramatic hike in the last capacity auction triggered widespread concern among officials in New Jersey and other states for its impact on ratepayers. The average electricity bill in New Jersey increased by 20% on June 1.

LaRossa said the company anticipates “a near flat impact on customer electric bills” from the recent auction when it is factored into the state’s Basic Generation Service rates that will take effect June 1, 2026.

In the longer term, one measure that would help the state increase its generating capacity is a bill, A5439, that would allow electric public utilities to own and operate electric generation facilities, LaRossa said.

“In New Jersey, policymakers have begun to actively weigh the priorities of economic growth with system reliability and affordability and the state’s environmental policies,” he said.

PSEG is pushing the state to address some key issues, he said: “What are the forecasts they’re looking for? What are the reliability outcomes they’re targeting? What are the affordability targets they have? And then finally, the environmental policy goals. When you put those four pieces together, we think we’ll be able to find the right answer and solution for the state.”

However, he said PJM’s capacity process, especially its governance, needs reform, echoing concerns expressed by other critics of the RTO.

“We’ve been very vocal about that for many years,” he said. “We don’t think that it is attracting additional generation. … The facts are that there has not been any new base load generation built in New Jersey for quite some time.”

“The governance at PJM doesn’t allow for a lot of the things that people are talking about to just be unilaterally implemented,” he said, citing the example that for state governors to get involved in the process, PJM members must give a vote of approval. “This governance process is the core problem.”

Nuclear Advances

LaRossa said PSEG is taking steps to enhance its nuclear power generation, noting that an enhancement project at the Hope Creek Generating Station nuclear facility operated by the company in Salem, N.J., will add 200 MW. He characterized the enhancement, which is expected to go online between 2027 and 2029, as “the size of a small modular creator of incremental, carbon-free, dispatchable power.”

He said the company also will benefit from the recent federal funding bill, which continued the production tax credits for nuclear facilities and extended depreciation rules that will help PSEG’s nuclear fleet.

PSEG’s second-quarter results for 2025 grew from $434 million ($0.87/share) in 2024 to $585 million ($1.17/share). Non-GAAP operating earnings for the quarter were $384 million ($0.77/share) in Q2 2025, compared with $313 million ($0.63/share) in the same period last year.

Posted on

U.S. Peak Electricity Demand Sets Back-to-back Records

Peak electricity demand in the 48 contiguous states set records twice in the last week of July, reaching 758,053 MW and 759,180 MW over one-hour periods July 28 and 29. 

The U.S. Energy Information Administration announced the developments Aug. 5 and attributed it to a heat wave coming amid the continuing growth of power demand. 

The previous record was 745,020 MW, recorded July 15, 2024. 

There is disagreement about how much and how quickly U.S. electric demand will increase, but there is wide consensus that growth will occur, due to transportation and building electrification, reshoring of manufacturing and rise of energy-intensive artificial intelligence data centers. 

The EIA’s forecast calls for electricity demand to grow by an annual rate of just over 2% in 2025 and 2026. 

This is a marked change from much of the century so far, EIA said, noting that average annual increase in demand was only 0.1% from 2005 to 2020 and just 0.8% between 2020 and 2024. 

The back-to-back demand records at the end of July 2025 came as much of the nation was within a heat dome, subjecting tens of millions of Americans to very high temperatures and causing their air conditioners to consume more electricity. 

Preliminary data from EIA’s Hourly Grid Monitor indicates the new all-time peak, 759,180 MW, was reached about 6 p.m. Eastern time July 29. 

The Grid Monitor indicates that in the 60-minute period: 

    • The highest demand was in the Mid-Atlantic (154,380 MWh), Midwest (129,574 MWh) and Texas (81,572 MWh). 
    • The major energy sources meeting this demand were natural gas (348,891 MWh), coal (133,711 MWh), nuclear (95,287 MWh) and solar (88,389 MWh). 
    • Two other renewables were far behind — hydropower was near its peak output for the day at 39,392 MWh, while wind turbines produced only 25,772 MWh, down 57% from their peak output for the day, reached 16 hours earlier. 
    • The U.S. imported 5,883 MWh from Canada and exported 230 MWh to Mexico. 

Daily demand peaks began to subside after July 29, preliminary data shows, dropping to 631,287 MWh from 6-7 p.m. Aug. 1.  

Over the weekend, the peaks dipped further to 588,925 and 600,233 MWh. They bounced back to 645,449 MWh as the work week began Aug. 4. 

Posted on

MISO Stakeholders Move to Enshrine Conduct Rules in Governance Guide

MISO stakeholders have adopted the spirit of MISO’s new code of conduct into their comprehensive rulebook while adding rules that empower committee chairs to shut down rude behavior or order attendees out of conference rooms.

MISO’s Steering Committee voted to include rules similar to MISO’s code of conduct in the Stakeholder Governance Guide at an Aug. 5 meeting.

A draft version of the guide now provides a “Respectful Conduct in Stakeholder Meetings” section that calls for “a foundation of mutual respect, professionalism, fair debate and dialogue.” It details a zero-tolerance policy for name-calling, sarcastic comments, demeaning remarks, repeated interruptions and disruptive behavior. MISO’s code of conduct, introduced in early July, similarly forbids rude or callous language, deliberate meeting disruptions or disregarding committee chairs’ instructions. (See New MISO Stakeholder Code of Conduct Forbids Rude or Callous Language.)

MISO Reliability Subcommittee Chair Ray McCausland, of Ameren, said while MISO published its own conduct rules, the list to be included in the Stakeholder Governance Guide is written by stakeholders and considered separate from MISO’s. The MISO Code of Conduct is set to be included in an appendix to the Stakeholder Governance Guide.

Steering Committee Chair and ITC’s Brian Drumm said stakeholders can think of the code as a notice to be on their “best behavior.”

The guide’s more detailed language that largely tracks MISO’s code replaces years-old and less specific conduct language that laid out MISO’s grounds for stakeholder removal due to abusive or disruptive behavior. The new insert goes a step further than MISO’s new code and confers responsibility on committee chairs and vice chairs to quell unruly meetings.

The guide says chairs and vice chairs can:

    • Call a meeting participant to order “immediately upon a breach of decorum.”
    • Warn an individual about consequences for continued disruptions.
    • Refuse to recognize a participant “until order is restored.”
    • Order a participant to leave for the remainder of a session.
    • Initiate disciplinary procedures, “which may include formal censure, suspension or removal from the stakeholder group.”

“These rules exist, not to silence disagreement, but to preserve a space where all voices can be heard without hostility or harassment,” the guide’s draft wording concludes.

Market Subcommittee Chair Tom Weeks, of the Michigan Public Power Agency, said while he supports “civil and professional discourse” in meetings, he’s heard concerns from stakeholders that the code and accompanying guide changes could stifle conversation because some stakeholders’ points might be perceived as intimidating. He said while he didn’t oppose the new wording, stakeholders’ concerns are not “overblown.”

“We don’t want to swing the pendulum to the other side where people don’t feel free to make substantive comments,” Weeks said. He asked stakeholders to keep in mind that some stakeholders can deliver comments with more passion and enthusiasm than others.

The revisions concerning conduct were part of a larger batch of edits to MISO’s Stakeholder Governance Guide, which is altered as stakeholders deem necessary. The Steering Committee either adopted suggested edits and sent them along for final review from MISO’s Advisory Committee or determined that certain changes needed more refinement and sent them back to the Stakeholder Governance Working Group, which drafted the changes.

The Steering Committee did not approve another edit to the guide that would have allowed MISO itself to present motions during stakeholder meetings. Some questioned the appropriateness of MISO raising voting motions.

McCausland said the intent of the change was to spell out that MISO could introduce a motion but that a stakeholder is required to move such a motion to the floor for a vote. Some Steering Committee members said the wording wasn’t clear, and the committee ultimately sent the item back to the working group for revision.

Posted on

CISA Releases New Cyber Tools for Defenders

The Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) has released two software tools to help cybersecurity teams detect and respond to attacks against their networks.

CISA announced the releases a day apart, on July 30 and 31. First out was the Eviction Strategies Tool, developed alongside engineering and information technology consultancy MITRE. The agency then revealed Thorium, created with the help of Sandia National Laboratories.

The Eviction Strategies Tool comprises COUN7ER — a database of adversary tactics, techniques and procedures (TTP) matched to appropriate countermeasures — and Playbook-NG, a web application through which cyber defense teams can draw strategies from COUN7ER.

To use the tool, an entity’s cyber staff first input TTPs from MITRE’s ATT&CK matrix or describe threat actor activities. Playbook-NG provides a list of recommended responses, which the user can export for later use. Users can also start with a template created by CISA that describes “specific collections of TTPs … that a cyber defender may use as is or quickly customize.” No information about the users or their inputs is saved.

Jermaine Roebuck, CISA’s associate director for threat hunting, said in a statement that the agency had “seen organizations struggle with identifying the right steps to take and the correct sequencing of actions” to remove cyber intruders from their networks. COUN7ER is meant to serve as “a Rosetta Stone of defensive measures cross-referenced with multiple threat frameworks. CISA will regularly update COUN7ER to account for new incidents and threat intelligence, and it will test countermeasures through internal tabletop exercises.

Thorium provides a platform to integrate multiple forensic analysis tools and index for malware threat information. It is intended to help analysis with the “vast amounts of malware” affecting organizations across the public and private sectors, which currently rely on “a long list of malware analysis tools with specific capabilities” that often were not meant to work together.

According to CISA, the software can process more than 10 million files per hour and schedule over 1,700 jobs per second. The tool provides search and text-tagging functions, access controls and automated tools for scaling and virtualization. Roebuck said the agency hoped by sharing the platform to “empower the broader cybersecurity community to orchestrate the use of advanced tools for malware and forensic analysis.”

Grant Applications Open Through Aug. 15

CISA, along with the Federal Emergency Management Agency, also announced on Aug. 1 the last round of grants for the State and Local Cybersecurity Grant Program (SLCGP) and Tribal Cybersecurity Grant Program (TCGP).

The programs, created by the Infrastructure Investment and Jobs Act of 2021, are intended to support state, local, territorial and tribal governments in reducing cyber risk and building resilience against cybersecurity threats. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.) $91.7 million will be available for state and local governments through the SLCGP, and $12.1 million for tribal governments through the TCGP.

According to the Notice of Funding Opportunity, interested parties must file their applications for either program by Aug. 15. This represents a much shorter window than the last time applications opened in 2024, when applicants had from Sept. 23 to Dec. 3 to submit their requests. (See DHS Offers $280M in Grants for Cyber Investments.)

Candidates must address at least one of four objectives in their submissions:

    • Establish appropriate governance structures to improve cyber response capabilities and ensure continuity of operations;
    • Identify areas for improvement in their current cybersecurity postures;
    • Implement security protections in accordance with the risks they face; and
    • Ensure organization personnel are appropriately trained in cybersecurity.

Awards under SLCGP have a ceiling of $4.2 million and a floor of $256,000; TCGP awards have a $2.7 million ceiling and a $39,000 floor.

“CISA is proud to empower state, local and tribal governments to build more resilient cyber ecosystems,” CISA’s Acting Director Madhu Gottumukkala said in a press release. “This unified DHS approach enables innovative solutions that strengthen digital infrastructure, and helps communities invest in meaningful cybersecurity improvements to protect the critical services they provide. This is another example of investing in our communities while being good stewards of our taxpayer dollars.”

Posted on

Feds Pile on More Barriers to Wind and Solar

The Trump administration has taken further steps to thwart renewable energy development, adding new directives limiting wind and solar development on federal land and at sea. 

Most notably, an Aug. 1 order (SO 3438) from Interior Secretary Doug Burgum prioritizes efficient use of federal land for energy generation — an impossible challenge for sprawling solar and wind farms, which need square miles to generate as much power as a fossil or nuclear plant covering just a few acres. 

In other recent moves, the Department of the Interior’s Bureau of Ocean Energy Management on Aug. 4 rescinded the schedule of seabed leases for offshore wind power development, one of President Donald Trump’s regular targets. 

On July 30, BOEM rescinded designation of all wind energy areas on the outer continental shelf along the East, West and Gulf coasts — more than 3.5 million acres determined to hold the best potential for wind farms. 

A July 29 order (SO 3437) from Burgum ended “preferential treatment” for wind projects and placed new potential hurdles to its development. (See Trump Administration Takes Another Swing at Wind Power.) 

A July 15 internal directive required any and all decisions and actions pertaining to wind and solar at Interior to be reviewed and signed in succession by two high-level deputies and then Burgum himself. (See Interior Dept. Places Solar, Wind Under Close Review.) 

The steady stream of directives is becoming increasingly redundant in their intended effect if not their specified actions. 

There are likely multiple reasons for this, Ted Kelly, lead counsel for U.S. clean energy at the Environmental Defense Fund, told NetZero Insider. If one strategy falls to a court challenge, the others might stand. Also, the administration is very message-oriented: Serial announcements make Interior look good to Trump’s inner circle and make Trump look good to his core constituency, he added. 

The number and tenor of the directives also can create paralyzing uncertainty within the profit-driven private sector. 

“I think we’ve seen it in different areas; they kind of have a dual strategy of, create the uncertainty as much as they can, and then also get to the aggressive attacks when they can,” Kelly said. 

EDF saw this two-track approach with the stop-work order on Empire Wind 1 and revocation of a loan guarantee for the Grain Belt Express transmission line, he added. 

Kelly said EDF is challenging some actions in court, but others are not actionable yet. 

Burgum offered a robust justification with his Aug. 1 order, announcing it as an effort to “Rein in Environmentally Damaging Wind and Solar Projects.” He said the order would better manage federal lands and minimize environmental impact on them: “Gargantuan, unreliable, intermittent energy projects hold America back from achieving U.S. energy dominance while weighing heavily on the American taxpayer and environment.” 

Federal law requires Interior to make judicious decisions about use of federal land and seabed, the news release continued. “These laws ultimately raise the question of whether the use of federal lands for wind and solar projects is permissible, given these projects’ encroachment on other land uses and their disproportionate land requirements, especially when reasonable project alternatives with higher capacity densities are technically and economically feasible.” 

Interior can do only so much to thwart onshore renewables development: It holds sway over public land, but plenty of private land is available. 

Offshore wind energy development, however, is entirely within federal purview, unless the turbines are placed close to shore in state waters — a politically and technically challenging step that has not been proposed. 

On his first day in office, Trump directed a halt to all new offshore wind power leasing and directed an ominous-sounding review of existing leases for potential modification or termination. In the wake of that memorandum, federal permitting reviews and other regulatory work essential to planning an offshore wind farm slowed or halted. 

But notwithstanding the weekslong Empire Wind stop-work order — which actually may have been an attempt to twist the arm of the governor of New York state over natural gas pipeline permitting, rather than a true attempt to stop the wind project — the Trump administration has allowed construction to continue on the five active projects: Coastal Virginia Offshore Wind, Vineyard Wind 1, Revolution Wind, Empire Wind 1 and Sunrise Wind. 

The administration has moved to prevent any steel from being placed in the water on other projects, however, including a revocation of the EPA air permit for Atlantic Shores Offshore Wind and a challenge of the Maryland construction permit for US Wind. 

Wind opponents are suing the federal government (1:2025cv00152 and 1:2024cv03111) for approving construction of US Wind’s Maryland proposals. The government told the U.S. District Court for Delaware on July 28 that it plans to move for a voluntary remand of US Wind’s construction and operations plan. 

If granted, this would send the massive 90-part blueprint approved by the wind-friendly Biden administration back for review by the Trump administration, potentially dooming it. 

Boosting fossil fuel production and sidelining the renewables sector is exactly the turnabout from the Biden years that Trump promised on the campaign trail. 

But it is not good policy, Kelly said, given that major increases in generation capacity are at least five years away for natural gas and 10 for nuclear. 

“There’s the real contradiction and hypocrisy of their insistence, on the one hand, that there’s an energy emergency and that we need to get all generation online as quickly as possible,” he said. “But on the other hand, these clean energy types of projects don’t count as energy, and we’re going to throw up roadblocks in the middle of them, when really they’re the only things, other than some gas plants that are already under construction or under order, we can build in the next five to 10 years.” 

Wind and solar provided 14% of utility-scale generation in the U.S. in 2023 and accounted for 78% of capacity additions in 2024. 

In January 2025, shortly before President Joe Biden left office, the National Renewable Energy Laboratory released an analysis showing federal lands hold the potential for 5,750 GW of utility-scale photovoltaics, 975 GW of geothermal and 875 GW of wind generation. 

Posted on

Calif. Fights to Maintain ZEV Momentum

In the face of federal attacks on California’s landmark zero-emission vehicle regulations, the state is “doubling down” on efforts to spur ZEV adoption. 

The California Air Resources Board (CARB) in July completed a series of four public sessions seeking feedback on ways to encourage ZEV adoption — part of an initiative called ZEV Forward. Input from the sessions will help shape recommendations CARB will send to Gov. Gavin Newsom in August. 

“Across the country, people are looking to California to fill that void that now exists at a federal level,” California Transportation Secretary Toks Omishakin said during a session in Sacramento.  

And CARB on July 24 approved amendments to its Advanced Clean Trucks (ACT) regulation to give truck manufacturers more flexibility in complying with the rules. ACT requires truck makers to deliver for sale in the state an increasing percentage of ZEVs over time. 

ACT is a complement to CARB’s Advanced Clean Cars II regulation, under which car manufacturers must provide an increasing percentage of ZEVs through 2035, when all new cars sold in the state must be zero-emission or plug-in hybrid. 

The federal government is now trying to overturn those regulations. 

But CARB has prepared for challenges to ACT. In July 2023, the agency entered into the Clean Truck Partnership with truck makers, promising to provide more compliance flexibility to manufacturers in exchange for a pledge to comply with the regulations regardless of the outcome of litigation or changes to CARB’s authority to enforce them. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)  

“One of the reasons that we were really interested in this Clean Truck Partnership is to provide both certainty to the state and to manufacturers going forward, where there might be a potential for a change in the federal posture around clean energy and clean technology,” CARB Executive Officer Steven Cliff said during the July board meeting. 

The ACT amendments the board approved July 24 include a pooling provision, in which a manufacturer may transfer surplus ZEV credits generated in one state to another state that has adopted ACT.  

Amendments adopted in October 2024 gave manufacturers three years, rather than one, to make up a ZEV credit deficit from a particular year. The amendments also allow manufacturers to use credits from near-zero-emission trucks to make up part of a deficit. (See Calif. Revises Clean Truck Rules to Ease Compliance.) 

The Waiver Battle

In May, Congress adopted three resolutions to roll back EPA waivers that allowed California to enforce three of its clean vehicle regulations: ACT, ACC II and an omnibus rule that sets emission standards for internal combustion heavy-duty trucks sold in the state. 

On June 12, the day President Trump signed the resolutions, California filed a lawsuit in U.S. District Court calling the overturn of the EPA waivers unlawful.  

To rescind the waivers, Congress used the Congressional Review Act, which was designed for overturning federal rather than state rules, according to the complaint. In addition, the EPA waivers are not rules and thus aren’t subject to the CRA, the lawsuit said. 

In addition to California, plaintiffs include 10 other states: Colorado, Delaware, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington. 

Also on June 12, Gov. Gavin Newsom fired off an executive order “doubling down” on the state’s commitment to clean cars and trucks. 

“We won’t let this illegal action by Trump and Republicans in the pockets of polluters stand in the way of commonsense policy to clean our air, protect the health of our kids and compete on the global stage,” Newsom said in a statement. 

The order directs state agencies, including CARB and the California Energy Commission (CEC), to make recommendations to the governor within 60 days on ways to spur ZEV adoption in the state.  

It also directs CARB to develop an Advanced Clean Cars III regulation “consistent with state and federal law” that would build on existing regulations or provide an alternative if California doesn’t prevail in the court on its regulations. 

Ideas to surface at the July public meetings included offering more incentives and loan programs for ZEV buyers, expanding hydrogen-vehicle infrastructure or offering pooled insurance programs for car share fleet operators. 

Others emphasized the need for approaches that don’t require a federal waiver. 

ZEV Sales Growth

In the second quarter of 2025, 21.6% of new vehicles sold in California were ZEVs, amounting to 100,670 vehicles, the California Energy Commission (CEC) reported. That number is lower than sales in the second quarter of 2024. 

The dip in sales was driven by lower Tesla sales, while non-Tesla ZEV sales remained strong, the CEC said. 

At the national level, EV sales in the first half of 2025 were up 1.5% year-over-year, with 607,089 vehicles sold, according to a report from Cox Automotive’s Kelley Blue Book. Second-quarter figures were down 6.3% year-over-year. 

“With government-backed incentives set to end in September and economic pressures mounting, the second half of the year will be a critical test of EV demand,” Stephanie Valdez Streaty, senior analyst at Cox Automotive, said in a statement. “Q3 will likely be a record, followed by a collapse in Q4, as the electric vehicle market adjusts to its new reality.” 

For medium- and heavy-duty trucks in California, manufacturers sold 131,552 vehicles from model year 2024. Of those, 30,026 were ZEVs, or 22.8%. Cliff provided the figures during CARB’s July board meeting. 

And manufacturers have accumulated about 26,000 more ZEV credits than are needed to comply with ACT, he said. 

Coalition Formed

California is not alone in its ZEV efforts. 

In May, Newsom and governors of 10 other states launched the Affordable Clean Cars Coalition, an initiative organized by the U.S. Climate Alliance. The goal is to make cleaner vehicles more affordable and accessible by reducing costs, increasing options and expanding infrastructure. 

Participants are California, Colorado, Delaware, Maryland, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island and Washington.