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December 21, 2025

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ERCOT’s TAC Extends Duration of Ancillary Services

ERCOT stakeholders have advanced a protocol change that provides longer-duration ancillary services and state-of-charge (SOC) parameters in advance of real-time co-optimization’s deployment in December.

The ERCOT-sponsored protocol change (NPRR1282) updates duration requirements to 30 minutes for regulation service and responsive reserve service and one hour for ERCOT contingency reserve service (ECRS). It also revises reliability unit commitment studies’ requirement to a one-hour duration for all ancillary services, excluding fast frequency response.

Staff told Technical Advisory Committee members that longer-duration AS are needed to manage grid variability and uncertainty. The grid operator, the Independent Market Monitor and stakeholders were split on the appropriate duration for non-spin and ECRS.

Several renewable interests said ERCOT’s RTC dispatch or SOC enforcement requirements will be “unnecessarily and administratively restrictive” of the amount of megawatts energy storage resources can offer.

The IMM recommended setting the non-spin duration constraint to one hour instead of four, saying that would incent batteries to provide energy rather than reserves. It said the four-hour duration also would deplete batteries’ SOC.

“The operations posture we have is the operations posture we have,” said Nitika Mago, senior manager of balancing operations planning. “As things evolve, I’ve conceded again and again we are happy to revisit it. But today, with the way we operate the grid and with the type of risks we see for non-spin, a four-hour duration is appropriate.”

In the end, Mago’s commitment to review information generated during RTC’s market trials, which begin in July, and an analysis of duration in the 2027 AS methodology document won over many stakeholders with concerns.

A motion to approve the NPRR with comments filed by ENGIE and Jupiter Power, and its associated Nodal Operating Guide change (NOGRR277), failed 11-18. When the comments were removed, the measure passed 26-2, with one abstention. ENGIE and Jupiter Power cast the dissenting votes.

The NPRR was granted urgent status so its parameters can be installed for RTC’s market trials.

Members Table Curtailment Change

TAC’s members unanimously agreed to table NPRR1238 and NOGRR265 after a lengthy discussion on their merits. The changes introduce a new early curtailment load (ECL) category and also would establish a process allowing loads to operate as an ECL so they can be accounted for differently in load-shed tables.

The committee will take up the issue again during a special webinar June 12.

ERCOT legal staff recommended tabling the two measures pending the Texas Legislature’s final consideration of Senate Bill 6. The legislation, addressing large loads, was under consideration before the session’s expiration June 2; several parties agreed with the need to align with the legislative process. (See Growing Clean Energy Sector in Texas May Avoid Damaging Legislation.)

Staff said the grid operator generally supported the NPRR but said they had concerns over large-load curtailments before energy emergency alerts.

Stakeholders expressed concerns with mandating loads — primarily industrial — to register as curtailable. NPRR1238 is intended to cover flexible loads sensitive to high prices, not all large loads.

The Public Utility Commission’s Barksdale English agreed with the decision to table the changes, saying it would be “smart” after amendments had been added two days before.

Oncor $855M Project Endorsed

TAC endorsed staff’s recommendation to award Oncor Electric Delivery a $855.3 million project in West Texas by placing it on the combination ballot, which acts as a consent agenda.

Oncor submitted the proposed Delaware Basin Stage 5 project for the Regional Planning Group’s review in May 2024. Wind Energy Transmission Texas (WETT) submitted an alternative project in August 2024.

Staff said Oncor’s proposal addresses reliability concerns and accommodates “significant and rapid load growth” in the petroleum-rich Delaware Basin area and also was less costly and required the least amount of transmission lines requiring regulatory approval. Oncor’s project requires 220 miles of transmission approval, while WETT’s costlier proposal ($871 million) is 232 miles long.

The project was identified in a 2019 ERCOT study that found the need for an import path to serve load once the Basin’s peak demand is greater than 5,422 MW. Staff said the 2023 Regional Transmission Plan’s 2025 case exceeds that level.

The project is expected to be in service by December 2029.

Committee members also confirmed Longhorn Power’s Bob Wittmeyer and ERCOT’s Patrick Gravois as chair and vice chair, respectively, of the Large Load Working Group by adding the recommendation to the combo ballot. The group, which recently removed “Flexible” from its title, has scheduled a workshop July 11 for data centers and electronic loads, with a focus on behind-the-meter systems that can survive low voltage and stay on the grid or resolve low-voltage issues.

Outage Capacity Changes

Stakeholders unanimously approved staff’s revisions to the methodology used to calculate the maximum daily resource planned outage capacity (MDRPOC).

The revisions are intended to provide sufficient outage capacity compared to historical levels by applying a risk-based construct for outages more than seven days ahead. Staff created a new MDRPOC curve to better evaluate thermal resources, and they have incorporated minimum outage levels in winter and summer to spread outages throughout the year.

ERCOT plans to apply the first future year MDRPOC to subsequent future years, saying there is a higher risk of limited resource commitments and project load growth in later years. Renewable resources and storage units will have their MDROPC calculated based on 110% of the historical maximum planned outages from the previous three years.

The measure passed 17-0, with 10 abstentions. The independent generators, power marketers and retail segments each provided three abstentions.

ERCOT is accepting comments on its proposal through June 9. It will go before the board during its June 23-24 meeting.

TAC Endorses ADER Doc

TAC endorsed a governing document for the third phase of ERCOT’s Aggregated Distributed Energy Resources (ADER) pilot project by adding it to the combo ballot.

Staff proposed increasing participation limits to 160 MW for energy and 80 MW for non-spin reserve service and ECRS, respectively. Phase 3 will allow a new participation model similar to non-controllable load resource (NCLR) and will enable third-party qualified scheduling entity (QSE) aggregation under the NCLR model, regardless of load-serving entity affiliation.

The grid operator will continue to analyze ADERs’ effect on system reliability and market efficiency, focusing on shift factor discrepancies and telemetry validation improvements.

ERCOT said that as of May, three ADERs have been qualified. They offer 15.5 MW capability for energy, with 8.6 MW for non-spin and 8.8 MW for ECRS. Nine additional ADERs are in various stages of registration, it said.

The pilot began in July 2022 and recently transitioned to ERCOT. (See “ADER Discussion Moved to WMS,” ERCOT TAC Opens Discussion on Proposed RTC Changes.)

The combo ballot also included the strategic objectives for the Retail Market and Wholesale Market subcommittees, three other NPRRs, one NOGRR, a single change to the Planning Guide (PGRR) and an Other Binding Document (OBDRR) that, with required board approval, will:

    • NPRR1226: Direct ERCOT to prepare and publish estimated demand response data showing aggregated state estimated load points selected by ERCOT. Loads selected for the report will be based on periodically updated off-line analysis of the frequency and magnitude of reductions observed in historical state estimator load data that is associated with LMPs, ERCOT-wide conservation appeals or other market signals.
    • NPRR1267: Require a large-load interconnection status report be published. The report won’t define “large load”, leaving that to NPRR1234 (Interconnection Requirements for Large Loads and Modeling Standards for Loads 25 MW or Greater). Confidential customer information on large loads will be aggregated.
    • NPRR1276: Incorporate an OBD, “Emergency Response Service Procurement Methodology”, into the protocols to standardize the approval process.
    • NOGRR275: Align the guide with protocol changes to eliminate scheduling center requirements for QSEs that are not wide-area network participants.
    • OBDRR054: Create a process by which transmission and/or distribution service providers will require market participants to successfully test retail transactions before their data universal numbering system is activated in a TDSP’s production system.
    • PGRR125: Add language to that guide that allows an interconnecting entity or property owner to demonstrate compliance under the Lone Star Infrastructure Protection Act should it have a subsidiary or affiliate that falls under the act’s citizenship or headquarters criteria. The subsidiary must not have direct or remote access to or control of the project, the project’s real property, resource integration and ongoing operations, the market information system, other ERCOT systems or any confidential data from the systems.
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AI Adds New Dimension to Utility Cyber Threats, Experts Say

Artificial intelligence may be helping employees streamline a variety of tasks, but AI also is making work easier for threat actors plotting cyber attacks against electric utilities, experts said during a WECC webinar. 

And the AI influence comes as utilities are facing cyber threats from multiple directions.  

“Sophisticated state actors” are trying to access electricity networks for future disruptive attacks, according to Phil Tonkin, field chief technology officer at cybersecurity firm Dragos. Tonkin was a panelist during the June 4 cybersecurity webinar, part of WECC’s Reliability in the West discussion series.  

According to the federal Cybersecurity and Infrastructure Security Agency (CISA), cyber actors sponsored by the People’s Republic of China want to pre-position themselves on IT networks “for disruptive or destructive cyberattacks against U.S. critical infrastructure in the event of a major crisis or conflict with the United States.” 

In addition, Tonkin said, there are activists looking for low-hanging cybersecurity fruit and criminals who are eyeing organizations to target in ransom attacks. 

Dragos has been tracking a group called Voltzite that targets electrical infrastructure.  

“This is not a hypothetical threat,” Tonkin said. “We have seen this organization knocking on the door of many power utilities across the U.S., and through the Pacific as well. On top of that, we’ve seen actual successful intrusions into utilities.” 

Treigh Pedroche, senior security architect at WECC, said generative AI can help a threat actor figure out how to exploit a cybersecurity vulnerability that previously might have required advanced reverse-engineering software skills. 

“Prior to these tools, I had to be maybe [an] expert-level software engineer,” Pedroche said. “Now I just have to be good at using a Gen AI tool.” 

Another issue is when employees use AI for tasks such as summarizing data or writing executive summaries. The information provided to AI is loaded into public models, Pedroche said, and threat actors may then be able to extract it. 

AI also can help attackers devise phishing emails, identifying employees to whom to direct the messages and crafting convincing language, which is especially helpful for foreign adversaries. 

Tonkin gave an example of an email sent to a utility employee by a “customer” who was worried about a buzzing power pole in their yard. They even attached a photo. 

“That’s the sort of thing people are going to fall for,” Tonkin said. “And that’s what’s happened in a number of countries around the world. There’s a European utility which was exploited just like that.” 

In 2024, four cybersecurity intrusions in the Western Interconnection were reported through the Department of Energy’s Electric Emergency Incident and Disturbance Report, according to WECC’s most recent State of the Interconnection report.  

In 2023, Dragos helped Littleton Electric Light and Water, a public utility in Massachusetts, root out Voltzite hackers who had gotten into the utility’s network. It was Voltzite’s first known intrusion into a U.S. electric utility’s computer system. (See Dragos Outlines Voltzite Electric Utility Breach.)  

Working Together

Tonkin said the industry thus far has been keeping pace with cyber threats. But he noted that continuous efforts are needed to stay one step ahead of adversaries. 

Electric utilities have an advantage in that regard, he said, because their service territories largely are distinct. Because they’re not competing against each other, it’s easier for utilities to share information and help each other out. 

Pedroche pointed to resources available to utilities, such as intelligence reports from Dragos and CISA. 

“For us, the defenders, we’re almost always on that back foot,” Pedroche said. “Utilizing those [resources] as best we can to the fullest is really going to be key.” 

In addition to its cybersecurity webinar, WECC will be hosting a Power Systems Security Conference on Aug. 12-14 in Salt Lake City.  

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NPCC Warns of Weather Impacts on Summer Margins

The Northeast Power Coordinating Council, the regional entity covering New York, New England and four Canadian provinces, said in its 2025 Summer Reliability Assessment that only the Maritimes provinces of New Brunswick and Nova Scotia show a significant likelihood of needing to implement operating procedures during the summer months under expected peak conditions. 

However, the RE acknowledged that New York and New England also face the risk of loss of load expectation under more severe conditions, illustrating “a growing concern regarding resource adequacy under extreme conditions.” NPCC said utilities have “strategies and procedures … in place to manage potential operational challenges and emergencies as they arise.” 

NPCC approved its SRA on May 9 but released it June 4, following the release of NERC’s summer assessment on May 14. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.) The assessment covers the week beginning May 4 through the week beginning Sept. 21. 

Coincident peak demand for the entire region was estimated in the report at 104,606 MW, occurring during the week beginning Aug. 3 with a forecast net margin of 9,279 MW, or 8.9%, in the RE’s 50/50 forecast (representing a 50% chance that the actual peak load will be higher or lower than the prediction). The net margin forecast in 2024 was 12,382 MW. 

Overall, NPCC’s projected generation capacity has decreased by about 1,300 MW from last summer to 157,000 MW, with the biggest capacity reduction due to the planned retirement of the Pickering G1 and G4 nuclear units in Ontario. 

The revised net margin, excluding bottled resources (calculated by subtracting the available transfer capacity between Quebec and the Martimes and the rest of NPCC from the total net margin for the two subregions), stood at 8,397 MW. NPCC’s lowest margin for the summer is projected as 4,675 MW, or 4.5%, during the week beginning July 13. By comparison, NPCC’s all-time coincident peak demand was 112,552 MW on Feb. 3, 2023, and its all-time peak for summer was 112,384 MW on Aug. 1, 2006. 

Resource fuel type by reliability coordinator area for the coincident peak week beginning Aug. 3. | NPCC

In the 90/10 forecast, representing a 10% chance that peak load will exceed expectations, peak load was significantly higher, at 111,061 MW, resulting in a net margin of 2,825 MW and a revised net margin of 1,943 MW.  

Finally, the RE’s above 90/10 forecast — “a low-probability, high-impact composite scenario [relying] heavily on individual area risk assumptions” — had demand even higher at 114,943 MW, with more than 5,000 MW of additional unplanned outages and derates, resulting in a revised net margin of negative 7,381 MW. A negative revised net margin “indicates a combination of imports and operating procedures will be necessary to mitigate potential resource shortages,” NPCC said. 

The “single most important variable” affecting demand this summer is weather conditions, the report said, noting that despite the identification of the overall peak week, “summer peak demand could occur during any week of the summer period because of these weather variables.”  

This fact could add to the reliability challenge if, for example, a widespread weather event causes multiple regions’ peaks to arrive at the same time. NPCC observed that peak demands in New England and New York already “have a high degree of correlation” historically, and Quebec’s summer peaks in recent years have begun to contribute to the coincident peak as well. 

Generation resource mixes continue to vary widely across the RE’s footprint. In Quebec, hydro and tidal power are expected to make up 88% of all generation, with wind second at 9%, while in New England, hydro and tidal stand at just 11% and dual-fuel plants take the largest share at 31%, with gas close behind at 30%. In New York, dual-fuel dominates at 49%, and in Ontario, nuclear has the largest share, with 32%. Finally, in the Maritimes, no single generation source accounts for more than 25% of the mix; the largest share of generation is held by coal, at 22%. 

NPCC noted its support for registered entities facing adverse system operating or weather conditions, outlining its ability to coordinate emergency communications including conference calls between affected entities. The RE also monitors weather conditions and supports information sharing and other coordination efforts between the natural gas and electric industries. 

The “assessment indicates our region has spare capacity for this summer, which can be used to help mitigate reliability risks that may result from unexpected unavailability of key facilities, fuel supply interruptions, generation maintenance or higher-than-anticipated demand,” NPCC CEO Charles Dickerson said in a statement. 

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FERC not in Charge of Modernizing Western Grid, Christie Says

PORTLAND, Ore. — In their respective speeches during the annual meeting of the Western Conference of Public Service Commissioners, outgoing FERC Chair Mark Christie and former Colorado Gov. Bill Ritter both emphasized that the West controls the future of the Western Interconnection, not Washington.

Christie addressed WCPSC participants remotely June 2, a few hours before news broke that President Donald Trump would nominate Laura Swett of Vinson & Elkins to replace Christie on FERC. (See related story, Trump Replacing FERC Chair Christie with Laura Swett.)

Christie said in his speech that the “early days” of FERC trying to force states and utilities to join an RTO are over.

“It’s called standard market design, and I remember that, and I thought that was a horrible mistake. And fortunately, it didn’t happen,” Christie said.

“It’s not for us at FERC to tell you what to do,” he told the audience. “You’ve got to make that choice on what’s right for you.”

The chair said if the West decides to create an RTO, the industry should think of it “as a bundle of services,” functioning mainly as a grid operator.

An RTO is “not one single service. … I liken it to going through a cafeteria,” he said. “You can pick what you want and not pick what you don’t want.”

Christie’s comments come as many in the power industry in the West are deciding whether to join day-ahead markets offered by either SPP or CAISO.

“You’ve had the choice for years to go into CAISO’s energy market, the [Western Energy Imbalance Market], without even joining … the CAISO itself. So, you can even pick the market without the RTO, but you’ve got a choice of a real-time energy market,” Christie said. “You’ve got a choice of a day-ahead market now; CAISO has it; SPP offers it.”

Christie also heaped praise on the Western Power Pool’s Western Resource Adequacy Program (WRAP), saying, “I think the concept is great.” (See related story, Industry Needs ‘New Planning Paradigm,’ BPA Chief Tells Regulators.)

SPP operates WRAP, and the program will provide a mandatory RA framework for participants in Markets+ in an effort to ensure members with a surplus generating capacity assist those with a deficit.

“Resource adequacy is a challenge everywhere,” Christie said. “And we’ve seen with the data center explosion … load forecasts that are just mind-boggling.”

In a similar vein, Ritter, founder of Colorado State University’s Center for the New Energy Economy, noted the energy industry is grappling with significant change, both politically and technologically.

For example, artificial intelligence will impact technologies that provide power to the grid, but also power demand on the grid, Ritter said during his WCPSC address June 4.

Another change is shifting views on the energy transition, Ritter noted. He pointed to the One Big Beautiful Bill Act that recently passed in the House of Representatives. The bill would extend tax cuts for individuals and render energy tax credits effectively useless. The proposed legislation is a sharp departure from the Inflation Reduction Act of 2022, passed by Democrats, which expanded clean energy tax credits. (See House Passes Reconciliation Package that Would End Energy Tax Credits.)

Long-term planning and near-term decision-making become difficult when “the politics of the moment can shift on a dime,” Ritter said.

However, the West still exercises control over how it chooses to modernize its grid, whether it’s through RTOs or day-ahead markets, but that requires bipartisan discussions over state lines, according to Ritter.

“We need to talk across political boundaries, within states, in order to solve this issue about how we should build out transmission of the West and what that should look like as we go forward, as we look at the things that are going to change,” Ritter said.

“It’s going to be difficult, but if we don’t do it, we’re going to wind up a little bit like Washington, D.C., sounds right now,” Ritter said. “A fairly toxic place — difficult to operate.”

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IEA Predicts Another Record Year for Energy Investments

The International Energy Agency is forecasting record energy investment worldwide in 2025, despite the present uncertainties and headwinds. 

As it released the 10th edition of its annual report June 5, the IEA said investment in clean technologies is predicted to hit $2.2 trillion this year, or about two-thirds of the total energy investment. Both figures would be record highs — the $3.3 trillion total investment would be 2% more than in 2024. 

Photovoltaic solar is drawing more investment than any other technology, IEA said, and China is investing more than any other country or bloc of countries. 

“When the IEA published the first ever edition of its ‘World Energy Investment’ report nearly 10 years ago, it showed energy investment in China in 2015 just edging ahead of that of the United States,” IEA Executive Director Fatih Birol said in the news release. “Today, China is by far the largest energy investor globally, spending twice as much on energy as the European Union — and almost as much as the EU and United States combined.” 

The 10-year stretch was marked by another change: a de-emphasis on fossil fuel investments. In 2015, investment in the fossil sector was 30% higher than in electric generation and grids. In 2025, electricity investments are expected to be 50% greater than in fossils. 

The volatility seen in the global economy and trade so far has not had a major effect, Birol said: “The fast-evolving economic and trade picture means that some investors are adopting a wait-and-see approach to new energy project approvals, but in most areas, we have yet to see significant implications for existing projects.” 

IEA also flagged a disconnect that has been apparent in some regions for some time: The investment in grids to transmit all this new electricity is not keeping up with the investments to generate and use that electricity. 

Transmission investment stands at $400 billion annually but is being held back by cumbersome permitting processes and limited supply of transformers and cables. 

There also remains a significant geographic disparity in all types of investment. Many emerging markets and developing economies lag far behind the advanced economies, IEA said, particularly in Africa, which is home to 20% of the world’s people but attracts only 2% of global clean energy investment. 

Looking specifically at the United States, the IEA report contrasts its increasing production and export of oil and natural gas over the past decade with its decreasing percentage of electricity generation investments going to fossil fuels. 

The International Energy Agency expects investment in renewable power generation to outstrip fossil fuel power by a wide margin in the advanced economies and China but a narrower margin in emerging markets and developing economies. | IEA

IEA also notes the surging investment in data centers and the interest in powering them with clean energy, and the resulting enthusiasm for next-generation nuclear power to fulfill that need non-intermittently. 

With its deep financial resources and its long history in nuclear power, the United States could emerge as a leader in next-generation nuclear, as well as in other technologies, such as geothermal, IEA said. 

But here again, interconnection delays and transmission constraints are a potential hurdle. Power availability is the top concern for 90% of data center developers, IEA said, and nearly 50% consider upgrading grid infrastructure to be the best possible mitigation for this. 

Compounding the problem, data center operators are competing with generation and transmission developers for the already-inadequate supply of key grid components such as transformers, IEA said. As a result, while a data center can take three to six years from concept to completion, new grid infrastructure can run five to 15 years. 

FERC Order 2023 and other grid reforms may prove to be critical tools to enable growth, it added. 

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MISO’s 2022 and 2023 Queue Study Cycles Delayed Again

MISO’s 2022 and 2023 generator interconnection queue cycles are lagging behind their stated timelines once again as the RTO continues working to produce study results in a new, automated process.

The grid operator said it now will post a final system impact study for the 2022 cycle July 8 and move those generation proposals to the second phase of the three-part queue by Aug. 6. It will move on to studying project applications submitted in 2023 on Aug. 20.

This is MISO’s second postponement for the 2022, 2023 and 2025 queue cycles. The grid operator skipped acceptance of a 2024 cycle while it tried to get a handle on study delays and design a megawatt-capped queue that could sort out projects over a one-year span instead of three to four years.

In January, MISO planned to begin studying the 2023 cycle in May and the 2025 cycle by the end of the year, a few months behind the schedule it announced in 2024. At the time, the grid operator envisioned all generation projects from the three cycles striking interconnection agreements over 2026, with the 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026. (See MISO Unveils Later Timeline for Queue Processing Restart.)

MISO’s Kyle Trotter said MISO would post a new schedule soon detailing when it will proceed with the 2025 cycle of projects.

Senior Manager of Resource Utilization Ryan Westphal said MISO wants to finalize the 2022 cycle’s system impact study after multiple rounds of adjusting modeling assumptions at stakeholders’ suggestions and presenting different drafts of the study for review.

“We’re ready to move forward at this point,” Westphal said during a June 3 teleconference focused on MISO’s interconnection process. He added that MISO will account for project withdrawals from the 2022 cycle in the screening process for the 2023 batch of projects.

MISO is using Pearl Street’s automated SUGAR (Suite of Unified Grid Analyses with Renewables) study software to screen generation projects and perform the first phase of studies in the queue. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Westphal said MISO’s later, Aug. 20 study kickoff also would give the RTO time to seek FERC approval to include MISO and SPP’s $1.65-billion Joint Targeted Interconnection Queue (JTIQ) portfolio in its modeling for the 2023 cycle of generation projects. The move is unpopular among MISO’s generation developers, who are set to shoulder all JTIQ costs; they’ve said the cost allocation could attach high, unpredictable expenses to their projects. (See MISO Gen Developers Sour on RTO’s JTIQ Cost Allocation.)

“We want to make sure we have enough time to hear back from FERC,” Westphal said.

MISO has 1,273 projects totaling 237.8 GW in its interconnection queue.

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PJM Board Elects David Mills as Chair

The PJM Board of Managers has elected David Mills to serve as its chair.

“It is an honor to lead this board at a time when continuity and stability are critical to our mission of preserving the reliability and affordability of the grid,” Mills said in an announcement PJM published June 5. “Our stakeholders have made clear their desire to strengthen communication channels with the board, which we have already taken steps to accomplish. I look forward to working together to make the hard choices required of us to maintain the balance between electricity supply and demand.”

He was elected to the board’s chair-elect position in 2024, putting him in place to assume leadership if the prior chair, Mark Takahashi, left the role. Takahashi was not elected to another term on the Board of Managers during the May 12 Members Committee meeting and took his name out of the running before the vote was set to be reconsidered the following day. Mills was elected formally to be the board’s chair on May 14.

“David is a very capable leader,” PJM CEO Manu Asthana said in the announcement. “He understands the tradeoffs required to preserve reliability and affordability, and he has demonstrated his commitment to listening to and working in partnership with our stakeholders. I am confident that the reins of the PJM board are in able hands.”

During the May 12-14 PJM Annual Meeting, Mills said he supports the board taking steps to improve communications with stakeholders. He said he would seek to add agenda items to future Members Committee meetings for attending board members to speak with stakeholders during the meeting, as well as for them to remain accessible after the meeting and wait until the following day to return home.

Mills first was elected to the board in 2021. He has chaired the Competitive Markets Committee and is a member of the Nominating Committee. Prior to joining the board, he served as Puget Sound Energy’s chief strategy officer and previously worked for the Bonneville Power Administration. He earned a Bachelor of Science in economics from Portland State University.

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UPDATED: ‘Pathways’ Bill Passes California Senate on 36-0 Vote

The California bill to implement the West-Wide Governance Pathways Initiative’s Step 2 proposal to allow CAISO to relinquish market governance to an independent “regional organization” (RO) passed the state Senate on June 4 on a 36-0 vote, with four members abstaining. 

SB 540 was approved after 40 minutes of floor debate in which several senators expressed concern about the extensive amendments added to the original bill, particularly a provision creating a new Regional Energy Market Oversight Council responsible for ensuring CAISO’s participation in a regional energy market that “serves the interests of the state.” (See Amended ‘Pathways’ Bill Boosts — and Complicates — Calif. Protections.) 

The new council would be authorized to mandate withdrawal if those interests are compromised. 

Those senators sought assurances that the bill’s sponsors, Sens. Josh Becker and Henry Stern, both Democrats, would work with members of the state Assembly to return the bill to something closer to its original form. 

But other senators said they wanted to ensure preservation of an “off-ramp” from the RO, expressing worry that the ISO’s participation could compromise California’s environmental and clean energy policies, particularly in the face of the Trump administration’s efforts to support coal-fired generation. 

Becker assured his colleagues the bill would not increase California’s exposure to federal political interference, but did point to the risks of the state losing potential “partners” on the electricity grid to “a market out of Little Rock” — SPP’s Markets+, the competitor for participants to CAISO’s Extended Day-Ahead Market (EDAM). 

“Make no mistake: if we do not act, we will be worse off,” Becker said. 

‘Strong Coalition’

During the debate, Sen. Tony Strickland (R) called the recent amendments to SB 540 “very problematic” but expressed confidence that Sens. Becker and Stern would “work out some of these problems” as the bill advances through the lower house.  

Strickland pointed to the “strong coalition” backing the bill, including labor and business groups.  

“I haven’t seen a coalition like this in a long time, and I’ve been on [Senate] Energy Committee going back 13, 14, 15 years,” he said. “Because everybody understands status quo is not an option. We need to get this fixed. We need to move forward. We need to make sure energy is reliable for all California residents.”

Sen. Angelique Ashby (D) opened her comments saying she likes to “brag” about the publicly owned utility that serves her constituency, the Sacramento Municipal Utility District (SMUD), and voiced concern that SMUD had changed its position on the bill in light of the amendments.  

Ashby asked the bill’s authors how they will “get from where you are now back to a space where you can earn the support of the one of the most trusted entities in the state of California, which is SMUD.” 

“I know SMUD, other than [having] issues with the bill, would like to see it move forward, and I’m committed to working with them going forward,” Becker said. 

Sen. Christopher Cabaldon (D) said a small portion of his constituents are served by SMUD and echoed Ashby’s concerns, urging “less work” to be done on the bill. 

“Because the problem here is all of the benefits of this bill — and they are numerous and profound — depend on us actually joining with the region and the region joining with us,” he said. “I think the problem that I hope we will work on to resolve in the Assembly is that we cannot replicate all of the state rules and interests and what have you, as though the rest of the world is just waiting for California to allow them to be partners.” 

Sen. Rosilicie Ochoa Bogh (R) said she supported the bill in the Senate Energy Committee “because it reflected a bipartisan, holistic compromise. Literally every group, as mentioned earlier, related to energy, visited my office, and nearly all were in alignment. Not all were pleased, but they were aligned.” 

But Ochoa Bogh said the proposed oversight council in the amended bill “fundamentally alters the governance structure” by giving the body “extraordinary authority” over California’s participation in a regional market. She said that would “inject an uncertainty into what should be a technical, market-driven process” and compromise long-term resource planning if the state were “suddenly withdrawn,” threatening grid reliability and affordability for residents. 

‘Energy Island’

Sen. Thomas Umberg (D) said SB 540 is “a very difficult bill” because it brings up “a clash of interests that is very difficult to reconcile” — namely, the differing views on climate change between California’s leaders and the Trump administration. 

“The challenge is that, once we’re in [the RO], it may be very difficult to leave, either legally or practically, because we become so reliant on the grid. And it also vests California in a place where, potentially, the current administration can wreak havoc on California,” Umberg said. 

Sen. Suzette Martinez Valladares (R) recalled a previous visit to CAISO was a “phenomenal experience” before noting the ISO has “urged” for a “regional approach.” She warned that California faced risking becoming “an energy island” like Texas, but also said she wanted additional clarity around the role of the proposed oversight council. 

Sen. Ben Allen (D) added his voice to supporters of the bill but said inclusion of the oversight council was “bizarre” and represented a “bad direction,” in part because it would make withdrawal from the RO a “governor-dominated” decision. He pointed to a suggestion that the decision should come down to “some sort of supermajority vote in the legislature.” 

Sen. Aisha Wahab (D) expressed the greatest reservations about SB 540, saying creation of the five-member oversight council is “not enough” and that she was concerned “that we’re not going to bring it back to the legislature to have a full picture of what this regional organization will actually look like.” 

“If it is that we have a lot of confidence in a regional organization — the fact that it won’t impact the RPS and won’t take away green jobs and won’t force Californians to subsidize an organization they no longer have control over — then we should be able to review the facts once we have more concrete evidence,” she said, later abstaining from voting on the bill. 

Sen. Anna Caballero (D) said she favored “regionalism” because “I think our weather patterns and the energy that we can create regionally is diverse enough, so it’ll benefit California.” But she also called for the bill to include the option for an “off-ramp” from the RO to avoid tying the hands of a future governor and legislature. 

In his closing speech stumping for his bill, Sen. Becker reminded his Senate colleagues that SPP’s Markets+ has been able to attract more participants in recent months. 

“So, if they’re able to sort of pull something together, we’ll end up isolated — so we need to do this,” he said. “I appreciate everyone who’s had their input and wants to keep working on this going forward.” 

Reactions

Clean energy groups that have backed the Pathways Initiative commended the California Senate for advancing the bill while also urging changes to the bill as it moves through the Assembly. 

“California can’t afford to go it alone when it comes to meeting skyrocketing energy demand while tackling the energy affordability crisis,” Edson Perez, California lead at Advanced Energy United (AEU), said in a statement. “We need to be able to keep the lights on in the fourth-largest economy in the world without charging ratepayers an arm and a leg. Joining a robust Western regional energy market is essential to keeping energy costs under control while still spearheading the transition to clean energy.” 

AEU said bill supporters “remain committed to ongoing collaboration to ensure the final version reflects the shared priorities of the diverse coalition engaged in this effort for regional energy collaboration.” 

“Today’s Senate vote is an important step in a long process to ensure California is at the forefront of a fast-moving revolution in how electricity will be bought and sold across the West,” Katelyn Roedner Sutter, California state director at the Environmental Defense Fund (EDF), said in a statement. “California cannot keep the lights on or solve the climate crisis alone — we need an electricity system with diverse clean resources that can withstand simultaneous extreme weather events.” 

Roedner Sutter said EDF shares “significant concerns about recent bill amendments that undermine the benefits of California’s participation in a Western market and urge California leaders to act decisively to avoid losing more trading partners to a competing Arkansas market.” 

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Ontario Nodal Market Operating as Expected at 1-month Mark

Ontario’s nodal market is showing promise one month after its launch, with improved price certainty, increased day-ahead trading and LMPs reflecting expected congestion patterns, IESO officials say.

IESO’s Market Renewal Program (MRP) is designed to improve the way the grid operator supplies, schedules and prices power by creating a financially binding day-ahead market (DAM) and adding about 1,000 LMP nodes. The ISO says the nodal market, which launched May 1, should save Ontario $700 million over the next decade through reduced out-of-market payments and increased efficiency. (See IESO Nodal Market Launch Successful.)

In a briefing June 4, IESO said the initial month of operations were “consistent” with the MRP’s goals. The only glitches to date were a day-ahead market failure May 22 and a delayed opening to the new virtual market.

While day-ahead prices were not financially binding in the prior market — meaning all settlements were against real-time prices — about 95% of energy volume is now clearing in the DAM. Most non-quick-start generator commitments are being made in the day-ahead rather than in real time, and pre-dispatch reviews are selecting least-cost resources.

‘Encouraging’ Results

“The results that we’re seeing from the first couple of weeks are actually really encouraging,” said Darren Matsugu, director of markets. “Our locational prices really have aligned with the expectations that we’ve seen historically based upon congestion across different parts of the province.

Darren Matsugu, IESO | IESO

“With the introduction of the day-ahead market … we are seeing improved real-time certainty, both from participants and importantly for the ISO.”

Most export transactions now are being scheduled day-ahead, up from virtually none in the old market. The shift “really gives the ISO a much more complete picture about the next day’s operation than we used to see,” Matsugu said.

While the real-time market has shown more volatility than day-ahead prices because of unanticipated outages and supply/demand changes, those spikes are muted in consumer prices because only 5% of energy volume is settled in real time.

“We’re seeing really complete participation and competitive participation [in the day-ahead market], which has given us good confidence in those day-ahead market results,” Matsugu said. “And of course, if there’s any additional scheduling needed in between day-ahead and real-time, we are seeing that this vastly improved pre-dispatch sequence is doing a good job of selecting the least-cost resources.”

A Small Snapshot

Officials cautioned that their ability to draw conclusions is limited because of the short time the market has been operating. Participants still are learning about the market and developing their trading strategies, they said.

“A full year, covering all four seasons, will provide more complete information,” IESO said.

nodal market

IESO day-ahead, real-time and pre-dispatch prices | IESO

“Market performance really does need to be considered under a wide variety … of system conditions,” Matsugu said. “Every season, every month, presents itself with very material differences in terms of demand, supply conditions, transmission [and] outages. All those things are very different, and the market needs to perform very different optimization through the year. So, for example, performance during the summer and winter peak days, there’s quite significant differences in system peaks and that kind of transition from overnight periods. And those really are kind of our best test of the market’s ability to be able to efficiently maintain reliability.”

‘Defects’ Corrected

The transition to the new market “went very smoothly thanks in no small part [to] the efforts of many of you out there,” said Candice Trickey, director of MRP readiness.

nodal market

Candice Trickey, IESO | IESO

She singled out the MRP Implementation Working Group, composed of representatives from different market sectors that helped the ISO design training and testing of the new market.

The first run of the DAM calculation engine was successful on May 2, and the first market settlement statements were issued May 15.

“Since the transition, the settlement statements have been issued on time, and there have only been a small number of disagreements that we’ve seen by a limited number of participants,” she added. “To date, anyway, we haven’t seen any widespread calculation or settlement errors.”

Although the ISO’s support teams saw a large jump in the number of contacts and tickets in the first week, “those have fairly quickly petered out to more normal volumes,” she said.

IESO identified some “defects” during and after the launch. “Not a surprise, once you put everything into production; new things pop up, and we did identify some defects,” Trickey said. “Those have all been quite quickly addressed through either workarounds or permanent fixes. Most of those things were fixed before any of you saw them.

“This was a very complex project [involving] more than 10 different systems that we had to integrate together,” she added. “They all ran 24/7, providing a continuous stream of results and instructions and reports. So, it’s no surprise that we experienced a few hiccups.”

Timothée Denis of Air Liquide said his company’s day-ahead trading limit — 50 MW before the transition — initially was limited to 25 MW at the new market’s launch. “So we had to bid on half of our capacity and liquidate the rest of that on the real-time market,” he said, adding that the problem was resolved May 22.

Virtual Market Delayed

Trickey also said there were some problems completing authorizations for virtual traders, which delayed the launch of the virtual market from May 8 to May 13.

The new system allows market participants to submit hourly bids and offers in any of nine virtual transaction zones.

A defect related to virtual trades caused IESO to declare a day-ahead market failure for the May 22 trade date, causing it to use real-time prices.

The ISO halted virtual trading to avoid further DAM failures until a fix was implemented, with virtual trading resuming May 24.

“Since then, we haven’t experienced any other issues, but it is early days, and we still remain on high alert, monitoring and watching to see if anything else should arise,” Trickey said.

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Consumer Liaison Group Discusses ISO-NE’s Failing Accessibility Grade

Speakers and attendees of the ISO-NE Consumer Liaison Group’s quarterly meeting June 4 advocated for governance changes at the RTO after the grid operator received a failing grade on a recent report card on RTO transparency. 

The report, commissioned by New England-based environmental justice nonprofit Slingshot, graded each RTO and ISO on public accountability, transparency and accessibility. ISO-NE was the only grid operator to receive a failing grade, which the report attributed to the RTO’s “exclusive stakeholder process and inaccessible, opaque board proceedings.”  

The report also detailed concerns about the limited voting power of end-user organizations in the NEPOOL voting process, language barriers, the lack of a “streamlined public comment process” and the entrenchment of existing leadership. 

None of the grid operators, however, received higher than a “C+.” 

Governance issues have been a major topic at the CLG since a coalition of environmental and consumer advocates took control of the CLG Coordinating Committee in late 2022. (See Climate Activists Take Over Small Piece of ISO-NE.) 

Activists have argued frequently that the nonpublic nature of NEPOOL proceedings and meetings of the ISO-NE Board of Directors prevents meaningful public engagement, while the RTO has pointed to recent steps taken to increase engagement, including annual public board meetings and the addition of an environmental and community affairs policy adviser. (See In Conversation with ISO-NE’s First Community Affairs Policy Adviser.) 

Anne George, chief external affairs officer at ISO-NE, called the Slingshot report inaccurate and said it overlooked data and information the RTO has made available to the public.  

“Obviously we’re not happy receiving an ‘F’; we disagree with a lot of what’s in that report, and we think it would have been helpful to talk with the researchers,” George said. “I don’t think we’re planning any major changes in what we’re doing based on that report.” 

Bryndís Woods, principal analyst at the Applied Economics Clinic and one of the report’s authors, defended its methodology, stressing that the researchers were able to consider only publicly available inputs. Woods noted ISO-NE has made recent steps toward translating some materials into Spanish that were not captured in the report. 

ISO-NE

RTO transparency, accessibility and accountability grades | Applied Economics Clinic

Charles Hua, executive director of PowerLines, an affordability-focused nonprofit, said cost pressures have caused increased consumer interest in engaging with energy policy issues.  

“The vast majority of Americans feel powerless to do anything about their utility bills,” Hua said, adding that limited public education and opportunities to engage with public utility commissions and RTOs create “significant risk for all stakeholders in the system.” 

“It’s critical we create opportunities and processes for consumers to participate,” he said. 

Joshua Macey, associate professor of law at Yale Law School, made the case that RTOs and ISOs across the country, including ISO-NE, structurally favor the interests of incumbent transmission and generation owners. 

“What you see across all [RTOs and ISOs] is that the voting empowers entities that owned facilities in the 1990s,” Macey said, adding that utilities — and transmission owners in particular — played a major role in establishing the existing governance structures.  

NEPOOL voting rules give each of the six sectors an equal share of the voting power and require an approval threshold of 60% for market tariff changes, 66% for non-market changes and 70% for endorsing candidate slates for the ISO-NE board. The high thresholds create a requirement for broad support for rule changes and board endorsements. 

While ISO-NE is an independent organization, the transmission and generation sectors, which have a “a significant financial interest in the assets that are already on the system,” would have the power to block any slate of candidates for the board, Macey said.  

So far, no slate of candidates for the board has ever been rejected. Slates are chosen by the Joint Nominating Committee, which typically consists of members of the ISO-NE board, representatives from each sector and a state representative.  

Macey said the power of incumbent interests has contributed to resource adequacy rules that typically “favor incumbent resources” and provide inadequate incentives for resource entry. He also added that the TOs’ retention of filing rights over local projects likely has contributed to the high costs of asset-condition projects. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) 

Macey said the RTO has made progress in recent years in changing its rules to enable the addition of new renewables and said electricity restructuring has driven “meaningful cost reductions” and lowered barriers to decarbonization.

“As many challenges as we have here in New England … we should thank our lucky stars that we are not in a vertically integrated market,” Macey said.