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December 7, 2025

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Power Play: Pragmatism, Adaptation and a Touch of Wishful Thinking at Climate Week NYC

New York, frenetic at the best of times, bordered on frantic when Climate Week coincided with the U.N. General Assembly meeting in September.

While the U.N. addressed climate in its hushed halls, experts and pundits at hundreds of Climate Week events scattered across dozens of locations analyzed every aspect of it. Like a subway running beneath this melee of meetings, there were common themes that connected the many panels and events I attended: Old goals were quietly dropped, new challenges accepted and an AI-led future imagined.

Note: Many panels were under the Chatham House Rule or on background only, so some ideas and quotes below are not attributed. Just know that all the speakers had lengthy titles, impressive biographies and well-known employers.

Hello ChatGPT, Goodbye 1.5 Degrees

This was my first climate event where there was little mention of the Paris Accord goal of limiting the global average temperature increase to 1.5 degrees Celsius above pre-industrial levels. “One-point-five” used to be a term so common it was rarely explained. IYKYK — and Climate Week attendees know. This year, the few times it was used, it was in a casual aside about the target there was no chance of meeting, or the limit that already may have been exceeded.

Only two years ago, many in the climate space called for radical emissions cuts to reach the goal. Today, the consensus among the business end of the climate community — asset managers, developers, business leaders and consulting giants — is that the goal is about to be in our rearview mirror, courtesy of the rise of AI. U.S. political headwinds and two more years of too little action? Just speed bumps on the way.

“The net-zero, 1.5-degree scenario is now a mathematical exercise. We could not get there from a policy perspective,” the leader of an energy analytics organization said. “We retain it because it’s important to look at it, but it’s not something that we were able to achieve other than [through] a mathematical formula.”

Move over Mitigation, the Age of Adaptation has Arrived

The other common climate term noticeably absent was mitigation. It used to be that mitigation was king and adaptation was a quitter’s word, one for those who didn’t believe we had the skills and will to pull humankind out of its climate nosedive.

Today, adaptation is a necessary evil needed to cope with the damage being done to the planet. It is not that everyone won’t do their best to mitigate, but it’s no longer enough.

Dej Knuckey

“I’d like to avoid being seen as the pessimist in the room,” an in-house climate scientist at an analytics firm said. “We can turn this problem around and talk about the benefits of adaptation, or the benefit-to-cost ratio for adaptation. A recent study by JP Morgan has calculated that the reduced or avoided risk is between $2 and $43 per dollar invested in adaptation. It’s a huge opportunity.”

If you are building infrastructure today, the head of infrastructure at one of the world’s largest asset managers said, you might as well make it strong enough to withstand a future riddled with climate disasters. In the emerging markets, for example, he said it was “significantly cheaper to build something … to an international standard that will withstand the expected impacts of climate change that will come over the next couple of decades. We build to a certain standard that we hope we don’t need, but hurricanes have become stronger, fire risk is greater.”

Electrical transmission and distribution assets should be built with community vulnerability in mind, he said, so they not only could provide service during extreme climate events but also would not cause those disasters.

Business discussions about a post-1.5, adaptation-focused world were positioned as “pragmatic.” The word was used with a touch of guilt: not that they wanted to go gentle into that good night, but it seemed futile to rage, rage against the dying of the light. In an unwinnable war, pragmatists should focus on minimizing the damage … and perhaps even profiting from hardening the infrastructure ahead of the impending crises.

AI: Energy’s Frenemy

The rise of AI and the massive data centers that power it are the culprits behind the surrender of the target. But AI is seen as both a power-hungry enemy and an efficiency friend.

At Deloitte’s three-day Climate Week Horizons conference, data centers were cited as driving demand for electricity.

“There is no doubt that AI is creating the single largest [rise in] energy demand in decades,” said Martin Stansbury, principal and U.S. power, utilities and renewables risk and financial advisory leader at Deloitte. “And the real question is: Can we build it fast enough? Can we build it clean enough, and can it be resilient enough for the market?”

“By our analysis, we see about a five times growth in data center power demand by 2035,” Kate Hardin, executive director at Energy, Resources and Industrials Research, said at the Deloitte event. She said industrial electrification was the other major trend driving demand.

On the flip side, AI was cited as the potential hero for optimizing everything from buildings to ports … as well as the grid itself. While many speakers worried about how quickly generation could be built to service AI data centers or how the related demands on water supply would be met, others believed AI would unlock more energy savings than the data centers themselves would consume. Ultimately, AI will be a self-correcting challenge.

Speaking at Axios House, Tom Steyer, the billionaire co-executive chair of Galvanize Climate Solutions and former Democratic presidential candidate, talked about AI’s ability to make the grid substantially more efficient.

“If you look at renewables in this country, the big pain points are permitting and access to the grid,” he said, citing a discussion with a Californian investor-owned utility who told him it took 12 years to permit and build a new distribution line.

“The grid in California is 32% efficient. The grid in the United States is 42% efficient. We have the ability now, using real-time information and AI protocols, to completely change that number. If we can go from 32 to 64 [percent efficiency], we’ve rebuilt the grid,” Steyer said.

The chair of a major AI developer speaking at a different event had a similarly optimistic take: “The potential for efficiency and productivity of our existing infrastructure, using sensors, using artificial intelligence, is off the charts.” For example, data and sensors enable better use of the existing grid through dynamic load ratings. “When cable lines are cooler, they can get more current through them. Imagine if we could predict the weather, that would predict the temperature of the line, that would allow us to optimize how much current we put through. These are the sorts of things that are possible.”

AI’s potential to optimize generation assets would create further potential for gains, he said, increasing the output from existing renewables capacity. “Imagine that: 10 to 20% for effectively nothing.”

Efficiency Opportunities at Every Turn

It’s not just generation and the grid that could be net beneficiaries of the AI revolution, some argued, but every industry that depends on electricity will gain efficiency.

For example, the real estate sector is unmatched when it comes to climate risks and opportunities, said Lauren Pesa, partner and U.S. real estate sustainability leader at Deloitte. “Real estate is the largest asset class in the world, representing two-thirds of global wealth. First Street Foundation projects up to $1.47 trillion in real estate value in the U.S. could be lost in the next 30 years due to climate risk.”

Yet this massive asset class, a major consumer of the grid’s electricity, is ripe with opportunities to be both more resilient and more efficient. AI and machine learning are key for moving digital building management systems from set-and-forget to active optimization, said Ben Dwyer, SVP of global sales at Kode Labs, at the Deloitte event. “With the evolution of what’s going on with automation, AI and [machine learning], you’re essentially able to, over time, optimize the building to run as efficiently as possible.”

While optimizing energy use will be important, smart buildings’ ability to be more resilient during climate events such as Texas’ freeze and hurricanes will be critical, he said. “What smart buildings allow you to do is get ahead of these large events and ensure that your buildings are prepared for these things to happen, to ensure that not only the asset is protected, but the individuals that inhabit that building are protected,” Dwyer said.

From left: Lauren Pesa, Deloitte; Austin Koch, Hartford Insurance; Caitlyn Raines, Esri; Ben Dwyer, Kode Labs | © RTO Insider

Ports are another example. Beth Rooney, port director at the Port Authority of New York and New Jersey, told a Deloitte panel on aging infrastructure that the port is on the cusp of a transformation.

“Between today and 2050 … we’re going to double, if not triple, our cargo and passenger volume. I don’t have land to expand to, so we have to take the land that we have and use it more efficiently and more productively. And that’s where technology comes into play.”

The Port Authority, whose infrastructure includes aviation infrastructure, tunnels, bridges and rail terminals, was using technology ranging from underwater drones to inspect pilings (fun fact: cleaner water is degrading the port’s pilings faster) to GIS systems for more efficient maintenance. The ports were improving efficiency through four uses of technology, she said: predictive decision making, real-time risk management, enhanced visualization to see what’s going on across 3,000 acres, and hyper-connected logistics.

“We will not be able to handle the volume that is coming our way, not just in New York and New Jersey, but across the United States, if we don’t change the way we do business,” she said.

Wishful Thinking or Wondrous Optimization?

Overall, the consensus was that AI would save more energy than it consumed, leaving the world better off, even if there would be more fossil emissions to cope with during the transition. There was little talk about sequestration, despite the reluctant admission that fossil fuels would supply much of the AI-driven demand for now.

The head of an electrical components manufacturer warned against overestimating the amount of energy required by AI data centers. Last year, data centers consumed 1.3% of global electricity, so doubling by 2030 and doubling again by 2035 still would leave it consuming only about 5% of the world’s energy.

The question of how the markets would meet AI’s power demand brought out the list of usual supply suspects, most notably nuclear, with small modular reactors commercially viable and available within the next five years, and every color of hydrogen. AI still was in its relative infancy, and potential efficiencies, ranging from improved cooling technologies to quantum computing, were expected to lower energy demand as the technology matured. Similarly, value could be extracted from the waste heat by industry or district heating systems, where they exist.

The Waiting Game

Behind the barricades around the United Nations, President Donald Trump was ripping into climate goals when he wasn’t grumbling about halted escalators and broken teleprompters. However, business meetings mere blocks away seemed unconcerned that he labeled climate change a “con job” and wind and solar energy a “scam”. If anything, his comments evoked smirks and assurances that project development operates on timescales that stretch well beyond any single administration.

An industry analyst said, “No matter what the president says, 91% of new additions to the grid in the United States this year have been batteries and renewable energy. So, if you don’t think the transition is happening, you’re burying your head in the sand.”

And regardless of the president’s opinion, fiduciary duty required investment advisers to manage the $16 trillion of U.S. employee retirement funds prudently, a lawyer said. “What does that mean with respect to climate change? When we have all the scientific data, [it] means you have to actually be mindful that these risks are going to have a financial impact on the portfolio,” she said.

The dozens of speakers at events on and off the record agreed: Trump’s comments at the U.N., and his administration’s policies to date, were an annoyance, but not the driving factor for an industry that plans in decades. As the CEO of a major energy generation asset owner said, “There’s nothing I could build today that [will] have a payback period during the Trump administration. There’s nothing I could build today that’s going to have a payback period in the next three administrations.”

Practical Action, not Political Oration, is What Matters

Steyer said the administration’s policies may slow the energy transition, but couldn’t stop it: “Is [Trump] an existential threat to the world’s ability to make this transition and to solve climate change? No. We’re [the U.S.] 11% of emissions. Our emissions may go down slower, but … except for the year of COVID, we have never reduced emissions, and we’re supposed to reduce emissions 40% this decade,” Steyer said.

China’s action would far outweigh any U.S. inaction. “In the first half of 2025, Chinese emissions went down 1%. China is a third of global emissions. Between 2018 and 2024, 95% of new fossil fuel demand came from China. If China’s peaked, the world’s peaked.”

As Deloitte’s principal and sustainability leader, Geoff Tuff, put it: “The headline is, no matter what we hear in different parts of the world, and no matter what reports you may see, the energy transition continues, and it will continue. And it’s just the sheer reality. If you fast forward the clock 30 or 40 years, we will have a fundamentally different energy mix than we do today.”

A Week to End All Climate Weeks

Like the COP28 I attended in Dubai two years ago, it was good to experience Climate Week NYC, if only so I could check it off my list and never go again. I’m too old to shout over a techno beat at a climate-startup-investor schmoozefest, too jaded to hear one more high-octane luxury brand’s CSO congratulate their token coral-growing PR effort, and too tired to negotiate the subway sauna while running from one event to the next.

If I sound like a curmudgeon, I am. There’s no simple way to sort the hundreds of events across dozens of locations, no consistent way to apply for them, and no unifying calendar and map to navigate your choices. And while the coinciding event at the U.N. brings climate experts in from the most-impacted nations, it also drives hotel prices to astronomic heights, even by New York standards. Maybe they could build an AI agent to sort it all out.

But despite the stressors, this curmudgeon left happy to see that pragmatists are running the energy transition, tackling the big, hard challenges as they arise, undeterred by the political distractions happening a few blocks away.

Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience. 

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Christie Appointed Director of New William & Mary Energy Law Center

William & Mary Law School announced it has appointed former FERC Chair Mark Christie as the 2025 Lowance Fellow, a visiting professor of the practice of law and the founding director of the school’s new Center for Energy Law & Policy. 

Christie served on FERC for nearly five years and was chair for the last seven months, until this past August. Before that, he was chair of the Virginia State Corporation Commission, on which he served for 17 years. He also previously taught law at the University of Virginia and Virginia Commonwealth University. 

“I love the whole process of teaching,” Christie said in an interview Sept. 29. “First of all, you got to learn before you can teach, and so teaching is very educational.” 

William & Mary said the new energy law center “will serve as a hub for convening policymakers, scholars and students to address critical issues shaping the future of energy regulation.” Christie said the center offers him a chance to continue working on policy, with its first public activity being a conference scheduled for spring 2026 on how Virginia and the rest of the country can meet the needs of data centers and everyday consumers. 

The center also will “host webinars on timely energy issues, sponsor research projects by William & Mary faculty and students, and promote cross-disciplinary collaboration across the university, including opportunities for business and policy students,” the school said. 

“We are ground zero for the planet for the challenges of data center development and the reliability and the consumer cost issues that the whole country is dealing with,” Christie said. “Now, how do we pay for these? How do we keep the reliability? So, it’s a perfect place to do this in Virginia and in William & Mary, which is an outstanding law school.” 

The return of load growth has put pressure on prices and reliability, which has led to calls for major changes at PJM, the largest RTO in the country and one Christie has tracked his entire career as a regulator. He recently spoke at a forum hosted by Pennsylvania Gov. Josh Shapiro (D) where he and other state governors in PJM called for reforms in its governance process. (See related story, PJM Members Confirm 2 Board Nominees; States Call for Governance Overhaul.)

Shapiro and Virginia Gov. Glenn Youngkin (R) had asked that Christie and former FERC Commissioner Allison Clements be named to PJM’s board. The governors raised the issue with Christie shortly after he left FERC, and he said he would have served if asked, but the RTO ended up picking others.

“PJM faces a tremendous political problem, and when I say political, I’m not talking partisan; I’m talking the reality that you’ve got 13 states with obviously very different views about, certainly, what the generation mix ought to be,” Christie said. “So, it’s tough enough to try to come out with something that’s a consensus among the states, but I’m looking to see that the states use the authority we gave them in Order 1920-B, which is to decide on cost allocation, and file that with FERC.” 

PJM is making policy calls around issues without giving the elected representatives of its 67 million consumers enough of a voice, Christie said. 

Another policy issue that has come up lately and periodically over the past 20 years is the role of the Independent Market Monitor. When Christie was president of the Organization of PJM States Inc., his yearlong tenure was taken up by a complaint states filed trying to preserve the independence of Monitor Joseph Bowring, the result of which was universal rules through FERC Order 719. 

But some interests in RTOs do not want IMMs at all. The idea has cropped up occasionally in PJM and just recently at MISO, where Monitor David Patton has clashed with stakeholders and leadership because of his views on transmission expansion. (See MISO Board Orders More Detail into Monitor’s 2026 Budget.) 

“I am not usually at a loss for words,” he said. “People that know me would say that it’s very rare that Mark Christie is at a loss for words. I can hardly even think of the words to describe how essential the market monitor is. … 

“Consumers are absolutely, totally defenseless and regulators are totally in the dark [without a monitor] because I can tell you from my experience in PJM, I don’t know how many times as a state regulator we got critical information from Dr. Bowring that we had to have to make decisions.” 

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NYISO Dogged by Uncertainty in Comprehensive Reliability Plan

NYISO’s draft 2025-2034 Comprehensive Reliability Plan, released Sept. 25, shows a wide range of possible scenarios for resource adequacy in New York, with the most negative outlook showing a deficit of up to 10 GW by 2034. 

The ISO is contending with aging generation, climate change causing heightened weather variability, generator and transmission project delays, and large load additions. 

“While each of these factors presents its own set of risks, their combined effects can be far more consequential,” the draft says. “A single uncertainty may reduce reliability margins, but multiple uncertainties occurring together — such as higher demand coinciding with delayed transmission projects or overreliance on aging generation — can result in critical supply shortfalls.” 

“The one thing I hope you take away from this presentation is that ‘uncertainty’ is the key theme of the CRP,” Ross Altman, NYISO senior manager of reliability planning, told the Transmission Planning Advisory Subcommittee. “It’s quite critical in how we view reliability with such shrinking margins that we are seeing.” 

To illustrate this, Altman pointed to the 2024 Reliability Needs Assessment that identified a reliability need in New York City for about 97 MW by 2033 because of transmission security problems. A change in the demand forecast modeling eliminated the need. (See NYISO Cancels 2033 Reliability Need for NYC.) 

“That’s not a very comfortable place to be, but it did resolve the reliability violation,” Altman said. 

The draft evaluates each identified risk’s impact on the statewide reliability margin before examining several combinations of the best- and worst-case scenarios from each. It includes 11 scenarios forecasting different system conditions and combinations of demand, new generation, retirement, transmission upgrades and weather conditions.

Of these scenarios, only two saw summer and winter sufficiency by 2034. One of them is a lower-boundary scenario where load growth follows the Lower Demand forecast in the 2025 Gold Book. The other is a scenario in which all generation in the queue is constructed on schedule, and all battery storage is able to be discharged at maximum during peak hours. 

“Most of the combinations of scenarios show decreasing margins through 2034, with the range of future margins growing over time. The most optimistic scenario combinations show positive margins by 2034 that are roughly equivalent to today’s margins in the positive 2,000-MW range,” the draft says. “On the other hand, the most pessimistic scenario combinations show deficiencies of up to 10,000 MW by 2034. 

“While a negative statewide system margin is not, on its own, a violation of a reliability criterion, it is a leading indicator of the inability to securely meet system load under applicable normal system conditions.” 

“We’re really concerned about this whole analysis,” responded Kevin Lang, a lawyer from Couch White representing New York City. He said the margins that determined reliability needs were extremely small. While he said he appreciated the various scenarios and sensitivities included in the draft, he argued that NYISO had a responsibility to explain all of it to the public. The tight margins and differences in outcomes because of different assumptions made “material differences” to whether action had to be taken now. 

“This idea that we look at one baseline and say, ‘There’s no reliability need, no need to do anything’ — I think we need to reconsider that,” Lang said. “Because many of your scenarios suggest that there is something.” 

Altman agreed and said the ISO should not focus on a single determination or set of assumptions when there is a wide range of possibilities for how the system could evolve. The final CRP’s recommendations would make that clear, he said. 

One stakeholder said he hoped the ISO would emphasize that the uncertainties go in both directions so the public would not view forecasting uncertainties in “an overly negative light.” 

The draft shows several blank pages and notes about what will be included in the final report. 

“There’s no way we’re voting on this in October,” said Doreen Saia, chair of the environmental law practice at Greenberg Traurig. “We cannot rush this. We just got this information. It’s a lot of information. It’s going to be critical to formulate it correctly and responsibly.” 

She pointed out that the draft did not include an executive summary, conclusion or recommendations yet. 

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Data Centers ‘Exacerbating’ Tx Line Overload Forecasts in Bay Area

The construction of new data centers could lead to transmission line overloads in the Bay Area, CAISO forecasts show.

Speaking during a 2025/26 transmission planning workshop on Sept. 24, CAISO representatives said the Los Esteros-Metcalf 230-kV line in San Jose could become overloaded in both near- and long-term panning scenarios, with data center load “exacerbating this issue.”

Potential data center loads also contributed “significantly” to forecasted line and transformer bank overloads in the De Anza region, which is north of San Jose.

And in the East Bay region of the Bay Area, two of the East Shore 230/115-kV transformer banks and the Grant-East Shore 115-kV lines also show overloads under both near- and long-term scenarios, with a major contributing factor tied to forecasted data centers, CAISO said during the workshop.

Kanya Dorland, a senior analyst at the California Public Utilities Commission, asked if forecasted overloads in Palo Alto also were due to planned data centers.

“And if it is data centers, do you have confirmation that the data centers have control of the sites that they are going to be located at?” Dorland asked at the workshop.

“We have modeled these data servers from the [California Energy Commission] load forecast,” a CAISO representative on the call said. “At this point, we don’t know which overloads are caused by individual loads.”

“You don’t have any information about what is driving the overloads?” Dorland said.

“Right now, we haven’t dug into what exactly is creating the overloads, which we plan to do after this stakeholder meeting as part of mitigation development,” the representative said. “And then, from there on, we need to coordinate with Pacific Gas and Electric to see what they are finding as part of their load interconnection study and see what upgrades are necessary.”

“It would be great to have more transparency to show the amount of overload is contributed by data center loads,” Dorland said.

The representative said the ISO can’t guarantee that “we will be able to provide that kind of information.”

In Palo Alto, CAISO said there is a planned upgrade project of a 115-kV line, which will help alleviate some of the overload issues, but other issues will continue to persist. Compared with the previous transmission planning cycle, Palo Alto’s load forecast increased by 47 MW in 5 years, 70 MW in 10 years and 78 MW in 15 years.

In CAISO’s transmission planning process in 2025, the ISO implemented a new load modifier to represent data centers — the Data Server modifier.

The ISO continues to study potential transmission system overloads as part of its transmission planning process and will include recommendations in its draft transmission plan by the end of March 2026, CAISO told RTO Insider.

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ERCOT Board Approves AS Procurement for 2026

ERCOT’s Board of Directors has approved staff’s recommended methodologies for acquiring minimum ancillary service requirements in 2026, but not before revisiting the same discussions that stakeholders have over conservative operations and target procurement levels. 

The board’s Sept. 23 approval allows ERCOT to use a probabilistic methodology — an analytical approach incorporating randomness and uncertainty by assigning probabilities to outcomes and events — to calculate hourly ERCOT contingency reserve service (ECRS) and non-spinning reserve service quantities. The probabilistic model aligns ECRS and non-spin requirements with the risk profile, where higher risk equals a higher requirement and lower risk equals a lower requirement. 

Staff’s proposal also makes minor changes to regulation service and responsive reserve service (RRS). 

“I appreciate the tension between reliability and efficiency and cost effectiveness,” ERCOT CEO Pablo Vegas said as the hourlong discussion, scheduled for 20 minutes, wound down. “That’s a tension that I think we all deal with in what we do day to day.” 

The Independent Market Monitor again made the case that ERCOT is over-procuring non-spinning reserves and other long-lead-time ancillary services. It offered a compromise that halved the length of staff’s recommended look ahead at forecast errors or forced outages, from six hours to three, saying it would be just as reliable as staff’s proposal but for less cost. 

The Monitor also joined the consumer stakeholder segment in suggesting an end to the grid operator’s conservative operations approach, which stockpiles operating reserves in anticipation of tight conditions. 

“Somebody needs to figure out what the offramp is from conservative operations, so that we’re not just doing this forever,” IMM Director Jeff McDonald said. “I feel for ERCOT having been put in a situation where they have to incorporate that kind of an unwritten policy directive into their actual reliability operations, but there’s got to be an offramp for that.” 

ERCOT Director John Swainson pushed back against the Monitor’s recommendation. He questioned McDonald’s suggestion after ERCOT staff had said they were following the Texas Public Utility Commission’s criteria. In a 2024 report on ancillary services, PUC staff found conservative operations should be maintained to balance system improvements made since the February 2021 winter storm until additional data are available. 

“We have no idea how you calculated or what the hell you’ve done, and you come up with a different answer,” Swainson said. “We just can’t believe you. I mean, your credibility with us as directors is zero.” 

“I’m not really sure how to address that,” McDonald said in response. 

PUC Chair Thomas Gleeson offered McDonald a lifeline, saying the IMM and Potomac Economics’ David Patton have spent “a lot of time with me” on the issue as recently as the prior weekend. 

Texas PUC Chair Thomas Gleeson explains his thoughts on conservative operations. | ERCOT

“I’m in agreement with the IMM that we need to look at all of this,” he said. “I don’t think we should ignore the price formation aspects of the posture that we’ve taken … to ignore the price-formation impacts of the conservative operations posture that we’ve taken would be foolish, at least as I sit here as a commissioner.” 

Gleeson pointed to ERCOT’s Real-time Co-optimization + Batteries (RTC+B) project, to be deployed in December, and reliability standard analysis that will take up much of 2026 as reasons to wait before making further market changes. 

“While I agree that we need to look at this and potentially make some changes in this direction, I think it is more prudent to wait until next year,” he said. “I think this needs more discussion.” 

Adding “real time co optimization + batteries into the market is going to be one of the biggest market changes economically and operationally that we’ve gone through in over a decade,” Vegas said, agreeing with Gleeson that “it’s very prudent to see the impact of that over multiple cycles.” 

In the end, the board agreed with staff and other stakeholders to wait until 2027 to revisit and further examine ancillary service methodologies for potential adjustments. 

RTC+B Completes Major Test

“It feels like if it’s a football game, we’re first down and goal from the 8-yard line,” ERCOT’s Matt Mereness said in briefing the board on the RTC+B project. “There’s still a way to go, but things have been going pretty well.” 

Mereness, senior director of market operations and implementation and the RTC+B project manager, said the initiative is five months into market trials and testing and stabilizing systems. The first of two planned production tests was conducted Sept. 11; ERCOT operators controlled the real-time market and frequency for two hours, and market participants were able to submit accurate telemetry, bids, offers and follow RTC+B dispatch, he said. The RTC+B systems were able to award and dispatch energy and ancillary services in real time every five minutes. 

A second production test is scheduled for Oct. 30. ERCOT’s most significant market redesign since the switch from zonal to nodal in 2010, RTC+B is scheduled to be deployed Dec. 5. 

“We don’t normally take six months to implement something, but when you implement a major redesign of your real-time market and your four-second control of the system, you need to test it,” Mereness said. “It’s not just about ERCOT being successful. It’s about 95 other companies that are batteries, resources and generators that have to move their machines.” 

During the first production test, solar and wind energy dropped by 3,000 MW and two units tripped offline, but “other things” picked up. 

“It wasn’t necessarily an easy-peasy test like some of us thought it would be,” Mereness said. “The good news is that the operators and engineers are now looking at how [our system reacted]. The nice part of actually doing a dress rehearsal is people look at the money; they look at the megawatts; and they see if they can follow.” 

ERCOT plans to publish a market notice Nov. 5 to alert market participants that RTC+B is live and the transition has begun. 

Another ‘Mild’ Texas Summer

Barring an unseasonable warm spell during the fall, ERCOT will go a second straight year without setting a new demand peak, Vegas said during his update to the board. The grid operator recorded a high of 83.68 GW on Aug. 18, less than 2 GW from the all-time peak of 85.51 GW set in August 2023. 

While no new peaks were set during a “mild” summer — the June-July period was only the 43rd-hottest in recorded history — ERCOT’s energy consumption has grown year over year. Vegas said the consumption, which increased 2.53% from 2010 through 2020, has doubled to 5.12% since then. 

“This is a little bit like the proverbial frog that’s boiling slowly in a pot of water … and doesn’t realize that it’s actually boiling,” he said. “This is what’s happening here. Under the surface, we’ve got energy growth growing very rapidly, but because we haven’t had extreme weather events in the last couple of years, we have not seen new peak demands push up that peak demand level any higher. It’s important to not ever be lulled into complacency.” 

Vegas said ERCOT is at an “inflection point of an acceleration of demand growth.” Fortunately for the ISO, staff are analyzing 6,000 MW of new generation that will be synchronized to the grid in the first quarter of 2026. That’s the most ever studied at one time, Vegas said. 

Energy storage resources (3,042 MW) and solar (2,055 MW) account for much of the generation, with four gas projects accounting for the remainder (1,103 MW). Vegas said the first three Texas Energy Fund projects are among the gas projects under study. (See NRG Energy Secures $216M Loan from TEF.) 

“This is a positive trend,” he said. 

Solar and ESRs continue to be the ISO’s workhorses during the critical afternoon hours. Solar set four records during the summer, the last on Sept. 9 (29.83 GW); the 29.34-GW solar peak July 29 broke the grid operator’s mark for wind generation (28.47 GW) for the first time. ESRs also set records this summer, with a high-water mark of 7.51 GW on Sept. 10. 

“The additions of solar and batteries have helped us handle the growth in the summer months, where we’ve seen a lot more consumption,” Vegas said. 

Board Approves Transmission Projects

The directors approved two regional transmission projects that could cost as much as $827 million to build and that have been recommended by ERCOT’s Regional Planning Group and passed the Technical Advisory Committee. (See “$827M in Tx Projects OK’d,” ERCOT Stakeholders Endorse 2026 AS Methodology.) 

CenterPoint Energy’s Baytown Area Load Addition project in the petrochemical industrial region east of Houston is projected to cost $545.3 million for 45 miles of 138-kV lines and additional capacitors. CenterPoint submitted a $141.7 million estimate to address reliability issues caused by proposed new load; ERCOT staff said additional temporary work would be required for all structure replacements, accounting for about 45% of the capital costs, maintenance-outage issues and the expense of rebuilding 138-kV lines among industrial facilities. 

Bryan Texas Utilities’ Texas A&M University System RELLIS Campus project has an estimated capital cost of $282.1 million. The project includes 40 miles of new 345-kV double-circuit lines to the RELLIS campus; constructing or rebuilding about 10 miles of 138-kV lines; and expanding the campus’ existing 138-kV substation. 

Benjamin Barkley, CEO of the Texas Office of Public Utility Counsel, abstained from the vote on the Baytown project. 

The board also approved a price correction for the day-ahead market on its June 27 operating day. ERCOT said a software malfunction related to a generic transmission constraint affected day-ahead prices and wasn’t discovered until after the two-business day deadline for corrections. 

The correction resulted in a maximum absolute value effect of $26,525 to counterparties and $124,385 due to ERCOT. 

Complete Board Seated

Independent Directors Christopher Krummel, Kathleen McAllister and Bill Mohl, fresh off recent selections to the board, participated in their first meetings Sept. 22-23. They have also been appointed to the board’s subcommittees, which are fully rostered for the first time in 2025. (See ERCOT Fills out Board with 2 Final Selections.) 

Consent Agenda Passes

The board’s consent agenda included 10 nodal protocol revision requests (NPRRs), three changes each to the Planning (PGRRs) and Settlement Metering Operating (SMOGRRs) guides, two modifications to the Nodal Operating Guide (NOGRRs), single revisions to the Variable Cost Manual (VCMRR) and Retail Market Guide (RMGRRs), and a system change request (SCR) previously endorsed by TAC that will: 

    • NPRR1265: implement procedures for distributed generation reporting by clarifying DG’s definition and defining the new term, “unregistered distributed generators” (UDGs). The NPRR would establish procedures for UDG reporting to ERCOT and reporting requirements from the ISO. 
    • NPRR1266: specify that a transmission-voltage customer that is a securitization uplift charge opt-out entity may not transfer its status to other entities. The measure adds a requirement that a transmission service provider (TSP) associated with an electric service identifier originally granted opt-out status must compare at least monthly the names of transmission-voltage customers originally granted the status and inform ERCOT of any changes. The TSP requirement excludes those that are securitization uplift charge opt-out entities. 
    • NPRR1277: revise the minimum current exposure and estimate aggregate liability (EAL) formulas, improving the efficacy of existing credit formulas that measure credit exposures in the ERCOT market. The EAL formula revisions include applying the real-time forward adjustment factor against the respective days’ real-time liability estimated (RTLE) and then taking the max over the lookback period; and introducing seasonal variability in the lookback period as it is applied for RTLE. 
    • NPRR1279: enable generation resources to file exceptional fuel costs that include contractual and pipeline-mandated costs and strengthens the process for ERCOT and the Monitor to verify the costs. 
    • NPRR1281: strengthen the relationship between the settlement of firm fuel supply service (FFSS) and operations by clarifying its hourly rolling equivalent availability factor language to ensure the accurate calculation of the FFSS standby fee.  
    • NPRR1283: require that any necessary subsynchronous resonance studies be complete and mitigation be in place before the initial synchronization of an ESR, new generation resource or a settlement-only generator before the initial energization.  
    • NPRR1288: simplify the congestion revenue rights (CRR) auction by removing the ability to transact in multiple month strips that create optimization issues for ERCOT.  
    • NPRR1289: provide an option pricing report that would be posted following each CRR auction. The report will contain shadow prices for all biddable source-sink paths for each month within each time of use for the auction period and establish a minimum CRR bid of 1 MW. 
    • NPRR1290, NOGRR278: address several gaps and clarify protocol language to support the RTC+B initiative’s implementation. 
    • NPRR1291: incorporate the Texas PUC’s substantive rule setting a goal for average total residential load reduction into the protocols, specify data exchange methods and formats, and extend the deadline for posting the annual demand response report. 
    • NOGRR272, PGRR121: establish new advanced-grid support requirements — including model-quality tests and unit validation requirements — for inverter-based ESRs with a standard generation interconnection agreement executed on or after April 1, 2025. 
    • PGRR120: prevent generators from interconnecting to the ERCOT grid if they would be radial to a series capacitor under N-1 conditions. 
    • PGRR129: establish requirements for posting the Grid Reliability and Resiliency assessment and update a list illustrating data sets and classifications. 
    • RMGRR183: incorporate several updates that have been implemented as part of previous project improvements to transmission and/or distribution service providers’ Competitive Retailer Information Portal self-service tool. TDSPs will be able to assign weather moratoriums by county name instead of service territory. 
    • SCR832: discontinue and eventually retire a report not being used by market participants. 
    • SMOGRR032: incorporate the Other Binding Document “TDSP Access to EPS Metering Facility Notification Form” to standardize the approval process. 
    • SMOGRR033: incorporate the Other Binding Document “TDSP Cutover Form for EPS Metering Points” to standardize the approval process. 
    • SMOGRR034: remove obsolete gray-box language associated with NPRR1020 (Allow Some Integrated Energy Storage Designs to Calculate Internal Loads). 
    • VCMRR044: set the variable operations and maintenance cost in the mitigated offer cap for hydro generation resources to the real-time systemwide offer cap and the incremental heat rate value to zero. 
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Stakeholders Press IESO on Governance, Transparency

IESO’s plan to give its staff authority to set market parameters without approval by the Board of Directors has sparked a debate over the ISO’s governance and the role of stakeholders. 

The board has been responsible for setting parameters used in the calculation engines since the ISO’s market launch in 2002. But the changed composition of the board and increasing complexity under the Market Renewal Program (MRP) mean the process is “outdated,” Josh Duru, senior market rules and manuals adviser, said in an engagement session Sept. 16. 

The parameters include the maximum market clearing price (MMCP), maximum operating reserve price (MORP), constraint violation penalties and floor prices for variable generators, and “flexible” nuclear. The MRP added the determination of the settlement floor price to the board’s responsibilities. 

Under the proposed change, the parameters would be set by IESO, “with stakeholder input, in the same way in which most other market rule requirements are established,” the ISO said. The board would “maintain its usual oversight and approval function but should not be required to set technical parameters directly.” 

Changes to the Board of Directors

“At market opening, the board had 15 members, nine of which were stakeholder directors. So, at that point in time, they had the … very technical knowledge in order to set these values,” explained Jo Chung, supervisor of market rules and manuals. “But over the years, that has obviously changed, and we don’t have that stakeholder representation directly on the board.” 

The composition of the board changed as part of the 2015 merger of IESO and the Ontario Power Authority. 

The board, which is appointed by the provincial government, currently includes CEO Lesley Gallinger and five others: 

    • interim board Chair David Collie, former CEO of the Electrical Safety Authority of Ontario and a former executive at Burlington Hydro and Hydro One; 
    • Simon Chapelle, who runs a consulting firm focusing on telecommunications and rural economic development and is former municipal councilor for the city of Kingston; 
    • Frank Fazzari, head of accounting firm Fazzari + Partners; 
    • Tom Mitchell, former CEO of Ontario Power Generation (OPG); and  
    • Robert Wong, principal of executive consulting firm Hesketh Sloane Advisory and former chief information officer at Toronto Hydro-Electric System. 

  • Stakeholder Concerns

The proposal to change how parameters are approved led to a lengthy debate during the webinar about the ISO’s governance and transparency. 

“This seems like a pretty dramatic change, despite the fact that it’s being portrayed as something different,” said Akira Yamamoto, director of regulatory and market policy for TransAlta. 

Yamamoto said other grid operators have an “independent adjudicator” involved in approving changes for essential parameters such as price floors and caps. 

Akira Yamamoto, TransAlta | Independent Power Producers Society of Alberta

“That whole process … in Ontario is a little bit more inside baseball, but there was some process,” Yamamoto said. “And I think the entire elimination of it raises pretty significant concerns about how dramatically the market design could potentially be changed at, ultimately, a staff level.” 

Chung insisted the change is not intended to undermine transparency and noted that the MMCP and MORP have not changed in more than 20 years. 

Role for Technical Panel on Manuals

The discussion also touched on questions over what goes into the market rules, rather than the market manual, and when the ISO should bring such changes to the Technical Panel for public discussion.  

The Technical Panel has authority over changes to market rules but not manuals. (See What to Know About IESO.) 

“That’s always been a debate,” said Julien Wu, director of regulatory affairs at Brookfield Renewable’s Evolugen and a former member of the Technical Panel. 

IESO’s Duru said staff are discussing with the panel when it should review market manuals. 

“I’ll be very pleased if I see this matter actually addressed,” responded OPG’s Vladislav Urukov, who represents market participant generators on the Technical Panel. 

Vladislav Urukov, Ontario Power Generation | IESO

“If you remove the board oversight, and also were somehow able to make changes outside of Technical Panel oversight as well, I think that would be quite concerning. I think that there has to be some means for the participants to object and put counterarguments,” he continued. “And to date, I haven’t found that the baseline change process is robust enough and transparent enough and visible enough [to afford] such feedback. 

“What the ISO hasn’t really done to the extent that it ought to have is present analysis — technical analysis — that supports some of the values. … There has to be very robust, extensive analysis that participants can digest and challenge some of the assumptions … to be able to appreciate why the ISO is picking a value. You know, ‘Why is it 100 and not 125?’” 

Urukov added that he is concerned that “if the discussion of the manuals goes in a way that isn’t helpful, then there’s no guarantee that this would actually go to the Technical Panel. And if it’s only an education session, then there is no ability for participants to vote against or object.” 

IESO’s Chung responded that to change the MMCP, “the ISO would have to go through a very robust stakeholder engagement [and] probably include consultants to provide analysis. 

“We would not just change the value lightly. It would be a pretty big process.” 

Julien Wu, Evolugen | Ontario Waterpower Association

Wu said he agreed the board should not be setting technical parameters. 

But, he said, “there’s a difference between saying that the board itself is not going to set the parameters [and] removing that obligation for the board to have some kind of governance review of the parameters.” 

To “remove any kind of board oversight — that takes away the ability of market participants outside of the consultation process to document any kind of concern or disagreement with the output values,” Wu continued. “So maybe there is a middle way where the board itself doesn’t have the authority to set — or responsibility to set — these values, but there’s still a way, either through the [Technical Panel] or anywhere else, where serious concerns can still be [documented] by the market participants.” 

Less Discretion

Yamamoto said IESO should not expect stakeholders to give the grid operator the level of deference they did during the development of the MRP, saying the ISO should return “to a more robust forum.” 

“Saying, ‘Well, this worked for MRP, and therefore we’re going to design the going-forward processes as if we need all this discretion that we had in MRP’ is a wrong-minded approach,” he said. 

IESO: Goal is to Increase Transparency

James Hunter, IESO’s director of legal services, said the ISO is seeking to increase, not reduce, transparency and opportunities for input. 

He noted that the legacy rules do not require that the parameter values be published in either the rules or the manuals and gives the ISO board power to change them without any stakeholder engagement. 

“MRP introduced the constraint violation penalty values into the manuals for the first time in order to increase transparency around them,” Hunter said. “MMCP and MORP have never been published. We’re proposing to add them to the manuals. And the objective is not to request discretion from stakeholders. What we’re trying to do is bring the establishment of these values into alignment with other technical parameters that are in the market rules. 

James Hunter, IESO | James Hunter

“We want to increase transparency by publishing the manuals. … There’s opportunity for stakeholder feedback that has not been the case historically.” 

But, he acknowledged, “I think what we’ve heard today is — in various forms — the suggestion that maybe there’s a need or an opportunity for even more stakeholder involvement into establishing these values. 

“I think we’ll certainly talk about this [at the October Technical Panel meeting] as an instance of the more general question about how to determine where content is placed and rules and manuals.” 

Next Steps

Following the engagement session, ISO officials extended the deadline for written feedback on the proposal by one week to Sept. 30, as requested by Wu. 

The Technical Panel will discuss the proposal Oct. 7, with a scheduled vote Nov. 11, preceding a board vote Dec. 8. 

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Sturgeon Protection Eased as Empire Wind Makes Up Lost Time

The balance between benefit and harm that some regulators try to maintain has been reset again, this time to the potential detriment of an ancient fish slurping through the seabed off the New York coast. 

The state’s Public Service Commission previously had barred developers of the Empire Wind 1 project from laying their export cable in October and November to limit potential harm to the Atlantic sturgeon and shortnose sturgeon. 

But a 23-day federal stop-work order this spring put the offshore wind project behind schedule, and Empire petitioned July 3 to modify the time-of-year restriction and be allowed to work from Oct. 1 to Nov. 15 (21-T-0366). 

The PSC granted the request Sept. 18, finding that alternative approaches would present serious risks to the project or the endangered sturgeons or both, and risk delaying completion of an emissions-free 810-MW power facility the state is counting on to help meet its decarbonization goals. 

The possibility of harming the local ocean ecosystem in the name of protecting the planet is a rallying cry of offshore wind opponents, particularly the prospect of harm to whales. 

The ancient armor-plated sturgeon probably is not what comes to mind when most people think of the ocean. But its bottom-feeding habits and its migratory patterns may place it in the path of submarine cable installation crews in early autumn in the New York Bight. 

The choice here comes down to more fully protecting the fish vs. cleaner air for New Yorkers and a fractional reduction in the carbon emissions blamed for global climate change. 

The choice can be an uncomfortable question for those trying to save the planet, who likely would prefer to do all of the above. None of the three environmental advocacy organizations asked to comment for this story about striking a balance between harms and benefits offered any response. 

Developer Equinor gave NetZero Insider a list of steps it is taking to avoid impacting sturgeons with the cable installation and to mitigate what impacts do occur, but it offered no opinion on the harm-benefit balance. 

A PSC spokesperson explained in detail how the commission and its staff arm, the Department of Public Service, make these decisions and strike a balance: 

“Staff evaluates any modification applying the same thinking used generally throughout our transmission siting proceedings. Staff assess how these modifications will impact the environment and the public, balancing the need to complete projects in a timely and efficient manner that is consistent with approved construction practices, among other considerations, while also seeking to minimize impacts to the greatest extent practicable. This balancing must also consider whether the facility, or in this instance the requested amendment, will serve the public interest, convenience and necessity. Staff also consults with other agencies, such as [the Department of Environmental Conservation and Department of State], as appropriate to inform its review.” 

In this case, the DEC and DOS advised that continuing the cable installation work through October and November might adversely affect the protected sturgeon species but that pausing the work then resuming it in the winter or in 2026 would impact the sturgeon more significantly. 

The PSC approved the change unanimously as part of the Sept. 18 meeting’s consent agenda, the list of dozens of measures approved with a single vote without discussion. 

Ancient and Modern

The PSC record on the Empire Wind export line — two 230-kV HVAC transmission lines running to the Brooklyn waterfront — is a reminder of how complex the state’s regulatory regime can be. 

Empire Wind’s initial application in June 2021 for permission to build and operate the line was followed by 469 filings before the PSC finally approved the request in December 2023. As of September 2025, the record totals 743 filings, some pertaining to details as obscure as site fencing, dust control and unexpected recovery of human remains. Sturgeon protection constitutes only a tiny portion of the record. 

The sturgeons in question are part of a family estimated to have existed in similar form for more than 100 million years. With their bony armor plates, they are a living fossil of sorts, a throwback to the dinosaur era. 

Until the last 200 years or so, the waters of what is now New York were a good place for them to live. The 150-mile Hudson River estuary offered plenty of space to spawn and long expanses of riverbed muck hiding the small creatures they sniff out, slurp up and swallow whole. 

Thanks to overfishing and other conflicts with human activity, the shortnose and the New York Bight distinct population segment of the Atlantic sturgeon both are classified as endangered. But they still swim in the Hudson and the Bight, and they sometimes get caught by fishers pursuing other species or get smacked by passing vessels. 

The jetting and/or plowing of 15.2 nautical miles of trenches in the seabed is another potentially disruptive or injurious activity for them to cope with. 

To reduce the chance of harm, Empire Offshore Wind LLC said in the Sept. 25 revision of its sturgeon plan that it would: 

    • Monitor for acoustically tagged Atlantic and shortnose sturgeon before each start of construction, and suspend or delay construction if a specimen is within 200 meters of the work area.  
    • Station a dedicated visual observer on a monitoring vessel, watching for sturgeon or other protected species. 
    • Report sturgeon detections to researchers and regulators. 
    • Document and report details of injured or dead sturgeon.
    • Use a cushioned hammer, bubble curtain and silt curtain during pile driving. 

Beyond all this, Empire Wind will increase its contribution of mitigation funds to the Hudson River Foundation to assist with its research activities, which Empire expects will provide a net benefit to the two sturgeon species to offset whatever negative impacts the offshore wind project creates. 

Empire said in another PSC filing that it would use as little of the Oct. 1-Nov. 15 window as possible but that it could not predict a completion date. 

An Equinor spokesperson told NetZero Insider that the $7 billion Empire Wind 1 project is more than 50% complete. 

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FERC Denies IBR Clarification, Adds to OER’s Mandate

In separate orders issued Sept. 25, FERC denied a request for clarification of its order approving NERC’s new inverter-based resources ride-through standards, along with updating how the commission processes certain filings from the ERO. 

FERC approved NERC’s IBR ride-through standards, PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers) and PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) in Order 909, issued July 24.  

PRC-029-1 contained an exemption period that would give owners of legacy IBRs — resources already in operation when the standard goes into effect — 12 months after the effective date of the standard to request an exemption to the ride-through requirements. 

The order dealt with IBRs equipped with choppers, which are used in offshore wind projects to protect converters by dissipating excess power during grid faults. It directed NERC to determine whether those resources have challenges meeting the ride-through standards and account for the difficulty — and to estimate the “lead time between adopting IBR specifications and placing the IBR in service.” NERC must submit its determination, along with any other exemptions it deems appropriate, within 12 months of Aug. 28, 2025, the effective date of the order. 

However, the American Clean Power Association and the Solar Energy Industries Association (acting jointly as “Energy Trades”) then filed a request for clarification of the order Aug. 25 (RM25-3). The organizations expressed concern that, with PRC-029-1 to take effect Oct. 1, 2026, the industry would not have enough time to “make legally effective any proposed modifications submitted by NERC” if the ERO waited until Aug. 28 to make its filing, and claimed this “regulatory uncertainty” could create reliability risks in some regions. 

The Energy Trades asked FERC to clarify that NERC did not have to wait until Aug. 28 to file, and even encouraged NERC to file by May 28, 2026, saying “this would give the commission sufficient time to act on the filing.” But FERC declined to issue this clarification, said it considered the 12 months already given “a reasonable time frame for NERC to … make its decision” and expressed confidence the ERO would not delay its filing unnecessarily. 

FERC also pointed out that NERC has several options to address the Energy Trades’ concerns, such as updating its implementation plan for the modified standard or exercising its enforcement discretion to defer enforcement while registered entities implement the requirements. 

OER to Hear More NERC Cases

The commission’s orders also included a final rule reassigning the handling of certain NERC filings from the commission’s Office of Energy Market Regulation (OEMR) to the Office of Electric Reliability (OER) (RM25-13). 

Under current FERC regulations, the director of OER has the authority to approve uncontested applications from NERC, except applications pursuant to sections 39.8 and 39.10 of the regulations, which are handled by OEMR. Those sections respectively involve: proposals to delegate the ERO’s enforcement power to a regional entity; and proposed organizational rules or rule changes, including any RE rule or rule change. 

The change, which will bring all uncontested NERC applications under the purview of OER, was decided because of the office’s “frequent interactions with the ERO and OER’s applicable expertise,” commissioners said in the order. It will take effect immediately upon the order’s publication in the Federal Register. 

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Stakeholder Forum: Collaboration, Determination and Optionality are Keys to Continued Market Expansion in West

By Chris Robinson and Scott Simms

The future Western markets picture is in sharper focus now: We are progressing toward broad participation in two day-ahead markets. Such widespread participation in expanded market offerings may have seemed doubtful previously — even as recently as 10 years ago at the start of the Western Energy Imbalance Market (WEIM). Collaboration, determination and optionality have been critical to getting us to this pivotal point. 

Utilities and other market participants have recognized the potential benefits of expanded market participation and have worked hard to develop market options that meet their needs — including creative solutions that do not require participation in an RTO, new governance structures, and market designs that are compatible with continued OATT transmission service. Developing such options has facilitated organized market participation to grow, both geographically and in the breadth of services offered. 

Chris Robinson

The passing of AB 825 marks a significant milestone for planned EDAM participants, laying the groundwork for implementing the Pathways “Step 2” proposal. This proposal will establish a new regional organization that will partner with CAISO to implement the Extended Day-Ahead and Western Energy Imbalance markets. At the same time, PacifiCorp and Portland General Electric have had their EDAM tariffs approved by FERC, and all signs indicate a 2026 go-live date. 

Meanwhile, Markets+ also is moving forward with implementation. Nine utilities have made substantial financial commitments to secure the development of the market, with more utilities indicating their intent to join. In addition, many more participants and stakeholders are actively engaged in this final implementation phase. The market go-live is in 2027. 

While we know there is frustration among some parties that a single market could not be achieved, ultimately the region should celebrate the collective progress that these markets represent and respect the decisions that each entity has made regarding its individual participation.   

For entities such as PPC, Tacoma and BPA (as described in their Day-Ahead Market Policy Record of Decision, Appendix B), the risk of participating in a market that continues to have statutory ties to a single state or subset of market participants is untenable. 

Scott Simms

Even under the Pathways governance proposal — which is enabled by California AB 825 — CAISO continues to retain statutory obligations to the people of California and legally must be the operator of EDAM in order for California entities to participate. We respect the decision some entities have made that this level of independence is sufficient for their participation in EDAM, but it continues to be a deal-breaker both for us and for many others.   

It is our hope that after many participants have made their market decisions, both market tariffs have been approved by FERC, governance structures are known, and implementation efforts are under way, we can all turn our attention to good faith efforts to make the soon-to-coexist market approaches in the region as successful as possible. 

Achieving the additional efficiency and access to resources that will be offered by either market will benefit the region much more than having utilities not participating in organized markets — which is a likely outcome without the optionality that has been developed. As long as entities across the West remain committed to continued regional trade, coordination and reciprocal efforts to enable market participation, there can be significant benefits for the region at large. 

We applaud our colleagues whose hard work, determination and collaboration were able to bring AB 825 over the finish line. Our hope is that we collectively can bring that same energy and genuine spirit of collaboration to the hard work needed ahead to successfully implement both markets, including seams negotiations when the time is right. 

Chris Robinson is general manager of Tacoma Power and is the Public Power Council Executive Committee chair. 

Scott Simms is the CEO & executive director of the Public Power Council. 

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Advocates Defend Energy Efficiency Programs in Massachusetts

Climate and consumer advocates are calling on Massachusetts lawmakers to preserve the state’s energy efficiency programs as legislators work to develop an energy affordability bill in response to high gas and electricity costs over the past winter. 

Advocates have expressed concerns that lawmakers may roll back efficiency spending to provide short-term relief to ratepayers. They defended the state’s Mass Save efficiency program at a hearing held by the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) on Sept. 25. 

While Massachusetts’ energy efficiency programs frequently rank among the best in the country — with the state placing second on the American Council for an Energy-Efficient Economy’s (ACEEE’s) 2025 State Energy Efficiency Scorecard — the programs have drawn increased scrutiny over the past year amid increased affordability concerns. 

Over the past winter, sustained lower-than-average temperatures drove high energy prices across New England. In Massachusetts, higher gas supply rates coincided with increased distribution rates, which were driven largely by investments in Mass Save and a state program to replace leaky gas pipes. 

Following public pressure for immediate rate relief, the Massachusetts Department of Public Utilities in late February ordered $500 million in cuts to the Mass Save budget. The utility-administered program is funded through charges on gas and electricity rates, and it offers rebates and incentives for building insulation, efficient appliances and heat pumps.  

While the 2025/27 budget — totaling $4.5 billion after the cut — still is higher than the $4 billion for 2022/24, the reduction drew some criticism from efficiency advocates, who argued it would reduce the long-term benefits of the investment. 

The Massachusetts Department of Energy Resources estimated the original $5 billion investment would return $13.6 billion in overall benefits, including $5.4 billion in direct energy savings. The 2025 ACEEE scorecard estimated that Mass Save investments have returned $3.50 for every dollar invested since 2013. 

Political battles over energy efficiency funding are not limited to Massachusetts; Rhode Island Energy has proposed to cut its program’s funding by 18% in 2026 compared to 2025 levels. 

Meanwhile, the federal One Big Beautiful Bill Act eliminates significant tax credits for HVAC equipment — including heat pumps, electrical upgrades and insulation — at the end of 2025. 

At the TUE Committee hearing Sept. 25, advocates argued that additional efficiency spending must not be put on the chopping block as lawmakers look for near-term rate savings. 

Amy Boyd Rabin, vice president of policy and regulatory affairs at the Environmental League of Massachusetts, advocated for legislation to “create a mechanism to fund energy efficiency and decarbonization efforts beyond our electric and gas bills, taking the burden of Mass Save off of ratepayers’ backs, without hurting the programs or the benefits they can deliver for consumers and the climate.” 

She estimated that Mass Save “has reduced Massachusetts’ energy use by 13.9 billion kWh annually, or 28% of current electricity sales. That’s equivalent to the annual production of all our renewables in ISO-NE each year.” 

Boyd Rabin added that, since its inception, the program has provided “$40.3 billion in benefits” from $11.8 billion in spending, a 3.4-to-1 return on investment. 

“No financial adviser on Earth would urge us to pull out of a fund returning $3.40 for each dollar you put in,” Boyd Rabin said. 

Kyle Murray, director of state program implementation at the Acadia Center, emphasized the regionwide wholesale markets price suppression benefits of these investments. 

He pointed to the ISO-NE capacity scarcity event June 24, when locational marginal prices spiked to $1,110/MWh between 6 and 7 p.m., and highlighted an Acadia analysis estimating that demand reductions associated with behind-the-meter solar saved the region $19.4 million during the day. (See Extreme Heat Triggers Capacity Deficiency in New England and Behind-the-meter Solar Shines in ISO-NE Capacity Deficiency Event.) 

“ISO-NE does not similarly track the impact of energy efficiency. However, make no mistake: But for those critical investments we have made in energy efficiency over the years, those price spikes would have been dramatically worse,” Murray said. 

Responding to public comments, Sen. Mike Barrett (D), TUE co-chair, spoke favorably about energy efficiency investments, noting that, by statute, Mass Save spending is justified only “when it’s the least expensive alternative” to meeting power demand.  

He expressed concern that, while the costs associated with Mass Save are outlined on electricity bills, the savings are not easily apparent to ratepayers, masking the program’s benefits. 

“Mass Save is not Robert Redford; Mass Save is a character actor that gets lost in the scene precisely because they’re effective,” Barrett said. 

Rep. Mark Cusack (D), who is in his first year as the House co-chair of the TUE Committee, largely did not respond in substance to the public comments at the hearing, which were overwhelmingly supportive of preserving or expanding the state’s energy efficiency and building decarbonization programs. 

Rep. Jeffrey Turco (D) appeared more skeptical about efficiency investments, saying that “to the consumer, we keep hearing that we’re saving $3.41 for every dollar invested, but the cost of electricity is going up every year, and it’s by design.” 

Increasing the cost of electricity in the short term in pursuit of long-term benefits causes consumer frustration “because the utility keeps going up, and despite saying, ‘Yes, we’re saving you money,’ the proof is not in the pudding on a monthly basis,” Turco said. 

In response, Murray said, “One of the most difficult challenges of energy efficiency is that it’s difficult to prove a negative.” 

He stressed that while the value of efficiency can be hard to quantify precisely, “if we don’t continue to do this, you’re asking constituents in five, 10, 15, 20 years to bear significantly higher costs.”