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March 4, 2025

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MISO Approaching LMR/DR Accreditation Based on Availability

CARMEL, Ind. — MISO is nearing an overhaul of its capacity accreditation methods for load-modifying resources (LMRs) and demand response that would be based on whether they can assist during periods of high system risk.

The grid operator plans to accredit LMRs and its emergency DR and behind-the-meter generation depending on their offers during low-margin and risky hours where a capacity advisory, maximum generation alert or warning, or energy emergency is in place. The RTO reasoned that those hours best reflect when it is likely to need those resources.

MISO said it would require DR and LMRs to designate a response time when registering their assets. It plans to dock accreditation when resources report inaccurate availability.

Joshua Schabla, MISO market design economist, said the RTO has “dozens” of DR resources that have never updated availability throughout a planning year.

“We want to accredit a resource based on when it’s most needed. That’s the crux of this,” Schabla told the Resource Adequacy Subcommittee on Feb. 26. He warned that MISO compensates resources that never perform, and he said some resources “look like they exist when they in fact do not.”

MISO said data from its demand-side resource interface show that about 2 GW of DR is accredited but is never designated as available or self-scheduled.

The RTO plans to rely on the past year as a reference for accreditation. Staff said they are aware that using a single year makes for a more severe accreditation style, but that is by design to send a signal to respond. Last year it mulled using the past three years as a reference but decided that would water down accreditation too much.

Additionally, the RTO plans to split its LMR category into rapid responders with greater responsibility and those with a more lenient availability scheme by the 2028/29 planning year. (See MISO Closing in on New LMR Accreditation.) Nimbler LMRs would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step 2 events. Slower LMRs would have a maximum six-hour response time and would be called up earlier — sometimes on a voluntary basis — during maximum generation warnings.

The accreditation plan would have an all-or-nothing aspect: MISO plans to assign zero values for the entire duration of an emergency or near-emergency event when resources fail to make any contributions for even one hour.

“It sounds harsh; it sounds mean. But that’s the line we’ve drawn in the sand. … That’s the tension we experience between availability and adequacy,” Schabla said.

He also said MISO wants to transition to an unlimited number of deployments instead of limiting DR’s deployments to a handful of times per season, as is practice now.

However, after a DR resource, BTM generator or the slower LMR type deploys once in a year, they can choose to declare themselves as unavailable in future deployment calls in exchange for reduced accreditation. Schabla said those resources can decide if a deployment is too expensive to carry out. The category of faster LMRs, on the other hand, would not be permitted to designate themselves as unavailable under any circumstances.

MISO staff have stressed that it is imperative that LMRs respond when called upon to retain resource adequacy as the fleet transitions.

“We want to make sure their accreditation is tied to their performance,” Zak Joundi, executive director of market innovation, said in front of MISO South regulators Feb. 24. Joundi reminded attendees that LMRs have chosen to register as capacity resources.

As part of its accreditation filing, MISO plans to debut a capacity availability tolerance band for DR resources, in which they would be required to perform between 88 and 112% of their stated load-reduction capability. MISO would cap the tolerance band at no less than 1 MW and no more than 30 MW for underperforming resources. Despite the upper bounds of the tolerance band, DR resources would not be penalized for overperformance.

Some stakeholders have said the tolerance band is too complex to include in the new accreditation method.

“Forecast errors are inevitable, and penalties are not appropriate for LMRs providing good-faith estimates,” WPPI Energy’s Steve Leovy said. MISO should waive accreditation penalties when LMRs provide “near-real-time demand data” or have used rigorous forecasting methods to estimate their availability, he said. A few tens of megawatts of standard deviation should not make a difference to MISO operations, he argued.

Schabla said LMRs using a firm service level to gauge reductions instead of a megawatt amount would not face accreditation penalties without the tolerance band. He pointed out that LMRs specifying megawatt reductions likewise face performance penalties. MISO’s DR resources can use either a firm service level or a megawatt value as the measuring stick for their reductions.

“We believe it’s fair to treat all demand response resources the same,” Schabla said, stressing that resources should be indicating their availability. He said there are LMRs in MISO who input the same availability information year-round, never adjusting for likely seasonal changes. The RTO expects DR to perform when called on, even if it proves expensive for the resource. Schabla said it is only fair that unresponsive resources take hits to their accreditation when unavailable.

“We’re paying you for years in between deployments,” he explained, adding that MISO compensates LMRs to respond only in emergency situations.

The RTO has called up LMRs 12 times since 2017, with half of those occurring during winter storms over the last few years.

“These events are very infrequent, and that’s to be expected in a system with a one-day-in-10-years reliability standard,” Schabla said.

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Study Finds Considerable ‘Grid Flexibility’ Potential in New York

A Brattle Group study released in February found that New York could achieve 8.5 GW in “grid flexibility” measures by 2040, saving consumers more than $2 billion a year.

The study was commissioned by the New York Department of Public Service as part of its Grid of the Future initiative, which defined grid flexibility as the “ability to shift either demand or supply to meet bulk power system and/or local distribution needs.” (See NY PSC Launches Grid of the Future Proceeding.)

The 8.5-GW figure is roughly 21% of NYISO’s forecasted winter peak demand and more than six times the current potential of 1.2 and 1.4 GW in the winter and summer, respectively. Grid flexibility measures could help by “displacing the need” for higher-cost resources, the study says.

“This report has really important implications for regulators, decision-makers and figures in industry,” said Amy Heart, senior vice president of public policy at Sunrun. “It sets out what the potential is, and how to get there. It demonstrates that this isn’t theoretical.”

The study says that implementing grid flexibility improvements could avoid $2.9 billion a year in power system costs by 2040, $2.4 billion of which could be returned to consumers. These cost savings come primarily from reducing how much investment in generation capacity would be needed to maintain reliability. Avoided distribution and energy costs were $408 million and $384 million, respectively.

“Really for the first time this says that there is a unique way for a flexible grid to meet this growing demand,” Heart said. “And we have the potential to use these resources and build programs that are cost effective.”

Currently New York’s grid flexibility primarily comes from NYISO demand response programs — Special Case Resources and Emergency Demand Response — amounting to about 1,300 MW of flexibility. An additional 414 MW of flexibility is facilitated by the Economic Demand Response program, in which large consumers reduce loads based on price signals in the day-ahead market.

Brattle found that managed electric vehicle charging, heat pump load control and residential behind-the-meter storage all had significant potential for increasing grid flexibility. In a future report, Brattle will examine the potential of thermal energy storage, thermal energy networks, increased efficiency, front-of-meter distributed storage and large loads with microgrids.

“This flexibility study is looking at things that we’re either currently doing or really close to doing, moving out of a pilot phase into mass market,” said Deb Peck Kelleher, deputy director of the Alliance for Clean Energy New York, highlighting EV charging demand-reduction programs. “I’m glad to see that those programs are working as they were envisioned to work.”

Noah Ginsburg, executive director of the New York Solar Energy Industries Association, said that he was pleased that the report looked at the grid in a holistic way and that it did a good job identifying both barriers and opportunities for flexibility.

“The moral of the story to me is if we are smart and address these barriers and create the right pricing and regulatory conditions to deploy a lot of these flexible assets, that’s just a huge savings opportunity,” Ginsburg said.

Barriers Identified

Brattle identified several key barriers to getting grid flexibility measures implemented, with the lowest-hanging fruit being regulatory barriers like zoning, permitting and lack of state goals.

This hampers adoption by consumers and does not incentivize utilities to incorporate grid flexibility into their projections. The study also notes that New York’s cost-benefit analysis framework may undervalue flexibility initiatives, leading to the deprioritzation of some technologies.

Brattle is saying, “‘Hey, just make this simple and effective and easy for customers to navigate, to sign up and to bring these resources to the table,’” Heart said. “These are the sort of tangible actions that we can get everyone together and hammer out.”

Tariff complexity prevents consumers from understanding or evaluating potential benefits from established compensation mechanisms. Utility tariffs also lack support for bidirectional distributed energy resources, like chargers and batteries, which depresses adoption. Retail rates also are not designed for customers to take advantage of grid flexibility.

Ginsburg said that local building codes compound other regulatory problems. He noted that in most of the Consolidated Edison footprint in New York City, residential battery storage is banned for fire safety reasons.

“This isn’t a matter of getting batteries built; it’s a matter of fairness,” Ginsburg said. “Frankly, New York City and Con Ed ratepayers are funding a lot of the statewide incentive programs that the city of New York doesn’t allow them to access.”

Now that Brattle had identified the barriers, it was now on DPS to pick a pathway to advance, Ginsburg said. He said he hoped this would lead to improved rate design and compensation for distributed storage programs both behind and in front of the meter.

Peck Kelleher said that the biggest challenge for DPS would be coordinating across all of its various proceedings and initiatives revolving around grid modernization.

“It was great work that was published by the Brattle Group,” Peck Kelleher said. “But how to take that data and inject it into each of the separate proceedings and keep them going in the same direction” will be a challenge.

Realistic?

“I think all power systems have unexploited flexibility and that something can, and should, be done,” said Francisco de Leon, a professor of electrical engineering at New York University. “I don’t think flexibility is the final answer to electric energy challenges of the future because its full-blown implementation (as described in the report) is very expensive.”

While de Leon said he was not opposed to the idea of increasing grid flexibility, the report was being “overly optimistic” about grid flexibility. He said the expected cost of generation in the report was far too high for the state to bear politically.

“Using the numbers in the report, the cost of marginal generation of electricity is expected to increase from $40 to 70/kW-year to over $200,” de Leon wrote in an email. “Would you like your electricity bill to increase by three to five times?”

Brattle says its analysis “found that overall net costs may be small relative to the size of the state’s economy and will be offset by the health and societal benefits. Nevertheless, managing power system costs will be crucial to delivering an affordable transition for New Yorkers.”

But de Leon said to expect a change of state government if the price of generation goes up that high as a result of decarbonization. With the current federal government not investing in renewables, and likely consumer unwillingness to deal with such steep price increases, decarbonization by 2040 was extremely unlikely, he said.

While load shifting could be “low hanging fruit,” de Leon was also pessimistic about HVAC upgrades serving as a cost-effective way to reduce demand. He said that the cost of acquiring and installing new heat pumps makes retrofitting cost “thousands of dollars per room,” which is difficult to sell to homeowners and “impossible” to sell to renters.

“We should not pass on the opportunity of heat pumps for new construction,” de Leon wrote. “But in my opinion the cost to retrofit old buildings is very large.”

Demand for electricity is going to grow in New York, whether from AI centers or electrification or manufacturing; no matter what the cause, people still want ways to manage their electricity, Heart said.

“The question becomes how are we going to squeeze as much juice out of these resources that are in people’s homes and businesses to help keep those costs low,” Heart said.

She pointed to the distributed resource deployment in Massachusetts where consumers can enroll in smart thermostat, solar and battery programs that compensate them for injecting power into the grid. (See Mass. DPU Approves 1st Round of Utility Grid Modernization Plans.)

“They have a very successful program,” Heart said. “While we encourage experimenting, we’ve done pilot programs; you don’t have to start from scratch. You can take this framework.”

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Wash. Bill Seeks to Attract Fusion Energy Developers

A bill to help attract nuclear fusion energy ventures to Washington is working its way through the state legislature.  

House Bill 1018 would allow developers of fusion projects to approach either the Washington state government or appropriate county government for permission to build on a parcel of land in the state. That would give fusion projects the same options that solar and wind energy ventures have in picking their approving authority.  

Most solar and wind developers in Washington have chosen the state as the entity less likely to bow to local opposition to a project.  

The state pathway in Washington is through the Energy Facility Site Evaluation Council (EFSEC), a committee of representatives from several state government departments. EFSEC makes recommendations to the governor, who issues final decisions. 

The Washington House approved HB 1018 95-1 on Feb 6, and the bill is now in the Senate’s Environment, Energy and Technology Committee.  

The Puget Sound area now boasts five fusion-related ventures. They include Helion Energy, which is working to provide fusion power to Microsoft by 2028; Zap Energy and Avalanche Energy, which are also working to develop fusion reactors; and ExoFusion and a subsidiary of Japan-based Kyoto Fusioneering, which are developing fusion-related technologies. 

Helion and a separate project at Lawrence Livermore National Laboratory have achieved fusion reactions that release more energy than went into the reactor. Based in Everett, Wash., Helion in January landed $425 million in funding from various investors. 

At a Jan. 20 House committee hearing on the bill, Helion representative Tom Bugert did not commit to a specific timeline for when fusion power would be commercially viable, but said “it’s right around the corner.”  

“I believe fusion energy is the future of clean energy. … This bill will attract cutting-edge research,” said Rep. Clyde Shavers (D), the bill’s sponsor. No one spoke in opposition to the bill during the hearing. 

Meanwhile, three other bills involving EFSEC died in committee because no action was taken on them by the Feb. 28 deadline to leave their committees. These were:  

    • House Bill 1188, which would have required affected tribes and the host county to approve an energy project before EFSEC makes its recommendations to the governor. The bill was a Republican response to EFSEC last year recommending that then-Gov. Jay Inslee approve a large wind farm in the Horse Heaven Hills area of Central Washington despite opposition from the Benton County government and local residents. Inslee approved the project. (See Wash. Gov. Approves Controversial Wind Farm.) 
    • Senate Bill 5283, which would have prohibited EFSEC from ignoring land use or zoning laws for siting electrical battery storage facilities in environmentally sensitive areas. The bill also represented a GOP reaction to EFSEC overruling Benton County’s land use and zoning laws. 
    • House Bill 1237, which was Democratic legislation that would have required a public hearing prior to an EFSEC recommendation in which the council determines that a proposed site is not complying with applicable land use plans or zoning ordinances. 
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Data Center Grid Integration Top Theme at CEC Workshop

As some data center operators plan to power their facilities with onsite generation, one researcher suggested it might be better to get electricity from the grid instead. 

“At the end of the day, the hyperscalers do not want to be in the business of running a powerhouse on their data center property,” said David Porter, vice president of electrification and sustainability at the Electric Power Research Institute. “What they really want long-term is a reliable and resilient power supply. And that doesn’t come from any better place than the grid.” 

Porter’s comments came during a California Energy Commission workshop Feb. 26 on California’s economic outlook, including data center growth. The workshop is part of the CEC’s 2025 Integrated Resource Planning Report (IEPR) process. 

Even if a data center had small modular reactors or a combined cycle turbine on site, Porter said, operators would have to contend with maintenance, refueling and repairs. 

“And it’s not a great equation for anybody that is connected to the grid to have the grid operator provide only backup service in times of extreme need and have to hold capacity back in their planning processes for some of those rare-type conditions,” he added. 

An issue for data centers is that the energy-intensive facilities can be built relatively quickly but may need to wait for capacity or transmission infrastructure. 

Helen Kou, a global research lead on data centers at BloombergNEF, said a standard feature of data centers is a backup generation system for reliability. But grid interconnection issues are now prompting data centers to explore a broader role for onsite generation. 

“As data center loads continue to scale, the exact mix of onsite generation, be it natural gas, batteries, renewables or small modular nuclear, really just ends up depending on the project timeline, local regulatory frameworks and the corporate sustainability goals of the data center facility owner,” Kou said during the CEC workshop. 

Bridging the Gap

Another strategy is the use of “bridge” solutions to meet a data center’s energy needs until transmission is available. 

That could mean bringing in skid-mounted generation, Porter said, or installing solar-plus-storage to temporarily serve the data center. Even after the data center connects to the grid, the solar-plus-storage could stay in place in front of the meter as a grid resource, he added.  

Another hot topic for data centers is their ability to be flexible in their energy use, particularly during grid-constrained hours. 

One possibility might be for a data center to tap into its backup generation system at those times, panelists said. That could create air quality issues if backup power comes from diesel generators. But other technology is available.  

Panelist Kushal Patel from Energy and Environmental Economics (E3) pointed to a Microsoft data center in San Jose, Calif., that has a backup power microgrid fueled by renewable natural gas. The RNG microgrid also allows Microsoft to participate in PG&E’s Base Interruptible Program, which pays customers to reduce electricity use when energy supplies are tight. 

“The kind of capability and the kind of resource may be there,” Patel said. “Are there the right kind of regulatory incentives, policies in place to be able to maximize that?” 

EPRI in October announced an initiative called DCFlex, which will establish flexibility hubs for data centers to try out new strategies that boost operational and deployment flexibility, streamline grid integration, and transition backup power solutions to grid assets. (See EPRI Launches DCFlex Initiative to Help Integrate Data Centers on the Grid.) 

The initiative is bringing together hyperscalers, data center developers, technology providers, utilities, ISOs and RTOs. In February, EPRI announced an expansion of the program into Europe. 

Peak Load Growth

In its 2024 IEPR, the CEC projected about 3,500 MW of new data center peak load in California by 2040, on top of roughly 1,000 MW in 2024. (See CEC Ups Data Center Demand Forecast After PG&E Revisions.) Those estimates will be updated as part of the 2025 IEPR. 

Southern California Edison has about 80 MW in existing data center demand and is forecasting an increase to 1,000 MW by 2045, Elliot James Dean, an SCE data science specialist, said during the CEC workshop. Uncertainty in the forecast comes from potential on-site generation, increased energy efficiency, technology advancements and market conditions in the SCE service territory. 

The data center pipeline in Pacific Gas and Electric’s territory totals 5,500 MW, including almost 1,500 MW in final engineering or construction, according to a workshop presentation. 

One key question for utilities is how many inquiries from data centers are “real” versus an information gathering process to compare different regions. Dean said SCE has started assigning a confidence level to each project, based in part on whether it is also making inquiries elsewhere. (See Data Center Load Uncertainty Tied to Broader Economy, Google Rep Says.) 

“That is not very straightforward,” Dean said. “And clear communication from the project is greatly appreciated on that piece for sure.” 

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As Policies in Washington Change, Grid Investment Still Needed

WASHINGTON — Even as President Donald Trump and the new Republican-controlled Congress begin to roll back the clean energy policies of the Biden administration, the grid still needs to expand to meet new demand and become more resilient to extreme weather, state regulators heard last week.

Democrats tried to pass numerous transmission “permitting reform” bills last Congress to help realize the clean power investments in the Inflation Reduction Act, and that has impacted the partisan split on the subject. But now that demand is growing at a pace not seen in decades from data centers, the need to expand the grid goes beyond connecting renewable resources that are far from cities.

“We’re trying to solicit as many comments as we possibly can so that we can get this right, because it’s going to be threading a needle between the Republicans and the Democrats,” Sen. Shelley Moore Capito (R-W.Va.), chair of the Senate Environment and Public Works Committee, said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit. “There’s certain things that I might want that I’m going to fight hard for. There’s certain things, particularly on the transmission side, that the Democrats want. We’re going to try to marry those up and make an effective and long-lasting permitting.”

“There’s a lot of voices making that connection: that companies are looking for electrons,” Clean Energy Buyers Association Senior Director Bryn Baker told reporters Feb. 26 in a webinar on the state of transmission policy under the Trump administration and the new Congress. “And that there are economic advantages to those states and regions that are proactively planning for transmission, and that’s fundamental to getting those industries sited and built here.”

Serving the new loads from data centers, which are being built out by some of CEBA’s members, will require all kinds of investment in transmission, from interregional lines to reinforcing the existing system with grid-enhancing technologies and advanced conductors.

“I think transmission is kind of under that umbrella of energy infrastructure,” Americans for a Clean Energy Grid Executive Director Christina Hayes said on the webinar. “We’ve heard a lot more clarity under Secretaries [Doug] Burgum and [Chris] Wright [head of the departments of the Interior and Energy, respectively] talking about the importance of the backbone of the grid.”

Four years ago, predictions for demand growth were flat in most of the country, and AI was more of a vague concept for science fiction novels than it was a reality both on app stores and in the physical world, she said.

“The growth of data centers and artificial intelligence is driving up energy demand in ways we have not seen in decades, making transmission reform even more critical,” Hayes said. “Despite significant discussion about energy policy, we still need more definitive action, especially if we want to meet our projected energy demands.”

Even without hyper-scalers driving demand to new levels, the power system needs to be adequately maintained, and Exelon CEO Calvin Butler said that requires some spending. He recalled that before his company bought Pepco, the utility was running about a 6.4% return on equity and was in the fourth quartile for reliability.

“The utility wasn’t meeting its obligation to provide strong customer service and strong reliability,” Butler told NARUC during a panel on capital markets Feb. 25. “What we have recognized as a company [is that] operations and high customer satisfaction are foundational elements. We have to do that well before we can come to you and talk about our long-term strategy.”

By 2021, Exelon had gotten Pepco’s ROE up to 9.4% and its reliability improved by 50%, which involved investing in the underlying infrastructure needed for reliable and resilient service, Butler said.

In a panel Feb. 24 at NARUC on mutual assistance during extreme weather events, Southern Co. CEO Chris Womack said his firm was ready to meet demand from new sources thanks to the amount of investments it has made in its system, including new generation.

“With the careful oversight of our state regulators, elected officials, customers and shareholders, we have designed and engineered a remarkably flexible, resilient and affordable system,” Womack said. “We recently added new nuclear generation and now can dispatch in the largest nuclear station in America at Plant Vogtle.”

The Trump administration’s goal is for “energy dominance,” which Womack said translates to energy abundance that is important to meeting the new loads coming online in Southern Co.’s utility territories.

“Both energy dominance and energy abundance require a safe and secure energy grid, and thankfully, our nation’s power grid is up to that challenge,” Womack said. “It is advanced; it’s flexible and is integrated in a way that allows us to rely on each other day to day.”

Wildfires are becoming more common in Oregon, Portland General Electric CEO Maria Pope said. Devastating fires in California last decade caused its northern neighbor to start considering how the events could impact its utilities back when they were rarer, which proved prescient as Oregon saw more acres burn than any other state or Canadian province in 2024.

Now wildfires are so common, Pope argued that regulators need to insulate utilities from potentially devastating litigation as long as they can prove they followed a set of best practices, which would be similar to legal defenses against medical malpractice.

“Until we have something like that across this country, we’re going to continue to have economic hardship on the utilities,” Pope said. “Wildfire is an example. Like all the storms we’re talking about here, disasters are society-wide problems, and they need a society-wide solution, not just the backstop of a utility and the devastation that that brings the utility’s balance sheet.”

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ERCOT TAC Opens Discussion on Proposed RTC Changes

AUSTIN, Texas — ERCOT staff and the Technical Advisory Committee’s leadership teed up for discussion Feb. 27 a pair of protocol revision requests related to the grid operator’s real-time co-optimization (RTC) and battery project, set to go live in December.

That gave TAC’s members an early opportunity to dive into the two proposed changes (NPRR1268 and NPRR1269) and lay out their concerns before the cadence of meetings quickens and they are brought for approval before the ERCOT Board of Directors in April. Staff hope to resolve those concerns, clearing the way for market trials and implementation.

“We really only have one shot at these in March,” said TAC Chair Caitlin Smith, with Jupiter Power, alluding to the committee’s only remaining meeting before the board gathers.

“Now is the time to engage as needed,” ERCOT’s Matt Mereness, chair of the Real-time Co-optimization plus Batteries Task Force, told TAC. “This is why we wanted to get it on the table. We didn’t want this to happen next month, when we’re under the gun.”

Two key upcoming meetings are those of Mereness’ task force (March 5) and TAC’s Protocol Revision Subcommittee (PRS) (March 12). The PRS is responsible for reviewing and recommending action on formally submitted NPRRs.

TAC would then consider the likely revisions to the proposed changes and any new NPRRs during its March 26 meeting. The board will meet April 7-8, with RTC market trials set to begin in May.

“That’s a pretty tight timeline,” Smith said. “There’s not really time for an extra TAC [meeting] between [March 26] and the board” meeting.

Much of the discussion centered on NPRR1269, staff’s effort to codify policy changes that were deferred from the original RTC-related protocols developed in 2020: parameters for ancillary service proxy offers floors; scaling factor values for ramping; and AS demand curves (ASDCs) for use in reliability unit commitment (RUC) studies.

ERCOT’s Independent Market Monitor filed comments saying proxy offers should be set at fixed values corresponding to the variable cost to provide the service. It said setting ASDC at 95% of the AS plan for a given product — as ERCOT plans to do — “results in proxy prices that are excessively high at times and could lead to reliability and market performance issues.”

The IMM also said capping AS’ proxy price at $2,000 is arbitrary and “excessively high relative to the cost to provide the service.”

Andrew Reimers, the IMM’s deputy administrator, said he has brought the Monitor’s concerns over the RUC offer floor to several stakeholder meetings.

“We were really hoping that this wasn’t implemented with an eye towards making sure that RUC always procured the whole AS plan; that there are going to be plenty of circumstances where we’re knowingly going short on the AS plan and printing non-zero prices for non-spin or ECRS [ERCOT contingency reserve service],” Reimers said. “We’re accepting the point that RUC is a different kind of tool than the real-time market or the day-ahead market [DAM] and already has kind of different penalty functions in it.

“Now that this is swinging back around to, ‘OK, well, if you’re going to do that in RUC, then you should also have the same offer floor in DAM,’ that’s a real problem for us and might be a deal breaker.”

Mereness said the task force’s consensus is that AS proxy offers distort the market and should be rare exceptions and quickly corrected. The PRS plans to request urgent status for NPRR1269 in March to keep the change on track for regulatory approval ahead of the RTC+B market trials. While the trials begin in May, ERCOT is opening the sandbox for system testing before then.

The IMM is behind NPRR1268, which defines a methodology for disaggregating the operating reserve demand curve (ORDC) and creates “blended” ASDCs.

“We had cliffs on the curves. Now, we have ramps in the curves,” Mereness said.

Texas Competitive Power Advocates, a trade association of competitive generators, filed comments supporting ERCOT’s suggestion to add an ASDC floor in RUC that ensures security-constrained economic dispatch (SCED) can procure its AS requirements. The association said that under this construct, market prices will incent the market to self-commit the capacity to meet the AS requirements, rather than have RUC commit them.

Michele Richmond, TCPA’s executive director, called in to the meeting to clarify that the association’s comments were not intended to set a price floor.

“The [Texas Public Utility Commission] has made it clear through their direction that they want to avoid [operations] watches. They want to consider the conservative operations that ERCOT has been doing,” she said. “We want to make sure that whatever amount of ancillary services ERCOT needs to procure in that endeavor are done through the competitive market, through market solutions, and not through out-of-market actions.”

After meeting twice on NPRR1268, the RTC+B Task Force is leaning toward a separate revision request with a broader scope for the aggregated ORDC and ASDC issues, Mereness said. He said a broader consensus exists with NPRR1270, with stakeholders wanting to remove its original qualification expansion to automatically include all SCED resources for the ECRS and non-spin AS products.

The RTC process dispatches energy and ancillary services interchangeably in the real-time market. ERCOT procures AS in the day-ahead market and says it does not typically move the products between resources in real time. The grid operator expects to save $1.6 billion annually in reduced energy costs.

The grid operator has been working on RTC since 2017, when the PUC directed it and the IMM to assess the process’s benefits. Work was delayed for several months after the disastrous February 2021 winter storm, known as Winter Storm Uri, that brought the ERCOT grid within minutes of collapsing.

ADER Discussion Moved to WMS

Stakeholders agreed to park continued discussion of an aggregated distributed energy resources (ADER) pilot project to the Wholesale Market Subcommittee.

The hope is that the WMS will be able to resolve issues around direct participation of third-party aggregators in the pilot and flexibility on limits, as well as consumer protection concerns and implications for load-serving entities.

Matt Mereness, ERCOT | © RTO Insider LLC 

The ADER pilot project is in its second phase and eyeing a third. The PUC voted Feb. 13 to move the project into ERCOT’s stakeholder process to determine the best way to move the initiative forward. (See “ADER Project Moved to ERCOT,” 2 Companies Withdraw Texas Energy Fund Projects from Consideration.)

The pilot began in July 2022 and has resulted in three virtual power plants participating in the wholesale energy market and providing certain AS. Eight additional ADERs have been approved and are in various stages of registration. Their total capacity, qualified and potential, is 25.7 MW of energy, 11 MW of non-spin reserve service and 8.8 MW of ECRS.

Staff have been working with the ADER Task Force to develop a governing document for Phase 3 and gain board approval in April. Potential changes include a new participation model that would allow ADERs to provide AS as non-controllable load resources (NCLRs) not economically dispatched in real time, and all third-party aggregators as NCLRs when aggregation is larger than 100 kW.

The ADER pilot was originally given a three-year time frame.

Amended NPRR Passes

TAC endorsed a proposed protocol change (NPRR1190) that would allow recovery of a “demonstrable financial loss” arising from a manual high dispatch limit override reducing real power output when the output is intended to meet qualified scheduling entities’ load obligations.

The measure was amended to include ERCOT comments received Feb. 27. Staff pushed to lower the $10 million threshold to trigger a review proposed by Reliant Energy to $3.5 million, saying the larger threshold, based on historical payment amounts that included Uri, was not appropriate given recent market pricing changes.

Reliant’s Bill Barnes said he acknowledged the $10 million threshold was too high and agreed to the reduced amount.

Committee members tabled the NPRR in October 2024 after it was also tabled by the board and remanded back to TAC over concerns of a more equitable and fair treatment of all parties.

The measure passed 26-4, with four members of the consumer group casting no votes.

TAC also endorsed a slim consent agenda that included its 2025 goals and strategic objectives, a proposed protocol change and a revision to the Verifiable Cost Manual (VCMRR) that would, if approved by the board:

    • NPRR1241: clarify the hourly standby fee claw backs for firm fuel supply service during a winter weather watch by using a sliding scale approach.
    • VCMRR042: add seasonal sulfur dioxide and nitrogen oxide prices obtained from indices to calculate emission costs from May through September; annual prices would continue to be used from October through April.
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Will Trump Reorder Interconnection Queues for Natural Gas?

WASHINGTON —Solar, wind and storage are critical for meeting growing U.S. energy demand because they are cheaper and faster to build than natural gas, and they represent 95% of the 2,600 GW sitting in RTO and ISO interconnection queues across the country, according to Ray Long, CEO of the American Council on Renewable Energy.   

But the industry should not depend on the current queues, said Andrew Wheeler, who led EPA during President Donald Trump’s first term.  

“I am not convinced that the queue is going to remain the way it is right now,” Wheeler told an audience of clean energy industry leaders at the ACORE Policy Forum on Feb. 26. “I think there could be a reordering of projects based upon [system] needs and going back to the president’s executive order on the energy emergency.” 

In addition to Trump’s Day 1 executive order declaring a national energy emergency, Wheeler also pointed to the Feb. 18 EO putting independent federal agencies such as FERC under more direct executive control. “There’s going to be a little bit more political scrutiny, I believe, on energy projects going forward,” he said. 

Individual energy projects could be re-examined, and the need for and viability of each one justified, he said. “I think that’s going to be … the course for the next few years.” 

The potentially conflicting narratives of the industry and the Trump administration were a recurring theme at ACORE’s two-day event, which opened with Long’s comments and an on-stage discussion between Wheeler and Ernest Moniz, who led the U.S. Department of Energy during former President Barack Obama’s second term.  

The extent to which energy policy ― and the debate surrounding it — can be depoliticized remains a vital question as the Republican-led Congress begins to wrestle with the massive budget cuts that will be needed to extend Trump’s 2017 Tax Cuts and Jobs Act.  

ACORE CEO Ray Long | © RTO Insider LLC 

The House of Representatives’ budget resolution (H.Con.Res. 14) passed Feb. 25 would require $2 trillion in spending cuts, with the largest slice — $880 billion – coming from appropriations under the jurisdiction of the House Energy and Commerce Committee.  

Moniz expects that at least some of the clean energy tax credits and other incentives from the Inflation Reduction Act will be cut. But, he said, U.S. energy policy will remain market driven. 

“Where energy policy is going is determined by where the energy sector is going, and I think certainly one trend which will continue is electrification playing a more important role in the energy economy, [with] multiple sources, obviously, for that electricity,” Moniz said.  

“It’s a reality that most of the new capacity added has been renewables [and] second, natural gas,” he said. “I don’t see how that’s going to change in these next days.” 

Trump’s climate denial notwithstanding, climate change also will continue to propel the growth of clean energy, Moniz said. “We’re going to see increasing extreme weather. … There’s a strong association in the public’s mind between that and warming; so again, I see more continuation than disruption in how we go forward.” 

Consumers vs. Producers

Since the November election, one of the main messages coming out of clean energy trade groups like ACORE is that they want to work with the Trump administration.  

Like Trump, the clean energy industry wants permitting reform “that protects the environment while eliminating bureaucratic red tape,” Long said.  

Another common goal is reducing energy costs for consumers with “an all-of-the-above approach to diversify the energy mix,” he said. “Wind and solar produce the cheapest power right now. … Removing any one technology puts the United States at a competitive disadvantage.” 

Still another argument is that the wind, solar and storage projects in interconnection queues are the “low-hanging fruit” for meeting near-term demand growth from data centers and keeping the U.S. ahead of China in the race to develop artificial intelligence. 

Renewables are “the things that are going to get built between now and 2030,” Long said. “Other technologies, such as natural gas ― peakers, combined cycle — new and existing nuclear, won’t come online until after 2030.” 

But, again, Wheeler foresees disruption to such expectations. While noting that the first Trump administration did “nothing on the policy side … that disadvantaged renewable energy,” he predicted an acceleration in natural gas development.  

“The Trump administration is going to make sure that they have the permitting and leasing in place not just to access natural gas but also to build new natural gas plants,” he said. 

Just one example: EPA Administrator Lee Zeldin may be exploring options for overturning the endangerment finding, the 2009 ruling that gives the agency the authority to regulate greenhouse gas emissions under the Clean Air Act, according to The Washington Post. 

Looking at the upcoming negotiations over budget cuts in the House and Senate, Rep. Sean Casten (D-Ill.) pointed to another threat to clean energy. A key question in the energy policy debate is “should our energy policy exist to benefit consumers or producers?” Casten said during an on-stage conversation with Robin Millican, head of strategic initiatives and integration at Breakthrough Energy.  

trump

Robin Millican (left) of Breakthrough Energy talks with Rep. Sean Casten (D-Ill.) at the ACORE Policy Forum on Feb. 26. | © RTO Insider LLC 

While the majority of IRA tax credits and incentives have gone to develop clean energy projects in Republican districts and states, the Republican leadership in the House leans heavily toward fossil fuel-producing states, he said. Both Speaker Mike Johnson and Rep. Steve Scalise, House majority leader, are from Louisiana, a state heavily invested in offshore oil and LNG. 

“The parts of the country that are primarily extractive [are] where Republican leadership is from,” he said. “What the White House is pushing is a producer-focused policy, and a push to cheaper energy is a competitive threat to them.” 

Casten also expressed concern about FERC’s independence, and Chair Mark Christie’s “politically astute” statements in the wake of Trump’s executive order on executive control of independent agencies. (See FERC’s Christie Says Existing Policies Can Align with Trump Order.) 

“We don’t know at this point whether Christie is going to defend [grid] reliability over political pressure,” he said. “I mean, can you imagine if FERC had to have interregional cost allocation conversations where they’re sitting there saying, ‘Well, the two senators on this side of the cost allocation equation are on these committees … and this one is up for election, and this one’s not.’ That’s a good way to have blackouts.” 

‘Fast as We Can’

So, current political rhetoric aside, can the clean energy industry find ways to work with Trump and the Republican leadership in Congress? 

Moniz says the way forward will require “much more coalition building,” especially for developing new technologies for clean, dispatchable power, such as small modular reactors or other advanced nuclear. 

Beyond the challenges of permitting the new technologies, Moniz said, scaling them will require “substantial demand aggregation. … Without it, we will not get the kind of investments in rebuilding the supply chain that we are going to need and building a workforce that we are going to need if we’re going to profit from learning and cost reduction over time.” 

Scaling that kind of demand aggregation will, in turn, require governors, state regulators, the federal government, hyperscalers and utilities to work together, he said. “But even that, I think, will not be enough. That has to be supplemented by some level, at least for a while … of federal and state risk sharing because right now investors, public utility commissions in the United States are going to be unwilling to take on the risk implicit” in such capital-intensive new technologies.  

“The question is, can we bring together the whole system, in terms of technology, policy [and] business models?” he said. Moniz is optimistic that innovative technology and business models “will continue to keep pace,” but sees policy and regulatory change still lagging.  

“That’s the place where, let’s say, school is out in terms of our ability to pull all that together,” he said. 

Moniz continues to believe bipartisan solutions will be the most durable and downplays the importance of the current Republican trifecta controlling the White House and both houses of Congress, which, he said, is not a new phenomenon. 

“This is the fourth change of president in a row where the new president has come in with a trifecta,” he said. Obama, the first Trump administration and Biden all started with their party in control of Congress.  

“I personally think that checks and balances work better, and apparently voters do as well, since the history of those trifectas was relatively short,” he said. 

“I am very supportive and eager to see the clean energy transition continuing, but I have to always remind our friends that we have to go as fast as we can, not as fast as we’d like, because, by definition, you can’t go faster than you can.” 

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MISO Aims for 4 New Tx Planning Futures in 9 Months

MISO expects the revamp of its transmission planning futures will be done by November and will yield an extra scenario dedicated to slow-moving generation construction.

The RTO said load growth from data centers, AI computing and domestic manufacturing makes it clear its current trio of 20-year futures that form the basis of its long-term transmission planning is outdated. It also said it foresees the potential for hydrogen production demand in later years of the futures.

MISO used the three futures it’s now retiring to rationalize about $32 billion in transmission investment between its first and second long-range transmission plan (LRTP) portfolios. It plans to use its upcoming revised futures to chart a third LRTP portfolio for MISO Midwest. (See MISO Pauses Long-range Tx Planning in 2025 to go Back to the Futures.) MISO established its current futures in 2019 and last updated them in 2022.

“It’s critical to do this now because we’re at another inflection point,” MISO Senior Vice President of Planning Jennifer Curran said during Feb. 28 Futures Redesign Workshop, the first in a series with stakeholders to modernize the futures.

Curran said though MISO has warned several times about inflection points over the years, members’ estimated load growth makes the RTO’s latest take-notice just as legitimate.

Curran said load growth trajectories are outstripping what’s contemplated in the existing futures. She also said MISO plans to add a fourth future to contemplate what happens if generation additions remain sluggish, as they have in recent years, noting that MISO needs to understand “what happens if things don’t pick back up really soon.”

She said MISO hopes to emerge with a new set of futures within nine months, something she acknowledged would be an uphill battle.

“It’s of critical importance to get these updates as soon as we can,” she said.

Director of Economic and Policy Planning Christina Drake said MISO decided its members’ integrated resource planning, the footprint’s load growth, continuing decarbonization and generation retirements will be the “load-bearing walls” of the new set of futures.

MISO’s proposed four, 20-year futures include:

    • A “lower load growth” scenario, in which demand projections don’t materialize due to an economic slowdown, and some utilities and states’ emissions reductions announcements are unrealized.
    • A “stated policy” future, in which estimated trends like reindustrialization, data center growth and electrification hold steady while members expand generation and meet their current emissions goals.
    • A “higher load growth” future, in which supply needs inch beyond today’s forecasts driven by high-powered load.
    • A “supply shift” future, in which MISO said “supply frictions” limit the pace of generation additions and load growth has to be managed through existing generation and demand-side resources.

While the first three futures largely use the logic MISO employed in its existing futures (slow, medium and fast-paced options), Drake said MISO must work through the “finer details” of its new fourth future. MISO also anticipates retirement delays and more demand-side resources in addition to unfulfilled emissions reductions targets.

Across all futures, MISO will apply an age-based retirement assumption to generation if members haven’t specified a retirement date. That age-based date will arrive years sooner for coal and gas units in the more progressive “stated policy” and “higher load growth” futures.

This time around, MISO will transition to Energy Exemplar’s more sophisticated PLEXOS tool to model generation expansion. It’s retiring use of the Electric Power Research Institute’s Electric Generation Expansion Analysis System, which MISO said was hitting the limits of the variables it can simulate as the system becomes more complex.

Curran warned the work could feel “uncomfortable” for some stakeholders because change is difficult. She stressed MISO’s goal is to land on a range of possibilities and asked that stakeholders not get hung up on modeling precision.

“It can be hard to predict next year, much less 20 years out. I can’t say it enough that it’s the bounds that are important,” she said.

WPPI Energy’s Steve Leovy said it was disconcerting MISO seems to be abandoning accuracy to establish its bookends.

Kavita Maini, a consultant representing MISO industrial customers, agreed and asked MISO to “not trade speed for accuracy.”

WEC Energy Group’s Chris Plante said he was “fearful” MISO would use its search for general bookends to justify omitting sensitivities or robustness testing.

Curran said she expects there will be some variables that won’t meaningfully change MISO’s transmission expansion needs.

“I guarantee that there are going to be things that we assess as immaterial that stakeholders will disagree with,” she said. “I will caution that one person’s crazy is another person’s reasonable.”

MISO also will include energy adequacy assessments as part of its futures. Drake said MISO hopes its adequacy assessment will support its states — which hold resource-planning power — in making informed decisions.

Maini asked if MISO has considered that its members will relax some carbon-cutting endeavors in resource plans due to the Trump administration’s standpoints on clean energy. She also asked if MISO has analyzed how trends might change if the Inflation Reduction Act is axed.

Drake said the Inflation Reduction Act might not have as much bearing on planning as some might assume. She said MISO’s research to date has found that member plans would predominately set the futures’ course.

“It was basically not as impactful as what was coming through our member plans,” Drake said.

MISO plans to discuss other assumptions at upcoming workshops. It plans to hold another Futures Redesign Workshop with stakeholders March 19.

Multiple stakeholders urged MISO to allow them to record and transcribe the workshops so others at their organizations can keep up with futures development. The grid operator prohibits anyone from recording meetings, save for a few self-recorded workshops throughout the year. It has opted not to allow futures workshops in its archives.

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NEPOOL Transmission Committee Briefs: Feb. 27, 2025

FERC Order 904 Compliance 

ISO-NE has revised its compliance proposal for FERC Order 904 to allow generators to be compensated for reactive power outside the standard power factor range, the RTO told stakeholders at the NEPOOL Transmission Committee meeting Feb. 27. 

Order 904 prohibits compensation for reactive power within the standard power factor range. ISO-NE sought to keep its existing system of reactive power compensation in response to FERC’s Notice of Inquiry and Notice of Proposed Rulemaking prior to the final rule, but the commission rejected the RTO’s arguments (RM22-2). 

At a prior meeting of the TC in early February, the RTO proposed to end all compensation for reactive power, while several stakeholders argued for a more limited compliance plan strictly focused on removing compensation for the standard range. The RTO delayed the vote and ultimately accepted the suggestion. (See NEPOOL Markets Committee Briefs: Feb. 11, 2025.)

“The revised compliance proposal will eliminate VAR [volt ampere reactive] capacity cost credits to qualified reactive resources within the power factor range of 0.95 leading to 0.95 lagging at continuous rated output but will now continue to compensate for reactive power provided outside this range,” said Kory Haag, principal operations analyst at ISO-NE. 

ISO-NE estimated that the total annual compensation for reactive power is about $16 million, with $3.4 million for reactive power outside the standard range. 

The TC voted to support the proposal, with no opposition and 55 abstentions. Multiple stakeholders expressed concern about the order itself, arguing that it undermines grid reliability. 

“We are frustrated by the underlying order but appreciate the steps ISO-NE [has] taken to comply with the order,” said Bruce Anderson, general counsel for the New England Power Generators Association. “We also appreciate that ISO-NE took the broadly shared NEPOOL feedback on its original proposal and made changes to that proposal that look to carry out FERC’s directives.” 

Economic Study Process Improvements

The TC also voted to support updates to ISO-NE’s Economic Study process, centered around requests for proposals to address the issues identified during the process. 

The updates “incorporate revisions to identifying system efficiency issues and needs by establishing a clear trigger for when to issue an RFP, defining benefit metrics for evaluating RFP responses and streamlining the RFP process into a single stage,” said Patrick Boughan, supervisor of economic studies and environmental outlook at ISO-NE. 

ISO-NE plans to run a System Efficiency Needs Scenario (SENS) every two or three years, looking at 10 years into the future. SENS tests would be used to identify potential transmission solutions. The RFP process will be triggered if ISO-NE’s modeling shows savings of at least $4.3 million from congestion relief. 

In feedback submitted prior to the meeting, RENEW Northeast criticized the proposal’s method of modeling imports, arguing that it “may be artificially reducing the quantity of imports in the model and as a result having the opposite effect of underestimating the benefits of congestion relief.” 

ISO-NE responded that its modeling approach “is consistent with practices in NYISO, PJM and MISO,” adding that valuing imports at the border locational marginal price “is the most logical way to value imports in the modeling context.” 

RENEW also argued that SENS test should include some projection of capacity market savings and asked the RTO to consider creating a process for smaller solutions that do not meet the $4.3 million savings threshold. 

ISO-NE said estimating capacity market savings would introduce a significant amount of uncertainty and added that the cost threshold was calculated based on the cost of projects on the Regional System Plan and asset condition lists. 

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Feds Pause $1M Pathways Initiative Funding, Group Leader Says

The federal government has put on hold nearly $1 million in funding toward the development of a new independent Western “regional organization” (RO) to oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the West-Wide Governance Pathways Initiative’s Launch Committee said Feb. 27.

The funding status is unknown because of a communication pause from the U.S. Department of Energy, according to a committee presentation.

“Given some of the cuts and uncertainty with the federal government, that funding is currently on hold,” Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, said during the stakeholder meeting.

However, the Launch Committee does not expect the uncertainty of federal funding to slow down its work significantly. The current political environment has impacted some partners of the Pathways Initiative, “and we are sensitive to that. But directly for the work that we’re doing, we think we’re going to be able to continue to move forward,” Staks said.

Pathways received nearly $1 million from the DOE under former President Joe Biden’s administration in November to underwrite the committee’s efforts to establish an RO to oversee CAISO’s WEIM and EDAM.

The award was issued through the Pathways Initiative’s philanthropy adviser Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.

President Donald Trump’s administration on Jan. 27 paused all federal grants and loans, according to a memo issued by the White House’s Office and Management and Budget.

“With or without that DOE funding, the RO is going to need additional funding,” Staks noted.

Setting up an independent RO comes with several costs, including legal review of various documents, seating a board and ongoing facilitation costs, among other things, she said.

Staks said the committee hopes to have a draft budget to share with stakeholders by spring. She recognized that “all of our work thus far has been funded by a variety of stakeholders, and we are extremely grateful for that support and commitment.”

The Launch Committee’s success also hinges on the California bill to implement the Pathways “Step 2” plan to transform CAISO’s governance. Lawmakers introduced the bill in the state Legislature on Feb. 20. The proposed legislation sets conditions under which CAISO and California investor-owned utilities can participate in energy markets governed by an independent RO.

The Launch Committee is also working to finalize corporate documents, including registering as a nonprofit organization and refining the nominating committee process used to seat the RO board. The entire process to establish the RO will be marked by an extensive stakeholder process and negotiations between various parties, Staks noted.

The Pathways bill states that CAISO can join the RO-governed market on or after Jan. 1, 2027, which the Launch Committee believes “will not be too early,” according to Staks.