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December 8, 2025

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BPA Outlines Next Steps in Markets+ Implementation

As the Bonneville Power Administration prepares to join Markets+, the agency hopes to complete the initial program governance setup and define its commercial model for market participation early next year, though questions persist about the timeline and market seams.

BPA provided the update during a Dec. 4 day-ahead market participation workshop. BPA committed to SPP’s Markets+ in May 2025, and the power agency is to begin participating in the day-ahead market in October 2028. (See BPA Chooses Markets+ over EDAM.)

But several key steps remain, according to Nita Zimmerman, acting vice president of bulk marketing at BPA.

“The policy direction is to pursue Markets+, but several important steps still remain, which include a rate case, a tariff proceeding, a National Environmental Policy Act analysis and the successful negotiation of a Markets+ implementation agreement,” Zimmerman said.

Another step includes defining BPA’s commercial model framework. While the network model deals with physical elements, such as electrical nodes, metering and transmission elements, the commercial model connects those physical elements to the financials, explained Sara Eaton, senior analyst at BPA.

“The commercial model is creating that mapping between the network model, the physical and then the financial,” Eaton said. “So, when we say ‘commercial model,’ it’s going to have settlements impacts, and that’s why it’s really important to get it right and to start those conversations early.”

To define the commercial model, BPA must answer questions about how entities interact in the market, how resources and loads are modeled, and how information is shared among market participants, said Libby Kirby, BPA’s Markets+ program manager.

“A lot of those framework questions drive all of the downstream work that ends up happening,” Kirby said.

“So, once we have gotten some of those commercial model framework questions answered, we will move into some of those more formal work streams — developing software, developing processes, etc. — as well as getting into our internal testing,” Kirby said.

According to BPA’s presentation slides, the agency aims to complete the initial governance program setup by March 17, and the commercial model by March 31, 2026.

Other preparations include aligning the agency’s provider-of-choice contracts with Markets+ and preparing the exit from the Western Energy Imbalance Market.

Another issue is the market seams expected to arise from the split between Markets+ and CAISO’s Extended Day-Ahead Market. (See SPP Markets+ Cruising Through Early Development.)

Steve Greenleaf, senior director of regulatory affairs and policy at Brookfield Renewable, asked whether BPA plans future workshops on seams or if those concerns are limited to SPP.

Kirby responded that BPA does not view seams as an “SPP-only issue.”

“I think we all have a stake in the outcome, and so I don’t think we expect to just say, ‘Yep, [SPP is] going to do it all, and we have no interest in that,”’ Kirby said. “I think we have lots of interest and probably some opinions that we’d like to share with them.”

She noted SPP plans to host a symposium on seams in February.

“I don’t know that there’s an explicit full road map … yet that sort of bridges both sides, but I think that is something that [SPP is] considering, and that we very much know that we will continue to poke at,” Kirby said.

‘Weakest Link’

Henry Tilghman, a consultant with the Northwest & Intermountain Power Producers Coalition, questioned whether BPA can keep its Markets+ implementation timeline, given that certain upgrades are still pending.

“The reason I’m asking is a chain is only as strong as its weakest link, and the [Automatic Generation Control] upgrade has been pending for at least a year and a half,” Tilghman said. “And for some reason, I still can’t get a timeline for when that’s going to be completed.”

“What is your confidence level in delivering on the schedule given that there is a very important software upgrade that doesn’t have any timeline to complete, as near as I can tell,” Tilghman said.

Kirby described her confidence level as “decent.”

“I think it’s too early to be too confident. It’s too early to be too pessimistic,” Kirby said. “Right now, we are making plans to meet it. Right now, we think we can meet it, including with AGC. But I think obviously there are risks. There are risks for workload; there are risks if we go live and [market participants] aren’t ready, what do we do? We have to have contingency plans. We have to have backup plans. I think that is all part of the conversation right now.”

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Rosner Voices Support for Large Load ANOPR

BOSTON — FERC Commissioner David Rosner was supportive of the Department of Energy’s request that the commission assert authority over the interconnection of large loads while emphasizing the importance of collaboration and consensus-building in response to concerns raised by state regulators.

Speaking at a meeting of the ISO-NE Consumer Liaison Group on Dec. 3, Rosner said the Advance Notice of Proposed Rulemaking submitted by the department to FERC includes “ideas that I know people in this room have talked about for a long time and that I think we know will work.” (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)

“I think there’s a lot of consensus on: We need to do this because there’s a lot of economic development opportunities for the country and states that want to build, but we also need to do it in a way that protects consumers,” he added.

Certain aspects of DOE’s request have drawn significant pushback from state regulators. A resolution passed by the National Association of Regulatory Utility Commissioners stressed that FERC must not assert control over “end-use sales,” which are “squarely within the exclusive jurisdiction of state retail energy regulatory authorities.”

The resolution also warned that “large load interconnections without sufficient available generation capacity could threaten reliable power service to existing retail customers.” (See Regulators Urge FERC to Honor State Authority over Large Load Interconnections.)

Expediting the interconnection of large loads, including hyperscale data centers, is a politically sensitive issue across the country. Critics of hyperscale data development point to impacts on energy costs and emissions, as well as the relatively limited number of people the facilities employ. Growing bipartisan pushback against data centers has blocked or delayed about $64 billion of investments over the past two years, according to a recent study.

The ANOPR floats the idea of processing large load interconnections within 60 days, which has caused some concern about effects on load forecasts. In regions with wholesale markets, rules encouraging co-location could remove generation from the market and drive consumer costs up.

Regarding the controversial aspects of DOE’s request, Rosner said he is excited to work with his fellow commissioners “to figure out which of these levers do we need to pull on to solve this problem.”

He said the benefit of an ANOPR proceeding is that because it is a generic rulemaking, commissioners can have open conversations with stakeholders to build consensus.

Reflecting on his work on Order 1920-A, he stressed the importance of state buy-in. Working closely with then-Commissioner Mark Christie, “one of the things that we did was to dramatically elevate the state role and state input into the development of those plans.” (See FERC Order 1920-A Wins Approval with Accommodations to States.)

Getting states to agree on transmission cost allocation plans “de-risks the ability of the utility to actually build these projects, and it makes them more likely to actually get sited,” he said, noting that FERC does not have authority over transmission siting, except in “very rare cases that have never worked.”

Rosner also emphasized the importance of the independent, bipartisan structure of FERC, which he said is “fundamental to having durable solutions.”

“It’s a good model, and it didn’t happen by accident,” he said. “I know there’s some litigation in the courts about the president’s ability to exert influence over these agencies and make staff decisions, and we’ll see what happens.”

The Supreme Court is scheduled to hear oral arguments on Dec. 8 for Trump v. Slaughter, a case that could lead to rollbacks of limits to the president’s ability to fire members of independent agencies. (See Former FERC Commissioners Ask Supreme Court to Preserve Agency Independence.)

New England Issues

Rosner also commented on several New England-specific issues, including capacity accreditation, asset condition projects and the region’s gas constraints.

He said ISO-NE’s efforts to establish an internal, non-regulatory entity that reviews spending on asset condition projects — potentially enabling third parties to challenge costs with FERC — appears to be a step in the right direction. (See ISO-NE Gives Update on Asset Condition Reviewer Role.)

Regarding ISO-NE’s work on capacity accreditation, he said it will likely benefit from learning from reforms that have been implemented in other regions.

“I am really encouraged by New England’s move toward accreditation,” he said. “What I like about tools like this is that they send signals to the private sector and to our state policymakers — who I know play a big role in what gets built here — of, ‘here’s how your investment will pay off.’”

He also said he remains concerned about the region’s constrained access to pipeline gas.

“I have worries about making sure that lights stay on and will stay warm and safe in our home,” he said. “I do want to have a sort of all-options-on-the-table approach to this.”

During peak periods, there may be opportunities to increase efficiency across the gas and electric systems through artificial intelligence, Rosner said. He also pointed to success in California around using demand response to shift natural gas use throughout the day, saying, “I wonder if there’s the potential for using that here.”

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Grid Strategies: Pace of Load Growth Continues to Speed up

The power industry’s own demand forecasts expect national summer peak to swell by 166 GW by 2030, which would be the equivalent of adding 15 times the peak load of New York City, Grid Strategies said in its latest load growth report.

The estimates, which are based on reports submitted to FERC through Form 714, include 90 GW of new data centers, 30 GW of industrial growth, 10 GW from oil and gas and mining, and 30 GW from other sources. This is the third report in a row published by Grid Strategies showing demand growth, and the pace has grown each time, the firm’s president, Rob Gramlich, said during a webinar hosted by Americans for a Clean Energy Grid on Dec. 4.

“We’re talking about over 5% annual growth, which is pretty extraordinary,” Gramlich said. “Now it’s not, by historical standards, a growth rate that is unprecedented.”

It certainly is in total gigawatts, however, as the last time the electric industry saw growth at similar levels in the middle of the 20th century, it was from a smaller base, he noted.

“We’ve been able to meet the pace of growth in the past,” Gramlich said. “But of course, we’ve, in a way, as an industry and a regulatory community, lost our muscle memory on a lot of these things. It’s just not something that most of us in our careers have had to deal with.”

Energy use is growing even faster than the peak numbers, at 50% over the next half decade, which means the new demand has a higher load factor, he added. The bulk power system in the U.S. averages a 60% load factor today, but that is expected to reach 66% by 2030 as new demand comes online, the report says.

“Data centers generally operate at an above-average load factor,” the report said. “For example, Dominion Virginia reported an 82% load factor for large data centers in 2024, and Duke Energy states that it plans for new large loads to have an 80% load factor. It appears that some large load forecasts may use higher values, perhaps as high as 100%, which is unrealistic.”

The utility reports to FERC are likely overstating the amount of data center load, with an estimate from Cleanview showing just 60 GW by 2029, and TD Cowen predicting 65 GW by 2030 based on orders for advanced microchips.

“Somewhat similar to what we have on the generation side, there are always way more proposed projects than there are actual projects that go forward,” Gramlich said. “I never liked the term ‘speculative’ about generation. I don’t really like it about load either. It’s just how the business works. If you’re building anything, you have to not put all your eggs in one site basket.”

All the new load being projected means that the industry and regulators are going to need to expand the BPS, Virginia State Corporation Commission Judge Kelsey Bagot said on the webinar.

“We’re certainly going to have to build a lot of generation right, which necessarily includes the transmission component,” she added.

Generally, the industry has been reactive but meeting the needs of these new customers while keeping costs affordable will require it to be more proactive in its planning, Bagot said. The cost of the expansion naturally leads to questions about allocation, which can lead to litigation at the state level and goes to the core of concerns that existing ratepayers have about affordability.

“In order to be comfortable proactively building, I think we need to pay attention to cost allocation, and at the state level, that means making sure that we are allocating transmission build to the folks that are driving the need for the build, right?” Bagot said. “That will get the end-use customer more comfortable with the amount of transmission that we’re building.”

Getting the expansion done affordably means using all the tools available, including advanced transmission technologies, distributed energy resources and virtual power plants, said Sarah Freeman, a principal at the Regulatory Assistance Project.

“It’s so critical that we encourage/force our utilities to take these bigger picture looks,” Freeman said.

Amazon Web Services Energy Policy Manager Ray Fakhoury agreed that the industry needs to proactively plan to meet new loads more than it has recently, and he said the new technologies his company and others are working on — those that are driving the growth — can help.

“There is a way to integrate artificial intelligence, machine learning [and] the highest standards of all of these software programming so that we can identify the optimal spots to build out transmission,” he argued.

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Colorado PUC Approves Extension for Comanche Coal Plant

The Colorado Public Utilities Commission granted a one-year extension to Unit 2 of the coal-fired Comanche power plant as uncertainty lingers about the fate of outage-plagued Unit 3.

The commission approved the extension Dec. 3. Comanche Unit 2 now is scheduled to retire by Dec. 31, 2026, rather than at the end of 2025. The 335-MW Unit 2 began operating in 1975.

The commission’s decision was in response to a petition filed Nov. 10 by Xcel Energy subsidiary Public Service Company of Colorado (PSCo), which is the coal plant’s primary owner and operator. PSCo was joined in the petition by the Colorado Energy Office, the state Office of the Utility Consumer Advocate and PUC trial staff. (See Xcel Seeks Extension for Comanche Coal Plant from Colorado Regulators.)

The petitioners argued the extension was needed because of the unexpected outage of the 750-MW Unit 3, which began Aug. 12 and is expected to last until at least June 2026.

Other factors contribute to the need to keep Unit 2 open, the petitioners said. Those include growth in the peak demand forecast in PSCo territory and the delay of generation and storage projects because of supply chain and tariff issues.

The PUC emphasized the Unit 3 outage was the sole reason for granting the extension.

“Clearly we wouldn’t be making this decision if not for the unreliable operation of Unit 3,” Commissioner Tom Plant said.

Comanche Unit 3, which went online in 2010, has a history of unplanned outages. From mid-2010 through 2020, the unit averaged 91.5 outage days a year, according to a March 2021 report from the PUC. A 2020 outage lasted much of that year and extended into 2021.

For two years starting in August 2023, the plant has been shut down unexpectedly for part or all of 138 days, according to Western Resource Advocates (WRA).

Unit 3 is slated for retirement by Jan. 1, 2031, as Xcel plans to exit from coal by 2030. Unit 1 retired in 2022.

Commissioner Megan Gilman expressed concern that PSCo might be presuming that fixing Unit 3 is the best path forward. In addition to unknown costs to repair Unit 3, the costs to extend the life of Unit 2 aren’t yet known, she said.

“We are in the dark about what any of this costs,” Gilman said. “We are just in a real reliability pickle because once again Unit 3 has broken in a catastrophic way. And it just so happens that we’re already somewhat tight on resources, so now it has really created a significant problem.”

The commission’s decision requires PSCo to report to the commission by March 1 on the status of Unit 3. A more detailed report is due by June 1.

Commission Chair Eric Blank said he wants monthly reports from PSCo on costs to fix Unit 3.

“I’m not interested in seeing very large capital expenditures on an after-the-fact prudency review fight,” Blank said. “I’d like at least visibility into what’s going on ahead of time.”

Commissioners noted there would be no presumption of prudence from the monthly reports.

The commission also placed a cap of 3,942,000 MWh on combined generation from Units 2 and 3 in 2026 — a status quo limit that was requested by WRA and other environmental groups.

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Analysis Offers Blueprint for Faster Data Center Interconnection

A new analysis models a markedly faster interconnection process for large data centers where the developer and utility can agree on flexible interconnection and the developer can secure some of its own generation capacity.

Camus Energy, encoord and Princeton University’s ZERO Lab analyzed six hypothetical data centers’ large load requests at locations within PJM that have been the scene of actual requests.

The analysis concluded that by agreeing to partial curtailment during limited periods of system stress, and by directly procuring accredited generation capacity, data center developers could reach operational status in roughly two years instead of five to seven years. It also found the approach would shield other grid customers from most of the costs.

It is, Camus said, the first publicly available study to combine real utility transmission system data, system-level capacity expansion modeling and site-level capacity optimization to evaluate how flexibility can accelerate data center interconnections.

And it provides a repeatable blueprint other utilities can follow, Camus said.

Different Approach

Load flexibility is a concept that is drawing attention as the rate of large load requests exceeds the pace at which the grid can be expanded to serve them.

A Duke University study in early 2025 concluded the existing U.S. power network could handle 126 GW of new demand with no new generation if data centers cut their energy use by as little as 1% in times of peak demand. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)

Some of the biggest names in the tech sector have begun exploring demand response as a way to limit exposure to the high cost and slow pace of building new infrastructure to serve these new large loads. (See Google Strikes Demand Response Deals with I&M, TVA.)

The new study — “Flexible Data Centers: A Faster, More Affordable Path to Power” — was funded by Google, which reviewed it prior to publication.

It advocates for a mixed, flexible approach.

The sticking point, Camus CEO Astrid Atkinson told RTO Insider, is that most tariffs have no middle ground — large-load customers can build their own generation behind the meter or they can get firm service from a utility, but not some mixture of both.

To change this, utilities need to have not only the willingness but the skills and technology to consider alternatives, she said.

Data center operators, too, need to open up to the idea.

“They’ve also been very reluctant to consider curtailment,” Atkinson said. “Historically, they want to make sure that if they’re building a data center facility, that they can use 100% of the power footprint that the facility is designed for. … Being paid to curtail is absolutely dwarfed by the opportunity cost of not using the resource that they’ve invested in.”

The “huge disconnect” between the time frames on which Big Tech and the U.S. power industry operate is leading to changes, she said, because there is plenty of room on the grid for what is described variously as conditional firm service, non-firm service or flexible connections.

The obligation-to-serve model “naturally means that the system, for the most part, does have a decent amount of slack capacity in many places, most of the time,” Atkinson said.

Some utilities are receptive to the idea, she added.

“There’s obviously a lot of complexity in how that plays out, but we have definitely seen utilities be actively curious and willing to explore flexible interconnection models for data centers and other large load assets.

“There’s also challenges in terms of, we need to adapt the existing market participation rules and the regulatory models that support connecting stuff to the grid.”

Updated interconnection methodologies and potentially new market mechanisms are among the potential changes, Atkinson said. But these are relatively new concepts for an industry that typically makes changes at a deliberate pace.

“This whole conversation, I think in some ways, was kicked off by the Duke University report at the beginning of the year. And it’s really just this year that data centers have been interested in and willing to explore this sort of model. So the conversation is relatively young.”

The Analysis

The analysis applied system-, utility- and site-level modeling to the six scenarios it created.

Importantly, the study looked at all 8,760 hours of the year, not just at the worst moments of the year.

It found that a 500-MW data center using flexible grid connection and bringing its own capacity to the table could lop three to five years off its grid connection process.

It found grid power was available for more than 99% of all hours in a year; on-site resources such as batteries, generators and load flex were dispatched 40 to 70 hours a year; transmission curtailment lasting four to 16 hours totaled seven to 35 hours a year; and generation shortfalls totaled 32 hours a year, mostly due to extreme weather.

And it found that while each gigawatt of new data center demand creates $764 million in supply system costs under a traditional firm-only interconnection, a non-firm interconnection could insulate the grid from almost all of that cost: Flexible interconnections with 20% conditional firm would avoid 273 MW of new build at a cost of $78 million per gigawatt; internalizing capacity would internalize $326 million in capacity costs per gigawatt; and the data centers’ bill payments would cover $329 million per gigawatt.

The research evaluated dynamic line rating (DLR) as a complementary option and found it boosted transmission capacity during most hours and significantly reduced the need for curtailment at the modeled data centers. While DLR is beyond the reach of data centers, they could partner with utilities to expand its use, the authors write.

The Conclusion

The report identifies four key barriers to implementing the flexible connection model it explores:

    • Planning frameworks assume every load always is at its maximum; regulators instead would need to incorporate limited large-load flexibility where voluntarily offered as an explicit input in integrated resource planning and resource adequacy processes.
    • Accreditation methods do not consistently define and value load-modifying resources; regulators would need to extend accreditation to recognize the reliability contribution of emergency load modifying resources in resource adequacy planning under predetermined bounds of duration and annual availability.
    • Tariffs allow only firm and non-firm service, and often not even non-firm service; FERC and state regulators should encourage transmission providers to change their processes to better use voluntary flexible loads.
    • Transmission and resource adequacy commitments would need to be recognized as independent of each other; FERC or other regulators could clarify this through rule making or guidance.

The report follows the list with an optimistic note: “Although regulatory frameworks are still evolving, momentum is building across federal, regional, and state levels.”

The authors add the caveat that the analysis is a demonstration of the methodology on certain sites and system configurations, not a comprehensive national assessment.

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NEPOOL Supports First Phase of ISO-NE Capacity Market Reform

BOSTON — The NEPOOL Participants Committee voted nearly unanimously to support the first phase of ISO-NE’s capacity auction reform (CAR) project, which would transition the region to a prompt capacity market and reduce the notification timeline for generator deactivations from about four years to one year.

ISO-NE forward capacity auctions (FCAs) historically have been held over three years prior to each capacity commitment period (CCP). Under the proposed prompt auction format, auctions would be held about a month prior to each CCP.

RTO officials have said moving to a prompt auction would help address issues related to “phantom entry” — in which new capacity resources fail to achieve commercial operations in time to meet their supply obligations — and challenges associated with forecasting demand three years into the future.

The changes are intended to take effect for the 2028/29 capacity auction. While the proposal is designed to be able to stand on its own, ISO-NE plans to file an additional set of changes that also would take effect for the 2028/29 CCP. The second phase of CAR centers around capacity accreditation and splitting commitment periods into winter and summer seasons.

The prompt market changes generally are viewed as the less controversial of the two phases, though developing the proposal still requires extensive work and stakeholder engagement to reach a consensus on the details of the new design.

Under the prompt framework, only resources that have proved they are commercially viable would be able to participate in capacity auctions. The proposal would shorten the qualification process, eliminate annual reconfiguration auctions and move the auction from a descending-clock format to a sealed-bid format.

Much of the stakeholder discussions centered around changes to the resource retirement process, which ISO-NE views as a necessary component of the shift to the prompt market. Under the new prompt framework, ISO-NE proposes to separate resource retirement from the capacity auction process.

“The current four-year lead time to retire under a forward market would be replaced with a requirement that a resource submit a binding, irrevocable deactivation notice one year in advance of the start of the delivery period,” ISO-NE wrote in a memo published prior to the Dec. 4 PC meeting.

At the meeting, several stakeholders praised ISO-NE for its receptiveness to stakeholder input throughout the process. However, multiple participants voiced lingering concerns that moving to a prompt market may increase market volatility, especially as demand grows and the balance of supply and demand tightens.

Others have expressed concerns about impacts on resource development. Under a prompt auction, resources would have no certainty about capacity prices when making development decisions.

However, proponents of a prompt market have argued that the forward capacity market has done little to incentivize new development following the elimination of the seven-year price lock for new entrants in 2021. A general increase in the time it takes to develop most new resources has made it difficult to develop new resources based on capacity market outcomes. (See FERC Orders End to ISO-NE Capacity Price Locks.)

One stakeholder said they remain worried that a one-year deactivation notification timeline would increase the risk of reliability-must-run agreements.

Despite the handful of concerns, the proposal passed with broad support and just one opposition vote at the PC, after receiving widespread support from NEPOOL technical committees in November.

ISO-NE said it plans to incorporate a stakeholder amendment to maintain existing rules around “ambient air de-list bids,” which allow participants to reflect in capacity offers the physical limits of resources at high ambient temperatures. This amendment received 83% support from the Markets Committee in November. (See NEPOOL Committees Support ISO-NE Prompt Capacity Auctions.)

ISO-NE said it plans to file the changes with FERC by the end of 2025. Stakeholder discussions of the second phase of the CAR project are ongoing; ISO-NE is targeting a second filing by the end of 2026.

Operations Updates

Also at the PC, ISO-NE COO Vamsi Chadalavada gave an update on RTO operations, noting that energy market value for November 2025 was up by about 40% compared to November 2024.

He added that ISO-NE is closely following a spike in prices in the day-ahead ancillary services market; average daily day-ahead ancillary service costs have increased by about 260% since September.

ISO-NE launched the day-ahead ancillary services market in March. It plans to formally discuss how the market is working — along with any changes that may be necessary — with stakeholders in March 2026.

“We still think some time is helpful to go through the winter cycle to see how it performs in the winter,” Chadalavada said, adding that he remains confident in the basic design of the market.

“The objectives are not going to change. It is, for us, I think the best way to secure those services,” he said.

Chadalavada also discussed the capacity deficiency conditions that occurred Nov. 23, noting the event was triggered by unexpected outages at three gas-fired plants, along with higher-than-forecast load and lower-than-expected net imports. (See Unexpected Generation Loss Triggers Capacity Deficiency in ISO-NE.)

Initial data indicate the average balancing ratio for the event was 69.3%, while pay-for-performance penalties and credits totaled an estimated $34.7 million, he said.

The balancing ratio determines each capacity resource’s responsibility to provide energy and/or reserves during scarcity periods, while resource performance relative to these responsibilities determines charges and credits.

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ERCOT Successfully Deploys Real-time Co-optimization

ERCOT says it has successfully deployed Real-time Co-optimization + Batteries (RTC+B) into the market, a mechanism used in most other power markets that procures energy and ancillary services in real time every five minutes.

The new functionality, which went live for the Dec. 5 operating day, also includes improvements to modeling and consideration of batteries and their state-of-charge available to provide energy and ancillary services.

CEO Pablo Vegas said RTC+B is the “most substantial” improvement to the real-time nodal market design since its inception in 2010.

“The implementation of this program marks a significant step forward toward more efficient markets and improved grid reliability,” he said in a news release.

The grid operator said RTC+B’s market design is a “key element” in the market’s strategic development and will yield more than $1 billion in annual wholesale market savings. It said RTC+B will provide more flexibility in real time for ERCOT to more efficiently procure energy and ancillary services. (See How ERCOT’s RTC+B is a Game-changer for Market Operations.)

The ISO listed other operational improvements from using resources more effectively:

    • using a variety of resources to better manage transmission congestion;
    • reducing operators’ manual actions and commitments;
    • modeling batteries as a single device to effectively dispatch their stored energy; and
    • replacing inefficient supplemental reserve markets.

ERCOT staff and market participants have been gearing up for go-live since the program was restarted in 2023. The RTC+B Task Force spent 27 meetings drafting more than 25 protocol changes related to the project and producing training videos. Since May, the task force has been overseeing testing and interactive market trials to stabilize the systems.

ERCOT’s Matt Mereness, who chaired the task force, said stakeholders’ collaboration and coordination resulted in a “smooth, seamless” cutover.

“This is something ERCOT could not have done alone, so thank you for the journey since May 5,” he told stakeholders during a final cutover call Dec. 5. “My gosh! We went live last night. Thank you so much.”

The cutover to RTC+B took place at midnight Dec. 4, when telemetry was switched to RTC. Staff reconfigured the market systems’ network, creating a risk of disconnecting some qualified scheduling entities (QSEs) — market participants responsible for scheduling energy and financial settlements on behalf of generators, ESRs and other energy providers — that eventually was resolved.

Mereness said “quite a few and [a] not-insignificant” number of QSE’s had problems setting their application programming interface (a set of rules and protocols that allows software applications to communicate and interact with each other) to the right endpoint.

“We all needed to step across the line together, and we weren’t all making it across the line at the same time,” Mereness said. He said everyone’s connectivity was reconciled and aligned and by 1:53 a.m., “We were operating on RTC+B.”

ERCOT expected 95 QSEs to participate in RTC+B.

Staff closed the day-ahead market at 10 a.m., and ERCOT was off and running with its first real-time co-optimized day-ahead market.

The deployment ends an effort that began in 2019 after a Public Utility Commission directive to ERCOT. It was delayed for several years after 2021’s Winter Storm Uri led to more pressing work for ERCOT staff.

The project added battery energy storage resources with the state’s growth of storage. Texas is second only to California in terms of installed capacity, having doubled battery capacity between 2023 and 2025 and now approaching 10 GW.

ERCOT said it will work through the stakeholder-led Technical Advisory Committee in helping determine which initiatives to advance now that RTC+B has been implemented.

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New England Energy Executives Debate Markets, Affordability

BOSTON — An increasing political anxiety around energy affordability permeated debates about wholesale market changes, federal policy and demand growth at the annual New England Energy Summit on Dec. 2.

Speakers at the event, hosted by the New England Power Generators Association (NEPGA) and the Dupont Group, grappled with how to lower consumer costs while simultaneously supporting the development of new generation and transmission infrastructure needed to keep pace with accelerating demand growth.

Panelists also expressed differing views on how prepared the ISO-NE markets are for a rapid increase in demand.

NEPGA President Dan Dolan stressed that wholesale markets have not been the cause of rising retail energy costs in New England, noting that capacity prices have remained low in recent auctions.

These low prices have contributed to “a four-year major retirement cycle with over 3,000 MW going away,” Dolan said.

NEPGA President Dan Dolan | © RTO Insider 

He emphasized the need to first ensure the markets are sending the right signals, and then let them operate, even if that leads to periods of high prices. To allow the market to respond to high prices, state and federal policymakers must focus on lowering barriers to development, he said.

He acknowledged that this is “easy to say, but extraordinarily politically challenging to implement.”

‘Massive Stress’

ISO-NE CEO Gordon van Welie said the transition to wholesale markets has brought major cost savings to the region over the past 25 years, in part by helping to shield consumers from poor investments. But there is still work to do, he said.

“There was a moment in 2019 when we seriously considered abandoning the capacity market,” he said, pointing to problems in the RTO’s Forward Capacity Market related to forecasting, phantom entry and accreditation. Its ongoing Capacity Auction Reform project is intended to address these issues for the 2028/29 capacity commitment period (CCP).

Van Welie added that the region would benefit from a more robust bilateral trading regime, which could help reduce volatility for consumers. He expressed hope that the RTO’s proposed transition to a prompt capacity auction — in which auctions would be held about one month prior to each CCP — would “push people more into bilateral contracting.”

While ISO-NE’s prompt market proposal has garnered strong stakeholder support, some NEPOOL members have voiced concern that the shift to a prompt market could increase inter-annual price volatility, while adopting a seasonal market would introduce intra-annual volatility. Some stakeholders have asked the RTO to look at ways to encourage bilateral trading to hedge the volatility risks.

Van Welie, who is retiring from the RTO at the end of the year, said market volatility increases the likelihood of political intervention — such as price caps — in the markets.

He added that politicization around energy has already increased in recent years, creating “massive stress” within ISO-NE, with various groups often blaming the RTO for issues outside of its control and politicians using the RTO “as a piñata.”

“It’s escalated to the point of bomb threats and death threats, and I think that’s really not a good place to be,” he said.

Yin and Yang

Referring to the political blowback that occurred in PJM following skyrocketing capacity prices, Anthony Crowdell, senior analyst for Mizuho Americas, expressed pessimism about the future of wholesale markets in a world of rapidly growing demand.

“I think that politicians will end up blowing up the markets,” Crowdell said.

Regarding offshore wind development, he said the Trump administration’s efforts to undermine the industry appear to have done irreparable damage.

“Unless it is a state entity or a federal entity building it, offshore wind is done in the United States,” Crowdell said.

Justin Trudell, CEO of FirstLight Power, said changes in federal policy have caused the company to shift some investments to Canada.

“The next hundreds of millions of dollars that we invest through FirstLight are going to be in Ontario and, likely, in Quebec,” Trudell said.

“What we’re seeing in Canada is when you do have alignment with the provincial and federal governments, you’re seeing explosive growth,” he added.

Other speakers downplayed the Trump administration’s long-term effects on energy development.

“I think there’s a lot of noise in the current administration, but I don’t see a lot of tangible things,” said Curt Morgan, CEO of Alpha Generation. He added that, beyond the offshore wind industry, “I don’t think they’ve moved the needle that much.”

Sherman Knight, CEO of Competitive Power Ventures, echoed Morgan’s comments and said the federal policy changes have not shifted the company’s priorities in the 2030-2035 time frame.

“I think we have to think about it from a more fundamental standpoint of what’s going to work,” he said. “There’s so much uncertainty over that long period of time, and you just can’t develop and build even within an administrative cycle.”

With significant demand growth on the horizon, Morgan stressed the need to stop the cycle of generator retirements. He criticized ISO-NE’s Pay-for-Performance (PFP) rules, which have led to significant penalties for slow-start thermal generators during capacity deficiency events.

“I have some real concerns about how we’re treating existing generation. But I tell you, over time, that generation is going to become as valuable as gold,” he said.

He also criticized the frequency of rule changes in the ISO-NE capacity market.

“Almost every year, we’re making a tweak or a change to the capacity market,” Morgan said. “People don’t believe the markets are going to be allowed to work, and frankly they haven’t been allowed to work.”

ISO-NE board Chair Cheryl LaFleur said that hints at an “age-old dilemma” that frequently came up during her time at FERC.

“People say ‘stop making changes, do not make any changes … except fix [PFP], fix ancillary services — just make my change, then stop making changes.’ It just seems to be the constant yin and yang.”

“I didn’t say it was easy,” responded Morgan.

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DOE’s National Petroleum Council Releases Report on Gas-electric Coordination

The Department of Energy released a pair of reports from the National Petroleum Council recommending changes to gas and electric coordination and to permitting rules for oil and gas.

The council is a federal advisory committee made up of leaders from the oil and gas industry and academia, with power sector interests participating in the coordination report.

“The National Petroleum Council’s findings confirm what President Trump has said from Day 1: America needs more energy infrastructure, less red tape and serious permitting reform,” Energy Secretary Chris Wright said in a statement Dec. 3. “These recommendations will help make energy more affordable for every American household.”

The coordination study shows how rising natural gas and electricity demand are combining with shifting use patterns to “strain natural gas pipelines in key regions of the United States.”

“Since natural gas became the dominant fuel for U.S. electricity generation in 2016, the interdependence between the gas and electric systems has deepened — but so have the risks of misalignment,” the report says. “The two systems function under fundamentally different commercial, regulatory and operational frameworks.”

The gas industry is built around long-term contracts and steady demand, while the wholesale power markets are based on real-time market dispatch and hourly price signals. The differences create persistent mismatches in timing and incentives, especially during periods where demand is high for both — most notably during extreme winter weather, the permitting report says.

That issue is bigger in organized wholesale power markets, in which generators depend on hourly price signals and lack the incentives to pay for firm pipeline capacity.

“Their gas procurements rely less on long-term delivery contracts and more on a variety of shorter-term commodity procurements and lower-priority transportation arrangements,” the report says. “When the gas and electric systems are both under stress, these arrangements are the first to be curtailed.”

The two reports both recommend building new infrastructure, with part of the recommended fix to longstanding coordination issues being expanding pipelines. Electricity generation has become the biggest consumer group for natural gas, beating out local delivery companies, as coal plants have retired and been replaced by generators burning cheap shale gas.

“As a result, gas demand has become far more variable and dynamic, with power generators — especially in deregulated markets — often relying on secondary or interruptible pipeline capacity, which amplifies intraday and seasonal fluctuations,” the report says. “The rapid expansion of wind and solar resources, which together account for more than 60% of new U.S. generation capacity since 2010, has made gas-fired units essential for grid balancing, requiring flexible fuel supply and rapid ramping capability.”

Some pipeline expansion has happened over the past decade, but most of that involved reversing flow directions and adding compressors rather than building new lines. That has helped to meet higher demand, but it has also contributed to fewer flexibilities for generators that would benefit from them.

Storage would also help generators, but the sector has not invested in it, with most expansions being tied to LNG exports, the report says.

The report recommends that Congress and the executive branch take immediate legislative and administrative action to reform permitting to unlock fit-for-purpose infrastructure investment. The two industries should work together to expand new infrastructure to serve generation and prioritize actions to enhance and expand existing infrastructure.

Most previous gas-electric coordination efforts have focused on the few peak winter days, but that risks the broader trajectory of the system, with electric demand poised to rise significantly in the coming decade and some regions’ grids shifting to winter peaks from summer, it says.

The report notes that current market structures fail to incentivize generators to secure either long-term gas transportation or highly flexible premium products. The two sectors’ different business models mean the pipeline sector has not expanded to meet the growing needs of power generation.

The report calls on ISO/RTOs and state and federal regulators to ensure adequate risk-based compensation for gas-fired power generators to get enough fuel and operate reliably when called upon.

FERC should direct ISO/RTOs to conduct comprehensive long-term planning that integrates resource adequacy and fuel assurance considerations, the report says.

On the gas side, the report recommends that policymakers and the industry work to address changing hourly gas flow patterns with alternative tariff structures that enable enhanced gas service offerings and flexible contracting arrangements with generators.

The Natural Gas Council, which is made of trade organizations from that industry, and the Reliability Alliance, which includes the Electric Power Supply Association, Interstate Natural Gas Association of America and the Natural Gas Supply Association, released a joint statement supporting the reports and asking for state and federal regulators to act on its recommendations.

“Time is of the essence,” they said. “Policymakers and industry must act swiftly to develop the infrastructure that will win the global energy and AI race while continuing to meet growing demand for affordable, reliable and secure energy. While the natural gas and power industries are fully capable and committed to supporting our nation’s expected energy demands, we need additional direction and policy changes from state and federal policymakers to facilitate prompt implementation of these recommendations. We ask Congress, the U.S. Department of Energy, FERC and state commissions to undertake action aimed at ensuring adoption of the recommendations in these reports.”

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TEP Wins Approval for Data Center Energy Supply Agreement

Arizona regulators approved a 286-MW energy supply agreement between Tucson Electric Power and the developer of an embattled data center project near Tucson.

The Arizona Corporation Commission (ACC) voted 4-1 on Dec. 3 to approve TEP’s agreement with data center developer Beale Infrastructure Group and its affiliate, Humphrey’s Peak Power, to supply energy to the Project Blue data center in Pima County.

TEP officials said they won’t need new, dedicated resources for the 286-MW agreement. Instead, they’ll have capacity from resources already planned through the company’s 2023 integrated resource plan. Capacity also will be freed up through expiring wholesale contracts with utilities that now plan to use other market resources, they said, as well as delays and reductions in industrial load.

Commissioners said that without the energy supply agreement (ESA), the developer could simply take service under a large-load tariff — without customer protections that are in the agreement. TEP representatives noted that they’re obligated to provide service to customers in its territory.

“I don’t think we have an option at ‘no,’” Commissioner Lea Marquez Peterson said. “We need to make sure that we have an ESA … that protects all the ratepayers.”

Among the protections in the 10-year agreement is a minimum monthly charge that would apply if actual electricity demand is less than the contracted amount. Beale must give at least three years notice to terminate the agreement.

Power will be provided under a commission-approved rate schedule that would be subject to commission review in future TEP rate case proceedings.

TEP said the agreement would allow it to spread fixed costs across more retail electric sales, reducing the need for rate increases.

Beale will pay TEP the estimated $4 million for two new 138-kV transmission lines to exclusively serve the project. The cost of a new switchyard will be recovered through the utility’s FERC open access transmission tariff.

Beale is expected to start taking service in May 2027, ramping up to 286 MW in 2028.

Opponents Speak Out

Project opponents, including many Tucson-area residents, expressed skepticism of the agreement. Some predicted the data center would further increase utility bills for residents, who are already struggling to make ends meet.

“The main question that has not been answered by TEP is, where is this 286 MW really coming from and when are we going to pay for that?” Lee Ziesche of the No Desert Data Center Coalition told the commission. “There is nothing in the energy supply agreement that protects us from paying for generation.”

Opponents also questioned the viability of the data center project. Just days before the commission meeting, news outlets reported — based on comments from Pima County supervisors — that Amazon had pulled out of Beale’s data center project.

“As far as we know, Beale doesn’t have a customer,” a project opponent told the commission.

In an email to RTO Insider, a Beale spokesperson pointed to previous public comments from Amazon Web Services saying they had no agreements in place in Tucson. A Beale representative also addressed the issue during the ACC meeting.

“We feel confident that we will have a customer ready by the time the data center comes online,” said Sam Arons, vice president of energy and sustainability for Beale Infrastructure.

Commissioner Rachel Walden voted against the energy supply agreement. She shared residents’ questions about how generation would be paid for and said the agreement should include more protections, such as a higher buyout rate if the developer pulls out.

“This kind of sets the stage for future contracts,” she said.

Annexation Request Rejected

Beale Infrastructure plans to build Project Blue on a 290-acre parcel in Pima County. The county Board of Supervisors approved the sale and rezoning of the county-owned land to Beale in June.

The developer asked the city of Tucson to annex the project site, a step needed to procure water to cool the data center. The developer offered to build an 18-mile pipeline to bring in reclaimed water.

But in August, the Tucson City Council voted unanimously to reject the project, mainly due to concerns about the large amounts of water and energy it would require.

In September, Beale announced an updated design for Project Blue in which a closed-loop, air cooled system would be used for cooling. Under the new design, “minimal” amounts of water would be recirculated through a closed-loop, air-cooled system to provide industrial cooling, Beale said.

The new cooling method didn’t change the amount of capacity requested in TEP’s energy supply agreement.

Beale has also committed to pursuing 100% renewable energy for its Pima County data center. Initially the data center will be powered by renewable and non-renewable energy, and Beale will buy renewable energy credits to offset the non-renewable power.

Longer-term, Beale plans to work with TEP on developing new renewable resources for the data center, which the developer would pay for.

Future Phases

The energy supply agreement approved Dec. 3 applies only to Project Blue, which is the first phase of Beale’s plans for data center development in the Tucson area.

A second project, known as Luckett Industrial, is planned on two parcels in Marana, Ariz. One parcel is served by TEP and the other is served by Trico Electric Cooperative.

“Trico and TEP have both submitted letters stating that they will work with Beale to support the data center’s needs without impact to service or rates for [other] customers,” a Beale spokesperson said in an email.