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December 7, 2025

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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.

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MISO Declines Stakeholder Ask for Pause on 2025 Queue to Clear Backlog

MISO said it will not postpone the kickoff of a study on its 2025 cycle of interconnection requests, rebuffing stakeholders’ requests for a slowdown to clear some of the queue’s four-year backlog.

“MISO doesn’t want to be looked at as slowing down the queue process. We do think we’re ready to kick off. … We’re committed to Jan. 5,” Manager of Generation Interconnection Ryan Westphal told the Interconnection Process Working Group during a teleconference Dec. 2.

Westphal said MISO would commence studies on the 2025 cycle of projects on Jan. 5, 2026, as scheduled.

Some stakeholders have advised MISO to delay the first studies on the 2025 queue cycle until the RTO is further along processing projects that entered three and four years ago, allowing developers to reach decisions on whether to continue with their plans. (See Stakeholders Ask MISO to Pause ’25 Queue to Get a Handle on 4-Year Backlog.)

But Westphal said FERC Order 2023 requires MISO to begin new interconnection study cycles 90 days after it closes an application window.

Westphal said MISO would have to seek a waiver with FERC to delay studies and cannot assume the commission would approve it, leaving the RTO no choice but to forge ahead with the early January timetable. He said MISO is working on prescreening the 2025 entrants.

“Seeking a waiver to postpone the 2025 cycle could be construed as MISO trying to slow down our queue process, which is directly counter to MISO’s direction to complete queue cycles in 373 days,” Westphal said.

Some stakeholders remain adamant that there are too many unknowns following study results to simultaneously process four years of interconnection requests.

REV Renewables’ Humberto Branco said the 2023 cycle is essentially a “wild card.” He said MISO trying to manage all cycles across all regions “just to get it done” is too much.

“There is some uncertainty there, I acknowledge that,” Westphal said. “We have to move these cycles forward as best we can.” He added that even later-stage queue projects fall victim to restudies.

Westphal said MISO continues to automate what it can using Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software. He said the RTO is now focused on automating some aspects of model building. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Westphal said MISO only includes network upgrades for generation projects that have made it to the third phase of the queue in its base case modeling. He said those upgrades are the most likely to be constructed and not disrupt lower-queued projects. Westphal said MISO doesn’t want to give developers unrealistic cost responsibilities.

MISO Director of Resource Utilization Andy Witmeier said interconnection customers can mitigate the risk of higher-than-expected network upgrades by using model data posted by the RTO in their own analyses.

“The status quo is no longer acceptable. We have to continue to move these queue cycles forward to get this cleared and move to a one-year queue process,” Witmeier told stakeholders.

MISO’s Central and West planning regions still have projects in the queue from the 2021 cycle. Westphal said MISO is “trying to wrap up” those projects in early 2026.

The 2022 cycle — MISO’s largest — will emerge from the three-part queue’s second phase in early 2026. The RTO meanwhile expects the 2023 cycle to enter the second phase of studies late this year and conclude in early April 2026, while the 2025 cycle will finish up the first phase in mid-April.

Altogether, MISO has 174 GW worth of projects in its queue, a value that has fallen from 312 GW at the beginning of 2025. (See MISO Interconnection Queue Dips Below 175 GW.)

Coalition of Midwest Power Producers’ Travis Stewart said he appreciated MISO’s engineering efforts but asked staff to post projected dates according to when it could “realistically” reach milestones, not just the tariff-defined deadlines. He added that he has noticed the RTO is processing queue cycles noticeably faster now.

“It feels, from my perspective, that the pendulum has swung in terms of timing,” Stewart said.

Westphal agreed that MISO is seeing speedier results. He said the RTO is poised to complete the 2025 cycle in the span of a year.

“We’ve all got to be ready to move fast, and not just MISO, to get these cycles processed,” Westphal said.

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MISO Floats ‘Zero Injection’ Agreements to Bring Co-located Gen Online

MISO is considering a new type of interconnection agreement for generation built on site and strictly for new large loads.

Marc Keyser, with MISO’s external affairs team, said the RTO wants to introduce “zero-injection generator interconnection agreements.” Under the agreements, generators built solely to serve a data center or other large load customer would connect to the grid without the ability to inject power into the grid and serve load solely at the same interconnection point.

“Let’s explore this hypothesis of zero-injection generator interconnection agreements. … We’re hearing our members say, ‘Please move quickly. Please help us facilitate large load interconnections.’ So, this is one way of doing it,” Keyser told stakeholders at a Planning Subcommittee meeting Dec. 3.

Keyser said zero-injection GIAs could benefit large load customers, with MISO recognizing on-site generation in interconnection studies, “potentially reducing network upgrade requirements to interconnect.”

“The intent here is speed,” Keyser said, adding that MISO could “reflect the reality” in its queue analyses that some new generators are built solely to serve a single large-load customer.

Keyser acknowledged that the new GIA type would have limits and said a generator that wants full rights on the MISO system would still have to submit to the full-length queue process.

“It’s certainly not a full solution. You have a generator that cannot inject when you come out of the end of this,” he said.

The idea is part of MISO’s larger push to create registration and market participation rules for co-located generation and load.

“As these configurations become more common, we want to make sure our frameworks evolve to serve them,” MISO Director of Expansion Planning Jeanna Furnish said.

Keyser said the new type of GIA could work alongside MISO’s other efforts to incorporate large loads, including its interconnection queue fast lane, its long-range transmission planning, its expedited transmission request process and its ongoing efforts to cut regular queue processing down from about four years to 373 days.

Furnish said MISO would focus on how it can better enable large load integration over 2026.

But stakeholders said implementing the new, limited GIAs might not be as simple as RTO staff made it seem.

WEC Energy Group’s Chris Plante said stakeholders need time to “opine on the merits of such an arrangement.” Plante said he wasn’t sure MISO applying network status to generation barred from injection would square with FERC’s rule against RTOs netting behind-the-meter generation with load.

“I’m not even sure that we know this is feasible from that standpoint,” Plante said. “I’m very concerned that we’ve put something on the table that hasn’t gone through a full stakeholder discussion.”

Keyser said the proposal is in the early stages and that MISO doesn’t intend to “create a netting situation between load and generation.” He said the RTO would contemplate the loss of generation in its interconnection studies so as not to lump load and generation together.

He added that MISO has filed GIAs in the past with zero megawatts of injection service specified in them.

But Plante said MISO should examine what the generation would do without the load. He said if load trips and its dedicated generation does not, the generation would be injecting on the grid, “even if momentarily.”

“Can we sustain the loss of a 1.2-GW data center?” Plante asked hypothetically.

The Sustainable FERC Project’s Natalie asked MISO to stay focused on the technical details of the proposal, especially how curtailments of generation and load might be handled should either go offline unexpectedly.

“I want to make sure we don’t forget the important technical questions,” McIntire said.

American Transmission Co.’s Erik Winsand said MISO must decide on how it would conduct technical studies, as well as what tariff changes might be necessary to make zero-injections GIAs a reality.

MISO staff committed to refining their plan. Keyser asked stakeholders to bring opinions on whether the RTO should require a contractual link between load and generation or if the load and generation should be allowed to span electrically similar pricing nodes. He also asked for more advice on whether MISO should prepare for planning and reliability risks under the new GIAs.

Hoosier Energy’s Tommy Roberts said the idea was “exceptional” and that the RTO should move quickly to implement it.

“We’re going to get run over if we move slowly,” he said.

However, Roberts said he was concerned that diagrams in MISO’s presentation appeared to show two separate points of interconnection between the load and generation, instead of both behind a single point of interconnection.

“There is some level of injection just between two points on a switchyard out of data center,” Roberts pointed out.

Keyser agreed that the chart MISO presented was flawed and said the intent is for both load and generation to be situated behind the same point of interconnection.

MISO is scheduled to discuss its proposal at a Planning Advisory Committee meeting Jan. 21, 2026, and again during a stakeholder workshop Jan. 30 dedicated to discussing the implications of large loads.

Keyser said MISO would move “rapidly” over 2026 to firm up the proposal.