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February 3, 2026

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NYISO Pins High Electricity Prices on Global Gas Market

With natural gas being the dominant fuel for electricity generation in New York, rising electricity prices are driven by the increased cost of gas because of the ongoing Russia-Ukraine War and increased LNG exports, according to a recent policy paper by NYISO.

The paper, released Jan. 29, comes after a week of winter weather and elevated off-peak prices. It relied on the Short-Term Energy Outlooks (STEOs) by the Energy Information Administration and an analysis of electricity prices by Lawrence Berkley National Laboratory.

Prior to the surge in LNG exports, prices remained low because of the shale gas fracking boom of the late 2000s, just as President Barack Obama entered office. Around the same time, Russia began antagonizing Ukraine, culminating in the invasion and annexation of the Crimean Peninsula in 2014. Russia, which also controlled most of Europe’s supply of natural gas, cut off supply to Ukraine the same year.

To counter Russia’s aggression and lessen Europe’s dependency, the Department of Energy under Obama began in 2012 to issue approvals of LNG facilities for exports to countries with which the U.S. did not have free-trade agreements, a policy that continued under Presidents Donald Trump and Joe Biden — though Biden would unsuccessfully attempt to pause such exports in early 2024.

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The U.S. became a net exporter of LNG in 2017 and the world’s leading exporter in 2023, according to a 2024 study at Harvard University. In its STEO for January 2026, EIA noted that LNG exports in 2025 increased by roughly 26% compared to 2024 exports, growing to an estimated 15 Bcfd.

“For context, U.S. residential gas customers consume approximately 12 billion cubic feet of gas per day,” the NYISO paper says. “In other words, the U.S. is forecast to export more natural gas than residential customers are expected to consume.”

The result has been a strong correlation between gas and electricity prices across the U.S., including in New York. The Transco Zone 6 pricing hub is the primary procurement site for the state’s gas fleet. In 2020, amid the COVID-19 pandemic, the price at the hub was $1.64/MMBtu. In 2022, Russia began its full-scale invasion of Ukraine, and exports to Europe — sent over pipelines that run through Ukraine — dwindled. The Transco 6 price shot up to $7.01/MMBtu.

The price for electricity followed the spike, from the record low of $25.70/MWh in 2020 to $89.23/MWh in 2022, according to the paper.

While prices for both electricity and gas fell in the short term, they gradually rose again over the next three years as LNG exports continued to grow. In 2024, gas traded on average at $2.10/MMBtu; by 2025 prices were hovering around $4.64/MMBtu. “The result was significantly higher wholesale prices for electricity as well — with an average price of $74.40/MWh throughout 2025, compared to $41.81/MWh for 2024,” the paper says.

The paper was published just after a Jan. 28 meeting of the Budget & Priorities Working Group in which stakeholders asked NYISO staff why energy prices were trading high when load was not near peak.

“We’re noticing right now that while the load isn’t great, the marginal cost of energy is very high,” said Kevin Lang, a lawyer representing the New York City and Multiple Intervenors.

Many stakeholders asked for specifics on hourly pricing, and what facilities on which pipelines were involved in setting daily natural gas prices.

“It’s not just as simple as ‘Transco 6 day-ahead cleared at X,’” said Doreen Saia, chair of natural resources law at Greenberg Traurig. “There’s a lot of factors going on.”

In an email, Lang told RTO Insider that the policy paper did not answer his questions about why energy prices had been surging during periods of low demand, particularly in recent days. According to Yes Energy data, off-peak prices have been on average higher than on-peak prices over the previous 10 days.

Barbara Kates-Garnick, a professor of the practice of energy policy at Tufts University and former Massachusetts Department of Public Utilities commissioner, said rising price trends could be broadly attributed to natural gas prices, Trump’s energy export policy and demand.

“Exporting LNG does subject all burns over time to world markets,” Kates-Garnick said. “Global natural gas prices were something that we had to become more sensitive to” during her time on the DPU and as undersecretary of energy.

She said the question facing local policymakers is whether to invest in infrastructure or “cobble” solutions together to deal with emergent price spikes.

“We keep pushing this can down the road. Every time it emerges, we address it as if it’s a new problem,” she said. “It’s very frustrating.”

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IESO, Stakeholders Ponder Changes to Hourly DR

IESO is reconsidering how it deploys hourly demand response (HDR) following complaints over partial activations and an increase in standby notices.

In a meeting Jan. 29, stakeholders expressed frustration over IESO’s issuance of standby notices and said partial DR activations were harming performance. The ISO also heard concern about its announcement that the capacity targets set in the Annual Planning Outlook will no longer be binding and may be adjusted upward or downward before the yearly auction.

Hourly demand response accounted for more than half the capacity procured in the 2025 auction (53.4% of summer, 76.7% of winter). (See Big Jump in Ontario Capacity Prices Signals Tightening Supplies.)

IESO said HDR resources are “critical” to reliability during tight supply conditions but that they have historically underperformed, making it difficult for control room operators to maintain supply-demand balance during emergencies. In summer 2025, IESO activated 16,775 MW of HDR, but only 12,153 MW (72%) was delivered.

IESO previously triggered HDR activations manually during a Conservative Operating State or NERC Energy Emergency Alert 1. More recently, activations have been triggered by pre-dispatch scheduling run prices exceeding $2,000/MWh.

HDRs were activated 10 times in summer 2025 and seven times so far this winter, an increase from the historical rate of two to three activations in summer and none in winter.

The ISO acknowledged that more frequent HDR activations could lead to “resource fatigue” and participants dropping out. In addition, “all-or-nothing” HDRs lack the ability to follow dispatch instructions for partial activations.

As a result, IESO said it will hold an engagement over the next three capacity auctions on potential changes to HDR rules and improvements to non-HDR rules that have been identified in previous engagements.

The engagement, scheduled to begin in Q1 2026, will initially focus on “achievable ‘quick wins’” due to the limited time available before the 2026 auction, the ISO said.

Standby Notices

IESO issues standby notices to provide HDR resources time to prepare for potential activations.

Gilon Hershkowitz, of steelmaker ArcelorMittal, asked for guidance to help DR providers understand when standby notices will translate to activations.

“We want to be able to respond to the activations with our full capacity. [With] the short notice it’s very challenging for us to do so,” he said. “If we receive [fewer] standby notices and [have] a higher level of confidence that when we do receive a standby notice — maybe there’s some other data that [will indicate] this notice will actually translate to an activation — teams can be prepared.”

Laura Zubyck, IESO’s capacity auction supervisor, said the ISO will review its procedures to “make sure the standby is working in the way that that we want it to.”

Ted Leonard, of EnPowered, said the Market Renewal Program, which introduced LMPs and a financially binding day-ahead market in May 2025, has resulted in a “new normal” with unintended consequences.

“HDR [is] a reliability product; it wasn’t constructed to have partial activations,” said Leonard, IESO’s former chief financial officer. “It’s not meant to be there to help suppress prices during high demand events. It’s meant to keep the lights on.

“Maybe we need to look back and say, ‘Was this the intended consequence?’” he added. “Was this what HDR is all about, or HDR is meant to be? Because it feels like we’re losing our way a little bit.”

Zubyck said higher-than-normal temperatures during summer 2025 caused an increase in HDR activations and — for the first time — partial deployments.

“Now that we are seeing a partial activation of an HDR, we need to look at it, and we need to understand if there’s perhaps some changes we need to make,” she said.

Inefficient Decisions?

Roman Grod, of Rodan Energy, said his company has been challenged by partial activations that differ hour to hour. “Let’s call it 10 MW in the first hour, 15 in the second and 20 in the third. … That’s when I think it gets a little more challenging, because then you’re forced to do this kind of cascading effect where you’re activating folks for … three hours, then a different … side of your portfolio for two hours, and then another one for three hours,” he said.

Aaron Lampe, of Workbench Energy, said the ISO’s optimization engine is making inefficient decisions in picking HDR resources because “unlike for other resources, where the tools the ISO has built respect the operating characteristics of those resources — things like minimum loading point, ramp rates, minimum runtime, daily energy limits, etc. — none of those are reflected for the DR resource.

“And so, the optimization engine is picking the DR resource in situations to fill these short gaps, assuming this is an essentially infinitely flexible resource and then activating them. But it’s actually a very expensive resource [because of] market payments outside of that optimization that are occurring.”

Zubyck said the ISO is reviewing its rules “from a holistic level.”

“It’s not as simple as … we need to just fix partial activations, or we need to do this item. We do have to kind of look at everything that happened and consider … those bigger questions.

“This is the feedback we want to hear: that it’s a challenge to go up and down for some resources, and that we may need to consider … solutions to deal with that,” she added.

Other Priorities

Lampe said that stakeholders have been waiting for several years for action on items that were “shelved,” in part because the ISO was consumed by developing the Market Renewal Program.

In late 2023, Lampe said stakeholders had a meeting with the ISO to discuss issues regarding DR data submission and metering requirements. “It’s been two-and-a-half years or so [and] we haven’t heard anything following up,” he said. “I just want to ask: Are those still being tracked? … And how do those fit in the relative prioritization?”

Zubyck said the issues will be included in the new engagement. “We will bring those items back out and start to speak with stakeholders again about reprioritizing them and … allotting them into the next few auctions,” she said. “They have not been shelved.”

Changing Capacity Targets

Rodan Energy’s Grod also expressed concern about the ISO’s announcement that the capacity auction targets published in the Annual Planning Outlook (APO) each spring will now be preliminary, with the binding target published in the Pre-Auction Report in summer.

“This change provides additional flexibility for the IESO to adjust the target in response to issues/uncertainties that may emerge after the APO is published,” said the ISO, adding that the changes “will have limited impacts on stakeholders.”

“The ability to decrease the target concerns us significantly,” Grod said. “Customers often commit to this program based off historic clearing prices and where they … see the market going. [The] target in the APO really provides some level of confidence that … pricing is going to stay somewhat stable.

“If the ISO has the ability to lower the target — say, by 500 MW — that’s going to have a significant negative impact on pricing,” he added. “And I frankly think that that’s the wrong signal we want to be sending, especially as we’re seeing this resource be … activated more and more often.”

Bryan Timm, senior adviser on IESO’s capacity auction team, said the ISO would raise or lower the target only in response to an “unusual or significant event.”

“If [a] procurement delivered fewer megawatts than we anticipated, that might cause us to consider raising the target to meet system needs,” he said. “So, these would be significant events, not … one-off, minor changes.”

Feedback

Feedback on the Jan. 29 engagement is due Feb. 12 via the feedback form on the Capacity Auction Enhancements webpage.

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With Sunrise Wind Ruling, OSW Industry now 5-0 Against Trump Admin.

A judge has granted developers of Sunrise Wind a preliminary injunction against one of the federal stop-work orders slapped on U.S. offshore wind construction.

The Feb. 2 ruling in the U.S. District Court for the District of Columbia (1:26-cv-00028) completes the judicial pushback against the Trump administration: One by one, in the space of three weeks, four judges have granted the five projects under construction in U.S. waters permission to resume construction.

Sunrise Developer Ørsted said it would resume construction of the 924-MW project as soon as possible and said: “Sunrise Wind will determine how it may be possible to work with the U.S. administration to achieve an expeditious and durable resolution.”

Durable is an important caveat.

President Donald Trump has attacked offshore wind relentlessly, starting with an executive order hours after his second term started. His administration has moved on multiple fronts to hinder construction of projects underway and block future construction from starting.

This culminated in the five stop-work orders issued Dec. 22 on grounds of national security that now have been set aside.

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Revolution Wind got its injunction Jan. 12, Empire Wind Jan. 15, Coastal Virginia Offshore Wind Jan. 16 and Vineyard Wind Jan. 27.

Counting an August 2025 stop-work order against Revolution that a judge lifted and an April 2025 stop-work order against Empire the Trump administration removed after discussions, the administration’s record is 0-1-6.

But the fight is not over, and the administration has secured an important achievement: Investors likely have been scared away from U.S. waters. Further, the offshore wind industry has been thwarted in its attempts to develop infrastructure, create an industrial ecosystem and build project momentum in the U.S.

There also is considerable financial impact on the developers.

Empire placed the cost of the April 2025 stop-work order at $200 million. Court papers estimated the costs at “millions per week” for Revolution and $2 million a day for Vineyard.

In a Jan. 30 regulatory filing, Dominion tallied the full cost of the December shutdown at $228 million.

Sunrise, which is at an earlier stage of construction than the other four projects, said in its Jan. 6 complaint that the shutdown was costing it more than $1 million a day.

Oceantic Network cheered this latest victory. CEO Liz Burdock said:

“Sunrise Wind represents a vital investment in strengthening both Long Island’s power system and the broader regional grid that millions of residents rely on — particularly during the harsh winter months. Offshore wind is uniquely suited for these conditions and stands ready to deliver steady, abundant power, easing the burden on families who have long relied on costly peaker plants to keep the lights on. Oceantic applauds this decision, which moves us closer to providing reliable, affordable clean energy and creating high‑quality jobs for the communities that stand to benefit the most.”

New York’s senior U.S. senator, Charles Schumer (D), posted on X: “Trump just received his 5th straight loss in the courts in his crusade to stop offshore wind and kill thousands of jobs. Trump is losing his war against offshore wind. I will keep fighting to make sure these projects and the thousands of good-paying jobs they create move forward to help reduce energy costs for the country.”

Some of the many opponents of offshore wind wasted no time replying.

“SHAME ON YOU! SHAME! SHAME! SHAME!” was among the milder comments.

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FERC Approves PJM CIR Transfer Proposal

FERC approved revisions to PJM’s tariff to streamline the process for the owners of a deactivating resource to transfer its capacity interconnection rights (CIRs) to a new unit at the same point of interconnection (ER26-403). (See PJM Preparing Alterations to Rejected CIR Transfer Proposal.)

Replacement resources would qualify for replacement generation interconnection studies in lieu of the full slate of network impact studies new resources must undergo. The replacement resource cannot exceed the maximum output of the retiring unit, and it must interconnect at the same substation bus and voltage. The studies are expected to take 180 days to complete.

Since the CIRs for the deactivating resource already have been studied and the unit included in PJM’s system modeling, the commission wrote it is not necessary for a replacement to undergo the full suite of studies to ensure deliverability. The creation of a parallel queue would not constitute queue jumping because the CIRs already have been studied and determined to be deliverable, while the network impacts of a greenfield project are unknown.

The filing is PJM’s second crack at creating a fast track for replacement resources after the commission rejected its first proposal in August 2025 because of two carveouts from the proposed requirement that projects be capable of entering service within three years. Those provisions would have created a one-time extension of the in-service date requirement and an exception for resources with long development timelines, which the commission wrote would undermine the purpose of PJM’s proposal: bringing replacement resources online faster (ER25-1128).

“PJM’s proposal permits milestone extensions only in certain circumstances, and only for up to a specific amount of time, which will help ensure that the replacement generation interconnection process results in the timely and efficient replacement of generating facilities. Unlike the prior proposal that allowed replacement generation project developers to unilaterally extend the commercial operation date for their project without restriction, the instant proposal allows PJM to ‘reasonably extend’ the in-service date or other milestones under specified conditions,” the order states, adding that if a developer requires a longer extension, a waiver can be requested from the commission.

Those milestone extensions would be permitted only for “delays not caused by the project developer and that could not have been remedied through the exercise of due diligence,” PJM wrote in its transmittal letter. Milestone extensions would be capped at three years past the original commercial operation date.

PJM wrote the proposal is one of several changes to PJM’s planning and interconnection processes intended to allow resources to come online more quickly as the RTO seeks to ward off a looming resource adequacy shortfall. Other efforts include the Reliability Resource Initiative, which allowed 51 resources that could quickly add capacity to be inserted into Transition Cycle 2, and expanded eligibility for surplus interconnection service. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

“At a time when PJM needs additional capacity resources in the near term to meet serious resource adequacy challenges, the expedited processing of replacement generation interconnection service requests claiming a deactivating facility’s CIRs can yield significant reliability benefits by facilitating the timely addition of new capacity while promoting the efficient use of existing infrastructure,” PJM wrote.

The Independent Market Monitor protested the filing, arguing it would divert planned resources from the cluster-based interconnection queue to a less efficient serial study process and further slow development by creating an incentive for resource owners to withhold CIRs until they can be sold to a developer.

During the stakeholder process that led to PJM’s filing, the Monitor proposed a model under which the CIRs associated with a deactivating resource would be made available to all resources on the grid as transmission headroom. It reiterated the argument that CIRs should not be for sale in its protest. (See “Voting on CIR Transfer Proposals Deferred to October,” PJM PC/TEAC Briefs: Sept. 12-13, 2024.)

“The basic purpose of the process is to permit existing generators to sell their CIRs to the highest bidder rather than to identify the best replacement resource. The proposal is inconsistent with open access and the purpose of CIRs. A proposal to truly reform CIRs would terminate CIRs immediately at the time a resource deactivates, and thereby avoid undue discrimination, promote competition and facilitate the rapid entry of needed new generation,” the Monitor wrote.

The commission wrote the proposal would not implicate market power as the ability to transfer CIRs already is codified in the tariff.

“This filing simply establishes an expedited review process for replacement generation resources interconnecting at the same location as a deactivating generating facility that would not change the voltage or maximum generation output at that location. Nothing in the instant filing would modify the existing rights to transfer CIRs or the transfer process,” the order states.

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IESO: Few Capacity Downgrades from Performance Adjustment Factor

IESO downgraded less than 100 MW of capacity for November’s auction in the first application of its Performance Adjustment Factor (PAF) in both the winter and summer seasons.

The PAF ensures the ISO procures only capacity that has been confirmed by testing.

“It really was a small number of megawatts that ended up being derated because of the [PAF] … less than 100; probably less than 50 megawatts. But it was a very small amount,” Laura Zubyck, IESO’s capacity auction supervisor, said during a Jan. 29 engagement. “We’ve seen good performance in our capacity tests, and so we rarely derate.”

Clearing prices hit a record $471/MW-day for summer 2026, nearly double the $243 from 2024, and $530/MW-day for winter, more than five times the previous $102. (See Big Jump in Ontario Capacity Prices Signals Tightening Supplies.)

IESO year-over-year capacity auction comparisons for winter. | IESO

IESO’s Paulo Antunes said the results reflected short-term changes in supply combined with a 200-MW increase in the target capacity. The auction cleared 1,832.8 MW for summer 2026 and 1,125.3 MW for winter 2026/27.

IESO cleared no imports from New York, a loss of 200 to 300 MW compared with previous years. Antunes said. In addition, about 200 MW of Ontario-based generation that previously participated in the auction instead signed contracts with the ISO under its second medium-term procurement.

“The remaining available supply in the market was not enough to offset the combined impact of these two factors,” said Antunes, who also noted the impact of increasing electricity demand and ongoing nuclear refurbishments.

Virtual hourly demand response resources made up the largest share of cleared capacity, representing almost 41% in summer and 60% in winter. (See related story, IESO, Stakeholders Ponder Changes to Hourly DR.)

The largest increase in cleared summer capacity came from system-backed imports, which accounted for almost one-third of cleared capacity.

The increase largely was enabled by increasing the Hydro-Québec import limit from 400 MW to 600 MW.

Generation-backed imports, in contrast, declined.

The 2025 auction also showed a narrowing gap between offered and cleared capacity. “In previous years, the gap has been much bigger, and this is resulting in an upward pressure on price,” Antunes said.

Julien Wu, of Brookfield Renewable, thanked the ISO for providing more detail on auction results than in past years but asked officials to provide still more, including information on the technology types that experienced derates due to the PAF.

“The more information we have, the easier it is for us to make scheduling and trading decisions,” he said.

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NYISO, Stakeholders Debate Changes to Demand Curve Reset

NYISO staff presented more of their initial ideas for improving the Demand Curve Reset process, centered on alternative shapes, slopes and points of the curve.

The ISO’s goal is to simplify the process for both staff and stakeholders. (See Resetting the Reset: Demand Curve Reform Discussions Begin.)

“The demand curve is at the core of aligning system reliability needs to market fundamentals,” Michael Ferrari, market design specialist for NYISO, told the Installed Capacity Working Group on Jan. 21. “Modifying them can enhance the efficiency of market signals to improve capacity market outcomes.”

The DCR shape and slope govern the value of capacity under different market conditions, sending price signals for new resource development and retirement of old units. The more installed capacity that is on the grid, the less any given megawatt is worth, and vice versa.

The curve is drawn from the zero crossing point (ZCP) to a reference point set by the cost of new entry and locational minimum capacity requirement. The ZCP is where the marginal price of an additional megawatt of capacity is equal to zero.

Currently, the curve slopes downward from the maximum clearing price plateau in a straight line to the reference point and the ZCP. Ferrari said NYISO had investigated “kinking” the demand curve into multiple slope segments, increasing the steepness of the curve to change prices more rapidly and increasing the ZCP. The ISO also discussed pinning the loss-of-load expectation reliability criteria to losing the largest generation unit in each location, similar to the N-1 contingency analysis in transmission planning.

“We are not trying to indicate an endorsement of any particular change or option,” Ferrari said, explaining that the presentation reflected “early analysis” of reform options.

Stakeholders said adjusting the ZCP might be difficult. Howard Fromer of Bayonne Energy Center said the first time the ZCP was set was a heavily negotiated process. Doreen Saia, of Greenburg Traurig, agreed.

“All of our locality curves have to work within the [New York state] curve,” she said. “If you extend out some of the curves too far, it eats into the ‘Rest of State’ price. … If you go too tight, then New York City gets problematic very quickly.”

Saia said that she welcomed looking at the demand curve and ZCP “with fresh eyes” because the situation has become much more complex, from both a regulatory and market player standpoint. More entities of more types are in the market trying to sell power.

One stakeholder mentioned that in the current DCR process, there are provisions to revise the shape and slope of the curve, but in practice this does not happen regularly. Ferrari said that the last time he recalled discussing changes to the ZCP was in 2014.

“Mike, I think you’re absolutely right,” Saia said. “We could have always looked at shape and slope, but for the first six or seven reset processes, the only thing that was even slightly considered was moving to a combined cycle gas facility” for the reference point.

Pinning the LOLE to a contingency analysis based on the largest generator also stirred discussion among stakeholders. Some said this would establish an incentive to build “really large generators” by essentially announcing that the demand curve would shift to accommodate them. One said that a contingency in the capacity requirement created uncertainty in developer cost-benefit calculations.

A NYISO staffer argued that using the largest generator had the benefit of greater clarity and transparency for understanding how the market would behave and would not necessarily increase market complexity.

Time-differentiated Transmission Congestion Contracts

NYISO is also considering alternative ways to divide transmission congestion contracts into more granular products.

Currently, TCCs are a 24-hour product only. NYISO is the sole RTO/ISO to offer only 24-hour financial transmission rights. This has been criticized by stakeholders as limiting the effectiveness of TCCs to serve as hedging mechanisms against congestion because they cannot distinguish between congestion patterns that change during the day or over the course of a week.

NYISO considered time-differentiated TCCs in 2021, proposing products for on-peak workdays, off-peak weekends and holidays, and off-peak “all other hours.” In 2025, Calpine proposed a system that broke TCCs into on-peak and off-peak hours. (See Calpine Sees Support for TCC Auction Proposal.)

The ISO is planning on finalizing a proposal in 2026, building off both its 2021 design and Calpine’s. Tariff language will not be pursued until it passes the annual project prioritization process.

Champlain Hudson Power Express Integration

NYISO provided stakeholders with an update on the Champlain Hudson Power Express integration process.

CHPE is a 1,250-MW HVDC line that will run between Quebec and New York City. It is expected to go into service in 2026, but the exact date is unknown. (See NYISO Proposes ICAP Changes for New Entry Ahead of CHPE.)

The capacity market is predicated on annual inputs with limited seasonality, and the capability year starts in May. If CHPE’s integration into the grid is mistimed, it could have major implications for capacity market parameters, such as the transmission security limit for the New York City-area capacity zones.

To accommodate this uncertainty, the ISO created two sets of market parameters, one assuming CHPE is operating and one assuming it is not. This creates two sets of TSLs, locational capacity requirements, capacity accreditation factors, unforced capacity demand curve parameters and load-serving entity minimum capacity requirements.

If CHPE provides notice by March 2 to participate in the ICAP market in May, NYISO will set the market to reflect its participation. The ISO intends to issue a notice by March 9 to market participants as to whether CHPE will be in the market.

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British Grid Operator to Highlight ERCOT Innovation Summit

ERCOT says Fintan Slye, CEO of Great Britain’s National Energy System Operator, will join ERCOT CEO Pablo Vegas to kick off the Texas grid operator’s third annual Innovation Summit.

Slye leads the publicly owned NESO, which manages Great Britain’s electric system and is responsible for planning the nation’s energy systems and markets. He has held leadership positions with the country’s Electricity System Operator and EirGrid, Ireland’s transmission system operator.

“NESO is at the heart of Great Britain’s energy system, and innovation is at the heart of everything we do,” Slye said in a statement. “At NESO, we are always looking to use innovation to help drive value for consumers and improve security of supply.”

He said it is “brilliant and timely” to participate in the summit and to collaborate with U.S. industry peers on grid upgrades, new data center demand, and other learnings and solutions that can benefit Great Britian’s energy system. The 2026 Innovation Summit, to be held March 31 at Kalahari Resorts and Conventions in Round Rock, Texas, will bring together industry stakeholders and thought leaders to share technological advancements and innovative solutions that advance grid transformation in Texas and beyond.

“Collaboration with our industry peers in the U.S. and across the globe is essential as we work toward building more resilient and intelligent solutions for rapidly evolving grids,” Vegas said.

The grid operator announced in September a Grid Research, Innovation and Transformation (GRIT) initiative designed to improve industry collaboration through expanded shared research and technology prototyping. The program’s technology initiatives focus on a range of areas, including smart controls for distributed energy resources, machine learning models to improve power flows and improvements to large load modeling.

ERCOT says between 850 and 950 participants attended each of the first two summits, either in person or virtually.

PJM CEO Manu Asthana highlighted the 2025 summit, also held in Round Rock.

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MISO Suggests Reliability Requirements, Partial Supply Deals to Handle Large Loads

MISO said it likely will create interconnection reliability requirements and explore new rules that could bring large customers online in stages, as capacity becomes available, to get a handle on large loads eyeing MISO locales.

MISO anticipates drafting “a set of guidelines and requirements” for large loads that wish to interconnect to maintain reliability. The RTO made the announcement at a Jan. 30 stakeholder workshop dedicated to large load preparation.

Executive Director of Markets and Grid Research DL Oates said MISO’s stakeholders view the grid operator as having a role in providing reliability interconnection guidelines.

Manager of Strategic Assessments Beibei Li said MISO can draw on its existing inverter-based resource requirements for ideas. She said MISO would need loads’ telemetry to maintain system reliability and stability and that it would use their data in modeling and planning.

MISO plans to introduce the topic to the Planning Advisory Committee for discussion in the next few months with the goal of working on a ruleset sometime around mid-2026.

Oates said MISO “is hesitant to provide exact dates” on when it could file tariff changes with FERC on the reliability requirements.

Oates said for years MISO has operated with an approximate 120-GW peak demand across its 45 million customers. He said by 2030, MISO could add anywhere from the “low 10s to the high 20s” of gigawatts.

“So, something like 15% of growth with a fair bit of uncertainty around that,” he said.

Oates said the new load coming MISO’s way is unlike anything MISO has seen: “It is, to put it very simply, very big.”

Jordan Bakke, MISO’s director of strategic insights and assessments, said there’s sizable reliability risk that large load customers could introduce.

“We expect large loads to behave in a way that’s hard to predict,” Bakke said. He said large loads have “unique disturbance behaviors,” including frequency sensitivity, low fault current and oscillations. He also said these loads have “unknown and varied ride-through performance” alongside complex protection schemes that make for complex stability assessments.

Minnesota Power’s Tom Butz said MISO appeared to have a great number of concerns over stability that come with large load customers. He asked if MISO has existing study processes to test how large loads specifically strain the system.

“MISO itself has very limited study as it relates to large load interconnection,” Bakke said.

Vice President of Operations Renuka Chatterjee said MISO will be “looking at some AI tools” for study assistance and promised “more to come.”

‘Speed to Partial Power’

MISO is toying with the idea of providing what it calls “speed to partial power.”

MISO Director of Expansion Planning Jeanna Furnish said large loads can make it online in a little more than a year, while generation takes about four years and transmission typically takes about seven to 10 years. She said load could be left trying to withdraw before generation or transmission arrive on scene.

Furnish said MISO’s ongoing work to create zero-injection generator interconnection agreements can help speed up generation projects that plan to send their output solely to their dedicated loads, not the greater system. (See Questions Abound over MISO Idea for Zero-injection Agreements.)

However, Furnish said MISO could implement ideas “while we wait on infrastructure.”

Enter MISO’s “partial power” brainchild. The grid operator said in some cases, it probably could serve a portion of large load customers’ needs with existing transmission for an interim period. Load then could be scaled up incrementally as generation or transmission is constructed. Finally, once construction is complete, the full load could be served with firm withdrawal capability at its interconnection point.

Furnish said providing service to fractions of load “helps address the challenges of using the system that is available and manage service as conditions change.” She said a ramp-up to firm service allows service even as upgrades come online.

Furnish said discussions on partial service applications similarly will be held at Planning Advisory Committee meetings.

Butz cautioned that MISO and members need to focus on energy adequacy because new large load customers have “twice the load factor” of MISO’s average load. He said the load surge comes as MISO’s highest-capacity-factor thermal resources plan to retire in droves.

“It’s really crucial that we understand how to serve high-load-factor load,” Butz said.

Chatterjee said MISO will strive to create “timely paths” for integrated large loads but “must keep the system reliable today and in the future.”

Chatterjee said MISO would examine which initiatives it could move fast on “without boiling the ocean.” She said the RTO already has done the “foundational work” to open up grid capacity through its expedited transmission project work.

Furnish also said MISO wouldn’t “copy and paste” other RTOs’ proposals in the large load space but is evaluating their work.

Reserve Product Revamp

Additionally, MISO said it needs to recalibrate its reserve products to account for greater uncertainty introduced by large loads.

Director of Reliability Coordination John Harmon said the “behavior of large load” isn’t reflected today in MISO’s ancillary service setup. He said it probably will have to keep more reserves and revise reserve products’ demand curves.

Harmon said large loads can quickly increase or decrease demand, especially when co-located generation or the load itself suddenly goes offline.

Harmon said the Reliability Subcommittee would handle modernizing the reserve scheme and noted the group already is working to create a dynamic regulation and ramp product that calls up a greater volume of reserves as system uncertainty rises.

Stakeholders asked what role MISO sees itself playing in controlling added costs on the system from load growth.

Bakke said that while MISO cannot influence much of the consumer costs that come with large loads, it views itself as responsible for cost-effective regional transmission planning to minimize the volume of more expensive, piecemeal transmission upgrades. He said the RTO likely must overhaul some of its process for furnishing reserves, since it expects that reserves will be used more often.

MISO will hold three more workshops on large loads over 2026: on April 30; July 31; and Oct. 29.

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EIA Charts Varying Impact of Gas Prices on Electricity Costs

The U.S. Energy Information Administration reported average wholesale day-ahead electricity prices were higher in 2025 than in 2024 at most but not all major trading hubs in the contiguous 48 states.

The largest decrease was $14/MWh at the Mid-Columbia hub in the Northwest. The largest increase was $29/MWh in ISO-NE.

In one of its regular “Today in Energy” posts, EIA said the national average was pushed higher largely by rising prices for natural gas, the leading source by far for U.S. electricity. Average benchmark Henry Hub spot prices were 56% higher in 2025 than the historic low prices seen in 2024.

This contributed to a minor shift in generation away from natural gas: Electricity generation in the 48 states increased 93 BkWh or 2% year over year, despite 2025 being one day shorter than 2024. Natural gas generation decreased 3% (53 BkWh), while coal increased 11% (76 BkWh) and solar jumped 32% (66 BkWh) to make up the difference.

The details of the shift varied by region.

In the PJM and MISO regions, total generation rose 3% (49 BkWh) in 2025 as gas generation decreased by 24 BkWh from 2024 levels, solar increased 24 BkWh and coal increased 49 BkWh.

In Texas, demand increased 5% (22 BkWh) in 2025; the major movers were natural gas (down 6 BkWh) and solar (up 20 BkWh).

In the Northwest, which saw a less severe winter in 2025 than in 2024, total generation decreased 4% (17 BkWh). Natural gas prices reached historic lows in the Northwest in 2025 amid subdued demand and ample supply from Canada, but natural gas generation nonetheless decreased 8 BkWh. Other movers were hydropower (3 BkWh higher), solar (2 BkWh higher) and nuclear (2 BkWh lower, thanks to a 65-day refueling outage).

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ERCOT Leaned on Mobile Gens, RMR Unit During Storm

ERCOT says Texas’ 15 mobile generating units and a reliability-must-run unit all played an “important reliability function” during the Jan. 25-27 winter storm, the state’s first major cold-weather event since 2021’s disastrous Winter Storm Uri.

Grid operator staff told the Texas Public Utility Commission during its Jan. 29 open meeting that CPS Energy completed repairs to its Braunig Unit 3 before the storm arrived and that it was committed throughout the event.

Dan Woodfin, ERCOT’s vice president of system operations, told commissioners that Unit 3 provided “necessary support” to relieve overloads in the San Antonio region after a large unit in Central Texas tripped Jan. 25. The trip caused “brief exceedance” on the South Texas export constraint and post-contingency overloads on some transmission lines between the region and Houston, necessitating a localized transmission emergency declaration that lasted about 13 hours.

Woodfin said the grid operator also committed the mobile generating units that were moved from Houston to San Antonio in 2025 to provide reliability support for the South Texas constraint. The constraint was binding throughout the storm, he said.

“The combination of these actions was sufficient to operate the system reliably until the large unit came back on” Jan. 26, Woodfin said.

CPS had intended to retire the 55-year-old gas unit in 2025, but ERCOT determined that it was needed to address the South Texas constraint. The RMR is the grid operator’s first since 2016, when it entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. (See “Braunig Outage to End in December,” ERCOT: New Ancillary Service Key to Resource Adequacy.)

“Kudos to ERCOT and to everyone involved for how the grid played out during this storm,” PUC Chair Thomas Gleeson said. “I think everyone resoundingly said this was a success [in] probably the most difficult storm we’ve had to endure since Winter Storm Uri. Everyone should be commended for the work done on this.”

ERCOT navigated the storm without resorting to calls for conservation, issuing energy emergency alerts or suffering systemwide power outages. Demand peaked at nearly 76 GW on Jan. 26, far short of early projections of 83 GW. Staff said the state’s cloud cover and closures of businesses and schools helped reduce demand.

“In summary, ERCOT successfully managed the Texas electric grid through this cold-weather event. As always, we will continue to learn from this event to improve our tools and processes going forward,” Woodfin said.

FFSS Criteria Approved

The commissioners approved staff’s proposal establishing the criteria for participation in ERCOT’s Firm Fuel Supply Service (FFSS) program and the grid operator’s requirements to implement it, a result of a law passed during the 2021 legislative session in Uri’s aftermath (58434).

The rule codifies requirements to procure FFSS during natural gas curtailments and cold-weather events. Staff identified three categories of resources eligible to provide the service: on-site, resource-controlled and contractual off-site. The latter expands the program, although its budget remains unchanged at $54 million.

Jeff McDonald, the Independent Market Monitor’s director, objected to the inclusion of gas-fired resources but said he understood that the 2021 storm “precipitated a need on the reliability side.” He said he was more concerned that FFSS, other ancillary services and residential demand response are all out-of-market actions that affect the ERCOT energy-only market’s reliance on shortage pricing to incent investment.

“They suppress the shortage-pricing mechanism from being able to adequately signal that there’s shortages,” McDonald said. “Therefore, there’s less revenue in the market. Therefore, you’re going to have delayed or reduced new investment.

“I would like to see these programs be diminished over time and more focus placed on the kernel of resource adequacy for ERCOT, which is shortage pricing,” he added. “I do understand the need after Uri. Cracks were exposed that needed to be filled. Enough time has passed now that I think it’s time to … focus more on in-market price signaling to provide reliability services to fill those cracks.”

Gleeson said he agreed with McDonald about the need to allow the market to provide revenues from scarcity, but he also said the rule makes sense “where we sit right now.”

“I think what you’ll see is continued discussion about that and the right timing to actually implement those changes,” Gleeson said.

Batch Zero’s Phased Study

ERCOT will conduct its first “batch” study of large load interconnection requests in two phases, Jeff Billo, vice president of interconnection and grid analysis, told the PUC.

The grid operator has proposed a “Batch Zero” process to address the 232 GW of interconnection requests from AI facilities, cryptocurrency miners and other large loads. Now, that batch’s first phase, or Phase A, will be limited to large loads that want to be energized early in 2027. Projects in that batch will undergo an abbreviated version of the Batch Zero study. (See ERCOT Again Revising Large Load Interconnection Process.)

A longer, full Phase B study will be for projects with longer timelines. It would begin in August and be completed early in 2027. Even then, the loads will have to pass ERCOT’s quarterly stability assessment five to eight months before they are energized.

“We need to do an operational assessment before those loads connect … to see if there’s anything that has changed since the studies were performed and see if we need to implement any sort of operational constraints to make sure that we know where the constraints are on the system,” Billo said.

The Batch Zero study will serve as a foundation for the other batch studies that follow every six months, beginning in the first quarter of 2027, Billo said. ERCOT will share the draft criteria for large load requests during a Feb. 3 workshop.

Responding to Federal Issues

Staff told commissioners that the PUC has joined the ballot pool for NERC’s Long-Term Planning Energy Assurance project (2024-02), allowing it to participate in future votes and comment windows (54987).

NERC has scheduled a workshop and meetings Feb. 17-19 to discuss concerns and start drafting revisions to the proposed standard, which has drawn pushback from utilities over a requirement to create corrective action plans. The standard failed to pass a first round of voting, garnering only 17.8% support.

PUC staff plan to return to the commission with comments to file in the proceeding.

“I think that’s the right course of action. I think corrective action plans seem out of scope for” NERC, Gleeson said.

The PUC has adopted a reliability standard that sets criteria for frequency, duration and magnitude of loss-of-load events. (See Texas PUC Sets Reliability Standard for ERCOT.)

Following a closed session, the PUC voted to file amicus briefs supporting FERC in two dockets before the D.C. Circuit Court of Appeals: Clean Wisconsin, the Natural Resources Defense Council and the Sierra Club’s appeal of the commission’s approval of MISO’s Expedited Resource Addition Study process (25-1264), and Advanced Energy United, Advanced Power Alliance, American Clean Power Association and Solar Energy Industries Association’s challenge to SPP’s Expedited Resource Adequacy Study (25-1265).