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February 17, 2026

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N.Y. Cancels Solicitation but Remains Committed to OSW

After 19 months, New York has abandoned its most recent attempt to procure offshore wind power, saying it would not be prudent to proceed amid federal policy uncertainty.

The decision is only the latest setback for a state that, despite multiple cancellations and cost escalations, has the largest offshore wind pipeline in the nation.

New York presented it as a delay, not an end, of its offshore wind ambitions.

In the same week that it canceled the procurement, New York issued a request for information on ways to keep the industry from further atrophy; told an industry conference that offshore wind remains an important part of its energy strategy; and approved the structure of the offshore wind renewable energy credit (OREC) system that subsidizes increasingly expensive construction.

New York launched its fifth offshore wind solicitation July 17, 2024. It attracted 25 proposals totaling 6,870 MW from four bidders — Attentive Energy, Community Offshore Wind, Ørsted and Vineyard Offshore.

Attentive withdrew its proposals in October 2024, and Ørsted in August 2025.

Attentive Partner TotalEnergies and Community partner RWE said in November 2024 and April 2025 respectively that they would put their wind energy development efforts in U.S. waters on hiatus because of the political uncertainty surrounding offshore wind.

And of course, Donald Trump was re-elected president in November 2025 with a promise to block offshore wind development and has been trying to follow through for 13 months.

Given all this, the New York State Energy Research and Development Authority (NYSERDA) announced Feb. 13 that it was canceling the fifth solicitation.

A spokesperson said: “Federal actions disrupted the market and instilled significant uncertainty into offshore wind project development. Given the current level of uncertainty, it would not be prudent to enter into new long-term OREC purchase and sale agreements at this time, and as such, NYSERDA has concluded ORECRFP24-1 without award.”

With that, four out of five of New York’s solicitations are now dead ends.

The two contracts awarded in the 2018 solicitation (to Empire Wind 1 and Sunrise Wind) were canceled because cost escalations rendered the contracts unprofitable. The two contracts totaling 2.6 GW awarded in the 2020 solicitation were canceled for the same reason. And the three projects totaling 4 GW chosen in the 2022 solicitation were rendered untenable when General Electric halted development of the specified turbine.

Only the 2023 solicitation — a rush effort to salvage the state’s imploding offshore wind portfolio — has yielded steel in the water: Empire Wind 1 and Sunrise Wind (1.73 GW combined) are now under construction, at much greater cost than first agreed on.

But that is more than other states with offshore wind aspirations can say.

With the 132-MW South Fork Wind (which was completed in 2024 outside the NYSERDA procurement structure), New York now has three wind farms spinning or being built off its coast.

No other state has more than one, and most have none.

Speaking to Oceantic Network’s IPF 2026 on Feb. 10 in New York City, NYSERDA President Doreen Harris reiterated the state’s commitment to offshore wind despite Trump’s persistent efforts to destroy the sector, including one stop-work order against Sunrise and two against Empire. (See U.S. Offshore Wind Supporters Map Path Forward.)

It is an important part of New York’s strategy to meet rising power demand, she said: “To be clear, offshore wind remains a central part of how we get from here to there on the order of 7 GW of incremental capacity between now and 2040.”

That is a telling detail.

New York’s official offshore wind goal, established by its landmark 2019 climate law and specified on NYSERDA’s own website, has been 9 GW by 2035.

‘Meaningful Step’

So New York is pushing the timeline back and potentially changing the path but not abandoning the effort.

NYSERDA on Feb. 10 issued a request for information (RFI) seeking industry input on a potential predevelopment support program by which the state would enable the private sector to “continue investing responsibly in their lease areas to advance project development during a period of federal uncertainty, so that projects are well positioned to move forward efficiently when federal conditions become more favorable.”

One potential approach for this could be co-investment by the state, Harris said.

Also looking forward, NYSERDA on Oct. 2, 2025, proposed an offshore wind implementation plan that among other things structures the OREC system to reduce impacts on electric utility ratepayers, including through sales to voluntary third parties.

The Public Service Commission approved the plan at its Feb. 12 meeting (case 15-E-0302). PSC Chair Rory Christian said in a news release: “The commission acted to ensure the orderly management of the OSW program and corresponding sale of OSW Renewable Energy Certificates (ORECs) by NYSERDA when the program becomes operational. Our decision today will benefit residential and commercial customers by ensuring that ratepayer costs related to offshore wind development are reduced.”

The New York Offshore Wind Alliance issued a statement supportive of the state’s three policy moves.

“We understand NYSERDA’s decision to close the 2024 offshore wind solicitation without awards was because the original proposals were based on a completely different federal landscape,” said Alicia Gene Artessa, director of the industry group.

“We are strongly supportive of NYSERDA’s recent RFI exploring a predevelopment model for offshore wind solicitation. We believe that fundamentally changing how New York procures offshore wind energy is the right path forward while we adapt to the current federal instability.”

And she said: “We are also encouraged to see that the PSC approved NYSERDA’s Offshore Wind Implementation Plan yesterday. This is a meaningful step from the PSC to allow for more flexibility in the sale of ORECs and ensure our current under-construction projects continue to be managed effectively.”

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N.J. Targets Data Centers in New Source Push

New Jersey legislators have advanced a bill that would protect ratepayers from rate hikes triggered by data center development as the state looks for ways to add generation capacity, boost its infrastructure and curb energy use.

A Senate and an Assembly committee each backed S731. It would require the New Jersey Board of Public Utility (BPU) to develop a tariff to set special rates for “large load data centers” with a maximum monthly demand of at least 100 MW.

Also moving ahead were unrelated bills to require data centers to report their water and electricity use, to boost solar development and to study how advanced transmission technologies can help the state. The BPU also announced rates would be flat in the next period, which starts June 1.

The tariff set up by the BPU under S731 would shelter ratepayers from rate increases stemming from “increased electricity demand caused by large load data centers.” The tariff also should “incentivize large load data centers to develop and utilize methods to increase energy efficiency, including through the use of technologies that capture and utilize the heat produced by the large load data center.”

To submit a commentary on this topic, email forum@rtoinsider.com.

To make sure investments in the state yield their full potential benefits over time, the legislation requires the state’s four utilities to ensure data centers provide financial guarantees they will “take at least 85% of service they request for a period of not less than 10 years.” Data centers must show the proposed project is “unique and not duplicative of any other large load data center project” in or out of state.

The Senate Economic Growth Committee backed the bill 3-1. The Assembly Telecommunications and Utilities Committee backed a version 9-0 after testimony that showed vigorous support for the legislation.

Data Center Reporting Requirements

Preparing for the predicted dramatic increase in data centers and ensuring they pay for themselves without overly burdening ratepayers is central to the state’s efforts.

Analysts say one cause for the predicted energy shortfall is that the state, like others in PJM, has closed aging, fossil-fueled resources more rapidly than new, mainly clean energy sources have come online.

In a separate vote that also focused on data centers, the Senate Environment and Energy Committee backed S3379, which would require data center owners or operators to compile a water and energy use report to the BPU every six months. The BPU would publish the information, according to the bill, which passed without comment.

The data center tariff, while drawing mainly supportive testimony, demonstrated the complexity of the issue. Some legislators expressed concern that the state should avoid creating obstacles that could deter data centers from coming to the state, but most speakers focused on ratepayer benefits.

“Ultimately, this is about cost fairness for the people of New Jersey,” said Assemblyman David Bailey Jr. (D), a bill sponsor and committee member. “This is about us looking out for our constituents and their best interests and the overall health of New Jersey electrical grid.”

Zach Landesini, a resident of Vineland, N.J., said he sees the need for the legislation in the experience of his community with the development of a 700,000-square-foot data center by Data One, whose website says it will use 350 MW of power. Landesini said he envisions scenarios that emerge, and which the bill could address.

He said the project will draw 15% of its power from the local grid, and added: “What would happen if Data One needed to draw a larger portion of their power from the local grid?”

“How would this affect local ratepayers?” he asked. “This could happen for a variety of reasons, including technical deficiencies in power generation, and site expansion.”

Supply Side Pressure

Brian O. Lipman, director of the New Jersey Division of Rate Counsel, also backed the bill, but acknowledged that it couldn’t shield ratepayers from all the cost hikes associated with a data center. One committee member asked him how the state could calculate the increased cost of power when rates increased due to a data center pulling a large volume of power from the grid, effectively reducing the supply for everyone else.

“On the supply side, there’s not a lot we here can do, other than if we want to build generation somehow to add more supply,” he said. “What we can do is, and what we are doing is, we’re pressuring PJM: First of all, don’t sign up a data center if you don’t have the power to serve them.”

He noted that an alternative, outlined in a separate bill, would require new data centers to “bring their own generation.” But if New Jersey passed such a law and other states in PJM do not, data center developers would simply build outside of New Jersey, which nevertheless would bear that cost through its participation in the RTO, he said.

Harnessing New Technology

The debate over how the state addresses the looming energy shortfall, and the added pressure on generation and grid systems from data centers, stepped up in earnest in June 2025, when a 20% rate hike on the average electricity bill took effect.

Gov. Mikie Sherrill (D), who took office in January, pledged in her election campaign to freeze rates. Her first executive orders upon taking office laid out a range of measures designed to do so and boost state generating capacity, in part by accelerating solar development. (See New N.J. Governor Rapidly Confronts Electricity Crisis.)

In that vein, the Assembly Telecommunications and Utilities Committee moved ahead a bill, A3969, that would extend the state’s current goal of incentivizing 3,750 MW of solar power by 2026 to one of incentivizing 750 MW of power  per year through 2035.

The Senate Economic Development committee backed a bill that seeks to prepare the state’s infrastructure for future stress by using advanced transmission technologies (ATT). S2189 would require the BPU to evaluate the “attributes, functions, costs and benefits of ATT” and look at whether it could “enable an electric public utility to provide safe, reliable and affordable electricity to its customers, considering existing and planned transmission infrastructure and projected demand growth.”

The bill defines ATT as any software or hardware technology that increases the capacity, efficiency, reliability or safety of an existing or new electric transmission facility, including grid-enhancing technology and advanced or high-performance conductors.

Rate Hikes Temporarily Avoided

BPU President Christine Guhl-Sadovy announced the results of the state Basic Generation Service auction conducted in early February. The results, which largely are shaped by the PJM capacity auction, will mean the average electricity bill stays roughly the same when the new rates take effect June 1.

The minimal increase or slight decline for some ratepayers depending on their utility is due largely to a “collar” PJM agreed to place on its prices, limiting their increase, because of lawsuits filed by New Jersey and other states. Sherrill has advocated for an extension of the collar, Guhl-Sadovy said.

“I think we would anticipate there to be a higher price if we don’t have a collar,” she said. “Because we have significant load growth and so we need to get more generation and more capacity through things like demand response in order to meet that kind of load growth.”

She acknowledged the collar is a temporary measure and the trajectory of future rates is primarily in the hands of PJM. And she noted that Gov. Sherill outlined a series of initiatives to hold down rates and increase generation capacity in her first two executive orders. They included boosting solar and battery storage power and creating a virtual power plant strategy.

“Those things will not have an overnight impact on capacity prices, but they will certainly put downward pressure on capacity prices, because we will have more generation bidding into the capacity market,” she said.

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ERCOT Taps the Brakes on Batch Study Process

With the 232 GW of large loads seeking to interconnect with the ERCOT system having “clearly broken the process that we had,” CEO Pablo Vegas said the grid operator’s proposed batch process — or cluster studies, in most managed grids — will provide clarity and transparency to data center developers.

He told his Board of Directors during its Feb. 9-10 meeting that the batch studies will change a process that is “very different than what we’ve had before” by reserving capacity on the transmission system for the large loads’ future use.

“Today, that is not the way it works. It doesn’t work here, and it doesn’t work that way anywhere in any grid in the U.S.,” Vegas told the board. “What we found is that the processes that we had set up were really designed for a system where we were seeing interconnections in eight to 15 a quarter, to where we’re now seeing 80 to 100 in that same time period.”

ERCOT staff have proposed grouping together large load requests to be evaluated, rather than relying on the current individual studies that transmission service providers conduct. The studies will determine the amount of requested load that can be reliably served each year over a six-year period and the transmission upgrades needed to accommodate the full load requested. (See ERCOT Finds Stakeholder Support for Batch Process for Large Loads.)

The grid operator plans to begin the process with a “Batch Zero” study to transition from the current process. It will file a protocol revision request codifying the process and bring it to the board for its approval in June, followed by the Texas Public Utility Commission. If all goes as planned, Batch Zero will begin by late summer.

ERCOT originally planned to request a good-cause exemption from the PUC to begin the Batch Zero study in February. However, after a Feb. 3 workshop with stakeholders left many “open questions to be decided,” PUC Chair Thomas Gleeson said, the commission directed the grid operator to tap the brakes on its effort.

“A top-down, ERCOT-driven process where there isn’t a lot of input from stakeholders is really not the way to do this,” Gleeson said Feb. 11 during an industry conference in Round Rock, Texas. “I do believe that we’ll end up with a better outcome from getting all that information on the front end rather than being kind of centrally controlled by ERCOT and the PUC.”

The grid operator will continue to gather stakeholder input through the Large Load Working Group, stakeholder workshops and the stakeholder-led Technical Advisory Committee.

Batch Zero will set the foundation for the subsequent studies, which are to take place every six months. Another NPRR will be filed to codify the ongoing batch process and brought to the board in September.

“We heard the [PUC’s] message loud and clear. We need to keep the pace going on,” Vegas said. “This work continues to be an important part of supporting the economic growth that’s coming. We need to ensure that we have a more robust and a very scrutable process that’s going to benefit all stakeholders, but we can’t do that at the expense of expediency.”

Board Approves Tier 1 Project

The board approved a Tier 1 project previously endorsed by TAC, a $117.4 million, 138-kV South Texas Electric Cooperative transmission build. The project will accommodate a 300-MW ammonia plant near Victoria on the Texas Gulf Coast.

The project is expected to be in service in June 2028.

The board also elected Vegas as CEO and ratified ERCOT’s officers; confirmed TAC’s 2026 leadership; and signed off on the updated Market Credit Risk and Corporate Standard, which removes references to the Reliability and Markets Committee after it was dissolved in 2025.

The consent agenda included three protocol revisions and two changes to the Planning Guide:

    • NPRR1304: incorporate the Other Binding Document “Procedure for Identifying Resource Nodes” into the protocols to standardize the approval process.
    • NPRR1305: add the Other Binding Document “Counter-Party Credit Application Form” into the protocols to standardize the approval process.
    • NPRR1311: correct an error in the calculation of real-time reliability deployment price adders for ancillary services when ERCOT is directing firm load shed during a Level 3 energy emergency alert under the RTC+B protocols, ensuring final ancillary services prices cannot exceed $5,000/MWh.
    • PGRR127: outline the additional generators that may be added to the planning models to address the generation shortfall introduced by the implementation of House Bill 5066’s requirements and increased load growth. The PGRR would also add a supplemental generation sensitivity analysis for Tier 1 Regional Planning Group project evaluations to minimize the effects of the additional generation on transmission project evaluations.
    • PGRR132: clarify that new resources must interconnect to ERCOT through a new standard generation interconnection agreement.
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CAISO WEIM Surpasses $8B in Cumulative Benefits

CAISO’s Western Energy Imbalance Market has surpassed $8 billion in cumulative economic benefits since its 2014 launch after providing participants with $415.65 million in gross benefits in the fourth quarter of 2025, according to an ISO report.

In a news release accompanying the quarterly report, CAISO noted it has revised the methodology it uses to calculate WEIM benefits to reflect the market behavior of variable energy and battery storage resources.

NV Energy earned the largest share of Q4 benefits, at $83.10 million, followed by PacifiCorp ($66.45 million), Los Angeles Department of Power and Water (LADWP) ($40.71 million), Balancing Authority of Northern California (BANC) ($37.15 million), Public Service Company of New Mexico ($34.78 million) and NorthWestern Energy ($23.41 million).

PacifiCorp, with its East and West balancing authority areas, was the biggest net exporter of energy, at nearly 1.54 million MWh. The next largest exporters were CAISO (720,188 MWh), NV Energy (514,474 MWh), Salt River Project (427,248 MWh) and LADWP (250,431 MWh).

The biggest net importer during the quarter was CAISO, at over 1.02 million MWh, followed by BANC (507,535 MWh), Portland General Electric (433,229 MWh), Powerex (408,684 MWh) and PacifiCorp (391,588 MWh).

In the WEIM, a net export represents the difference between total exports and total imports for a BAA during a particular real-time interval, while a net import represents the inverse, meaning a BAA can be both a heavy exporter and importer over an extended period based on varying momentary needs and trading positions over that period.

CAISO’s BAA facilitated the greatest volume of wheel-through transfers, at 964,219 MWh, followed by PacifiCorp’s two BAAs (501,382 MWH) NV Energy (445,994 MWh) and Arizona Public Service (327,982 MWh).

‘Robust, Transparent, Reflective’

The Q4 report also came with some changes in how CAISO calculates WEIM benefits.

“With significant changes in market resources and operational dynamics across the West, maintaining an accurate picture of market performance is essential,” CAISO said in the release. “Additional time was needed to post this report so that the ISO — working closely with its WEIM partners — could refine the benefits methodology to reflect these evolving market resources and system conditions. This helps to ensure its logic remains robust, transparent and reflective of current conditions.”

The revisions are spelled out in the “Counterfactual Dispatch Cost” section of the updated “EIM Quarterly Benefit Report Methodology.”

In the case of variable energy resources, the revised methodology adjusts the market’s bid range logic for resource base schedules to reflect real-time dispatch (RTD) market data rather than the previous approach of relying on 15-minute market (FMM) data.

“This adjustment offers a more accurate reflection of actual market conditions in two key aspects. Dispatches and transfers from WEIM solution are based on the RTD markets and using bids from RTD market will better align,” CAISO explains in the methodology document.

“Second, the forecasted output for variable energy resources often differs between the FMM and RTD markets. By using the RTD forecast to estimate load imbalance in the benefit calculation, it more accurately reflects actual RTD conditions. It also eliminates imbalances that reflect forecast differences and focus on imbalances from actual market redispatches.”

In describing the impact of the change, CAISO cites the example of a wind resource having 73 MW of energy available based on the FMM forecast but getting reduced to 16 MW in the RTD forecast. Under the new logic, the resource’s bid range would be capped at 16 MW, putting both its base schedule and dispatch-adjusted base schedule at 16 MW heading into the real-time interval, leaving a load imbalance of 0 MW.

“This 0-MW imbalance reflects the scenario where the market is not redispatching the resource down. Instead, it simply accounts for the adjustment in the forecast available in RTD. Therefore, there is no WEIM cost associated with this resource,” CAISO wrote.

Another revision to the methodology deals with the modeling of battery storage resources in the counterfactual dispatch — that is, a theoretical dispatch that would occur without the availability of WEIM transfers.

CAISO explains that, prior to Q4 2025, batteries were modeled like conventional resources, with the model estimating an available dispatch range and determining the counterfactual dispatch based on the resource’s price — an approach that ignored a battery’s limits based on its state of charge. To address that, the updated methodology:

    • Adjusts a battery resource’s maximum bid limit based on its state of charge;
    • Enforces a constraint that prevents a battery from being dispatched below a defined minimum state of charge; and
    • Recognizes the end-of-hour constraint defined by a battery operator.
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Former FERC Chair Jon Wellinghoff: A Career Focused on Consumers

Former FERC Chair Jon Wellinghoff is best known as a champion of the demand side, from shepherding through the landmark Order 745 to his prior work for consumers and his subsequent jobs working on demand response.

“Everything in my life that I have done and tried to promote and advocate always comes back to — how do you best help consumers, ultimately,” Wellinghoff said in an interview. “I mean, the whole focus needs to be on the consumer. If you don’t think back from the consumer perspective, you know, it’s not about the utilities, it’s not about Voltus, it’s not about the generator, it’s not about any of those things. It’s about the guy, or the woman, who pays the bill.”

Since leaving FERC, Wellinghoff had a stint at Tesla when it focused on the energy transition. He’s been involved with Voltus since 2017 (first on the board, later as an executive), which seeks to pay consumers for leveraging their distributed energy resources to provide services to the grid.

His focus on consumers goes back to his education, where he got a master’s degree in mathematics from Howard University in Washington, D.C., and briefly taught at an inner-city school there.

“I quickly determined that teaching school is the hardest job in the world, and so I went to law school to become a lawyer,” Wellinghoff said.

He enrolled in the Antioch School of Law, which was in Washington despite being tied to Antioch College in Ohio. He was part of the first graduating class at the law school, which no longer exists, alongside legendary athlete Jim Thorpe’s daughter Grace Thorpe and “quite a few interesting folks.”

His early legal career was in line with his alma mater’s focus on consumers, as he became a staffer for a commissioner on the Nevada PUC. His stint there overlapped with the Arab Oil Embargo in a state where oil was a major source of electric generation.

“So, as a result, in the 18 to 24 months I was with the commission, we saw more utility rate cases being filed than that commission had seen in the previous 10 years,” Wellinghoff said. “So, in like a two-year period, I got this compressed experience with utilities and how they did utility rate cases and their impact on consumers.”

After that experience, he went to work at the District Attorney’s Office in Washoe County in Reno, Nev., where Wellinghoff represented consumers in utility rate cases.

“That was the first time that was ever done in Nevada, and probably in any state, by a state district attorney’s office where they actually represented consumers before the commission, and I then translated that into a statewide office where I actually helped draft some legislation that created a consumer advocate’s office in Nevada,” Wellinghoff said.

He effectively wrote the legislation that led to his next job as state consumer advocate in Nevada, where he continued advocating for consumers, arguing utilities had to control their costs.

“It was a battle, and it continues to be a battle, because the utilities are not financially incentivized to do that,” Wellinghoff said. “And I often did find that there were third parties like solar firms and energy efficiency providers and HVAC providers and others that you were more attuned to working with consumers to try to control consumers’ costs because they had some financial interest in doing that.”

He was one of the early consumer advocates, though around 10 other states had a version of that office when he started the job in 1981, and he kept working there until 1989.

In the 1990s he entered private practice, working on lengthy litigation stemming from a massive industrial accident when the PEPCON rocket-fuel plant in Henderson, Nev., exploded. It was equivalent to a one-megaton detonation, and it caused $100 million in damage in the Las Vegas area.

Working on that case, Wellinghoff did 150 depositions and learned about mass-tort litigation, which would serve him well when he returned to energy law full-time in 1998 to become the general counsel at the Nevada PUC.

“I was sort of in the middle of the Enron debacle, and we were actually drafting legislation in Nevada during Enron to restructure state of Nevada to make it competitive — to allow entities like Enron, as a retail provider, to provide retail energy services to consumers throughout Nevada,” Wellinghoff said. “We did that up until the crisis happened in California, where the whole wholesale market flew apart.”

Enron’s manipulations and the California energy crisis killed similar legislation in other states, and it made Wellinghoff turn back to his skills deposing witnesses who were involved in the crisis, which involved bad actors from many other firms. He did that from outside the PUC, where in private practice, he represented the MGM Resorts in Las Vegas, which included casinos like the Bellagio and had an aggregate power demand of 300 MW.

The utility for Las Vegas asked for $922 million to pay for inflated wholesale power prices at the time — a sum greater than every previous rate request it had ever filed, Wellinghoff said.

“I started taking depositions,” “And I took about 20 depositions of utility executives and of expert witnesses that the utility had hired or had as consultants, and they had one consultant who was charged with developing a software program to assess the risk of their trading program to trade energy in the wholesale market during the Enron debacle,” Wellinghoff said. “And I asked him if he ever assessed what the level of risk was to be short.”

The answer was no — the program kept crashing when trying to calculate the risk. The utility was unhedged and exposed to prices that were two to three times the norm. In a deposition, the consultant admitted “the risk of going short was very, very, very, very large,” Wellinghoff said.

The depositions were part of the evidence the PUC used to slash the request down to some $400 million, and the utility went bankrupt — its shareholders eating the risk it had tried to foist on consumers.

After that experience, President George W. Bush nominated Wellinghoff to FERC, where he served for seven years, five as chair after President Barack Obama elevated him.

“I’m still the longest serving chairman at FERC, which is kind of amazing to me, since this year is 20 years since I went into FERC,” Wellinghoff said.

While there have been other commissioners with long stints on the regulator in recent history, Wellinghoff said the job involves public service with little pay. He had 11 staffers reporting to him who made more money as long-tenured government workers. That pay issue is why most stop at one five-year term at best.

Before joining FERC, the only experience Wellinghoff had with markets was the “Enron debacle,” but there he learned about other wholesale markets like in ISO-NE, where at the time efficiency could be bid into the market, and demand response.

“I saw that there was room for creativity,” Wellinghoff said. “And I also truly believe that whatever could help consumers we should try to do. Whatever can provide consumers with ways to control their costs and be more efficient and get energy services, more reliably and more effectively. And I realized that markets are probably the way to do that.”

During his time as chair, Wellinghoff was able to move that ball forward with Order 745, which required demand response programs in the energy market to pay consumers the same as generators. That case was appealed by opponents and eventually made its way to the Supreme Court, which upheld the order in the EPSA v. FERC decision.

“That was, I think, the most important case that has ever been decided on a FERC opinion,” he said. “And I believe that that was also one of the most important cases in energy for consumers, because it was a clear victory for consumers that gave FERC the authority to oversee consumers’ participation in wholesale markets and provided consumers with that opportunity to participate at a fair level of compensation.”

Wellinghoff’s keynote address “Grid Innovation at the Intersection of Policy and Markets” will be delivered Feb. 25 at Yes Energy’s EMPOWER 2026 conference in Boulder, Colo. To learn more about EMPOWER visit yesenergy.com.

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MISO Load Forecasting Shows up to 82 GW in Data Center Load by 2044

MISO’s inaugural long-term load forecasting survey among its membership shows the possibility of 82 GW in data center load by 2044.

The RTO said responses to its pilot survey place data center demand at the top of the list. However, 55 of the 82 GW have been categorized as “low confidence.”

“There’s no surprise here that data centers make up the bulk,” Dominique Davis, manager of strategic insights, said Feb. 12 during a webinar hosted by MISO.

MISO plans to use the survey results to publish a finalized long-term load forecast in April 2026. The RTO said it will use complementary research and third-party analysis to supplement incomplete data to produce a final, nearly 20-year load forecast.

Beyond data center load, members reported the potential for an additional 4 GW in manufacturing load and 3 GW of other, miscellaneous load.

By MISO’s count, public announcements of large loads coming online by 2030 have more than doubled in the span of a year; however, the RTO warned that public announcements of large load do not necessarily reflect firm commitments. In 2024, MISO counted 14 GW of large load announcements. In 2025, it recorded 43 GW.

MISO Central — one of the RTO’s three reliability regions, containing Wisconsin, Michigan, Indiana, Illinois, and parts of Missouri and Kentucky — contains the most potential for large loads, at nearly 40 GW by 2030. However, more than half of that is what MISO considers “low confidence.”

“While this surge is notable, we’ve also observed cancellations for various reasons,” Davis said.

MISO divided load additions into high-, medium- and low-confidence categories:

    • High-confidence additions represent those that have associated interconnection agreements in place with regulators’ knowledge and construction underway;
    • Medium-confidence projects are those that have been submitted through a MISO planning process or have been publicly announced, but construction has not yet begun; and
    • Low-confidence projects are those in the early stage that are not in MISO’s planning process but appear in integrated resource plans or remain conceptual.

MISO’s data collection turned up eight spot loads that would require more than 1 GW, “which compose a significant reliability risk in the future,” Davis said.

The RTO said it cannot share its load forecasts on a local resource zone level because of utilities’ insistence on confidentiality and their nondisclosure agreements with developers.

To collect intel for its long-range pilot, MISO introduced confidentiality provisions that allowed it to receive greater insights from utilities, even when it could not share specific breakdowns. By contrast, the RTO’s 2024 load forecast relied on internally culled data from public sources.

MISO said it received submissions in response to its pilot survey from 44 entities, which are responsible for about 80% of the footprint’s load. “That’s a huge step towards transparency,” Davis said.

The RTO found that 31 responses on large loads additions match public announcements, she said. “So, we did get a good representation in that area.”

MISO is already home to about 17 GW in large loads.

Waning After 2035?

Davis said the survey results show that large load planning tapers off after the first 10 years of the survey and stagnates beyond 2035. MISO said most entities did not provide data on large loads beyond 2035.

Additionally, MISO said only 60% of its respondents even filled out the section on large load. “Confidentiality limits reduced data sharing and response rates, complicating double-counting checks and mapping large load submissions,” it said.

According to data from Yes Energy, over the next decade, the MISO territory is due to host or be affected by 50 data centers either already under construction or in advanced development; 74% of them list in-service target dates in 2026 or 2027. All of them have a 60% or better chance of being built. More than a dozen data center projects would be near Chicago.

Davis said MISO does not believe the responses are an indication that data center load would stagnate. She said for the final forecast, the RTO would fill in some expectations rather than accept an actual leveling-off of large load expectations.

Mississippi Public Service Commission consultant Bill Booth asked why MISO would not take members at their word and stop forecasting more dramatic data center growth beyond 2035. He said there could be improvements in data center management and strides made in efficiency that lead to demand inertia.

Davis said the industry does not appear primed for a slowdown by 2035. “We do understand this comes in phases, but how much energy they’re going to need in phases is not well understood.”

Stakeholders asked how much double-counting of facilities might be in the pilot survey.

Davis said MISO was able to pinpoint a few likely cases of hyperscalers shopping two locations, but she said survey answers left out a lot of identifiable information, especially for potential large loads in the nascent, “low-confidence stages.”

Booth suggested that MISO strike all low-confidence load growth from its forecast. He said he did not want up-in-the-air figures to influence transmission planning.

“Why would you use any information that isn’t reliable? Building a base on shaky data ensures that ratepayers are going to be paying for more transmission than needed,” he said.

Davis said MISO would not include 100% of low-confidence projects in its forecast. It will provide more data on its process when it releases the results in April, she said.

The Union of Concerned Scientists’ Sam Gomberg pushed back on the notion that MISO should wait and act on only loads that are a sure thing. He said that’s not how the electricity industry works.

“If we waited for the load to arrive, it’d be sitting there in the dark while we built,” Gomberg said.

He said MISO’s far-from-perfect effort is nevertheless a good start and shows the need to “drive forward on this low-certainty chunk of load” to figure out what could pan out. He said MISO should strive to provide more transparency.

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NYISO Recounts Challenges During January

ALBANY — The year got off to a difficult start for NYISO, but the ISO successfully navigated through several events, including a major winter storm, Aaron Markham, vice president of operations, reported to stakeholders.

“We had 19 consecutive days below 32 degrees [Fahrenheit] in Albany starting on Jan. 23,” Markham told the Operating Committee on Feb. 13. “There was lots of lake-effect [snow] and other storms that happened. We had a coastal storm that raised some issues with barge deliveries of fuel.”

During the storm and the period of extreme cold that followed it, natural gas index prices ranged between $50 and $200/MMBtu, Markham said. Spot quotes exceeded $300/MMBtu at times, driving up statewide wholesale energy prices and pushing dual-fuel units to oil. (See related story, Winter Storm Drives Potential Record for January N.Y. Electricity Costs.)

Markham said NYISO forecasts ahead of the storm had predicted roughly two weeks of extreme cold. This allowed the ISO to take early action to manage statewide fuel inventory, get generators committed and ensure units could operate. Over the first five weeks of the year, the state burned through enough fuel to lose 45% of its net liquid fuel inventory.

“Doing some rough math, that equates to 135 million gallons of liquid fuel that was burned during that period,” Markham said.

Despite this, some fossil fuel capacity was forced out of the real-time market because of difficulties with resupply. This peaked during the worst period of the storm around 5 p.m. Jan. 25, when roughly 1,900 MW were unavailable to dispatch. Markham said resupply was extremely challenging because of the weather. Barge routes were frozen or too rough to travel. Roads were hazardous for trucks. In some cases, the ISO directed gas units to “ease” the rate at which oil reserves were burned.

During the height of the storm, NYISO called external suppliers for all hours between Jan. 24 and 31. Special case resources and demand response were called for multiple hours across all zones to “avoid emergency conditions” Jan. 25-30. Load peaked at 24,177 MW on Jan. 30 around 6 p.m., the highest so far this winter.

“Our current estimates are that [demand response] reduced the demand between 350 and 400 MW,” Markham said. “Without the demand response, we would have been over the baseline forecast for the winter.”

On Jan. 26, NYISO requested and was granted a waiver from the U.S. Department of Energy under Section 202(c) of the Federal Power Act to temporarily bypass federal, state and local emissions limits during the storm, allowing them to run all generators at their maximum outputs. Markham said the ISO did not need to exercise the authority granted by the waiver because it balanced the system at the edge of emergency conditions.

In addition to the cold, NYISO also had to respond to a severe geomagnetic storm Jan. 19-20, the strongest since October 2003, according to the National Oceanic and Atmospheric Administration. The ISO restored out-of-service transmission lines and extended generator commitments to compensate.

Stakeholders requested that the ISO provide granular fuel data so they could understand the day-to-day constraints on the system. Markham said more information would be available at the end of winter.

Environmentalists praised the ISO for exercising diligence in avoiding emergency grid conditions and the need to burn units beyond local emissions limits.

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Pathways’ ROWE Selects Interim Leaders

The Regional Organization of Western Energy has selected Western Freedom Executive Director Kathleen Staks as its interim president, while regulatory attorney Lisa Tormoen Hickey will assume the role of interim secretary.

The two were elected to their positions by a vote of the ROWE’s newly installed Formation Board during its inaugural virtual meeting Feb. 12.

The ROWE is the product of the West-Wide Governance Pathways Initiative’s multiyear effort to develop an independent governance structure for CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market.

Staks and Tormoen Hickey sit on the five-member Formation Board. The body also includes Evelyn Kahl, chief policy officer at CalCCA; Jim Shetler, general manager of Balancing Authority of Northern California; and Scott Ranzal, director of energy policy and procurement at Pacific Gas and Electric. Staks also is co-chair of the Pathways Launch Committee, which developed the foundations of the ROWE. (See Pathways Takes Key Step Toward Establishing ROWE.)

According to the ROWE’s by-laws, as president Staks will technically take on the role of CEO, but both she and Tormoen Hickey have waived compensation for the interim positions. The ROWE will permanently fill executive positions after a search conducted by the organization’s initial board of directors.

During the meeting, Staks and Kahl emphasized the limited authority of the Formation Board and spelled out its objectives.

“This is an interim body … that was necessary for the initial formation of the ROWE and is tasked with conducting the work that’s necessary to keep the ROWE implementation moving forward, including — most importantly — seating our initial independent board [of directors],” Staks said.

Staks said other tasks for the Formation Board include securing funding for the ROWE until its tariff funding is in place, developing recommendations for the initial board that includes the ROWE’s statutory requirements, and “continuing progress on work streams previously identified.”

Those tasks could entail entering contracts with vendors — such as lawyers and facilitators — and securing a financing agreement with a bank, actions that first would go to the Pathways Launch Committee for discussion, she said.

The ROWE seeks $7 million to $8 million to cover startup costs for operations in 2026/27 and has entered funding discussions with CAISO, which earlier in February issued a straw proposal that would provide the ROWE with backing for a commercial line of credit through surcharges on market transactions. (See Pathways Asks CAISO to Kickstart ROWE Funding Discussions.)

Staks clarified that all actions and decisions by the Formation Board will take place in open meetings with opportunities for public comment.

“So, if and when we get to these decision points, we will do them in an open meeting, as we have done at the Launch Committee along the way to date,” she said. “Ultimately, once the initial board is seated, that group will determine the role of the Launch Committee and figure out exactly what it needs from that group of supporters.”

At the meeting, the Formation Board voted unanimously to approve two resolutions adopting internal rules and the board selection policy for the ROWE.

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PJM MRC/MC Preview: Feb. 19, 2026

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Feb. 19. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. A full report will be published Feb. 23.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

As part of its consent agenda, the committee will be asked to endorse:

B. proposed revisions to Manual 3: Transmission Operations and Manual 3A: Energy Management System Model Updates and Quality Assurance to conform with FERC Order 881. The changes would define how PJM and transmission owners would determine ambient-adjusted line ratings and dynamic line ratings. (See “Stakeholders Endorse Order 881 Manual Revisions,” PJM OC Briefs: Feb. 5, 2026.)

C. proposed revisions to Manual 28: Operating Agreement Accounting to rework when resources are considered to be starting from an offline state while determining real-time secondary reserve lost opportunity costs. (See “Definition of Offline Secondary Reserves,” PJM MRC/MC Briefs: Jan. 22, 2026.)

Issue Tracking: Identification of Offline Generation Resources for the Calculation of Real-time Secondary Reserve Opportunity Costs in Settlements

D. proposed revisions to Manual 40: Training and Certification Requirements drafted through the document’s periodic review. The changes aim to clarify that efforts to meet PJM’s continuing training requirement must be relevant to its applications.

Endorsements (9:10-10)

1. 2028/2029 Base Residual Auction, Installed Reserve Margin and Forecast Pool Requirement Values (9:10-9:35)

PJM’s Josh Bruno will present the recommended IRM and FPR values for the 2028/29 BRA, as well as the effective load-carrying capability resource class ratings to be used in the auction. The IRM would stay the same, while the FPR would increase by 0.0141 because of higher resource accreditation. Class ratings for resources that perform in the summer would increase, especially for gas, with the inverse for winter performers, such as wind. (See PJM Stakeholders Reject 2027/28 Capacity Auction Parameters.)

The committee will be asked to endorse the IRM and FPR values on first read, and same-day endorsement will be sought from the MC.

2. Generation Self-scheduling Market Rules (9:35-10:00)

Old Dominion Electric Cooperative’s Mike Cocco will present a problem statement, issue charge and quick-fix proposal to define gas resources that self-schedule and produce at least their committed capacity level as having met the requirement that capacity resources offer into the energy market. (See “Must-offer Requirement for Self-Scheduling Resources,” PJM MRC/MC Briefs: Jan. 22, 2026.)

The committee will be asked to approve the issue charge and endorse the proposed Operating Agreement, tariff and manual revisions.

Members Committee

Endorsements (11:30-11:45)

1. 2028/2029 BRA, IRM and FPR (11:30-11:45)

If endorsed by the MRC, Bruno will present the recommended FPR and IRM values to the MC, which will be asked to endorse them. The committee’s vote is advisory to PJM’s Board of Managers, which will make the final determination on the auction parameters.

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Eversource Adds $2.3B to 5-Year Capital Investment Plan

Eversource Energy has increased its five-year capital investment plan by $2.3 billion, an increase largely driven by investments in its gas and electric distribution systems.

The company now plans to spend about $26.5 billion over the next five years; $1.5 billion of the spending is incremental to the period overlapping the company’s previous five-year plan for 2025-2029. These totals include only projects with a “clear line of sight from a regulatory approval perspective,” CEO Joe Nolan said during the company’s fourth-quarter earnings call Feb. 13.

Most of the spending is intended “to address aging infrastructure needs under our multiyear projects such as the Electric Sector Modernization Plan and the Underground Cable Modernization Program, as well as complying with applicable state safety regulations,” Nolan said.

Of the $1.5 billion, Eversource plans to spend $696 million on electric distribution, $523 million on gas distribution and $233 million on transmission. For 2026 to 2030, electric distribution accounts for 43% of investment, followed by transmission at 27% and natural gas distribution at 26%.

Eversource forecasts annual transmission capital investments to increase by about 33% by 2030, though this number will likely grow as the company adds projects to its investment plan.

Increased spending on infrastructure has played a large role in driving up consumer energy costs in recent years, a trend that appears likely to continue into the foreseeable future. In Massachusetts, grid upgrades to prepare for the clean energy transition are a major cost driver, while upgrades to replace aging and deteriorating infrastructure on both the gas and electric systems also are a major contributor to costs. (See Conflict Brewing over Gas Transition in Massachusetts.)

Nolan said Eversource has ramped up its rollout of advanced metering infrastructure (AMI) in Massachusetts, installing more than 100,000 smart meters over the past year. He said the company plans to upgrade more than 1.5 million meters in the state. Once in place, regulators hope AMI help will enable incentives for demand flexibility.

Eversource, however, continues to hold off on investments in AMI in Connecticut. The company has clashed with regulators in the state in recent years and has expressed concern about the AMI cost recovery mechanism.

“We’re optimistic that we can at least get additional clarity around … the rules of the road down there to make it fair for us to make that investment.” Nolan said. “But we’re not going to make the investment until we feel comfortable with the recovery mechanism. … We’ve got a lot of money on the line down there right now.”

Regarding the Revolution Wind project, he said Eversource finished work on the onshore substation for the project in late 2025.

While Eversource sold its 50% share of Revolution to Global Infrastructure Partners in 2024, the company remains on the hook for construction cost increases. Eversource’s liability will end once the project achieves commercial operations, which project developer Ørsted forecasts to occur in the second half of the year.

In Ørsted’s earnings call on Feb. 6, the company said construction on Revolution is about 87% complete, with electricity beginning to be delivered in the coming weeks. (See Revolution Wind Weeks Away from Generating Power — Maybe.)