Year-over-year prices rose in MISO to serve a typical September peak.
MISO members served an average 76.3 GW daily load over September, with a 106-GW peak occurring Sept. 16. The month’s peak demand wasn’t unusual, less than a gigawatt from the 105.5-GW peak in September 2024 and smaller than September 2023’s 114.6-GW peak. Average daily load was up slightly when compared to the approximate 75-GW average in September 2024.
Real-time prices, however, rose almost 1.5 times from September 2024, at $41/MWh versus $28/MWh. Average natural gas prices climbed from $2/MMBtu in September 2024 to $3/MMBtu September 2025. Coal stayed flat at about $2/MMBtu year over year.
MISO’s solar peak was 14.5 GW while wind registered a 20.7 GW peak. Both occurred in early September.
Over the month, MISO experienced 47 GW in average daily generation outages, 9 GW higher than last September.
MISO declared a capacity advisory for the entire footprint Sept. 29 because of forced generation outages and limited transfer availability. It also called conservative operations on Sept. 28 due to unseasonably warm temperatures, generation outages and lower-than-normal renewable energy forecasts.
ALBANY, N.Y. — The Alliance for Clean Energy New York’s Fall Conference could well have had a somber atmosphere, given the way 2025 has gone for renewable energy.
But the annual ACE NY event, held Oct. 22-23, drew its largest audience ever, the mood was not somber, and state policymakers and industry leaders offered messages of full support even as they acknowledged the federal roadblocks thrown in their path.
“New York remains a steadfast leader in our work focused on advancing clean energy and environmental protection,” Department of Environmental Conservation Commissioner Amanda Lefton said in a keynote speech. “We have and will continue to achieve nation-leading progress, which is even more important than ever during these unprecedented times.”
Federal interference is the latest setback for a state that has fallen behind on its self-imposed timeline for grid decarbonization. If New York cannot add enough new renewables, it will need to keep some of the oldest fossil-burning plants in the country online longer or even consider new fossil generation, a prospect that is anathema to many state policymakers.
So the effort now is to get renewable projects off the drawing board and into motion in time to qualify for federal 45Y and 48E investment and production tax credits before the window closes next year.
In September, the New York State Energy Research and Development Authority launched a rush solicitation for late-stage large-scale solar and wind projects that could make the deadline. (See Latest N.Y. Renewables Solicitation a Race Against Time.) NYSERDA President Doreen Harris told the conference that industry rose to the occasion.
“The response was just what we needed and just what we wanted. These are projects that are ready to go, that are ready to compete, and ultimately ready to build,” she said Oct. 23, just two days after the first-stage application deadline for the solicitation.
New York and the renewables industry both need these projects to go forward, Harris said, and Gov. Kathy Hochul has committed to an all-of-government push to get as many new megawatts of capacity into the pipeline as possible. “I’d like to assure you that the shifting federal priorities are not impacting the level of ambition that we have as a state,” she said.
Harris said New York has 100 clean energy projects rated at a combined 10 GW in operation or under development; a dozen large-scale projects are under construction in the state or off its coast.
“That’s a huge pipeline. As someone who’s worked in this industry for decades now, that only happens if we have the durability of commitment, purpose and, ultimately, the ability to get through those challenges together,” she said.
Moving Forward
The first panel discussion was populated by the top ranks of power regulation and delivery in New York.
NYISO President Richard Dewey explained the central problem for New York’s grid in detail, and he also framed it succinctly: New clean-energy generation is not keeping pace with retirements and anticipated load growth, and the ISO is having to make some decisions that are unpopular with clean energy advocates.
“We’re getting pretty dangerously close to the margins,” he said. “It’s bad news if a generating station that is polluting the environment needs to stay online. It’s worse news if the lights go out, and that’s really what we’re trying to balance.”
Georges Sassine, NYSERDA’s senior vice president for large-scale renewables, spoke of the scramble unfolding as policymakers try to secure as many clean megawatts as possible before prices jump: “The state of New York has a big role to play in driving industry forward, but we are also, all of us collectively, reacting to this big tectonic shift on the federal front.”
The New York Power Authority is part of the scramble. Its latest mandate — develop at least 1 GW of new advanced nuclear capacity — is still well off in the future. But in the near term, NYPA is trying to maximize the tax credit eligibility of the 64 emissions-free projects in its 7-GW pipeline, Senior Vice President of Development Christopher Hutson said, and devise other funding mechanisms for those that miss out on the credits.
New York’s challenges developing clean energy existed long before President Donald Trump kicked off his campaign against solar and wind energy development in January.
New York is an expensive place to do business, and it typically has had a slow regulatory process for renewable energy development. One obvious example: There still is no official definition of “zero-emissions” power more than six years after the state’s landmark climate law mandated a zero-emissions grid by 2040.
Even attempts to speed things up tend to move at a deliberate pace.
The RAPID Act was signed into law in April 2024 to speed renewables and transmission development. Through great effort, draft regulations were produced in just six months. The draft went through an extensive in-person, virtual and electronic public comment process, then was revised. The revised regulations (24-M-0433) were posted Oct. 22 and are open for public comment though Dec. 8. There is no target date for the Public Service Commission to review the comments then revise and finalize the rules, presumably in 2026.
But all this deliberation is a critical part of the process, said Zeryai Hagos, executive director of the state Office of Renewable Energy Siting and Electric Transmission (ORES).
“We received over 2,000 comments” on the RAPID Act draft, he said, “and we got some really excellent feedback.”
The need to make the process work better is real, and it is pressing. A detail stood out for Hagos in NYISO’s latest Power Trends report: “For every megawatt that we add, we’re losing two when we look backwards over the last four or five years. We can’t keep going on that way. We need to be able to build these projects in a more streamlined manner.” (See NYISO Makes Case for Repowering in Latest ‘Power Trends’ Report.)
There will be attrition among the 110 proposals in the ORES pipeline, he said. For starters, about two-thirds have not reached a safe harbor point where they can qualify for the federal tax credits. Some do not have financing or interconnection or REC contracts secured.
But Hagos said the all-of-government approach Hochul directed means every agency will be pulling to get as many of those projects as possible as close to groundbreaking as possible.
“If you take away one thing from my message here, it’s not going to be because of ORES; it’s not going to be because of a New York state agency and our bureaucracy and inefficiencies that these projects don’t achieve their timelines. We are doing everything we can to coordinate and make sure we’re moving things as efficiently as possible.”
Jessica Waldorf, director of policy implementation at the Department of Public Service, spoke of the many and sometimes competing needs facing New York — updating an aging grid, slashing its carbon footprint, expanding its capacity, protecting its ratepayers and factoring in its stakeholders’ opinions — but also told the audience there are multiple efforts to strike the balance.
“We have a lot of challenges ahead, a lot of opportunities to be creative as a state, and that’s what we’re laser-focused on,” she said.
The Headwinds
Land-based wind and solar can continue in New York in the Trump era; it just will be even more expensive than it has been.
Offshore wind, which New York has been counting on as a significant part of its decarbonization strategy, is a higher level of hurt: The federal government controls what happens in U.S. waters.
After two stop-work orders, the Trump administration is — at the moment — allowing work to continue on the five offshore wind farms under construction in U.S. waters but has moved to block any others from starting construction. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)
New York’s own Public Service Commission canceled planning for an offshore transmission network to serve the fleet of wind turbines envisioned off the New York coast, saying there was no point in incurring costs now for transmission for generation that will not be built anytime soon. (See NY Steps Back from OSW, Halts Offshore Tx Planning Process.)
There has been skepticism about whether investors who have been losing money hand over fist will be willing to lay out billions more under a future president who is friendly to offshore wind.
In a bit of exquisitely literal timing a day before the ACE NY conference, JERA Nex BP announced that it was exiting the U.S. offshore wind market and shelving Beacon Wind, the first phase of which once held a New York contract.
None of these things were featured at the conference, where speakers instead cheered the two New York projects under construction and the one already completed, and looked forward to a brighter future after Trump’s second term ends.
“The state’s commitment to offshore wind is emblematic by the fact that our own governor has stood up for these projects in a way that not only kept Empire Wind 1 alive but ultimately allows us to say that offshore wind can and will be a very significant part of our state’s future,” Harris said.
(Empire Wind 2, meanwhile, has been shelved by its developer, and the Trump administration has said it is planning to reconsider the 2024 approval for the second phase of Empire Wind 1.)
Despite all this, New York is arguably the de facto leader among the states pursuing offshore wind, with three wind farms in operation or under construction — two more than any other state.
Oceantic Network CEO Liz Burdock said $25.5 billion has been invested in the U.S. offshore wind sector, and the market fundamentals remain strong. “We will be able to build a comeback in 2028-2029 because of this.”
The details of any such comeback probably are unknowable so far in advance; Burdock offered none. Harris too spoke about the state’s goal but not the means of reaching it in the current environment. Afterward, NYSERDA offered RTO Insider essentially the same thing: policy but not strategy.
“Offshore wind remains a vital part of New York’s all-of-the-above energy policy for the long term,” a spokesperson said.
Three industry speakers framed Trump’s second term as a reset, a chance to fine-tune the approach to offshore wind development.
Kris Ohleth, executive director of the Special Initiative on Offshore Wind, revised the old analogy that executing the clean energy transition is like designing and building an airplane while flying it.
Offshore wind is the plane, and it is now grounded, she said, so let’s figure out how to get it back into the air. “This is our opportunity to have that more robust conversation and build some of the fundamentals into the system that maybe we just didn’t have time or knowledge to do previously.”
Better risk management is important to developers, said Zach Fuerst, director of business development for Vineyard Offshore. “New York has done a lot already to help developers and take a lot of feedback from developers about how to mitigate that risk through inflation-adjustment mechanisms that are factored into the contract and the PPA, and those are immensely difficult things to get perfect or to get right.”
Matthew Brotmann of Equinor Renewables America said New York state has been a good partner in the push to develop offshore wind, but in retrospect there are things that could have been done differently. “The expectations on offshore wind were extremely high,” he said. “The expectations were unrealistic, but we were all very enthusiastic, and I was totally on board with that.”
Brotmann and Ohleth said the opportunity exists to shift the narrative from the costs of offshore wind to its benefits — reliable power at a fixed cost in a time of rising demand and rising costs for electricity.
Both also spoke of narrowing the scope of what offshore wind is expected to be: a source of electrons rather than a Christmas tree with a host of ancillary benefits for the state economies and local communities. This might lower the strike price.
Brotmann called for states to collaborate rather than compete on supply chains and infrastructure: “I think it’s going to be essential moving forward because, quite honestly, developers are quite gun shy about trying to invest in large infrastructure without a guarantee of a pipeline, which, given the current administration and who knows what the next administration will be, we can’t guarantee that.”
Fuerst spoke of laying the groundwork for 2029 or 2030.
“I think the resource isn’t going away, and I think the fundamentals of this market don’t go away, and I think what we do over the next three years will be critical as to how quickly the industry is able to move toward building again and really be able to deliver on some of the ambitious targets that New York has for offshore wind and for the climate.”
Interesting Times
Trump-bashing was not on the agenda at the conference, although there were plenty of oblique references to the effects of Trump administration’s policies.
As Harris put it: “Every week is a new adventure when it comes to what the federal government will be doing with respect to clean energy.”
But neither was there an atmosphere of defeat.
As Harris also put it: “I have to say, I am extraordinarily thankful this year and every year to be working in the state of New York, a state which has demonstrated the durability of our commitment, our ability to deliver on what we promise, and ultimately an industry that will only continue to build.”
The resolute messages are to be expected: The attendees for the most part have a significant financial or professional or emotional stake in the continued growth of renewables and are not ready to give up.
After the conference, ACE NY Executive Director Marguerite Wells told RTO Insider she saw a similarly cheerful tenor six weeks earlier at the RE+ conference in Las Vegas. (See Livewire: Renewables Ready to Out-innovate, Outlast Trump.)
“I think there is a reasonable amount of optimism for the near term, call it the next three or four years, for people who have projects that they can safe harbor equipment and try to get them built in four years before the tax credits expire,” she said. “There is cautious hope that that’s a path. I think the question in everybody’s mind, which I don’t believe anyone has answered, is, what do you do with your pipeline after that?”
There are factors pulling in opposite directions. The state provides strong support for renewable energy development, and it presents high costs for development. It is also well down in state rankings for solar irradiance and onshore wind speed but has good offshore wind speed.
The state’s 9-GW-by-2035 offshore goal now appears challenging to meet, but the state remains committed to pursuing it, and Wells said that even amid all the damage the Trump administration is inflicting on the U.S. offshore wind sector, there is some cause for optimism for New York. The demand for electricity along the East Coast will only be greater in 2029, she said, and the alternatives to offshore wind — gas turbines and nuclear reactors — are slow to deploy and expensive.
The developers that have shelved offshore wind projects could resume work on them, rather than write off the large investments they have made to date, she added.
“There’s going to be demand for what they have, and for some number of the players, there will be projects to build, assuming a new administration opens things back up again,” Wells said. “There are tons of people who will have fled and licked their wounds and put their money elsewhere after that. There’s a hope that there are some who did not.”
ERCOT stakeholders gathered in Austin on Oct. 22 for a Technical Advisory Committee meeting, only to have a large-load discussion break out.
And with good reason. Staff told TAC members that they are tracking over 200 GW in large-load interconnection requests, primarily from data centers and cryptocurrency mining. Over 130 GW of requests (a 182% increase) have been added to the queue in just the past 10 months. However, only about 6.5 GW have been energized or approved for energization, with an additional 4.7 GW being studied.
That led stakeholders to question whether ERCOT has placed a moratorium on energizing large loads.
Consultant Bob Wittmeyer, chair of the Large Load Working Group, said that is not the case. “More loads have been approved to energize [in West Texas] than we can handle, but those loads are not yet operational, and it will be a while until they are,” he said, repeating what was said at the LLWG’s meeting Sept. 19.
However, Evan Neel, with data center developer Lancium, said the discussion during that meeting was not clear, leading to uncertainty within the market.
“In fact, that following Monday, there were some market research firms that published headlines of the sort that ‘ERCOT pulls the plug on data centers,’” Neel said. “They were citing explicitly things that were said during that meeting,” Neel said. “Obviously that is a concern when we’re talking about bringing investment to the state.”
ERCOT has cited studies that indicate it could lose at most 2,600 MW of load under certain operating conditions, without exceeding the post-contingency frequency limit. Staff said in a June market notice it is “essential” that they have accurate large-load models to assess grid stability risks, saying recent operational events demonstrate “the dynamic models currently representing many of these [loads] do not reflect their actual dynamic performance.”
“We’ve seen conversations around numbers of about 2,600, but the market notice points to a bunch of historical events that have not been anywhere close to that,” Neel said.
Another, more recent market notice bypassed the stakeholder process and addressed large loads potentially energizing on the system without having cleared “certain important hurdles.”
The notice established a new approval process requiring confirmation of all necessary modeling and telemetry is in place before a large load’s energization. The process is effective immediately and applies to any studied large load, regardless of the planning process used to evaluate interconnection’s reliability.
“This is something we don’t do willy-nilly,” Chief Regulatory Counsel Nathan Bigbee said. “Sometimes we may not have time, or we may decide that we don’t have time, to pursue a revision request for the stakeholder process in order to address the reliability risk.
“ERCOT ultimately has a statutory obligation to ensure the reliability of the grid,” he reminded stakeholders. “In some cases where there isn’t sufficient time to pursue a protocol revision or other guide revision, we believe it’s incumbent on us to address that risk. Sometimes that requires establishing policy on an interim basis through a market notice.”
RTC+B Project Eyes Dec. 5
ERCOT’s Matt Mereness said the Real-time Co-optimization + Batteries (RTC+B) project continues to be on the right track as its Dec. 5 implementation date nears.
“It looks like it’ll be a fairly smooth transition without having to take special procedures,” he told TAC during his regular update to members.
ERCOT’s Matt Mereness, UT alum | ERCOT
The project is in its third and final phase, with the focus on go-live. A required live production test to ensure effective frequency dispatch and control, involving almost 100 qualified scheduling entities and additional marketers, is scheduled for Oct. 30, and a cutover workshop is set for Nov. 13.
Mereness said staff have been evaluating historical data to determine potential ancillary service demand factors, the hourly parameters for each service type that indicate an assumed deployment (energy reservation) based on demand forecasts, intermittent renewable resources and other system conditions. These factors are used in the reliability unit commitment (RUC) studies.
The RTC+B Task Force has scheduled an in-depth meeting Oct. 27 to delve into ERCOT’s analysis and planned values. It is part of a tripleheader meeting that day.
The switchover will take place between 11:59 p.m. Dec. 4 and 12:01 a.m. Dec. 5 as the market begins dispatching energy and ancillary services every five minutes in real time.
Members Show Their College Colors
Members were encouraged to show their college spirit, and some did, wearing jerseys or shirts that exhibited their academic ties.
The meeting soon devolved into good-natured ribbing between Texas Exes and Former Students from Texas A&M. (As good Aggies know, there are no ex-Aggies, only Former Students.)
TAC Chair Caitlin Smith, a University of Texas alum with Jupiter Power, was quick to needle American Electric Power’s Richard Ross, a proud Aggie. “Richard Ross told me the theme of the month is ‘Hook ’em Horns!’” she said.
Ross, who usually sets monthly themes for TAC and SPP stakeholder meetings, snapped to attention. “That’s not true! That’s not true at all!” he said. Caught without a theme, he instead recounted SPP staff’s use of the term “trauma bond.”
“That’s when new staff joins the [stakeholder] meetings and they have the anxiety because they oftentimes get candid feedback and discussion,” Ross said. Turning to ERCOT’s Elizabeth Morales, bedecked in a UT T-shirt for her first TAC meeting, he said, “Elizabeth, this your trauma bond with TAC. I will share with you that that is one ugly shirt you’re wearing.”
“It’s a beautiful burnt orange shirt,” Smith responded, coming to Morales’ defense.
Reliant Energy Retail Services’ Bill Barnes wore a football jersey from the Colorado School of Mines bearing his son’s No. 27. A sophomore, Max Barnes led the School of Mines’ 72-14 win over Adams State on Oct. 18 with 201 rushing yards.
ERCOT’s Jake Pedigo had to step in when a fellow alumnus of the University of North Texas couldn’t remember the school’s slogan. “We are the Mean Green Eagles,” he said, “and it’s ‘C’mon Green, Get Mean.’”
RUC Opt-out Window Expanded
TAC unanimously endorsed, with two abstentions, a protocol call change (NPRR1285) that expands the current RUC opt-out window to incent self-commitment, increasing capacity available to the market at lower expense and reducing RUCs and associated costs.
The endorsement came despite an objection from the Independent Market Monitor.
“On a principal level, it doesn’t really improve self-commitment,” said the IMM’s director, Jeff McDonald. He agreed with staff’s assertion that the change increases flexibility for a generator and its settlement options, but he said that “by increasing the amount of flexibility you have for your settlement options, it would actually decrease the incentives for self-commitment for resources who believe that they might be near the margin of being needed or not needed.”
Dave Maggio, ERCOT’s commercial operations principal, said NPRR1285 eliminates an extra two hours from the lead time before an opt-out decision, which becomes a telemetry function.
“[I] just wanted to make sure it’s clear that it’s not a reversion back to what we had previously,” he said.
TAC’s combination ballot, or consent agenda, included the annual major transmission elements list, five NPRRs, a Nodal Operating Guide revision (NOGRR) and a system change request (SCR) that, if approved by ERCOT’s board, would:
NPRR1263: remove the accuracy testing requirements for coupling capacitor voltage transformers.
NPRR1280: establish a regional planning group review process for proposals to permanently bypass an existing series capacitor or un-bypass a series capacitor previously designated as permanently bypassed.
NPRR1293: clarify the “Update Network Operations Model Production Environment’s” milestone dates.
NPRR1294: incorporate the other binding document “Demand Response Data Definitions and Technical Specifications” into the protocols, standardizing the approval process.
NPRR1299: clarify and clean up language related to the emergency response service program, including a data file produced at the end of the procurement process using code managed entirely within ERCOT’s Demand Integration group. The file is manually produced and must be posted manually, which is affected by weekends and holidays.
NOGRR279: modify the monitoring equipment installation deadlines established by NOGRR255 (High Resolution Data Requirements) to Jan. 1, 2029, consistent with NERC standard PRC-028-01 (Disturbance Monitoring and Reporting Requirements for Inverter-Based Resources), and clarify that synchronized resources with standard generation interconnection agreements executed prior to July 25, 2024, have 12 months after their commercial operations date to comply with the new equipment standards.
SCR831: modify the network model management system, operational data management system, topology processor and the modeling-on-demand system to incorporate short-circuit modeling data for maintaining models built by the system protection working group.
Key organizations across California voiced strong opposition to Pacific Gas and Electric’s proposed rate increases that are under review at the California Public Utilities Commission.
Protesting organizations include the California Farm Bureau Federation, the California Community Choice Association and the Environmental Defense Fund, among many others.
The proposed rate increases are part of PG&E’s 2027 general rate case application, which was reviewed at an Oct. 22 public forum with CPUC officials. PG&E submitted its current general rate case application on May 15, and the commission plans to approve adjusted rates in May 2027.
Critically, PG&E’s application does not include costs associated with recent wildfire mitigation work, community rebuilding projects, billing system upgrades, undergrounding, electricity procurement, fuel and purchase power, or costs to own and operate the Diablo Canyon Power Plant, the CPUC said.
Increases in prior PG&E rate case applications have been driven by wildfire mitigation work, safety work and inflation, PG&E said in its application.
Proposed increases in the 2027 general rate case application are about 8% in 2027 and about 6.1% in 2028, 2029 and 2030.
In 2027, the rate change would increase the average residential customer’s gas and electric bill by about 3.6% compared to a bill in 2025. Electric bills would increase by about 5.2%, while gas bills would decrease by about 0.6%.
The average residential bill would increase by about $9.94/month in 2028, $10.50/month in 2029 and $11.08/month in 2030.
PG&E requested $72 billion over four years to fund its operations and investments, and the application controls a little more than half of PG&E’s overall revenue, CPUC Commissioner John Reynolds said at the Oct. 22 public forum.
“I am mindful that when PG&E pledges that rates will remain stable for years to come, the rates are currently unaffordable for many residents in the state,” Reynolds said at the forum. “Stable rates will not offer [relief] to those who are struggling to pay their bills.”
Displeased Organizations
In comments to the commission, Kevin Johnston, representative of the California Farm Bureau Federation, said PG&E’s rate application contained “a number of assumptions and misdirection” that minimize what continue to be “significant increases” built upon “years of skyrocketing increases” in revenue requirements.
“The authorized revenue requirement in 2017 was $8 billion. The adopted revenue requirement in 2026 was $15.4 billion. A 92% increase in nine years,” Johnston said. “Customers want transparency, not spin.”
The California Community Choice Association added in comments that PG&E’s rate case application raises “critical questions concerning cost shifting.”
CalCCA is concerned specifically with PG&E’s request for $2.45 billion of capital investments between 2027 and 2030 in the company’s hydroelectric generation fleet. Many of the hydroelectric assets have outlived their expected lifespan, and PG&E is not required to relicense these assets, CalCCA said.
The Environmental Defense Fund said in comments that it’s concerned with PG&E’s capital forecasts for setting initial rates and the lack of information about data center forecasts in PG&E’s territory.
Texas Gov. Greg Abbott has appointed Morgan Johnson to the Public Utility Commission, adding a fourth member to the five-person panel.
Morgan Johnson | Morgan Johnson via LinkedIn
Johnson, a deputy general counsel for the Office of the Governor, was appointed Oct. 23 and sworn in. By being appointed while the Texas Legislature is out of session until 2026, Johnson can be seated immediately without confirmation.
“The electric, water and telecommunications industries are complex and have an enormous impact on the lives of millions of Texans,” Johnson said in a statement. “I look forward to working with my fellow commissioners and [PUC] staff ensuring affordability and reliability of these life critical services.”
Before joining the governor’s office, Johnson was a senior counsel at the Texas Commission on Environmental Quality. She also worked as an attorney at McGinnis Lochridge.
Johnson holds a bachelor’s degree in finance from the University of Texas at Austin and a law degree from the South Texas College of Law. Her term expires Sept. 1, 2031.
U.S. Secretary of Energy Chris Wright has directed FERC to initiate a rulemaking to accelerate the interconnection of large loads by asserting jurisdiction over end-use customers’ connections to the grid for the first time.
“It is my view that the interconnection of large loads directly to the interstate transmission system to access the transmission system and the electricity transmitted over it falls squarely within the commission’s jurisdiction,” Wright said in a letter sent to FERC on Oct. 23 with an attached advanced notice of proposed rulemaking (ANOPR).
Asserting FERC’s jurisdiction is in the public interest and in line with the Trump administration’s goals of revitalizing American manufacturing and driving innovation in artificial intelligence (AI), both of which require extraordinary quantities of electricity and substantial investment in the transmission grid.
Wright used his authority under Section 403 of the Department of Energy Organization Act to direct FERC to initiate rulemaking procedures and consider the ANOPR on reforms to ensure the timely and orderly interconnection of large loads to the transmission system.
“In light of the unprecedented current and expected growth of large loads seeking to interconnect to the transmission system, and to provide open access and non-discriminatory access to the transmission system, it has become necessary to standardize interconnection procedures and agreements for such loads, including those seeking to share a point of interconnection with new or existing generation facilities (hybrid facilities),” the ANOPR said.
The document lays out four legal justifications for the regulatory change, the first being that large load interconnections are a critical component of open access transmission service that require minimum terms and conditions to ensure non-discriminatory transmission service.
Second, the interconnection of large loads is a practice that directly affects FERC-jurisdictional rates, and the Federal Power Act has vested the regulator with exclusive authority to ensure wholesale rights are just and reasonable.
The ANOPR’s third justification argues it will not impinge on state authority over retail sales because FERC will not exert jurisdiction over any retail sales to the large load.
“Similarly, nothing in the proposed reforms governs the siting, expansion or modification of generation facilities,” the ANOPR says. “Authority over expansion or siting of generation facilities remains reserved to the states.”
Fourth, any contrary view of the proposed reforms conflicts with the Federal Power Act’s core purpose that grants FERC exclusive jurisdiction over transmission in interstate commerce and large loads connecting to the grid to obtain service benefit from that.
Any new rules should apply only to transmission facilities, consistent with FERC’s seven-factor test. The new rules also should apply only to customers with 20 MW of load, or for hybrid facilities where the load is greater than 20 MW.
DOE’s ANOPR suggests studying large loads and new generation together where possible as that would allow for efficient siting and minimize the need for network upgrades. Load and hybrid facilities should be subject to study deposits, readiness requirements and withdrawal penalties.
The studies should be done based on injection and withdrawal capacity available and be required to install system protection facilities to stay at or below those levels.
Curtailable load and hybrid facilities should have their studies expedited and the ANOPR asks whether requirements around curtailability can be included in the interconnection study process, or by other means.
Any generator that enters a partial suspension to serve large load will have to go through a reliability-must-run type study that will consider system conditions, including load growth, at least three years after the suspension.
FERC will have to justify its departure from long-standing rules that gave states jurisdiction over customer interconnection, which despite decades of orders on restructuring markets it has never claimed.
“Thus, while we believe in most cases there will be identifiable local distribution facilities subject to state jurisdiction, we also believe that even where there are no identifiable local distribution facilities, states nevertheless have jurisdiction in all circumstances over the service of delivering energy to end users,” FERC said in its Order 888 in 1996.
FERC Commissioner David Rosner posted on X that he was happy to take up Wright’s proposal and that dealing with the issues has bipartisan support on the commission.
“I am excited to work with my colleagues on Secretary Wright’s proposal,” he posted. “Getting large load interconnection right is a generational opportunity that is key to winning the AI race, reshoring American manufacturing, and keeping electricity reliable and affordable for everyone.”
Former FERC Chair Mark Christie said in an interview Oct. 24 that the ANOPR overlapped with the ongoing debate at FERC over co-location of load, which he wanted to get a final rule out on, but was unable to secure enough votes before stepping down in August.
The devil is in the details, and many questions will be answered as FERC works through a rulemaking process, but Christie warned that the change in jurisdiction could lead to problems.
“It’s going to have a monumental impact certainly on state authority to govern interconnection and set the terms of interconnection, and also it’s going to have a monumental impact on the states’ ability to maintain the integrity of their integrated resource planning process (IRP),” Christie said.
The order directs FERC to process large load interconnection requests with 60 days, which could mess up load forecasts on which IRPs rely. In RTO states, it will have the effect of removing existing generators from the market and putting upward pressure on prices to the extent it encourages co-location, and the issue of load forecasting also is pertinent due to the use of demand curves in capacity markets.
“That demand curve is set by load forecast,” Christie said. “So, if load is basically unpredictable, because FERC is now saying every single large load customer has to be interconnected within a short time frame, that’s going to potentially drive up the demand curve in the PJM capacity market.”
The main questions FERC will have to answer are what the rule change would mean for reliability, what it will mean for costs and cost allocation and whether it can claim an authority previously reserved for states.
“I think they’re all questions at this point, not conclusions,” Christie said. “I want to emphasize that they’re all questions at this point, not conclusions.”
Speaking at S&P Global’s Nodal Trader Conference, NRG Vice President of Regulatory Affairs Travis Kavulla said that hopefully the order moves the ball forward on dealing with large loads.
“Obviously all of these loads are connected at relatively high voltages, basically to the transmission system,” Kavulla said. “So, I have sometimes puzzled why state-regulated utilities acting in what seems to be solely in keeping capacity would be the arbiters of how that load gets on the system.”
One of Texas’ big examples is that it does not have separate authorities for transmission and distribution, which has helped make it a major market for hyperscale data centers, he added.
A key difference with Texas is that it is operating an intrastate market and it is not having its authority potentially usurped by the federal government, Christie said.
NARUC spokesperson Regina Davis said in an email that the proposal was being reviewed by the group and its state regulator members so it could not comment on specifics.
“Naturally, the matter of adequate load growth is a priority for NARUC and its members,” Davis said. “We engaged with FERC on the Joint Federal-State Task Force on Electric Transmission, which has evolved into the new Federal and State Current Issues Collaborative exploring cross-jurisdictional issues.”
Davis added that “the ANOPR points to data centers as one of the drivers of load growth, which is the focus of our Demand Roundtable that convenes hyperscalers and mega users in dialogues to discuss the critical issues surrounding increased demand.
“Achieving the grid reliability and flexibility needed to accommodate growing demand will require input and collaboration with state regulators and NARUC looks forward to working with FERC and other stakeholders to ensure the grid can meet future demand,” Davis said.
SIOUX FALLS, S.D. — MISO leadership shed more light on the RTO’s need for a pilot program to estimate load growth on a 20-year horizon after stakeholders asked for details.
MISO Executive Director of Markets and Grid Research DL Oates said MISO has fielded stakeholder questions since announcing its load-forecasting pilot. He said the many questions are a “flag” that it should better explain its plans. (See MISO Debuting Pilot for Better Long-term Load Forecasting.)
Oates said dramatic load growth is arriving just as MISO is experiencing tapering margins due to continued fleet change.
“All of this makes long-term planning more important and more difficult,” he said at the Organization of MISO States’ annual meeting Oct. 21.
He said MISO would update its late 2024 forecast and maintain annual load forecasting updates informed by future annual surveys.
In its 2024 load forecast edition, MISO predicted its 638 TWh of gross energy in 2024 would grow to anywhere from 921 to 1,225 TWh by 2044, driven mostly by data centers, electric vehicles and green hydrogen.
MISO previously said it could be navigating an annual peak around 140 GW by 2035. MISO’s 2025 summer peak nearly brushed 122 GW.
“It’s clear that new information has come to light since last year,” Oates said, adding that the pilot forecast would be “pretty exploratory.”
He said MISO doesn’t know how many members would respond to its survey and added that MISO likely would have to augment some questions in the next survey to improve data quality of responses.
Oates said MISO expects 13.8 GW in load additions in the near-term based on members’ expedited transmission project requests. But he said green hydrogen and electric vehicles likely would take a hit in MISO’s load forecasts due to policy changes within the federal government.
MISO plans to unveil its updated load estimates sometime in early 2026 after assembling member and national data.
In an early October letter answering FERC Chairman David Rosen’s questions about MISO’s large load forecasting, CEO John Bear said MISO recognizes “that more work must be done to address the new large load challenges, including leveraging new technologies and enhancing our processes.”
Bear said MISO’s pilot survey would help “shape enhancements to future long-term load forecasts.”
MISO and SPP said they will study more than 30 project suggestions — some estimated to cost more than $1 billion — in a four-state area in their pursuit of major, regionally cost-shared transmission projects.
The grid operators said they received 46 stakeholder-originated ideas for projects along their seam in Arkansas, Louisiana, Oklahoma and Texas. The two RTOs have culled the projects to 32 proposals and said they will test their potential and may build business cases for some under their coordinated system plan. (See MISO, SPP Still on Hunt for Joint Transmission Under CSP.) MISO and SPP ruled out most of the eliminated projects for focusing on local — not interregional — issues.
The 32 project contenders are concentrated along:
Northeastern Oklahoma to northern Arkansas, where stakeholders submitted multiple greenfield 765-, 500- and 345-kV project ideas alongside reconductoring and additional transformer suggestions.
Eastern Oklahoma to central Arkansas, which drew 500- and 345-kV line ideas.
The Oklahoma-Texas eastern border to northeastern Louisiana garnered 765- and 345-kV proposals with ideas for new transformers, substations and transformer upgrade submissions.
The Oklahoma-Texas eastern border to southwestern Arkansas, which could host new 500- and 345-kV lines and reconductoring, electrical reactor and double-circuit work.
Eastern Texas to central Louisiana, where stakeholders recommended 500-kV work.
Ashleigh Moore, of MISO’s interregional planning division, said MISO and SPP will analyze the candidates’ performance in terms of adjusted production cost savings, mitigation of reliability issues and transfer capability improvements.
At the Oct. 24 MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC), MISO and SPP said they would have draft recommendations ready to share by the Dec. 12 IPSAC meeting. Staff said they will have more data, maps, and benefit estimates and adjusted production cost savings estimates then.
The projects’ price estimates range from $54 million to nearly $4 billion for one HVDC idea in northeastern Oklahoma and northern Arkansas. Eight projects on the list are estimated to cost more than $1 billion.
Moore said MISO and SPP are encouraged by the “valuable project ideas” from their stakeholders and that they were glad to see some of the projects zeroing in on key reliability paths between the RTOs. She said MISO and SPP will narrow the 32 “good ideas” to “high-performing, feasible and cost-effective” projects.
MISO’s Jon George said the projects may culminate in a portfolio of interregional projects, with benefit-to-cost ratios calculated among a group of projects rather than individually.
The RTOs still are working on their 15-year modeling to build studies on and said it would be complete in November.
MISO and SPP said they may use the seven transmission benefits established in FERC Order 1920 to develop business cases for projects. If the two find beneficial projects, or a portfolio of projects, they would need to propose an interregional cost allocation plan for FERC approval. The two RTOs said cost sharing could be tackled in late 2026.
Southern Renewable Energy Association Executive Director Simon Mahan said while MISO and SPP’s coordinated system plan studies in the past have been disappointing, this fresh list of project candidates seems promising.
“I think this is going to be getting us closer,” Mahan said. He said some of the projects appear to be able to help outages that occurred earlier in 2025 in the Shreveport, La., area and previous voltage problems in northwestern Arkansas and southwestern Missouri during Winter Storm Elliot in late 2022.
MISO and SPP have never recommended a major, interregional cost-shared transmission project through their coordinated system plan study, despite five previous attempts. The RTOs’ $1.6 billion Joint Targeted Interconnection Queue transmission portfolio is to be paid for by interconnecting generation and is considered separate from their coordinated system plans.
Mahan said some of the project ideas appear to potentially boost transmission capacity to allow more MISO Midwest-South power flows. He asked if MISO would examine some projects for that value.
Moore said while MISO and SPP are time-constrained for this study, MISO plans to keep the list of projects ideas to draw on in future planning studies.
MISO-SPP TMEPS in the Works
Meanwhile, work will continue into 2026 on MISO and SPP rules to create a smaller, congestion-relieving interregional transmission project category.
MISO and SPP are in the process of drafting rules for a targeted market efficiency project (TMEP) type, modeled after the MISO and PJM existing interregional study that produces less expensive transmission projects that can be built quickly.
SPP Senior Interregional Strategist Jill Ponder said MISO and SPP plan to file new language to their joint operating agreement and an RTO-to-RTO cost allocation for TMEPs in either the first or second quarter of 2026.
Speaking at MISO’s August Planning Advisory Committee meeting, Moore said MISO and SPP view TMEPs as a “bridge in our planning toolbox” and said any MISO-SPP TMEPs will not “undermine or duplicate planning efforts.”
MISO stakeholders in written feedback expressed a concern that TMEP planning could risk overlapping with the existing MISO and SPP regional and interregional studies.
So far, the MISO and SPP draft TMEP study process would rely on historical data to weed out congestion on the seam and advance small transmission projects that can be built quickly to alleviate it. Moore said TMEPs are intended to supplement — not replace — long-term planning initiatives like MISO’s long-range transmission planning and the MISO and SPP Joint Targeted Interconnection Queue. Moore said TMEPs would solve only issues not expected to be “substantially alleviated by system changes” on a five-year horizon, including known upgrades.
Moore also said the two RTOs are striving to make the new process as transparent as possible. She said the RTOs will post historical congestion data annually and will commit to documenting the screening of potential projects in study reports “to explain why some move forward while others don’t.”
NV Energy has asked Nevada regulators for permission to join CAISO’s Extended Day-Ahead Market — a request that, if approved, would fill in a central piece of the market’s footprint.
The company filed the request with the Public Utilities Commission of Nevada on Oct. 22 as an amendment to its 2025-2027 Energy Supply Plan. NV Energy’s target date for EDAM entry is fall 2028.
The PUC is expected to issue an order within 135 days.
Factors in NV Energy’s decision include its positive experience with CAISO’s Western Energy Imbalance Market (WEIM), the company said in its filing.
And larger economic benefits are expected from joining EDAM rather than SPP’s Markets+. A Brattle Group study, updated in October, projected that NV Energy would save $93.1 million a year by joining EDAM, relative to participating in WEIM alone. In contrast, joining Markets+ would increase annual costs by an estimated $7.3 million.
NV Energy also pointed to better transmission connectivity with the anticipated EDAM market footprint compared to that of Markets+.
Another factor the company cited was the governance of EDAM as enhanced by West-Wide Governance Pathways Initiative and California’s AB 825, “including CAISO’s ability to respond more expeditiously to events with targeted, expedited stakeholder processes.”
California Gov. Gavin Newsom signed AB 825 into law in September, allowing CAISO to transition the governance of its markets to an independent “regional organization.” (See Newsom Signs Calif. Pathways Bill into Law.)
NV Energy also said it prefers certain EDAM market design features, including its resource sufficiency test, congestion rent allocation, virtual bidding, greenhouse gas accounting and voluntary participation in Western Power Pool’s Western Resource Adequacy Program (WRAP).
The company announced in August that it plans to withdraw from WRAP and revealed on Oct. 21 that it has been working with other EDAM participants on a potential alternative Western resource adequacy program. (See related story, EDAM Participants Exploring Potential New Western RA Program.)
In October 2023, the Nevada PUC opened a docket regarding regional market activities in the Western Interconnection. As part of the proceeding, the commission approved a report outlining the criteria to be addressed in a utility’s application to join a regional market. NV Energy’s application to join EDAM follows its announcement in May 2024 that it planned to join EDAM rather than SPP’s Markets+.
Other entities on board with EDAM are PacifiCorp and Portland General Electric, which have formally committed to joining in 2026. The Balancing Authority of Northern California, Los Angeles Department of Water and Power, Public Service Company of New Mexico (PNM) and Turlock Irrigation District have signed agreements to join in 2027; Imperial Irrigation District plans to join in 2028.
Arizona G&T Cooperatives, BHE Montana and Idaho Power have indicated they’re leaning toward EDAM.
NV Energy’s entry would add a substantial chunk of territory to the EDAM footprint, between California entities and PacifiCorp West to the west and PacifiCorp East to the east. Idaho Power would be directly to the north, while PNM extends the footprint deeper into the Southwest.
“Joining [EDAM] positions Nevada at the heart of the Western grid, connecting the Southwest and the Northwest to efficiently share affordable, reliable and flexible power across the region,” said Emilie Olson, Nevada lead at Advanced Energy United.
Olson said that joining a robust regional energy market is essential to NV Energy for controlling costs while tapping into a diverse regional energy mix.
CAISO said NV Energy’s filing is “a significant step forward” in its plans to join EDAM.
“We are eager to work with NV Energy and all the EDAM entities to deliver the full range of benefits, including improved resource sharing and meaningful cost savings for consumers across the West,” the ISO said in a statement.
President Donald Trump has named Laura Swett chair of FERC, the commission announced Oct. 24.
Swett was sworn in as a commissioner Oct. 20. Her term expires June 30, 2030.
“I am honored to serve as chairman of FERC and grateful for President Trump’s confidence in me to advance America’s energy priorities at such a critical moment in our nation’s history,” Swett said in a statement. “I look forward to working with my colleagues and FERC’s excellent staff to continue the commission’s crucial mission of ensuring reliable and affordable energy for all consumers.”
Swett takes over from David Rosner, who said at FERC’s open meeting the previous week that he would be happy becoming a commissioner again. Rosner was something of an interim chair, holding the office for only a few months after Mark Christie left the commission in August.
Swett was confirmed alongside David LaCerte to open seats on the commission Oct. 7. The two are Trump’s first nominees in his second term in the White House. (See Senate Confirms Swett, LaCerte to Open Seats on FERC.) LaCerte has not yet been sworn in as of press time.
Swett is no stranger to FERC, having been a staffer for former Chair Kevin McIntyre and Commissioner Bernard McNamee. She has been litigating FERC law for 15 years, which includes representing utilities, transmission owners and pipelines, most recently at Vinson & Elkins.
She received her bachelor’s degree from the University of Virginia and law degree from Georgetown University. She lives in Virginia with her family.
