ERCOT has filed a preliminary long-term load forecast for discussion at the April 17 Texas Public Utility Commission open meeting that predicts 367 GW of demand by 2032, a staggering 430% increase over its current peak demand of 85.5 GW.
The grid operator attributed much of the forecast to large loads identified by transmission and/or distribution service providers’ (TDSPs) submissions based on criteria established in ERCOT’s 2026 Regional Transmission Plan, as required by state law.
Staff expressed concern in the filing about using the preliminary forecast values as a modeling input for its 2026 reliability assessment or other transmission and resource adequacy analysis. They want to consult with PUC staff to evaluate whether it is appropriate to adjust the forecast, noting state law allows it “if the adjustment is supported by actual historical realization rates or other objective, credible, independent information.”
ERCOT projects 2026’s summer peak load will fall between 90.5 GW and 98 GW. The preliminary forecast projects demand to hit 112 GW this summer.
The grid operator cautioned the forecast is not a prediction of what will be built, but a preliminary snapshot to inform its transmission planning and resource adequacy reporting, and that adjustments should be expected as the data is further studied, reviewed and finalized for use in the planning process.
“Texas is experiencing exceptional growth and development, which is reshaping how large load demand is identified, verified and incorporated into long-term planning,” ERCOT CEO Pablo Vegas said in a statement. “As a result of a changing landscape, we believe this forecast to be higher than expected future load growth.”
The forecast was developed from data that included ERCOT’s base economic forecast and information provided by TDSPs that work directly with large load customers (75 MW and above) and others.
Data centers, cryptocurrency mining and industrial and oil and gas processes comprise the bulk of the large loads. Data centers alone account for 228 GW of the TDSP’s 243 GW submissions for 2032. Oncor, with a North Texas footprint that is ground zero for large loads, has submitted 109 GW of the large loads.
That has led to the grid operator’s proposed batch process, in which it will study clusters of interconnection requests rather than individually. ERCOT staff are working on a transitional batch study, called Batch Zero, that will streamline the interconnection process and set the stage for subsequent batches. They plan to bring their proposal to the Board of Directors for its consideration in June. (See ERCOT Batch Process Rules Headed to Stakeholders.)
Assuming board and PUC approval, the transitional Batch Zero study would begin July 10 and run into 2027. Loads that had validated studies as of March 4 will be eligible for Batch Zero. Loads without validated studies will have to wait until March 1, 2027, when Batch 1 is scheduled to begin.
A first cut filed with the PUC April 10 indicates 14 GW of requests meet the requirements to be included as base load in Batch Zero. An additional 9.2 GW still could qualify as base load when their studies are checked for validity. And 18.5 GW more requests could be included as studied load in Batch Zero but face a July 10 deadline to be deemed as base load should their studies be valid.
ERCOT said in its 2025 State of the Grid report that average annual electric consumption in its region is increasing by 5% over multiple years. The market has added 62 GW of new generation, primarily renewables and batteries, since 2021. An additional 450 GW of active requests sit in ERCOT’s generator-interconnection queue, as of January 2026.
MISO said it will pay attention to its maintenance margin while it considers changes to its 31-day limit on outages for capacity resources.
MISO staff said the RTO’s maintenance margin — used to schedule planned generation outages and grant capacity accreditation exemptions — is at times off-base in its risk-to-supply adequacy judgment when owners request downtime for maintenance.
MISO has been toying with the idea of altering its 31-day outage rule, which has been in effect since FERC approval in August 2022. (See MISO Re-examining Monthlong Outage Limit for Capacity Resources.) Now, MISO said its maintenance margin could use some work to maintain reliability.
“We will be evaluating it and making sure it’s accurate. Our goal is to make sure it’s completely accurate,” MISO Market Design Engineer James Curtis said during an April 14 Reliability Subcommittee teleconference.
Curtis said the maintenance margin shows too much wiggle room for outages in high-risk months in summer and winter. He said the maintenance limit allows 40 GW of planned, urgent and emergency outages for June 2026.
“I think we can all agree that 40 GW of outages in the summer is totally inappropriate,” MISO Market Design Manager Davey Lopez said. “That’s why we’re having this discussion.”
Curtis said when MISO’s maintenance margin is set too high, resources can take outages that put reliability at risk while still getting accreditation and non-compliance penalty exemptions.
MISO’s maintenance margin was introduced in 2013 and uses the average of the past 30 years of load data to calculate available reserves. MISO said the 30-year amalgamation results in only typical operating days, when it also should represent days with choppier operations. MISO said the 5 GW of import capability it assumes from neighboring regions when calculating the margin is too optimistic. It said a more realistic average ranging from 1.4 GW to 2.5 GW depending on the season is in order.
“It is critical that the maintenance margin is accurately representing the number of megawatts that can go on outage without causing reliability risk to the grid,” Curtis said.
MISO said it observed an average 20 GW in unplanned outages over summer 2025, a 42% spike over previous years, which contributed to tighter operating margins and ultimately four maximum generation emergencies.
Curtis said generation owners are planning outages “intentionally to avoid” MISO’s capacity replacement non-compliance charge by “straddling seasons” so the outage can occur in a month of one season and continue into another month of the next season, exceeding the monthlong limit without technically violating the limit.
Curtis said while MISO anticipated some of that type of behavior, it didn’t expect it to be at the scale generation owners are using it.
MISO expects capacity resource owners to either procure replacement capacity or pay penalties if they are offline for more than 31 days in a single season. They must notify the RTO 120 days in advance of planned outages to be exempt from capacity accreditation reductions. If MISO’s maintenance margin is above zero for a given period, resources can get planned outage exemptions for their accreditation.
MISO imposes a capacity replacement non-compliance charge when resource owners conduct outages longer than 31 days and fail to replace the zonal resource credits they signed up for. The charge is calculated by multiplying the capacity shortfall by the sum of auction clearing prices and the area’s cost of new entry.
Minnesota Power’s Tom Butz said he didn’t see how a more exacting maintenance margin would allow generation owners to take proper, long-term maintenance outages when necessary. Butz said MISO might consider allowing longer outages in spring and fall.
Butz previously asked for a better understanding of MISO’s maintenance margin and what calculations are used to determine when the system is tight.
“It just seems like it’s a post card that comes in the mail,” Butz said, adding that the maintenance margin seems like the “black box of black boxes.”
Curtis said MISO wants make sure generation owners have the necessary time for planned outages “so they’re not taking forced outages when something breaks.” He said MISO plans to discuss outage limits and monetary penalties further in upcoming meetings of the Resource Adequacy Subcommittee.
MISO will continue discussions on how its maintenance margin could change at subsequent Reliability Subcommittee meetings.
FERC announced that it needs until June to act on the Advance Notice of Proposed Rulemaking (ANOPR) initiated by the Secretary of Energy asking it to claim jurisdiction over the interconnection of large loads to the transmission system.
Secretary of Energy Chris Wright had asked for a ruling, which would have proceeded to the NOPR stage, by April 30.
“Our nation stands at a pivotal moment as we face rapid growth in demand from data centers and other large-scale consumers that are reshaping our transmission landscape,” FERC Chair Laura Swett said in a statement. “I want to reassure the public that we are addressing this challenge head-on, working tirelessly and collaboratively with stakeholders and federal partners to deliver real solutions. I encourage everyone to stay tuned as we build a resilient energy future together.”
FERC must balance speed with the need to respond to arguments in a voluminous docket because failure to do so would leave its actions vulnerable to court appeals. Hundreds of comments and replies totaling 3,500 pages have been filed in RM26-4, and in cases like it appeals are the norm. (See Parties Warn FERC Jurisdictional Fight Could Slow Data Center Connection Effort.)
Since the ANOPR was issued in October 2025, FERC has been approving rules for specific markets meant to speed up data center interconnection.
It also approved SPP’s High Impact Large Load initiative in January, which is meant to accelerate the interconnection of large loads and generators built to serve them. (See FERC Approves SPP Large Load Interconnection Process.)
FERC has approved other proposed tariffs and agreements for specific large load interconnections, while rejecting proposals that exceed its jurisdiction or lack reasonable cost allocation.
In “one of the largest and most brazen frauds in the history” of FERC, American Efficient has been ordered to pay a civil penalty of $722 million and disgorgement of unjust profits totaling about $410 million.
FERC’s ruling, issued late April 15, said the company “stole half a billion dollars from hardworking Americans by collecting compensation for fake ‘energy efficiency resources.’”
“This FERC will not stand for such scams,” Chair Laura Swett said in her opening comments at the April 16 monthly commission meeting.
“It’s particularly sad” the scheme emerged at a time when regular ratepayers have difficulty paying their bills, Commissioner David Rosner said at the meeting. This company is “an egregious outlier,” he added.
According to FERC, American Efficient’s affiliates began participating in PJM’s capacity market in 2014 and in MISO’s capacity market in 2017. The fraud involved “hijacking a regulatory mechanism intended to promote energy efficiency and converting it into an ATM for American Efficient’s worthless paper-shuffling scheme.”
“American Efficient operated a sweeping money-for-nothing scheme to extract capacity payments from PJM and MISO by falsely claiming ownership and control of energy efficiency resources,” according to a FERC news release about the ruling.
“Through this scheme, American Efficient bought sales data for EE products, papered those transactions as if it was acquiring rights to each product’s load reduction-related potential, and then monetized that sales data in the PJM and MISO capacity markets under the guise of offering actual capacity,” the commission said in its ruling.
Once the truth “about American Efficient’s business model emerged over time,” MISO and ISO-NE disqualified American Efficient from their capacity markets.
The independent market monitors for PJM and MISO later referred American Efficient to FERC for potential enforcement action. The commission’s Office of Enforcement began investigating the company in 2021, and in 2024 the commission issued the Order to Show Cause that started the proceeding.
In company comments included in the ruling, American Efficient says it does exactly what the FERC set out to achieve: “bringing within RTO/ISO capacity markets the benefits of permanent energy reductions by providing payments tied to those reductions.”
The company also “contends that it provides benefits by aggregating demand reductions from millions of individual product installations that would not otherwise be accounted for.”
American Efficient says FERC doesn’t have the authority under the Federal Power Act to order disgorgement. It argues that “if Congress wanted the commission to be able to order disgorgement of unjust profits under the FPA, it would have provided express authorization to do so, as it did in a section of the Natural Gas Policy Act (NGPA) that specifically identifies restitution.”
Despite harsh weather and unprecedented load growth expected throughout the Western Interconnection, Arizona utilities said they are well prepared to meet demand reliably in summer 2026.
“We do feel we have sufficient capacity to meet projected demand this coming summer,” said Grant Smedley, director of energy marketing and trading at Salt River Project. “We have sufficient fuel, and those generators are ready and maintained.”
Smedley’s comments came during an April 14 summer preparedness workshop hosted by the Arizona Corporation Commission.
Presentations from SRP and other Arizona utilities were preceded by an overview of conditions in the Western Interconnection by James Hanson, manager of operations analysis for WECC.
Hanson noted that March 2026 had been the hottest March on record in more than a dozen states. The heatwave decimated snowpacks in the Colorado River basin and parts of California. (See California Snowpack Near Record Lows as Summer Approaches.) Fire danger is expected to be above normal throughout much of Arizona and New Mexico through June.
A weather forecast for April through June shows an above-average chance of above-average temperatures throughout much of the Western Interconnection. In contrast to situations where a heat wave in one part of the interconnection is balanced by cooler temperatures in another region, the heat shown in the early summer forecast is widespread.
“When everyone’s hot, that excess energy is not available,” Hanson said. “It is serving local needs, and imports become very tight.”
The concerning weather trends are a backdrop to what Hanson called “unprecedented growth” in energy consumption and peak demand. Much of the load growth is due to large loads such as data centers.
Electricity demand is expected to grow by 25% across the Western Interconnection through 2035, with an even higher growth of 42% projected in the Southwest subregion.
Peak demand is projected to grow 20% over the next decade, from 160 GW in 2026 to 191 GW in 2035. The Southwest is projected to see 10 GW of peak demand growth over the next 10 years, or an annual average growth rate of 3%. The only WECC subregion with a higher annual growth rate is Mexico, at 4%.
“The West’s planned resource buildout will not keep up with anticipated load growth over the next decade, particularly in the Basin and Northwest subregions,” WECC said in its 2025 Western Assessment of Resource Adequacy, released in January.
Although 177 GW of new resources are planned, about 90% of those are inverter-based resources, such as solar, wind and batteries.
“Most of the new resources are weather-dependent, which creates uncertainty,” the WECC report said.
Commissioner Kevin Thompson called the high percentage of inverter-based resources “scary.”
“That’s absolutely bonkers to me,” he said.
Growing Peak Demand
SRP, Arizona Public Service and Tucson Electric Power each set peak demand records in August 2025, while exceeding their peak demand forecasts.
Utility representatives explained how they planned to meet the challenges of summer 2026.
Tim Rusert, director of power supply services at APS, said the company added 33,000 new customers in 2025, the most since 2007. In contrast to a demand growth rate of less than 2% from 2022 to 2025, the growth rate for 2026 is expected to be 5.3%.
“But we’re prepared. We’re focused on reliability,” Rusert said.
The summer peak forecast for APS is 8,648 MW. The utility has 9,974 MW of accredited resources, or about 1,326 MW of reserves. With a 15.4% planning reserve margin, APS is exceeding its longstanding minimum reliability requirement, Rusert said.
Following a 2023 request for proposals, APS has added 1,000 MW of accredited capacity, including solar, storage, wind and natural gas. Two new gas turbines came online at the Sundance power plant in late 2025; eight more turbines are under construction.
“We maintain a balanced generation mix, which gives us reliability in all conditions,” Rusert said.
Resource Diversity
SRP’s peak demand forecast for the coming summer is 8,869 MW — about 300 MW higher than summer 2025. In addition to its peak retail load, SRP is planning for 1,112 MW of reserves and 22 MW of sales to small Arizona entities, for a total of 10,003 MW.
An expected capacity of 10,489 MW exceeds that amount. Capacity includes 5,665 MW of natural gas resources; 2,544 MW of renewables and storage; 1,455 MW of coal-fired resources; and 826 MW of nuclear resources.
“That diversity has served us really well over the course of our history,” Smedley said. “That’s going to continue to be a really significant focus for us moving forward.”
New resources for SRP include the 55-MW Copper Crossing Energy and Research Center project, SRP’s first owned and operated solar facility. The project uses three different types of solar panels, and SRP will compare their performance. The site also will test three types of solar trackers and three different inverters and will use sky cameras to estimate cloud impacts to solar production.
At TEP, the summer peak forecast is 2,513 MW, slightly higher than the summer 2025 peak of 2,500 MW, said Lauren Briggs, director of resource planning.
TEP’s planning reserve margin target is 16.5%. But with new resources coming online, TEP expects to exceed that in 2026 with 22.1%.
New resources include the 160-MW Babacomari solar project and the 100-MW Wilmot II solar and four-hour storage project. Both are now in service.
Roadrunner Reserve II, a four-hour, 200-MW storage project, is expected to be in service in May.
TEP also counts coal, natural gas, wind, demand response and power purchase agreements among its resources.
ALBANY, N.Y. — Renewables and storage remain central to New York’s energy vision, even as the path to realizing that vision becomes harder or merely different.
Some discussions April 15 at the New York Energy Summit veered toward the “harder,” as panelists offered assessments and strategies for the obstacles facing the state’s continuing efforts toward decarbonization.
These can be intentional obstacles created by a federal government focused on fossil fuels or inevitable collateral results of New York’s dense regulatory landscape. But the effects are similar: Most types of renewable energy development are moving far more slowly than hoped despite strong support.
“The past 16 months have been lively! There have been some changes made!” Marguerite Wells, executive director of the Alliance for Clean Energy New York, said as she introduced a panel on utility-scale wind and solar.
“Depending on how you count, there’s been anywhere between 16 and 20 adverse actions that have been taken against renewables” by the second Trump administration, agreed Zack Hutchins, director of public relations for Boralex.
Onshore wind and solar are central to New York’s near-term planning for renewable generation but still constitute only a small percentage of the total energy portfolio. The state’s high aspirations for offshore wind are paused until a more supportive administration returns to Washington. New nuclear is being planned but may be a decadelong prospect.
The growing need for power and the advanced age of existing generation are such that new gas-fired generation is being considered.
So the renewables community wants to keep skin in the game.
Walter Crenshaw, senior director of operations at AES, said his company is rushing to safe-harbor its projects as it navigates whipsaw policy changes and pursues market share.
“This time period also overlaps with this tremendous growth and demand that we’re all trying to satisfy. And so we have this kind of dual effect, which has been really hard on the industry,” he said.
There are ways to reduce adversity, Hutchins said: “One of the big things that we’re concentrating [on] at Boralex is trying to eliminate or reduce our federal interaction as much as possible.” This includes not triggering environmental reviews because those appear to be a quagmire.
The renewables industry has a steadfast supporter in the New York government, he added.
“The state reaction and the way that the state has stood up to help support contracted projects, mature projects — one of the shining lights of the past 16 months is just the step up in the level of collaboration,” Hutchins said.
The state’s long-running effort to streamline its regulatory structure is appreciated, Crenshaw said. “New York has done a good job with aggregating land-use permitting through ORES [the Office of Renewable Energy Siting], which I usually hold up as a model to our Virginia policy people and others in PJM and then in the Southeast.
“Having the very clear guidelines on land-use permitting in New York has been huge. It’s a lot of things, but we know what we need to do.”
That is the intent, said Georges Sassine, senior vice president for large-scale resources at the New York State Energy Research and Development Authority. He likened all the bottlenecks that once existed to “death by 1,000 paper cuts” and said they are being eliminated systematically. Individually, they are small, but collectively their removal will make a big difference.
As NYSERDA, ORES and other agencies have been streamlining the development process, NYISO has been streamlining the interconnection process. Wells asked the panel about the effect of NYISO queue reforms.
“We’re being forced to make these decisions about what is really viable much earlier than we did in the past,” Crenshaw said.
“It’s moved us towards larger projects as well,” Hutchins said, “because interconnection costs, they don’t scale. You can have a $14 million interconnection on a 60-MW facility, and same on a 200-MW facility. That’s been one of the big changes with Boralex’s approach.”
One recurring problem is labor, Wells said. Workers are trained to build renewables, and then the construction pipeline thins out, so they make a lateral move to another industry. Then the renewables pipeline perks up again, so more workers need to be trained.
In 2026, there are 1,500 MW of renewable capacity being built onshore, and 1,000 more is scheduled to start this year. Combined with the offshore wind construction, this is the most ever, she said.
“It’s a good problem to have, but it’s a challenging problem,” Sassine said. “How do you prioritize all of these different projects? And unfortunately, we’re not in a place where we can prioritize; we have to build all of them.”
And yet not all will be built.
Sassine acknowledged the simmering problem with large-scale renewables proposals that have seen significant cost increases and are not able to proceed to construction under the inflexible terms of their subsidy contracts with the state. (See related story, Another Mass Cancellation of Renewable Contracts Brewing in N.Y.)
“If your cost structure is dramatically changing and the projects are uneconomic, you’re being forced to face a tough business decision on whether you want to cancel these contracts with us or even cancel the projects altogether,” he said. “So these are very difficult decisions. We want you to build, but also, at the same time, we want to be protecting ratepayers.”
Distributed Resources
Small-scale solar has taken off in New York, a contrast to inherently slower-moving utility-scale solar development.
“I know that’s old news, but it’s important to remember the highs as we now clearly face a number of headwinds,” Gabrielle Stebbins, senior director of distributed energy resources at the Center for Sustainable Energy, said as she introduced a panel discussion on distributed solar.
Oliver Sandreuter, director of business development at Lodestar Energy, said the industry must rush to protect what it has now, through safe harboring, but also act to protect its future.
“It’s a critical period of time to go on offense from a policy, regulatory standpoint, as we think about what comes next,” he said. “A lot of that is, thankfully, state-driven conversation, and we are fortunate to be here in New York that has been, as mentioned, a critical leader in DG [distributed generation] deployment. We are, I think, one of, if not the only, state that can claim we are ahead of schedule and under budget with our DG goals.”
Kristina Persaud, senior principal at Advanced Energy United, said the solar industry needs to present itself as the solution at a time of pressing need for new electrons on the grid and mounting concerns overpaying for those electrons.
“We need to think about the speed to market, and we need to think about grid optimization, and solar checks all those boxes,” she said. “It’s the most cost-effective new generation. The speed to market compared to other things, it’s unbelievable.”
Jeff Lee, business development director at Nautilus Solar, said changes are coming. “I think our industry has a very bright future for the next few years with the implementation of safe harboring and so on,” he said, but after that, “it’s a brave new world.”
“New York has been a top 10 market for solar over the past several years,” said Peter Muzsi, vice president of business development at Core Development Group. “I think we will continue to evolve. There still will be solar, even after the” investment tax credit ends.
But there is and will continue to be local opposition to solar, some panelists said.
Moratoria are proliferating steadily, Lee said, as is disinformation.
“One partner of ours mentioned they had an honest question about how solar panels that are not even moving, just sitting there on fixed tilt, are going to attract UFOs,” he said. “These are not isolated incidents … and I see everyone nodding their heads here on the panel.”
“I’ve heard some very bizarre things, that solar panels reflect heat back at the sun and amplify the sun, and that’s what caused global warming,” Persaud replied. “Education is huge here. It helps with NIMBYism, community engagement, some of that pushback.”
Lee wondered if a semi-organized, pseudo-official truth effort might help tamp down some of these misconceptions or limit their impact. But Stebbins tamped down that idea.
“Unfortunately, a lot of times, once folks have bought into the concerns or the disinformation, you end up talking yourself into a backwards pretzel. Because by saying that is not true, you’re providing more petrol to the fire.”
In their monthly open meeting April 15, members of NERC’s Standards Committee voted to disband a group formed three years ago to upgrade the ERO’s functionally defunct standards grading process.
In 2016 the SC created a team comprising the chairs of the SC, Operating Committee and Planning Committee (the latter two being predecessors to the Reliability and Security Technical Committee), along with representatives from the regional entities and NERC staff, to grade selected standards annually, in response to a directive by the ERO’s Board of Trustees to research whether revised standards resulted in improvements. But the process was performed sporadically at best and has not been conducted at all since 2022.
The SC and the Compliance and Certification Committee formed the Standards Grading Task Force in 2023 to develop improvements to the process, but they “struggled to find a recommendation on the path” forward, SC Chair Todd Bennett, of Associated Electric Cooperative Inc., told members.
Bennett cited several factors for the lack of results, including “competing priorities in the industry,” resource constraints and the perception among stakeholders that because the grading process does not produce standard authorization requests leading to new standards projects, there is “no net benefit” to participating.
Another reason for rethinking the standards grading task force is the upcoming changes to the standards development process, driven by the recommendations of the Modernization of Standards Processes and Procedures Task Force adopted by the board in February. Bennett said the MSPPTF’s proposals — which would see the SC disbanded by the end of 2027 and the standards process revamped to work more efficiently with the benefit of artificial intelligence — led NERC to conclude that the standards grading task force, and the grading initiative overall, were no longer needed.
“I don’t think that we’ve lost anything other than a mandated plan to do this annual review of a subset of standards … that [has] yet to display any real benefits,” Bennett said. “The capability [to improve existing standards] is still there, if a [potential] correction is identified by NERC, one of the subcommittees or an industry group.”
The proposal passed with no votes against it and a single abstention by Kimberly Janas, of the Illinois Attorney General’s Office.
Standards Actions
Members next voted to approve the addition of six supplemental candidates to the standard drafting team for Project 2023-09 (Risk management for third-party cloud services).
NERC selected the candidates from nominees submitted by industry in a solicitation approved by the SC at its February meeting after four of the SDT’s original 13 members left the project. (See Members Seek Clarity on NERC Standard Committee’s Future.)
The expansion will leave the project with 15 team members, including the chair and vice chair. NERC Manager of Standards Development Jordan Mallory explained that ERO staff felt the project needed a full complement because of “the very heavy lift this team has to do.” Also, despite the absence of a deadline imposed by FERC or NERC’s board, Mallory said the cybersecurity issues addressed by the project mean the team will “need to move relatively quickly” to finish the standards. The proposal passed unanimously.
The committee then voted to authorize posting the proposed standard PRC-029-2 (Frequency and voltage ride-through requirements for inverter-based resources) (found on Page 16 of the agenda), the product of Project 2025-05 (Ride-through revisions) for a formal comment and ballot period.
In Order 909, issued in August 2025, FERC directed NERC to modify its standards to account for IBRs equipped with choppers: equipment that protects offshore wind projects during grid faults. FERC ordered NERC to submit the updated standards by August 2026. (See FERC Approves IBR Ride-through Standards.)
Because of the approaching deadline, Manager of Standards Development Alison Oswald explained to the committee, NERC felt it necessary to shorten the normal 45-calendar-day comment period to 30 days. The committee therefore approved a waiver allowing this reduction, along with shortening any additional comment and ballot periods to as few as 20 calendar days and the final ballot period from 10 calendar days to as few as five.
FERC has extended the timeline for the New England transmission owners to refund customers for excess revenues collected after the commission in March set a lower base return on equity with a 2014 effective date (EL11-66, et al.).
The deadline for completing the refunds — originally set for just 30 days after the March 19 ROE order — will now be May 20, 2027.
FERC’s 14-month refund timeline falls in between those proposed by a group of consumer advocates, state agencies and end users and jointly by ISO-NE and the TOs.
The latter sought to push the deadline to December 2027. The RTO argued that “proposed refund schedule represents the fastest timeline under which ISO-NE can calculate and administer the refunds.”
In contrast, the consumer groups argued that FERC should not allow an extension exceeding nine months.
“A limited extension of the refund deadline may be appropriate, but the wholesale 20-month extension requested by the [TOs] and ISO-NE is premature, unsubstantiated and excessive,” they wrote. They argued that ISO-NE and the TOs failed to provide evidence or detail to justify their timeline.
“Given the extraordinary nature of the financial burden endured by New England ratepayers since the commencement of these proceedings, the [TOs] and ISO-NE should make every available effort to issue refunds as soon as practicable,” the consumer groups wrote, arguing that ISO-NE transmission rates are “by far” the highest of any RTO.
They also urged ISO-NE and the TOs to refund customers “on a rolling basis” prior to the deadline, to the extent that this is possible.
TOs already are contesting the refund obligations, which they estimate exceed $1.5 billion. Eversource Energy and Avangrid, the companies with the largest transmission footprints in the region, have asked FERC for a stay on the bulk of the refund obligations. (See New England TOs Seek Stay of ‘Astonishing’ Refund Obligations.)
On April 15, the two companies filed an emergency petition with the D.C. Circuit Court of Appeals with a similar request for a stay on the refund obligations.
“Absent a stay from this court, the order will impose immediate, irreversible financial and operational harm on the [companies] and their customers, harm that cannot be undone even if the order is later vacated,” they wrote.
“Critically, an extension of the refund deadline does not cure these harms,” they added. “Even if FERC were to grant additional time to process refunds, the [companies] would still be required to carry the full retroactive refund obligation on their balance sheets and to plan for its financing.”
PacifiCorp is on schedule to begin trading in CAISO’s Extended Day-Ahead Market on May 1, with the utility now in its final phase of market settlements and simulations testing.
Portland, Ore.-based PacifiCorp, which operates in six Western states, will be EDAM’s first participant, with Portland General Electric following Oct. 1.
The utility’s market simulations in EDAM’s parallel operations testing phase “have gone well overall, and we’ve been working through expected issues in close coordination with CAISO and our technology partners,” PacifiCorp spokesperson Omar Granados told RTO Insider.
“PacifiCorp continues to make steady progress on the systems and process changes needed to join EDAM, including routine software updates across multiple platforms,” Granados said. “A successful launch depends on tight coordination with CAISO and vendor, and we’re executing a sequenced rollout, with updates first at CAISO, then through PacifiCorp systems and outside vendors.”
Parallel operations testing has provided valuable insight into how the new imbalance reserve and reliability capacity products interact with energy supply and influence market prices, Granados said.
“While we continue to work through remaining market software items with CAISO and our vendors, the prices, awards and EDAM transfers we’re seeing are consistent with expectations and reinforce our confidence the market is operating as intended,” Granados said.
A 2024 study showed that PacifiCorp could earn up to $359 million a year in net benefits from participating in EDAM, nearly double a previous estimate. (See Updated EDAM Study Shows Doubling of PacifiCorp Benefits.) The study showed the utility could reduce its adjusted production costs by $53 million under and expanded EDAM footprint while earning an additional $120 million through EDAM congestion and transfer revenues.
Asked whether PacifiCorp thinks those estimated benefits still appear feasible based on the work the utility has been doing over the past few months to join EDAM on May 1, Granados said:
“While the study assumed a larger EDAM footprint than will be in place at go‑live, its key conclusions about the value of day‑ahead coordination remain consistent with what we’re seeing. Parallel operations show that the EDAM can efficiently schedule resources, transmission use and transfers to serve load at the lowest cost to customers. This lines up with the study’s findings on lowering electricity wholesale costs through improved scheduling.”
In January, PacifiCorp said a few challenges remained before the utility could go live in EDAM, including building and testing IT systems, and managing communication testing across numerous transmission customers and 14 neighboring utilities. (See EDAM Implementation Remains CAISO’s Focus in 2026.)
Granados told RTO Insider PacifiCorp has been addressing those challenges.
“We’ve been working closely with CAISO and our vendors to manage IT complexities and prepare for the market go-live, focusing on resolving key items and planning for future improvements,” he said. “Our transmission customers and neighboring utilities have been engaged and collaborative, and the volume of questions reflects solid progress and overall readiness.”
“We’ve also planned for unforeseen challenges by establishing tools and processes with CAISO to respond quickly and adapt as needed,” he added.
WASHINGTON — FERC Chair Laura Swett told the Energy Bar Association she wants to push the commission’s authority as far as she can.
“I know very well from litigating where the absolute edge of precedent is on many topics in our jurisdiction, and I have an appetite to push right up to that edge, if it may secure effective results,” Swett said April 15. “But the other side of that coin is my borderline obsession — it’s not borderline; it’s a full-blown obsession. I’m obsessed with legal durability.”
Swett said her personal goal was to “be one of the most impactful chairmen in FERC history,” especially given the issues facing the regulator now.
“We are at a historic crossroads of some of the biggest issues of our lifetimes when it comes to energy,” Swett said. “And so, I recognize the great responsibility that the commission has right now, over the next few years. Everything has to be very thoughtful and very grounded in the law. I can only accomplish my personal goal if our orders stand the test of time and appeal.”
Working in a democracy means FERC could have a different composition in a few years with different priorities.
“The only thing that I can do is help ensure that the orders that go out under my tenure are as tight and excellent as possible, and that means less susceptible to reversal on appeal,” Swett said. “When we leave out orders; if we don’t address arguments that are raised; if we don’t analyze the evidence, then we are vulnerable.”
Swett did not bring up any specific case regarding maximizing FERC authority, but the concept is at issue in Energy Secretary Chris Wright’s Advance Notice of Proposed Rulemaking, which directed the commission to consider assuming jurisdiction over large loads that connect to the transmission system by April 30. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)
While still fairly new to her current job, Swett has been working in and around FERC for 15 years, beginning as a law clerk at the Office of Enforcement while at Georgetown Law School, then becoming an investigator in the office and eventually an adviser to Chair Kevin McIntyre. In between stints at the agency, she worked in private practice representing all kinds of the entities the commission regulates.
“In the past 15 years, I kept a running list of observations about how FERC is run, how the industry is run and what we can all do better,” she said.
Swett is running FERC at a time when reliability is being challenged by the rapid integration of large loads, most notably — but not exclusively — data centers.
“Confronting the problem of large loads is, in my view, the most important and pressing problem in contemporary American public policy,” Swett said. “We have to ensure that these loads can connect quickly and efficiently, but at the same time, we have to ensure that the costs are allocated fairly.”
The authors of the Federal Power Act in 1935 did not anticipate artificial intelligence and the hyperscale data centers it needs, so now regulators and the industry need to evolve, she said.
“We have to use the precedent that we have and solve a problem that the law never anticipated,” Swett said. “However, the authors of the act did anticipate and understand the paramount importance of reliability.”
Reliability remains core to FERC’s mission, and it does not have to be in tension with integrating large loads, she said.
“There’s a lot of creativity that we’ve seen even in the past six months of my tenure, and stakeholders are committing to confront this problem head on, as are our partners at all levels of the government,” Swett said. “And the developers of organized markets have already proposed a number of creative solutions that FERC has approved.”
