Eversource Energy and Avangrid have asked FERC to pause refund obligations stemming from the commission’s recent order cutting the return on equity for New England transmission owners and requiring the companies to issue extensive refunds (EL11-66, et al.).
The order on March 19 reduced the TOs’ base ROE from 10.57% to 9.57%. It set an Oct. 16, 2014, effective date, which coincides with the previous effective date for the 10.57% base ROE overturned by the D.C. Circuit Court of Appeals. FERC also required the TOs to issue refunds for a 15-month period following the date of the original 2011 petition that triggered the ongoing regulatory proceeding. (See FERC Cuts ‘Ping-ponging’ ROE for New England Transmission Owners.)
In a filing submitted April 2, Eversource and Avangrid estimated that the regionwide refund obligations would total about $1.5 billion, including interest.
“The magnitude of the required refunds is astonishing,” they wrote.
They estimated that the refund obligations would total about $880 million for Eversource and about $203 million for Avangrid. The companies are the two largest TOs by mileage in the region and also own the two largest distribution networks.
They argued that the refund requirements would “cause immediate and irreparable harm” to themselves, their investors and energy consumers. The obligations would hurt the companies’ financial liquidity, cost of capital and stock prices, and would lead to “operational instability, including risks to system planning and investment if funds must be diverted abruptly to pay refunds,” the companies wrote.
Eversource CFO John Moreira said the refund obligation “requires utilities to raise and carry a massive, unplanned financial liability and fundamentally disrupts liquidity, credit metrics, capital planning and investor confidence.”
“Higher borrowing costs and constrained access to capital increase the long-term cost of service and place upward pressure on customer rates,” he said.
The companies argued that processing the refunds while regulatory and legal challenges are underway would create risks of volatility on customers’ electric bills.
“Rather than providing durable customer benefits, immediate refunds followed by later recovery would subject customers to fluctuating charges that are difficult to predict, budget for or understand,” they wrote.
In contrast, state officials and consumer advocates applauded FERC’s ruling as a win for customers.
“This decision makes clear that utilities should not be allowed to make exorbitant profits on the backs of ratepayers, and that those profits should go back in people’s pockets where it belongs,” Massachusetts Gov. Maura Healey (D) said.
The state estimated the refunds would return about $900 million to New England ratepayers.
Massachusetts Attorney General Andrea Joy Campbell said the decision “reflects years of work to challenge excessive transmission profits and deliver meaningful relief.”
Tina Bennett, CEO of PowerOptions, a nonprofit energy-buying consortium, said FERC’s decision to cut the ROE “confirms what we argued all along — that regulated returns must track actual financial conditions, not outdated assumptions.”
While the utilities may appeal, “the broader outcome is clear: ratepayers are better protected,” she said.
Extension Request
In a separate filing on April 2, the New England transmission owners and ISO-NE asked FERC for an extension to the time allowed to complete the refunds.
The commission’s order included just a 30-day period to complete the refunds. The TOs and ISO-NE asked FERC to extend the refund deadline until Dec. 13, 2027, and the deadline for the refund report until Feb. 1, 2028.
They argued that the complicated nature of calculating and issuing the extensive refunds makes the 30-day timeline infeasible.
“The refunds must be processed on three tracks: regional, Schedule 12C and local rates,” they noted. “Each track involves different billing entities, sequencing requirements and reconciliation steps, further compounding the complexity of implementing refunds over such an extended historical period.”
Debbie DiFiore of ISO-NE said in an affidavit that “the proposed refund schedule represents the fastest timeline under which ISO-NE can calculate and administer the refunds, provided that the [New England TOs] submit the necessary information in a timely manner and in the agreed-upon format.”
It was one of those unexpected, revelatory moments ─ when one least expects it, the world stops and reality shifts ever so slightly, never to be quite the same again.
“Electricity is variable.”
The speaker was Romita Biswas, technical lead and adviser for Electrify DC, a home electrification advocacy group, welcoming a roomful of clean tech folks to a distributed energy resources (DER) showcase at the Healthy Homes Fair in Washington, D.C., on March 21. What she was talking about, Biswas told me during a subsequent online interview, are the essential physical characteristics of electricity.
“Electricity is just the movement of free electrons … something that relies on motion,” she said. It is not this smooth, unchanging thing flowing into our home outlets but electrons buzzing back and forth across a narrow, but still variable band of frequencies, all of which we are constantly trying to control.
The electric power industry in the U.S. has been built on the concept that reliable electricity can’t be variable; that any power ─ like solar and wind ─ that is less than 24/7 firm and dispatchable is unreliable and, therefore, less valuable.
But Biswas challenges us to imagine a different kind of electric power system, one that takes advantage of electricity’s inherent variability. “Let’s choose when we consume electricity. Let’s say we want to consume it at a lower price,” she said.
The subtext ─ at least at Healthy Homes ─ was that a system built around variability could provide flexibility and affordability in the production and consumption of electricity, and the technologies to deliver both are available.
K Kaufmann
In January, I wrote a Livewire column predicting 2026 would be the year of flexibility. Three months in, flexibility has become an industry buzz word, but I’m concerned it could be co-opted ─ assimilated into regulatory frameworks ─ amid rising panic about demand growth, high electric bills and the midterm elections.
On the plus side, President Donald Trump’s war in Iran has upended traditional arguments that fossil fuels are the most reliable, secure and cost-effective source of energy ─ for electricity and transportation. Data centers and their appetite for electrons continue to disrupt the regulatory and business frameworks of utilities.
We are past silver bullets and simple solutions. Distributed energy resources ─ especially solar, wind and storage ─ are emerging as smarter options on all counts, and flexibility is the key to optimizing their value and accelerating interconnection.
The focus so far in 2026 has been primarily on data centers and an emerging imperative pretty much everyone agrees on ─ gigawatt-guzzling large loads must pay for or bring their own power. A bit of election-year grandstanding, Trump’s Ratepayer Protection Pledge is an attempt to claim credit for innovations already emerging from data centers, states and utilities themselves.
A new report from Latitude Media notes that 25 utilities across 18 states have developed new rate structures specifically for data centers, 18 of which were filed with or approved by their respective utility commissions in 2024 and 2025.
But ensuring data centers pony up for the power they need is unlikely to provide long-term protection from residential rate increases. In addition to their data center initiatives, investor-owned utilities across the country are increasing their capital spending on new power plants, poles and wires ─ investments they can put into their rate base to justify subsequent requests for rate increases.
(On April 1, Heatmap and the Massachusetts Institute of Technology unveiled their new Electricity Price Hub, a user-friendly website where you can find how much utility bills in any part of the country, down to the ZIP codes, have changed over the past five years. The average bill for my utility, Pepco Maryland, jumped 16.5% over the past year and is up a whopping 60.5% since 2020 ─ and yes, we’re in PJM.)
Mainstreaming Flexibility
Industry efforts to mainstream flexibility within existing frameworks can be seen in the various efforts focused on quantifying large-load curtailment in ways that align with how utilities, grid operators and regulators evaluate different resources; that is, making it something they can deal with.
The Nicholas Institute for Energy, Environment & Sustainability at Duke University kicked off industry discussions on flexibility with its February 2025 report, suggesting that if data centers curtailed their energy use even .25%, they could open up space on the grid for 76 GW of new demand.
Their latest report, issued in March 2026, takes the next step, calling on state regulators to develop official definitions of flexible large loads “based on a set of enforceable curtailment commitments meeting specific technical requirements.”
As spelled out in the report, the four must-have commitments would include:
being voluntary;
being part of the interconnection process, or a condition of retail service;
being long term, to support system planning; and
guaranteeing curtailment across a set of minimum parameters, including the percent of total demand to be curtailed, response times, length of individual curtailments and total hours of availability per year.
For example, to qualify as a flexible large load, a data center might have to commit to curtailing 50% of its total demand within 5 to 10 minutes. Individual curtailments could last up to four hours and be available at least 2% of the time.
Ensuring such commitments are long term and made up front ─ as part of interconnection or retail service ─ would “ensure that [they are] relevant to the assessment of what infrastructure (distribution, transmission and capacity) is necessary,” the report says. “The avoidance of infrastructure needs is what insulates existing customers from affordability and reliability impacts.”
The Electric Power Research Institute uses much the same curtailment parameters in its FlexMOSAIC initiative, unveiled March 23 at CERAWeek in Houston, the fossil fuel industry’s premier annual conference. Aimed at cutting “time to power” for data centers ─ how quickly they can get the power they need to get online ─ EPRI describes FlexM as a “technology‑neutral way to describe and evaluate large load flexibility, based on power system requirements — such as congestion relief, peak reduction, balancing and frequency response.”
The result of cross-industry collaboration ─ with NERC, CAISO, MISO, SPP, NVIDIA, Google and Meta on board, along with a pile of utilities ─ the goal here is “a shared language and transparent performance expectations,” according to a technical overview of the initiative.
A website provides hypothetical examples of the different kinds or combinations of flexibility that might be needed to ensure timely interconnection in the face of rare or frequent “energy scarcity events,” long-duration scarcity events and any grid events requiring fast response.
Of course, quantifying flexibility is essential if it is to be properly valued and compensated. The risk is that utilities, grid operators, and state and federal regulators might appear to support flexibility but set such rigorous requirements or standards that few if any projects would be able to qualify, allowing these gatekeepers to claim flexibility isn’t feasible.
According to the Latitude Media report, none of the data center rates enacted or in the works thus far incorporate flexibility.
Super-smart Plug and Play
More to the point, Trump’s support for data centers bringing their own power assumes the power brought most likely will be large-scale and either nuclear or fossil fueled. When the Department of Energy announced $1.9 billion in funding for transmission upgrades and expansion, any projects that would benefit solar or wind energy were specifically prohibited.
But as was made abundantly clear at the Healthy Homes Fair, flexible, distributed technologies have a vital role to play in boosting grid reliability and affordability and, again, are ready and available.
The big buzz at the event was plug-and-play, smart technologies, like home energy management systems that work with existing electrical panels, so pricey upgrades are not required for installing electric vehicle chargers or induction stoves.
Jane Chen, cofounder and CEO of Stepwise Electric, sees homes and the neighborhood poles and wires that serve them as the electricity system’s “last mile” delivery network and “problem child,” driving peak demand and grid congestion.
The Stepwise Tap, a smart black box | Stepwise Electric
The Stepwise product, called Tap, literally is a black box an electrician connects to an existing electrical panel in a few hours. It monitors and manages the electricity use of appliances and can respond to utility signals at times of high demand.
For example, it can turn down or briefly turn off certain appliances ─ such as an EV charger or heat pump water heater ─ to help ease stress on the grid while keeping the rest of a house operating normally.
Elastic Energy’s ER01 is an even smaller black box that doesn’t even need to be connected to an electric panel and can turn any home or business into a grid asset, according to CEO Ben Hilborn.
The box, which is a router, connects to home equipment ─ via Wi-Fi, Ethernet or LTE-M ─ and enrolls them in any appropriate utility demand management programs so they can use electricity efficiently and cost effectively “in real time, based on real pricing signals,” Hilborn said.
Breaking down the silos between how these assets get compensated “is one of the last true remaining unlocks” to achieving an “equitable grid for everyone,” he said.
In both cases, the black boxes allow for aggregation of distributed technologies and coordination with the local distribution systems.
Adding batteries to home appliances ─ such as Copper’s plug-in induction stoves ─ is another trend aimed at shifting and managing demand. The stoves can operate off grid, storing enough electricity to cook six meals, or 76 grilled cheese sandwiches, in the event of a power outage, according to Joshua Land, the company’s founder and head of strategic partnerships.
‘Get it Done’
The message is that flexibility is itself variable and multidimensional ─ we need it top-down and bottom-up ─ and smart, distributed technologies are the enablers. The challenge ahead is to accelerate commercialization and cut upfront costs. The households that could benefit most from the cost savings that clean, distributed technologies provide are frequently those that can least afford them.
A December 2025 report from Rewiring America argues that beyond bringing their own power, hyperscalers could open up more capacity on the grid ─ enough to meet all their demand growth ─ with strategic funding for home upgrades, such as solar, storage and heat pumps.
As is often the case, Google is leading the industry. On March 20, the company announced it will power a new data center in Michigan with 2.7 GW of solar power, advanced grid technologies and demand flexibility, plus will provide $10 million to fund home weatherization and energy efficiency upgrades in local communities. Another data center it is developing in Minnesota will include $50 million for smaller, distribution-level storage projects, along with 1.9 GW of utility-scale solar, wind and long-duration energy storage.
But beyond funding, we will need to make fundamental changes in utility industry regulation at the state level, said former FERC Commissioner Allison Clements, speaking at Healthy Homes.
The legacy U.S. grid, built out in the 20th century, is no longer “built for purpose” in our 21st-century digital economy, Clements said.
“If ever there was a time to take advantage of DER technology … it is right now,” she said. “We have an opportunity to make these things work, and if we don’t do it right now, we’re not going to get it done.”
Clements called for a new focus on “community power … [that] has the ability to reduce the amount of expensive power that your communities need to purchase, that your utility needs to purchase on your behalf.”
She also rejected the industry’s “technical, wonky, electricity regulatory language. … It hasn’t worked.”
Rather, like Biswas, she challenged people to “think about what it really means to make changes. Don’t accept that just because we’ve been really bad at it for 25 years, that that’s the way it has to be, because it doesn’t.”
Energy policy and regulatory news in 2026 has been all data centers, all the time. A new database shows 77 large load tariffs either in place or being considered at utilities around the United States.
As you might expect, the data center business is booming in places like Texas, Louisiana, California and Ohio. Regulators are scrambling to catch the wave.
Ken Sands
As RTO InsiderISO-NE correspondent Jon Lamson reported recently, even New England is grappling with potential data center expansion because of perceived affordability issues. New England has few data centers in the pipeline, in part because of the region’s high electricity costs. (See Data Center Interest, Opposition on the Rise in New England.)
All of this signifies a big shift in a brief period of time. RTO Insider’s James Downing recently reported that before 2025, most tariffs the Smart Electric Power Alliance tracked were for smaller customers — applying to facilities with demand of 5-10 MW.
As Downing reported: “Most of the tariffs characterize large loads by their size and load factor, but some get more specific and are aimed at specific types of customers, such as data centers or crypto miners. Other changes are designed to require data center projects to provide upfront interconnection deposits meant to weed out speculative projects shopping for the best, cheapest connections to the grid.”
Making Your Voice Heard
What do you make of all this? Are the tariffs an overreaction, an underreaction or an appropriate response? We’d like to hear from you.
We regularly publish opinion pieces in our Stakeholder Forum feature. We ask contributors for around 800 words, on a topic relevant to our RTO/ISO readership. We like to use a photo or a graphic to accompany the op-ed, as well as a mug shot of the writer(s).
Meanwhile, our data center coverage will continue, as we examine these large load tariffs and whatever emerges from stakeholder meetings in the various ISOs and RTOs. Stay tuned.
RENSSELAER, N.Y. — The results of NYISO’s 2024 transitional cluster deliverability study show that more than $1.1 billion of high-voltage transmission upgrades would be required to accommodate 48 projects in the batch of generation projects.
Hundreds of millions of dollars more would be needed to upgrade local transmission across the state’s capacity zones, according to a report presented at a special Operations Committee meeting March 31.
Whether developers will be on the hook for the upgrades is up in the air. NYISO plans to file a proposal with FERC to revise the deliverability study methodology.
This is the first round of the ISO’s ongoing move toward batched interconnection studies. Most of the projects in the batch are solar, storage, and onshore and offshore wind. Stakeholders approved the preliminary results unanimously.
The deliverability test checks to see whether the New York transmission system can accommodate the additional capacity. If necessary, the ISO will determine the cost of system upgrades to make delivery of the new resources’ capacity possible. These upgrades are broken down into “highway,” or high-voltage transmission facilities, and “byways,” lower-voltage localized transmission facilities. The cost of a highway upgrade is divided between transmission owners and developers. Byway upgrades are paid for by developers.
The test determined that projects located in the north and west of the state would all need highway upgrades to deliver their power through the Volney East and Total East interfaces. These upgrades would cost an estimated $1.107 billion, with roughly $88 million going to Volney East and the rest going to Total East.
Twenty-four projects spread across the Lower Hudson Valley, upstate, western and northern New York were determined to need byway upgrades. NYISO estimates these would cost $45 million and would cover the rebuilds of nine facilities.
Six of the 12 projects located in New York City would require byway upgrades across two local transmission facilities. NYISO estimates these upgrades would cost $619 million, of which $618 million would go to a new phased array relay control line from Fresh Kills on Staten Island to Rockaway Beach, Queens. Two new shunt reactors on Fresh Kills would also be required.
Six of the 13 projects on Long Island would require byway upgrades to be deliverable. These would be spread across three transmission facilities and cost roughly $419 million. The most expensive upgrade would be a new phased array relay between Brookhaven and Smithfield, with additional transmission upgrades in Holbrook, costing more than $334 million.
Of the more than 200 projects that initially joined the 2024 transitional cluster study, only 92 remain, and 89 are requesting energy resource interconnection service and capacity resource interconnection service (CRIS). The remaining three projects only requested CRIS.
Stakeholders questioned some of the parameters of the study, asking whether the ISO was testing for an extreme load case that “might never happen.” Zach Smith, vice president of system and resource planning for NYISO, said those requirements would be likely be changed before the end of the cluster study.
“Assuming the board approves, we’ll be filing with FERC for that revised methodology,” Smith said. He explained that the changes would be in effect before the cluster study concludes, assuming FERC responds within its required 60-day window. “We have to follow the current tariff for now, and that’s the purpose of today’s presentation.”
Wenjin Yan, manager of generation integration, explained there would not be an additional draft of the deliverability study forthcoming because under the new methodology many of the upgrades were unnecessary. Those that remained “completely overlapped” with upgrades identified in this study.
Data in the appendix of NYISO’s presentation demonstrated that the new deliverability study methodology would dramatically cut the number of upgrades needed. Specific cost estimates were not provided, but the results showed far fewer violations on Central East and Volney East.
The Bonneville Power Administration’s draft decision “solidifying” its day-ahead market choice in favor of SPP’s Markets+ has reignited a yearslong debate over the agency’s direction.
Advocacy organizations, public and investor-owned utilities, data center developers and attorneys general, among others, submitted comments before an April 3 deadline following BPA’s announcement that it is “solidifying its path” to join Markets+.
BPA’s March 12 draft decision differs from the agency’s day-ahead market policy and record of decision (ROD) it issued in 2025 in favor of Markets+ over CAISO’s Extended Day-Ahead Market, according to the agency. The earlier policies were “a direction toward participation in Markets+” when the market was still in a “conceptual stage,” BPA staff said during a March 12 workshop discussing the decision. (See BPA Releases Draft Decision Solidifying Markets+ Choice and BPA Chooses Markets+ over EDAM.)
Recent Markets+ developments have “allowed the agency to advance implementation planning efforts and further evaluate readiness requirements,” BPA Administrator John Hairston wrote in a letter accompanying the draft decision.
One key factor in BPA’s decision to opt for Markets+ over EDAM was market governance. Specifically, BPA argued Markets+ offers independent governance, whereas EDAM risked falling under the influence of stakeholders in California.
In response, EDAM proponents have pointed to the impact of the West-Wide Governance Pathways Initiative and California Assembly Bill 825 of 2025, which together allow CAISO to shift governance of EDAM and the ISO’s Western Energy Imbalance Market to a Regional Organization for Western Energy (ROWE). (See ROWE Close to Finalizing Board Selection Process.)
ROWE was incorporated in Delaware in February.
Some see the ROWE as a means to alleviate concerns among potential market participants that CAISO, whose governing board is appointed by the California governor, plays too large a role in the markets’ governance.
On April 3, Renewable Northwest (RNW), Portland General Electric and the attorneys general of Oregon and Washington said in separate comments that BPA should revisit its governance analysis in light of the establishment of ROWE.
For example, RNW asked BPA to explain how AB 825 and ROWE factored into the agency’s decision.
Those concerns were shared by data center developers in the Northwest.
In a joint letter, Google, Amazon, Microsoft, the Corporate Energy Buyers Association and Western Freedom said that “the record should reflect enacted legislation and implemented governance structures, rather than proposals that were still under development at the time.”
“Maintaining an out-of-date record while introducing this additional final proposed decision is unnecessary,” the large customers said in reference to Pathways and ROWE.
Microsoft, Amazon and Google operate data centers in Oregon and Washington. The companies, along with Western Freedom and the Corporate Energy Buyers Association, voiced concern over BPA’s draft day-ahead market decision. | Yes Energy
Western Freedom’s CEO Kathleen Staks also is co-chair of Pathways’ Launch Committee and is ROWE’s interim president.
RNW contended BPA has reaped between $26 million and $36 million in benefits since 2022 from participating in the WEIM and asked for more information on how moving to bilateral trading will impact electricity prices and reliability.
RNW’s concerns were shared by the large load customers. The customers also noted that BPA has experienced recent staffing cuts under President Donald Trump. (See BPA Looks to Fill 155 Positions After Hiring Freeze.)
“Bonneville’s departure from the WEIM is a significant change in operations for the West, and it’s one that is not simple to unwind,” the customers wrote. “Any new market may face unforeseen delays pushing that further. While staffing constraints may factor into capacity to participate, stakeholders need a clearer picture of the tradeoffs and alternatives.”
No ‘New Factual Findings’
In its comments, Earthjustice, the lead plaintiff in a suit challenging BPA’s May 2025 ROD in the U.S. 9th Circuit Court of Appeals, contended that the draft decision offered nothing new of substance regarding the “policy direction” BPA outlined in the ROD. (See Nonprofits Tell 9th Circuit BPA’s Day-Ahead Market Decision Poses ‘Imminent’ Harm.)
“While titled the ‘decision to join Markets+,’ Bonneville’s [proposed] decision does not amend or otherwise change its May 9, 2025, final day-ahead market policy and ROD, nor does it affect the finality of that decision,” the organization wrote, characterizing the proposed decision as “no more than the next step on the path to implementing” the decision already made a year ago.
“Bonneville is not making any new factual findings to support its decision to participate in Markets+,” Earthjustice said. “Put simply, Bonneville is no longer considering the economic benefits and drawbacks and environmental consequences of day-ahead market participation, nor is Bonneville considering market alternatives such as participating in the EDAM.”
Earthjustice also cautioned BPA not to withdraw from the WEIM in October 2027, ahead of the winter heating season.
“While Bonneville states it needs to depart the WEIM a year prior to joining Markets+, to provide the agency the opportunity to gain experience in ‘Markets+ mechanics,’ Bonneville has not presented any data reflecting the cost to customers from this early departure,” the group wrote.
Markets+ Supporters Urge BPA to ‘Finalize’ Choice
In its comments, the Public Power Council said there have been no major changes since BPA issued its initial day-ahead market decision in May 2025 that would justify the agency changing course.
Markets+ has continued to develop with entities preparing to join in October 2027, PPC wrote, adding “this additional certainty created by the regional entities’ commitments to participate in Markets+ should only strengthen BPA’s decision.” PPC noted that while EDAM has evolved “in parallel with Markets+,” CAISO’s offering “ultimately does not meet the requirements set forth by BPA and its customers.”
ROWE is still linked to CAISO and concerns remain about whether the organization will be fully “financially independent,” PPC argued.
“With no changes to CAISO statutory obligations, the relationship between CAISO and the ROWE does not meet PPC’s expectations of independence,” PPC wrote. “Thus, the creation of the ROWE does not change any of BPA’s analysis related to the governance structures of the two market offerings.”
Meanwhile, Powerex, which is set to join Markets+ on Oct. 1, 2027, added its support for BPA’s participation in SPP’s market and urged the agency to “finalize this decision.”
“BPA’s power customers need certainty to prepare for their market-related roles and responsibilities under the Provider of Choice contracts, and its transmission customers need to work with BPA on representing their BPA transmission rights in Markets+,” Powerex wrote. “BPA’s plan to align its go-live with the BP-29 rate period and initial Provider of Choice deliveries is sound, but the benefits of that alignment depend on BPA’s firm and durable commitment to Markets+, together with timely implementation.”
Snohomish County PUD, Tacoma Power, the Alliance of Western Energy Consumers (AWEC) and Northwest Requirements Utilities (NRU) argued BPA had provided sufficient justification to pursue Markets+, saying the agency should finalize its choice.
“The decision is grounded in thorough, objective analysis; it is aligned with the positions NRU has advocated for consistently throughout this process; and it provides the governance independence, economic benefits and environmental attribute protections that NRU’s members require,” NRU wrote in comments.
On the issue of WEIM, AWEC said the exit from the market is necessary “to transition to a new reliability coordinator, to amend its Provider of Choice contracts with its customers, and to engage in rate and tariff proceedings to fully implement the agency’s decision. AWEC is confident that BPA will work through these issues in lockstep with customers and stakeholders.”
ERCOT staff say they are about to transfer work on the transitional batch study process to streamline the interconnection of large loads, as most of the rule is laid out in a Planning Guide revision request.
“That is the appropriate stakeholder body that that will vote on [the rule]” before it goes to the Technical Advisory Committee, ERCOT’s Jeff Billo, vice president of interconnection and grid analysis, told the Public Utility Commission during its April 2 open meeting.
ROS has scheduled two special meetings in April to consider the rule before sending it up to TAC. That key stakeholder body has scheduled meetings May 13 and May 19-20 so it can move the rule to the ERCOT board for its June 1-2 meeting.
ERCOT has incorporated stakeholder comments in the revision request in question (PGRR145). It establishes the transitional Batch Zero that staff will use to evaluate large loads’ reliability effects on a systemwide basis. PGRR145 transitions large load interconnections from individual studies to a cluster-based approach that allocates available transmission capacity for studied and committed large loads.
The change was created by forklifting PUC staff’s proposal establishing interconnection standards for large load customers. They commended large load customers execute an intermediate agreement that makes certain disclosures before their inclusion in an interconnection study and to post $50,000/MW in financial security (58481). (See Texas PUC Proposes Large Load Interconnection Standards.)
“We are continuing to refine this as we go, as we take feedback from the comments and through the workshops,” Billo said.
He said staff plan more filings on April 8 for controllable-load resources (CLR) and bring-your-own generation (BYOG) concepts. Billo said a load-only CLR rule change, excluding batteries for the time being, can be included with Batch Zero. It would allow loads to commit to being CLR in return for being allocated their full megawatts, even though their full request may not be available immediately.
“Stakeholders have proposed a lot of interesting ideas. I would even say ERCOT is excited about some of the ideas,” Billo said.
The BYOG concept staff are most optimistic about, he said, is self-limiting facilities. Loads bringing generation would be studied to determine how much load they can pull from the system at a time. The burden would be on the load centers not to pull more than they are allowed to.
Assuming board and PUC approval of PGRR145 and other changes, the 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.
Rule for T&Ds’ ESR Capacity
The PUC proposes a rule change that would allow transmission and distribution utilities to contract with generation companies for energy storage capacity to ensure reliability for distribution customers. The rule also would establish how T&D utilities would recover the contracts’ cost and the generation companies’ responsibilities (59523).
The commissioners asked for stakeholder feedback during the comment period on whether a utility’s cost recovery should be limited to comprehensive base-rate cases or also be permitted in interim proceedings. They also asked for input on whether contracts should satisfy relevant accounting standards for a capital lease or finance lease or whether the criteria be required only if a utility seeks recovery, plus a reasonable return under the contract.
In other proceedings, the PUC:
Approved in part and rejected in part El Paso Electric’s request to build and operate a 100-MW solar facility and a 100-MW storage system at its Newman Power Station. The commissioners revised an administrative law judge’s decision by adding a production guarantee for the solar facility to “help ensure ratepayers see the full benefits of that facility, given its functional limitations” (57501).
Remanded back to docket management a proposed order approving Texas-New Mexico Power’s acquisition of a privately owned 138-kV transmission line and an associated substation in West Texas. The commissioners asked TNMP to amend the application to include whether or not ERCOT endorses the project (58416).
Consented to EPE’s request for a $1.26 billion rate hike but lowering the utility’s requested 10.7% return on equity to 9.35 to 9.4% after four years (57568).
The Western Energy Imbalance Market’s Intermountain West region saw its hourly exports increase by an average of 780% — or 680 MW — in Q4 2025 versus the same period a year earlier.
The region shifted from being a net importer in most hours of Q4 2024 to a net exporter in all hours of Q4 2025, DMM said in a March 30 market issues and performance report.
Wind, solar and hydropower generation increased significantly in the region, up 170 MW (30%), 740 MW (38%) and 120 MW (8%) year-over-year, respectively. Load decreased by about 1.8%. The primary resources in the Intermountain West continue to be coal and natural gas.
California experienced the opposite trend. The state imported a more significant amount of electricity in Q4 2025 compared with Q4 2024, with net imports increasing by about 32%, or 1.13 GW.
California’s imports increased during the morning hours — i.e., when solar generators are starting up and batteries are often waiting to charge. Solar generation, along with battery charging, started around 8 a.m. – leaving demand in the early morning hours to be met by imports, according to DMM’s report.
In the rest of the West, exports increased in Q4 2025 versus Q4 2024. The Desert Southwest saw its net imports decrease by about 33%, or about 350 MW. Most of this reduction happened during the evening and when battery storage discharge increased. Natural gas continued to be the largest source of generation in the Desert Southwest, but battery storage and solar generation increased significantly, DMM said.
Hydroelectric generation in the Pacific Northwest accounted for about 70% of total generation, increasing by about 1,270 MW, or 8%, in each hour from Q4 2025 to Q4 2024. Net imports and natural gas generation decreased across all hours, DMM said.
In total, net interchange after dynamic transfers increased in California by approximately 1,130 MW and decreased in the Desert Southwest by about 240 MW, Intermountain West by about 920 MW, and Pacific Northwest by about 690 MW, the report says.
DMM also found the congestion impact on price separation between WEIM areas was lower than a year earlier. Pacific Northwest balancing areas experienced more frequent price separation than other market regions, being transferred-constrained for about 18% of market intervals in the import direction and 16% of intervals in the export direction.
The Everett Marine Terminal (EMT) will be needed to preserve the reliability of the Boston-area gas system beyond the 2030 expiration date of the facility’s current utility contracts, gas companies told regulators in recent filings.
The LNG import facility, owned by Constellation and located just north of Boston, is strategically placed to alleviate low-pressure issues at the end of the pipeline network. It has direct injection capabilities and serves as a hub for the sendout of LNG trucks to satellite facilities.
It is under contract with Massachusetts gas utilities until the end of May 2030. The contracts took effect in 2024 following the retirement of the Mystic Generating Station, its anchor customer. In its approvals of the contracts, the Department of Public Utilities required the utilities to work to reduce their reliance on Everett and file annual reports on their efforts.
“EMT remains a critical reliability asset for Massachusetts LDCs,” Eversource wrote in its filing on April 1. “Even under aggressive assumptions regarding demand reduction and alternative infrastructure development, EMT continues to play a critical role in supporting design-winter, design-day and design-hour reliability, emergency response planning, and prolonged cold-weather operations.”
Since 2024, the Office of Energy Transformation has convened a working group intended to analyze and facilitate a transition away from Everett. The working group’s analysis indicates that “eliminating reliance on EMT for all LDCs by the end of the current contract term is not feasible,” National Grid wrote.
Another round of contracts could prove costly for ratepayers. The facility is not operating under a cost-of-service agreement, and advocates have expressed concern there is no clear limit to what Constellation could charge to keep EMT open beyond 2030. (See Conflict Brewing over Gas Transition in Massachusetts.)
In the 2024 regulatory proceedings, the Brattle Group on behalf of the Attorney General’s Office estimated the contracts would cost a combined $946 million over their lifespan. (See Everett LNG Contracts Face Skepticism in DPU Proceedings.)
The utility contracts include fixed-cost charges, LNG procurement charges and options to buy certain amounts of LNG supply. For the state’s major gas utilities, National Grid and Eversource Energy, the amount of LNG the companies are allowed to purchase increases over the span of the contracts.
The companies said a combination of supply-side and demand-side actions could help reduce reliance on Everett. These could include agreements with other LNG facilities, the addition of LNG vaporization facilities and pipeline expansion, demand reduction and electrification.
National Grid wrote the working group’s analysis “has consistently found that demand-side strategies represent the most scalable and durable pathway for achieving sustained reductions in EMT reliance.”
Demand-side solutions should be focused on providing “measurable peak-load relief in EMT-constrained areas, rather than pursuing reductions that are beneficial in aggregate but do not affect EMT-driven peaks,” the company said.
The filings also raised questions about cost shifting if one of the utilities can eliminate reliance on Everett. Eversource has signed agreements associated with an Enbridge project to expand the Algonquin gas pipeline system, which could eliminate the reliance of one of its service territories on the facility.
As Eversource cuts its reliance, “a greater share of certain of EMT’s fixed costs may be borne by the remaining contracting LDCs [local distribution companies],” National Grid wrote.
The Algonquin expansion project “may have the effect of shifting relative EMT cost responsibility rather than reducing systemwide EMT fixed costs,” it added.
It noted the working group’s analysis found “that cost mitigation for one set of LDC customers can result in increased cost exposure for others, given the absence of a regional cost-sharing mechanism for EMT and the limited jurisdiction of state and federal regulators over EMT pricing and operations.”
The Public Utilities Commission of Nevada voted April 3 to approve NV Energy’s application to join CAISO’s Extended Day-Ahead Market — a move some stakeholders view as a pivotal moment for Western electricity markets.
“I do view this order as a very important step for NV Energy and our state,” Commission Tammy Cordova said.
Cordova had proposed changes to the draft order, which she described as mainly wordsmithing, but she was outvoted on the proposed amendments.
Stacey Crowley, vice president of CAISO external affairs, provided a statement acknowledging the PUCN vote.
“CAISO appreciates the careful consideration of regional collaboration and looks forward to continued coordination with NV Energy, regulators and stakeholders as EDAM implementation efforts advance,” Crowley said.
CAISO and NV Energy will now work together on an EDAM implementation agreement.
NV Energy said it is reviewing the PUCN order.
“Extensive analysis” has shown that EDAM participation can potentially save customers tens of millions of dollars a year, the company said in an emailed statement.
“NV Energy remains committed to ensuring that any market participation delivers measurable cost savings and supports a reliable and resilient electric system for Nevada,” the company said.
EDAM Launching May 1
EDAM is to launch May 1 with PacifiCorp as its first participant. It will be followed by Portland General Electric in October 2026; Balancing Authority of Northern California, Los Angeles Department of Water and Power, Public Service Company of New Mexico and Turlock Irrigation District in 2027; and Imperial Irrigation District in 2028.
Brian Turner, senior director with Advanced Energy United, described Nevada as “a critical hub connecting the Northwest, Southwest, and Interior West.”
“The state’s participation in EDAM will allow power to be seamlessly shared across these regions … boosting reliability, lowering costs and making the most out of the West’s naturally abundant resources,” Turner said in a statement.
The PUCN decision comes at a critical time, Turner added, as the West remains split between two competing day-ahead markets. SPP plans to launch its Markets+ day-ahead offering in October 2027.
“Nevada’s move signals strong support for EDAM as the region’s most expansive day-ahead market, and helps move the West towards the broadest footprint, supporting a reliable and affordable grid,” he said.
Idaho Power and PowerWatch (formerly BHE Montana) have said they are leaning toward EDAM. But energy officials in Idaho, as well as in Utah and Wyoming, voiced concerns in March about ROWE’s data-sharing practices, saying failure to provide full access to data and market information risks infringing on states’ rights and undermining public confidence. (See ROWE’s Bylaws Must Ensure Market Data Transparency, States Say.)
Governance Transition
NV Energy filed its request to join EDAM on Oct. 22 as an amendment to its 2025-2027 Energy Supply Plan. (See NV Energy Files Request to Join EDAM.)
In approving the request, PUCN listed factors including NV Energy’s successful participation in CAISO’s Western Energy Imbalance Market (WEIM), its transmission connectivity with other EDAM participants and diverse energy resources available through EDAM.
Some parties in the proceeding raised questions about the independence of EDAM’s governance. (See EDAM Governance Questioned During NV Energy Hearing.) Under Step 2 of the West-Wide Governance Pathways Initiative, governance of EDAM and the WEIM is expected to be transferred to a Regional Organization for Western Energy (ROWE).
“The commission anticipates that Pathways Step 2 will further increase independent oversight,” the commission said in its order.
Some of Cordova’s proposed wording changes, which the commission rejected, were related to EDAM governance.
Although the commission’s approved order lists “CAISO’s governance structure” as a factor supporting NV Energy’s EDAM entry, Cordova had proposed removing that phrase.
The approved order says, “the Pathways Initiative has begun the process to establish the ROWE board and [the commission] finds this board will provide independent regional governance of EDAM and will enhance transparency and fairness for market participants.” Cordova had proposed saying the ROWE board “has the potential to” provide independent regional governance.
Conditions of Approval
As part of the order, the commission approved a $16.15 million budget for NV Energy’s initial EDAM implementation and a $16.52 million annual participation budget. Commission approval would be needed for any costs above those amounts. The costs will be split evenly between NV Energy subsidiaries: Nevada Power Co. and Sierra Pacific Power in the southern and northern Nevada, respectively.
Under the order, NV Energy must develop a way to measure annual adjusted production cost savings from EDAM participation. The order requires the company to file reports on the progress of its stakeholder process for revisions to its Open Access Transmission Tariff.
The order also notes that if NV Energy incurs surcharges for not meeting EDAM’s daily resource sufficiency evaluation, those costs will be paid by shareholders.
Nevada requires NV Energy to receive PUC approval to join an organized energy market. Utility regulators in some other states play more of an advisory role in market decisions.
Speaking at the Texas Reliability Entity’s Spring Standards, Security and Reliability Workshop, NERC compliance expert Brent Castagnetto told utilities security breaches are inevitable if they do not “elevate” their focus on the ERO’s Critical Infrastructure Protection standards beyond the regular audit cycle.
Castagnetto is co-founder of NovaSync, a provider of compliance tools focused on the CIP standards, who joined the workshop to discuss what he called the “CIP drip” phenomenon. He said the name came from a conversation a year earlier with Nick Santora, NovaSync’s vice president of growth and his co-presenter at the workshop.
“We were lamenting the fact that we both own homes, and homes often come with unique sets of problems depending on where you live,” Castagnetto said. “They could be external [or] internal; they could be the fact that you bought a crappy old house like I did and then fixed it up, or you could have challenges with buying a new home and shoddy craftsmanship. Whether you rent or own, it is likely that you’ve experienced a challenging issue, or a drip or a leak with your own home.”
Castagnetto said he and his company have seen the same kind of problem in many organizations’ CIP compliance programs. These processes usually are set up with good intentions, he said, but it’s impossible to anticipate every shortcoming ahead of time, and entities must actively check to see if issues are developing that need to be addressed.
“If we leave [these drips] unattended, and we have a leak that’s going through our foundation, that can lead to all kinds of problems, right? If we don’t address issues with our roof, we’re likely going to see some risk exposure there,” Castagnetto said. “The same thing applies when we look at audits that happen on a periodic basis, whether you’re on a three- or six-year cycle. … Is that good enough? No, you’re likely experiencing drips along the way that you have to address in a more meaningful and practical way.”
Castagnetto and Santora discussed some of the problems they have discovered that were developing without their clients’ knowledge. These fell into several categories, the first of which was issues having to do with employees, whom Santora quipped are likely to remain “a pretty big problem to solve … until the robots take over.”
Santora observed that any registered entity contains many people involved in CIP compliance, and keeping their understanding of the standards and their responsibilities up to date is an urgent requirement. He described the best training programs as a “two-way street, a push and a pull,” in which — rather than providing training and ordering employees to complete it — leadership engages with employees to learn what they are unsure about and what processes need updating.
The discussion of CIP training prompted Castagnetto to turn to the next topic, processes, which he called “critically important” but misunderstood by utilities who design their compliance processes as “calendar events and reminders that cue to do an activity or perform something.” He said this approach is less effective than one that focuses on “connecting the dots from the technology that we’re using to the people that are working in the process.”
“If you’re stuck in this mode where you’re using Outlook and calendar reminders to ensure that the … steps [are] undertaken to accomplish a specific task, it’s not going to work long-term for you,” he said. “Heaven forbid Outlook goes down … or that [responsible] person leaves, and now we’re just moving the calendar to somebody else. We’re passing the buck. You don’t want to find yourself in that situation.”
Entities also must understand that CIP compliance by itself is not enough to ensure the organization’s safety in the face of determined security threats, Castagnetto warned. He cited the case of Christina Chapman, an Arizona woman sentenced in 2025 to 8.5 years in federal prison for helping North Korean information technology workers obtain remote positions at more than 300 U.S. companies.
Chapman operated what authorities called a “laptop farm” at her home, storing more than 90 computers from the companies she fooled, as well as shipping devices to overseas locations. The North Korean employees used the “stolen or borrowed” identities of actual U.S. individuals to fool the IRS. While authorities eventually caught up with the scheme, it still generated more than $17 million in revenue for Chapman and North Korea. Castagnetto said the story shows that utilities cannot count on CIP compliance alone to protect them.
“There’s nothing in [the CIP standards] that says you have to go and verify these people, but we have to figure out a solution to it, because it can happen to us, and we don’t want to have that,” Castagnetto said.
