SPP has made it official: The operator of the sprawling Midwestern grid technically is in the Western Interconnection.
That means it has office space in downtown Denver that includes a sizeable meeting room, a break room and several offices with three workspaces. That allows SPP to boast a “physical presence” in the West, as one staffer said.
In April, it’s scheduled to become operational. That’s when the grid operator’s 14-state footprint will increase by three. Utilities from Arizona, Colorado and Utah will place their facilities under SPP’s tariff. It will make the grid operator the first to provide full market services in the U.S. system’s two major interconnections, thanks partly to three DC interties totaling 510 MW.
The expansion comes little more than a year after FERC approved an amended tariff that adds the western members to the RTO and drew praise from several commissioners. Judy Chang said the approval is “another major milestone for the market evolution in the Western part of the U.S.” (See FERC Approves Tariff for SPP RTO West.)
All seven members of RTO Expansion — as SPP refers to its new market on the other side of the Rockies — currently participate in SPP’s Western Energy Imbalance Service market; four of them (Basin Electric Power Cooperative, Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, and the Western Area Power Administration’s Upper Great Plains-East Region) are members of the legacy RTO in the East.
A 2022 Brattle Group study for SPP determined the expansion will produce between $68 million and $81 million in annual Westside adjusted production cost benefits and wheeling revenue. Eastside members will see between $3 million and $8 million of those benefits.
SPP says it will decide Feb. 2 whether to launch the market April 1 as planned.
“Right now, everything seems to be on track,” CEO Lanny Nickell told his board in November.” We’re looking forward to working with our new members in the West.”
The RTO expansion has been somewhat overshadowed by the noise surrounding SPP’s Markets+ day-ahead offering, which is providing Western utilities an alternative to CAISO’s Extended Day-Ahead Market.
The grid operator’s staff and Markets+ stakeholders are well into the initiative’s second phase, working together to build the market’s operating systems and conduct market trials and parallel operations. SPP says 41 entities have committed to covering the market’s $150 million in development expense; the costs will be recovered through future operations. (See SPP Markets+ Cruising Through Early Development.)
Interested market participants have until April 1 to register. They will have about 45 days to complete their registration workbook.
Arizona Public Service, Powerex, Public Service Company of Colorado, Salt River Project (SRP) and Tucson Electric Power are moving forward as balancing authorities. The Bonneville Power Administration will join the secondary market launch in October 2028, along with four other Pacific Northwest BAs.
SPP is targeting October 2027 as the Markets+ go-live date. When the Northwest BAs join in 2028, it will consist primarily of the Pacific Northwest, Desert Southwest and along the Rockies.
The series of complicated seams that will result have caught the attention of FERC, which has asked Western stakeholders to get ahead of seams issues before the markets launch. SPP, experienced in managing seams with MISO, ERCOT and WECC, is hosting a Western Seams Symposium open to western stakeholders at SRP’s Tempe, Ariz., headquarters Feb. 26. (See FERC Report Urges West to Address Looming Market Seams Issues.)
SPP’s western expansion effort is just one of its three overarching goals. The others are accelerating its generator and large load interconnection processes and mitigating its resource adequacy risk.
The grid operator will begin transitioning in 2026 to its Consolidated Planning Process, which combines its transmission planning and GI studies into a three-year process that aligns system modeling, planning assumptions and cost allocation across load and generation needs. The CPP’s “ready-to-go” construct replaces the current “request-then-analysis” framework by identifying system needs and costs before the generator asks to connect. (See SPP ‘Blazes Trail’ with Consolidated Planning Process.)
A transition study is underway and will result in a 20-year assessment in November 2026. The 2027 study will sunset the current process and integrate RTOE transmission needs before the first full CPP 10-year assessment in 2028.
The studies will be run in parallel with a strategic partnership announced during the summer between SPP and global tech giant Hitachi. The two organizations are collaborating to accelerate the GI process by reducing study times 80% through end-to-end industrial AI and advanced computing infrastructure. (See SPP, Hitachi Partner to Use AI in Clearing GI Queue.)
Several other 765-kV projects were set aside as SPP, like other grid operators, prepares for a future projected to be dominated by data centers, crypto miners and industrial electrification. A more recent Brattle Group study found the RTO will require at least $88 billion and up to $263 billion of generation investment to support load growth through 2050. (See SPP Study: $88-263B in Generation Needed by 2050.)
Naturally, affordability is a concern for regulators and other stakeholders. SPP has created the Cost Control and Allocation Review and Evaluation (CARE) Team, a cross-functional leadership body to review and recommend refinements or alternatives to the current transmission cost controls and cost-allocation methodologies. The team met once in December 2025 and took a deep dive into SPP’s various cost mechanisms; it has set a meeting schedule that lasts into November 2026.
“As I’ve been saying now for five years, PJM is heading for a reliability crisis, and now we’re there,” former FERC Chair Mark Christie said in an interview. “It’s no longer over the horizon. It’s right on the street with us, and the latest capacity auction results just drive home how bad the crisis is, when they fall short 6 GW of meeting the reliability requirement.” (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)
The primary driver for that crisis is the demand from new data centers, which has so far not been met with new generation to match it, he added.
“Really the problem is financing more than anything else,” Christie said. “We’re not getting large baseload generation built. We’re not getting combined cycle gas, which is the baseload generator of choice.”
Coal plants are not feasible at this point, and nuclear is not going to be ready at scale in time to meet the demand from data centers plugging into the grid soon, Christie said. Wind and solar, which dominate the queue, add much needed electricity to the grid, but they cannot be counted on to serve demand from data centers that want 99.999% reliable power, he said.
Christie’s home state of Virginia is a major contributor to the issue because it is home to the largest data center market in the world, Data Center Alley, and has contributed to the demand growth recently by plugging in new facilities that are ultimately served by imports from elsewhere in PJM.
“The Dominion zone was a big contributor to the deficit,” he added. “And we’re going to see whether the new governor and the new legislature are going to take action to try to get large baseload generation built.”
The supplies being added to the grid are either wind and solar or combustion turbines, and Christie is skeptical that the market on its own can add new baseload plants.
“I don’t know how high prices have to go to get large baseload generation built, but politically, you’re already getting a huge backlash because we’ve hit three all-time highs in the capacity market,” Christie said. “And we’re not getting large baseload generation announced.”
Virginia is one of the vertically integrated states in PJM, which means its political establishment needs to support the construction of new baseload, Christie argued.
“When I was on the Virginia commission, we approved four combined cycle natural gas generation units for Dominion, and every one of them got built,” Christie said. “Every one of them was ratebased, but the political leadership was supportive.”
PJM sits on top of huge supplies of natural gas in the Marcellus and Utica shale fields, which could power a new wave of combined cycle units.
“In the deregulated states, where they do not allow utilities to own generation, the question becomes: Who is going to build the large new combined cycle gas?” Christie said. “Are the [independent power producers] going to build it? We haven’t seen announcements of that.”
The Paradise Combined Cycle Plant in Drakesboro, Ky. | TVA
When states restructured their industries a quarter-century ago, PJM had excess supply, and the generators in those states were forced to sink or swim in the market, Christie recalled. Many sank, and it brought the reserve margins down for demand growth to return in a way no one expected.
“Now we’re in a perfect storm that, frankly, at the beginning of capacity market 20 years ago, nobody saw,” Christie said. “Nobody saw the explosion of demand coming from data centers 20 years ago.”
The capacity market was put in place at a time of wide reserve margins and slow, steady load growth. Ultimately, Christie thinks the states will have to address the issue on both sides of the supply and demand equation.
“The answer is really at the state level, not FERC,” Christie said. “The states have to deal with the demand side, with how they interconnect these large new data centers, and the states have got to deal with the supply side and getting generation built.”
Will the Market Respond?
Electric Power Supply Association CEO Todd Snitchler said the market will respond because PJM has now had three capacity auctions in the past year that have cleared at high prices.
“We’ve seen almost 12,000 MW of new generation that’s expected to be added to the PJM grid between now and roughly 2030,” he said.
EPSA and a fellow IPP trade group, the PJM Power Providers, created a chart showing all the projects, including uprates and new builds, that have been committed to serve load in the market. They argued that market participants should continue responding to the higher market prices seen in the last auctions, even though they have been muted by a cap that the RTO agreed to after a complaint from Pennsylvania Gov. Josh Shaprio (D). (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)
“I think the compressed timeline of the auction has made it appear that the market is slower to respond,” Snitchler said. “But you know, you don’t drop a $2.5 [billion] or $3 billion investment in six months, or even maybe 12 months. And so, I think you’re going to see people who have had some time to digest the auction results lead to outcomes that are going to include that new generation that everyone wants to see.”
Before the July 2024 auction, the previous three cleared at low prices that were effectively signaling generators to retire just before the issue of meeting demands from new large loads like data centers started to become a reality, Snitchler said.
“As you see real load growth for the first time, really in probably 30 years, it’s triggering a response, and that response takes a little time to develop,” Snitchler said. “You’re already starting to see where there is incremental investment and new investment being made in PJM, but also in other parts of the country.”
The issue of rapidly rising demand leading to narrowing reserve margins is not unique to restructured markets, with vertically integrated states in MISO and SPP facing the same issues, he noted.
“It’s really a systemic issue that we’re all trying to address and resolve because everybody wants to make sure that we ensure, first and foremost, a reliable system that is also cost-effective and affordable,” Snitchler said. “I mean, if those two tenets aren’t met, then the rest of this is academic. We have to be sure that we’re meeting those two objectives.”
The load growth the industry is facing is different from that of the past, which was driven by economic and population growth. The new large loads are clustering in specific submarkets like Arizona, central Ohio and Loudoun County, Va.
Data centers might have plans to ultimately consume the same amount of power as a major city, but generally they do not immediately plug into the grid seeking to consume a gigawatt.
“There’s a construction ramp where they start from zero, and then you have that first tranche where you need to power it up,” Snitchler said. “Then they add the next phase until they’re finally complete.”
That gives the industry some time to respond to the load forecasts, which Snitchler argued are overstating future demand. While the power sector has limited supply chains for components like combustion turbines, the tech industry has a limited capacity to build the advanced chips needed for artificial intelligence-related data centers springing up around the world.
“If you look at the number of chips that are available from Nvidia and the fact that they’re sold out for the next couple of years, and there’s only 60 GW of new energy demand from those chips globally, [and] if you look at what is being projected in PJM and Texas, it would require every chip that Nvidia is going to sell for the next two years and more, and that’s not how that’s going to work.”
Utilities have also issued optimistic load forecasts that reflect plans for data centers that are not going to be built, Snitchler argued. When AEP Ohio put in place a new tariff for large load customers, it saw a pipeline of 30 GW of data centers cut down to 13 GW, and it’s not clear if all those will come to fruition, he said.
“They’re clearly an effective advocacy tool if you want to secure the ability to ratebase new generation, because ‘nobody’s moving as fast as a utility could.’ … I’ve never heard anyone say [that], but that’s the story that’s being told,” Snitchler said. “Then you need to have as big a number on your load forecast as possible, because that means you’re the solution to the problem that you’re creating.”
Multiple utilities have pushed for restructured states in PJM to change their laws and allow them to ratebase new generation for the first time in 30 years, which is an idea that EPSA is opposed to, arguing it would spoil the markets its members rely on.
“I understand they have a target earnings goal that they have set for Wall Street,” Snitchler said. “But that doesn’t mean that we should reverse 30 years of policy to help them achieve it when there are more cost-effective and more efficient ways to do that, and by putting the risk where it’s been for the last 30 years on shareholders and investors of competitive power suppliers.”
The Slippery Slope of Re-regulation
Ultimately if states change the laws and guarantee rates of return for new utility-owned generation, that would cut into the revenues of market generation owned by IPPs who would eventually ask for their own guaranteed rates — unwinding markets altogether, PJM Independent Market Monitor Joe Bowring said in an interview.
“If PPL builds power plants and puts them in rate base, then all customers are paying for them,” Bowring said. “There’s nothing stopping PPL from directly working out a bilateral agreement with the data center and building a power plant for them. But that’s not what they’re asking to do. They’re asking to put in rate base and charge everybody for it, and that’s just a way of making everyone else bear the costs and risks of the data center load.”
PJM’s markets have been slow to add generation in part because of overhanging issues from the interconnection queue and unstable market design in the capacity market, Bowring said.
“The developers who were caught up in all those delays had delayed getting some of their basic milestones,” Bowring said. “They’re now trying to catch up, but they’re behind, and that’s part of the reason we haven’t seen a lot of new additions.”
On top of the lingering issues from the queue, the capacity market has seen its rules change often, and Bowring is also skeptical of how the RTO has implemented effective load-carrying capability ratings for power plants.
“If data centers want to come online quickly — which is fine, we want them to come online quickly — they should figure out how to bring their own generation,” Bowring said. “That doesn’t mean you’re turning data centers into power plant operators. You sign a bilateral contract with a developer; they build the power plant. They manage all that for you, but you have power, and that’s the quickest way to get things going, because the data centers have a huge incentive to get power quickly.”
Some of the hyper-scalers in the data center world can build their own power plants. Google parent Alphabet announced Dec. 22 that it was buying Intersect, which develops power plants for new large loads. But not every data center developer is among the largest companies in the world by market capitalization.
“The market is going to take a little while to react, and I’m hoping that in a few years that will restore equilibrium,” Bowring said. “But at the moment, as you know, we’re something like 6,600 MW short.”
While meeting new load has always been a key part of the business, the scale of the new demands from data centers is unprecedented.
“We’re talking 30[,000] to 60,000 MW of demand,” Bowring said. “That is absolutely unprecedented,” and it’s amid “a time when PJM was getting tighter for other reasons. That confluence is, I think, absolutely unique. I mean, PJM has been long for almost forever.”
The last time the PJM region faced a major shortage was decades before it was an RTO, and the power pool was dealing with the aftereffects of the accident at Three Mile Island in 1979, he added.
The issues data centers present to the grid are unique, and they need to be handled differently than load growth was in the past, Bowring said.
“The whole notion of just plugging in is naive, almost willfully naive, in some cases,” Bowring said. “I understand why the data centers imagined a few years ago [that] they could just plug into the grid and everything would be fine, but everyone knew at least a couple years ago that that was not going to work longer-term; that it was simply overwhelming the grid. So, it has to be dealt with in special and targeted ways.”
IESO has reduced its 2026 demand growth projection slightly, citing “international trade tensions.”
The revised projection came in its January 2026–June 2027 Reliability Outlook, which concludes Ontario is “well prepared” to meet its reliability requirements over the 18-month period.
IESO said firm energy demand rose about 2.3% in 2025 — “stronger than anticipated” — and will grow another 1.6% in 2026 and 1.1 % in 2027, with both peak and total energy demand to “moderate … as international trade tensions impact economic activity.”
In its previous forecast on Oct. 7, IESO projected 2026 growth would be 2.23%.
The ISO says 2026 growth will be driven by numerous “large step loads” — electric arc furnaces, electric vehicle battery manufacturers and data centers — in addition to the electrification of transportation and industry.
Reserve Above Requirement levels — the margin between available and required resources — are above summer and winter thresholds and expected to range as high as 4,500 MW.
The latest demand forecast, released Dec. 18, is “broadly consistent with, though lower than, the previous forecast,” IESO said. “In the longer term, the IESO continues to expect strong electricity demand growth.”
The demand models use actual demand, weather and economic data through September, with data on large step loads incorporated in mid-October. Planned generator and transmission outages reflect plans reported as of November.
Reduced Supply
IESO will lose more than 2 GW of generation when the Pickering B Nuclear Generating Station goes out of service in October 2026 for a $26.8 billion refurbishment that will extend the lives of Units 5 to 8 for up to 38 years. Work is set to begin in early 2027, with completion expected by the mid-2030s.
IESO hopes to add 185 MW in gas upgrades and 1,073 MW in battery storage and other resources from its Long-Term 1 procurements, which would leave the grid operator with a net reduction of 800 MW during the 18-month reliability horizon.
Reserve Above Requirement under expected weather and planned and firm demand scenarios | IESO
It also is counting on up to 260 MW of re-contracted capacity resources and more than 200 MW of re-contracted energy resources under its Second Medium-Term procurement.
The outlook does not include the results from the December 2025 capacity auction, which saw a record $645/MW-day (CAD) clearing price for summer 2026. “Forecast assumptions were based on capacity targets from the IESO’s 2025 Annual Planning Outlook, and incorporating the actual auction results would not materially change the outlook,” the ISO said. (See Big Jump in Ontario Capacity Prices Signals Tightening Supplies.)
The report said the refurbishment of the Bruce and Darlington nuclear plants remained on schedule, with work on Darlington Unit 4 expected to be completed in Q4 2026.
The ISO also is expecting completion of Phase 1 of Hydro One’s Waasigan Transmission Line Project — including a new double-circuit 230-kV line between Lakehead TS and Mackenzie TS — by Q4 2026.
New Format
The outlook identifies risks that can be addressed by coordinating maintenance plans for generation and transmission facilities. The Q4 outlook is the first using a “more focused and concise” format, IESO said. Details on assumptions, explanations and terminologies were moved to the Methodology to Perform the Reliability Outlook.
FERC revoked the operating license for a troubled hydroelectric dam in Michigan’s Upper Peninsula, citing a perpetual failure to address safety issues that could cost lives and the owner’s loss of land in bankruptcy proceedings.
The commission said owner UP Hydro “has discontinued good faith operation” of the Au Train Dam and decided that a license termination by implied surrender is in the public interest (P-10856).
With FERC’s Dec. 29 order, oversight of the dam shifts to the Michigan Department of Environment, Great Lakes and Energy (EGLE).
The 0.9-MW facility was built in the early 1900s to power a paper mill.
The revocation caps a tumultuous year for the dam and its old and new owners.
Since acquiring the Au Train Dam in 2010, UP Hydro has failed to remedy inadequate spillway capacity to lessen flooding risk, a condition of FERC’s transfer of the license. The company in 2020 told FERC it couldn’t finance spillway upgrades and filed for Chapter 11 bankruptcy in early 2023. At that point, FERC’s director of the Division of Dam Safety and Inspections told UP Hydro to at least lower the dam’s south levee to reduce flows through the spillway during floods. UP Hydro to date has not provided proof that it has begun that process.
Though UP Hydro sent a request to FERC in 2020 to surrender the dam, it rescinded the request in February 2025.
FERC’s regional Chicago office conducted a mid-2025 inspection and found additional neglect, including seepage through a newly discovered hole in the bottom of the vault, poor vegetation management, rodent infestations and shrubs and small trees growing in the channel downstream from the spillway.
The Au Train Dam is classified as having high hazard potential, meaning a dam failure would pose a threat to human life and cause significant property damage. The dam’s 40-year license, originally issued to the Upper Peninsula Power Co. in 1997, had about 11 more years to go.
“As a high hazard dam, the Au Train project poses a threat to public safety and UP Hydro has been unwilling and unable since 2010 to undertake required remediation,” FERC wrote.
Following UP Hydro’s bankruptcy, mortgage holder Stephenson National Bank and Trust in 2025 foreclosed 18 of the 22 parcels that the dam occupies and sold them to Green Bay, Wis.-based D. Charles Trust Investments.
The 18 parcels include those containing the powerhouse, transmission line, most of the impoundment and the surrounding project buffer. The investment company ordered UP Hydro to vacate the premises and decommission the powerhouse and said it would block access to the powerhouse Dec. 31, 2025.
“Loss of access to the powerhouse will immediately affect the licensee’s ability to comply with the terms and conditions of the license, including Article 401, which requires continuous minimum powerhouse discharge for the protection and enhancement of fish and wildlife resources in the Au Train River, or to ensure the safety of the facility,” FERC said.
FERC pointed to other failings by UP Hydro, including numerous past due dam safety submittals and audits, neglected coordination with downstream communities since 2021 and repeated failure to work with Michigan state agencies to permit and improve the dam.
The U.S. Department of Energy has ordered a non-operational 427-MW coal-fired generator in Colorado to be repaired and remain available to meet regional power needs for 90 days.
Energy Secretary Chris Wright issued Order 202-25-14 late Dec. 30, one day before the scheduled retirement of Craig Generating Station Unit 1 and 11 days after a valve failure took the 45-year-old generator offline.
The three-unit, 1,285-MW station in north-central Colorado is operated by Tri-State Generation and Transmission Association, which is co-owner of Units 1 and 2 with four other utilities and sole owner of Unit 3. Units 2 and 3 are scheduled for retirement in 2028; Unit 1 was to be retired Dec. 31.
DOE said in a news release that the Section 202(c) order prioritizes minimizing electricity costs and blackout risks and that Unit 1’s reliable supply of power is essential to keeping the region’s electric grid stable.
Tri-State said in a news release that it has a history of 100% compliance and will work toward the demands of this latest order.
That will need to begin with repairs to the valve that failed Dec. 19 but likely will entail “additional investments in operations, repairs, maintenance and, potentially, fuel supply, all factors increasing costs.”
Tri-State CEO Duane Highley said, “We are continuing to review the order to determine what this means for Craig Station employees and operations, and the financial impacts. As a not-for-profit cooperative, our membership will bear the costs of compliance with this order unless we can identify a method to share costs with those in the region. There is not a clear path for doing so, but we will continue to evaluate our options.”
Colorado Gov. Jared Polis (D) blasted the emergency order.
“This order will pass tens of millions in costs to Colorado ratepayers, in order to keep a coal plant open that is broken and not needed,” he said in a statement to Colorado Public Radio. “Ludicrously, the coal plant isn’t even operational right now, meaning repairs — to the tune of millions of dollars — just to get it running, all on the backs of rural Colorado ratepayers!”
Retirement planning for Craig Unit 1 began in 2016 and is based on economic factors, as well as numerous state and federal requirements.
Tri-State said in its news release that Unit 1’s planned retirement had been analyzed and did not raise resource adequacy concerns: “The retirement of Craig Unit 1 was specified in Colorado Air Quality Control Commission Regulation No. 23 on Regional Haze Limits, and the Regional Haze State Implementation Plan put in place in 2016. Tri-State’s 2020 and 2023 Electric Resource Plan (ERP) modeling reflected the previously announced retirement date for Unit 1. The model results of the 2023 ERP showed adequate resources to maintain reliability on Tri-State’s system following the retirement of Craig Station.”
Section 202(c) of the Federal Power Act was created for use in wartime or during a sudden increase in demand or decrease in supply of electricity. Historically, it has been invoked infrequently — the Biden administration issued 11 such orders in four years, all of them weather-related.
Wright signed 19 202(c) orders from May 16 through Dec. 30, a dozen of which directed continued operation of aging fossil generation assets.
Against this backdrop, the Dec. 30 order for Craig Unit 1 had been expected, so much so that the Sierra Club commissioned a December 2025 study by Grid Strategies calculating the cost of such an order: at least $20 million for 90 days on standby status and nearly twice as much on must-run status.
The 202(c) orders have been criticized for extending the operation of aging plants that are expensive and/or dirty to operate, but DOE continues to cite its July 2025 Resource Adequacy Report, which warned of a 100-fold increase in outages if the wave of retirements of firm fossil generation continues amid the buildout of intermittent renewables. (See DOE Reliability Report Argues Changes Required to Avoid Outages Past 2030.)
“I hereby determine that an emergency exists within the Western Electricity Coordinating Council (WECC) Northwest assessment area due to a shortage of electric energy, a shortage of facilities for the generation of electric energy and other causes and that issuance of this order will meet the emergency and serve the public interest,” Wright said in the Dec. 30 order for Craig Unit 1.
“From Dec. 30, 2025, Tri-State and the co-owners shall take all measures necessary to ensure that Craig Unit 1 is available to operate at the direction of either Western Area Power Administration (WAPA)-Rocky Mountain Region Western Area Colorado Missouri (WACM) in its role as balancing authority or the SPP West in its role as the reliability coordinator, as applicable.”
The order gives Tri-State and the co-owners of Unit 1 a Jan. 20 deadline to report measures they have taken and plan to take to ensure operational availability of Unit 1.
As Yogi Berra didn’t say (at least not first): It’s tough to make predictions, especially about the future.
But I’m going to stick my neck out and predict that the dozens of independent federal agencies like FERC will survive the Supreme Court’s revisiting of Humphrey’s Executor v. United States.
The conventional wisdom is that the court will invoke something called the “unitary executive theory” to reverse 90 years of precedent, and allow the president to unilaterally fire whoever he wants from any federal agency for any reason at any time.
The unitary executive theory doesn’t make any sense because it’s premised on the notion that Congress can’t pass a law granting a federal agency some element of independence from the whims of a president. Why can’t Congress do that? It’s the first branch of our government with the power to pass laws. That’s what it’s supposed to do. And let’s remember that the president can always veto a law he or she doesn’t like, which then requires Congress to muster an overwhelming majority to override the veto. And let’s note that the veto is a “legislative” power (it’s in Article I after all), which discredits the notion that legislative and executive powers can’t mix.
But somehow the idea emerged that Congress’ legislative power to pass laws, subject to veto, is circumscribed by a president’s executive power to override such laws because, well, he’s the president.
Let’s put aside all the intricacies and nuances that have inspired countless law review articles on this subject.
Instead let’s surmise what the swing justices think of Donald Trump’s conduct. Justices don’t live in a vacuum. They see the same stuff that we do (or at least I hope so).
Prior drafts of this column listed 34 of Trump’s worst constitutional, legal, ethical and aesthetic outrages in 2025 (actually 37 when I added the latest offshore wind, Greenland and battleship-naming outrages). But having depressed myself assembling the list, I realized that I shouldn’t pass it on, at least not in the holiday season. You may have your own list. And I hope the swing justices do as well.
I am guessing, and hoping, that the cumulative effect on the swing justices will be that they just can’t stomach giving Trump more power. They won’t take this further step toward autocracy, as happened in other countries. “Centralization of head-of-state control over the executive branch of government provides a pathway to autocracy. Indeed, unilateral presidential control of the executive branch constitutes a defining characteristic of autocracy.”
But maybe this is just wishful thinking.
Speaking of wishes, I wish you and yours the best for the year ahead.
AUSTIN, Texas — Having finally added real-time co-optimization to the market like every other U.S. grid operator with an effort that began in 2019, ERCOT can turn its attention to other pressing issues in 2026.
Of course, figuring out the most effective and efficient way to safely interconnect the hundreds of requests from large loads — data centers, bitcoin miners, large industrial facilities and the like — that have flocked to Texas’ welcoming arms tops the list. The grid operator began the year with 63 GW of interconnection requests in its large-load queue but enters 2026 with more than 233 GW, up 269%. Data centers account for about 77% of that load.
Then there’s ERCOT’s continuing work on a dispatchable reliability reserve service (DRRS), a product that staff call an ancillary service but that some stakeholders don’t. It is the third iteration of the product, mandated by state law in 2023 and a high priority for the Board of Directors and the Public Utility Commission.
A little less sexy initiative but equally important is the full-scale analysis that will take place in 2026 of the grid’s reliability standard. It will be the first formal evaluation of the new reliability standard the PUC established in 2024.
But wait. ERCOT isn’t finished with RTC. Nearly a dozen issues and tweaks have been identified to stabilize the market mechanism, requiring the task force that deployed RTC to stay active.
CEO Pablo Vegas says ERCOT is going through a transition “characterized by high and very rapid growth” of intermittent and short-duration supply resources.
“It’s characterized by a rapidly changing customer base that includes price-responsive loads like crypto miners, rapidly growing large-scale data centers, and continued penetration of distributed energy resources throughout the grid,” he told his board in December. “It’s a significant shift in operational requirements, and it represents an opportunity to create a more resilient and cost-effective grid for the benefit of all Texans.”
Vegas says ERCOT’s load growth is “fairly unprecedented” and renders obsolete historical interconnection processes. As of November, the ISO had energized only a little over 5 GW of large loads in 2025. To remedy that, Vegas and other members of his leadership team proposed a new approach to interconnection called a “batch study” process. (See ERCOT Again Revising Large Load Interconnection Process.)
Projects ready to be studied will be grouped together in batches and allocated existing and planned transmission capacity. ERCOT says this will provide large-load customers with study efficiency, consistency, transparency and certainty. The first group, Batch 0, will create a foundation and baseline for subsequent batches, building on the assumptions that have changed from the previous group.
Staff will develop the batch study’s framework, taking input from market participants and regulators. ERCOT has rolled out a stakeholder engagement plan during January and February that includes six presentations to the PUC and stakeholder groups. It plans to file a proposed study process framework for discussion before the commission’s Feb. 20 open meeting.
“There’s clearly a pressure to move quickly and support the economic growth that’s coming our way,” Vegas told the PUC in December.
ERCOT Tries Again with DRRS
There’s also pressure on ERCOT to produce the DRRS product, mandated by House Bill 1500 in 2023. The law requires the grid operator to develop DRRS as an ancillary service and establish minimum requirements for the product.
Lawmakers followed up by directing the PUC to revise ERCOT’s original protocol change to establish DRRS as a standalone ancillary service. The new direction resulted in allowing only offline resources to participate and the change was withdrawn.
ERCOT now has filed a protocol change (NPRR1309) that meets all statutory criteria and improves the previous change by allowing online resources to also participate in DRRS. The new design enables the product to be awarded in real time and co-optimized its procurement with that of energy and other ancillary services under RTC.
An accompanying protocol change (NPRR1310) adds energy storage resources as DRRS participants and a release factor so the product can support resource adequacy. NPRR1309 has been granted urgent status and is due before the board for its June meeting. The same status has not been accorded to NPRR1310.
“We recognize there’s likely to be a lively stakeholder debate,” Keith Collins, vice president of commercial operations, told the board in December. “We are optimistic that it can move through the stakeholder process expeditiously, but we didn’t necessarily want to burden it with a timeline for that.”
ERCOT contracted Aurora Energy Research, which has a large local presence, to study future resource adequacy conditions and the effect of different market designs, including variations of DRRS. The research firm determined that DRRS’ design adds more cost-effective dispatchable capacity and provides greater resource adequacy benefits in different load and extreme weather conditions. (See ERCOT: New Ancillary Service Key to Resource Adequacy.)
ERCOT’s large-load interconnection requests as of November | ERCOT
During a December workshop to review the report, stakeholders peppered Aurora staff with questions on the study. DRRS is meant to achieve a revenue goal, not an operational goal, the firm’s representatives said as stakeholders questioned whether it is an ancillary service.
Collins said the DRRS mechanism and its eligibility requirements strengthen reliability through ancillary services, whereas ERCOT’s operating reserve demand curve, about 10 years old, uses energy to improve reliability.
“In our mind, [DRRS] is using ancillary services to achieve reliability, so it is an ancillary service plus,” he said. “I’m not aware of any other market that has a tool quite like that.”
Saying he doesn’t understand how an ancillary service could ever procure 100% of eligible capacity, energy consultant Eric Goff, who represents the consumer segment, said, “It seems like that’s a stretch to call it an ancillary service.”
The workshop signaled the conversations that will happen over the next few months. ERCOT has scheduled another workshop for the Technical Advisory Committee on Jan. 7.
“Obviously, there’ll be more discussion on 1309 and 1310 next month,” Collins said.
Strengthening the Grid
After 2021’s devastating Winter Storm Uri and the legislative session that followed, the PUC ordered ERCOT to create a reliability standard as a performance benchmark to meet consumer demand for three years into the future. The standard is composed of three criteria to gauge capacity deficiency: frequency (not more than once every 10 years), magnitude (loss of load during a single hour of an outage) and duration (less than 12 hours).
ERCOT and its Independent Market Monitor are required to evaluate the costs and benefits of any market design changes proposed to address deficiencies identified through the assessment process. The first such reliability standard assessment will be conducted in 2026 and then every three years and will include a forward review and analysis of the generation mix.
Vegas said in December that additional supply has been “helpful” in improving the grid’s reliability characteristics.
“In the long term, there is increasing risk if the load materializes and infrastructure development doesn’t keep up,” he told the board.
ERCOT has deployed what it calls its “most significant” design change since its nodal market went live in 2010. The grid operator went live with RTC in early December and it has been successfully procuring energy and AS in real time every five minutes ever since. (See ERCOT Successfully Deploys Real-time Co-optimization.)
“Mission accomplished. It was absolutely brilliant,” ERCOT’s Matt Mereness, who chaired the stakeholder group managing the effort, told the board in December.
The ISO says new functionality, which also improves the modeling and consideration of batteries and their state-of-charge in participating in RTC, will yield more than $1 billion in annual wholesale market savings.
However, there’s still work to be done stabilizing RTC and transitioning to normal processers. Staff and stakeholders have identified nine issues to further evaluate in 2026. Those issues run from reviewing the ancillary service demand curve to evaluating concerns with AS deliverability and will be transferred to TAC.
ERCOT has identified five likely protocol violations and mitigation plans with the PUC and has filed a protocol change (NPRR1311) to reverse language allowing ancillary service prices above the $5,000/MWh cap during emergency conditions.
Mereness said the plan is to have everything resolved by Jan. 31. The grid operator will spend the first few months of 2026 releasing updates for remaining non-critical defects.
RTC’s successful implementation is another plus for ERCOT and Vegas. He told the board during its year-end meeting that the ISO is determined to be the “most reliable and innovative grid in the world … in the world.” (See “Vegas Sets Lofty Goal,” ERCOT Board Approves $9.4B 765-kV Project.)
“We are one [of the best], if not the leading, grids globally when it comes to operational and technical complexities,” Vegas said. To be successful, we need to be a clear leader on a stage that represents the entirety of this planet.”
As part of its strategy to “advance knowledge sharing in grid innovations,” ERCOT is hosting its third annual Innovation Summit on March 31 at a resort near Round Rock, Texas, where “visionaries, thought leaders and innovators” share ideas to address “challenges and opportunities facing grid operators around the world.”
Or those thought leaders could just ask ERCOT staff, who already may be there.
As 2025 dawned, the way ahead for NERC’s management seemed clear.
The ERO’s most recent three-year plan was set to expire in December, and NERC was set to develop a new one to begin in 2026 and carry the organization through 2028. But as the planning process got underway, ERO leaders began to realize the challenge they faced.
NERC was wrapping up the Interregional Transfer Capability Study, an unprecedented continent-wide examination of the transmission system with the potential to change how the ERO conducted reliability assessments. The second Trump administration had sowed major confusion about trade policy and other issues. The ERO’s Board of Trustees kicked off a review of the standards development process that wouldn’t be finished until February 2026. Multiple issues appeared to be in flux, a difficult environment for long-term plans.
With all this uncertainty in mind, NERC management decided that following through with the original goal would be “a fool’s mission,” as CEO Jim Robb told stakeholders in a May 21 webinar. (See 2026 to be ‘Bridge Year’ for NERC Budget.)
Instead, Robb and other executives agreed to treat 2026 as “a bridge year” in NERC’s budget and come back a year later to create a new three-year plan that would guide the ERO from 2027-2029.
Looking back on this decision near the end of 2025, Robb said he still believed it was the right call. The delay allowed NERC to get “a little bit more clarity on how we can make the most important difference possible” in the challenges facing the reliability landscape.
“We were just very early in our exploration of [large loads]. We’ve got a much clearer view now than we did a year ago,” Robb said. “Reliability assessments, same thing. … Gas-electric [coordination], I think we’re seeing a lot more progress than we would have guessed a year ago. So while there’s still a lot of uncertainty in the environment, I think a lot of it has resolved well enough for us to do a more thoughtful plan than we would have put in place [this] year.”
Cybersecurity Remains a Major Concern
In conversations with ERO Insider, Robb and other NERC managers described the organization as well-positioned to meet the year ahead, having overcome the uncertainty that characterized early 2025. One source of that ambiguity was the presidential transition, which left many crucial posts in government open — including the director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency.
Nearly a year after the inauguration, CISA still lacks a Senate-confirmed head. The agency has been led by Deputy Director Madhu Gottumukkala since his appointment in May 2025. President Donald Trump nominated Sean Plankey, formerly of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, to head the agency shortly after taking office, but his nomination has stalled amid holds placed by multiple senators.
More disruption came during the 43-day government shutdown, accompanied by the expiration of the Cybersecurity Information Sharing Act of 2015 (CISA 2015), which set requirements for cybersecurity information sharing by the federal government and provided liability protections for voluntary information-sharing by private entities.
CISA’s operations were restored on Nov. 12 when Trump signed a continuing resolution that also renewed CISA 2015 through Jan. 30, 2026, but the episode sparked fears about the continuity of the federal government’s role in the cybersecurity ecosystem. (See Stakeholders Urge Cyber Info Sharing Act Renewal.)
Michael Ball, CEO of the Electricity Information Sharing and Analysis Center, acknowledged the turmoil of the past year and the concerns it created among stakeholders. However, he said that, despite outward appearances, the connection between the government and the ERO, including the E-ISAC, remains strong.
“There is a lot of concern about what that [relationship] looks like down the road. I can say with a lot of confidence, at least from the lens that I have, that we haven’t seen that really degrade,” Ball said. “We have great contacts within the different agencies. The changes haven’t degraded the objective and the goal.”
“Where my concern would be is the degradation over time in that [commitment], and my optimism [there] is pretty high,” he continued. “We know that when there’s administration changes, there tends to be [a shift] without stakeholders that we work through, and they tend to reconstitute and sometimes create new opportunities.”
Cybersecurity remains a critical focus for NERC and the E-ISAC in 2026. As Russia’s conflict with Ukraine continues, tensions between China and Taiwan intensify and other nation-state actors like North Korea and Iran jockey for advantage, the chance increases that those rivals will try to advance their interests by damaging U.S. infrastructure. Groups believed to be affiliated with China are known to have infiltrated U.S. telecommunications networks, and as they gain experience and confidence the threat is only expected to grow.
Risks also remain from straightforward criminal actors employing ransomware and other tactics to gain financial benefit. Ball said the growth of generative artificial intelligence is “enabling amazing capabilities, even for what would have been less sophisticated threat actors” to conduct social engineering campaigns and gain access to utilities’ computer networks. These criminals are further fueled by an industry that has grown up to market malware, information and other cybercrime tools.
“The bad guys are bad, but they’re not dumb. They’re very, very capable … well-financed and well-resourced, and persistent — you can’t let your guard down once, because they’ll [be] there to take advantage of it,” Robb said.
Standards Modernization, Large Loads Efforts to Continue
Cybersecurity is far from the ERO’s only iron in the fire; NERC has multiple efforts underway that are expected to hit milestones in 2026. One of the most prominent of these is the Modernization of Standards Processes and Procedures Task Force, which the ERO stood up following a directive from the Board of Trustees in February 2025.
NERC’s board started the MSPPTF to examine the ERO’s standards development process after trustees twice invoked their authority under Section 321 of NERC’s Rules of Procedure to break voting impasses over proposed standards that put NERC at risk of breaking a FERC deadline. Chair Suzanne Keenan urged the task force’s leaders to make sure the process remains “stakeholder-based, with reasonable notice, opportunity for public comment, due process [and] openness.” (See NERC Leaders Highlight Canada-US Collaboration.)
NERC has called the resulting work one of the biggest outreach efforts in the ERO’s history, with presentations reaching more than 5,000 stakeholders over the last year. The task force is expected to deliver its final recommendations at the board’s February meeting in Savannah, Ga. NERC will then work on updates to the ROP, which must be submitted to FERC for approval.
“We’re still quite a ways away from implementation of a new process, but the team did a great job in living up to what we asked them to do,” Robb said. “It hasn’t been a smoke-filled room; there’s been a lot of engagement, and … the task force has taken what they heard in those engagements and used it to make the process better [and] more palatable. … So [we’re] very pleased with that.”
Large loads are expected to be another major area of focus for the ERO in 2026. NERC’s Large Loads Task Force has been operating since 2024 to study the impacts of data centers, hydrogen fuel plants and other emerging large loads on grid reliability, along with multiple simultaneous other efforts.
The organization also issued a Level 2 alert in September 2025. The alert provided recommendations for registered entities to mitigate risks associated with integration of large loads into the grid while requiring responses to a series of questions on their experience with large loads, their understanding of the risks associated with large loads and their current efforts to address those risks. Responses to the alert are due Jan. 28, 2026.
Robb described the ERO’s large loads work as “doing stuff in parallel that we would normally do in sequence.” Along with the LLTF and the Level 2 alert, NERC is developing a reliability guideline on risk mitigation with emerging large loads and recently commented on an Advance Notice of Proposed Rulemaking at FERC discussing potential changes to NERC’s registry criteria and standards actions on large loads.
“We won’t get ahead of our skis, but we’re going to be prepared to move as quickly as we can on each of these initiatives,” Robb said.
Changes to LTRA Process
NERC will be carrying out its plans at a time when the ERO receives a growing amount of attention from lawmakers and the general public. As a sign of how NERC’s profile has grown, Robb observed that at a 2024 meeting of the Senate Energy and Natural Resources Committee, both Chair Joe Manchin (I-W.Va.) and ranking member John Barrasso (R-Wyo.) used maps produced for NERC’s reliability assessments. The CEO also mentioned a recent appearance on NBC’s Today to speak about risks facing the energy grid.
“The CEO of NERC’s not supposed to be on the Today show. Just think about that — that the stuff that we’re doing is reaching a mainstream audience, not just the nerds in the corner planning the electric grid,” Robb said. “People are paying attention, and they’re using our materials to inform decisions.”
The increased attention to NERC’s assessments forms part of the backdrop for the ERO’s work to update its reliability assessments, particularly the Long-Term Reliability Assessment, which is published each year. The 2025 LTRA is due in January.
John Moura, NERC’s director of reliability assessments, said ongoing changes in the electric grid — including rapid shifts from traditional generation to inverter-based resources like wind and solar, along with the growth of large loads — meant the ERO’s previous approach to the LTRA was no longer valid. He described the former approach as “very much … ground-up,” involving collecting data directly from utilities which the ERO would “piece together at the end.”
Moura said recent experiences have demonstrated that “each system is more reliant on neighbors than we ever have been in the past … and so coming together earlier on in the process to make sure assumptions and scenarios and base cases are … modeled in unison [is] essential.” NERC began a pilot program in 2025 to establish common platforms and standardized assumptions for the Eastern, Western and Texas interconnections, enabling interconnection-wide energy assessments.
That effort has been productive, Moura said, although not ready to be used in the 2025 LTRA. He explained that the Interregional Transfer Capability Study, filed with FERC in 2024 in accordance with a mandate in the Fiscal Responsibility Act of 2023, provided a “foundation” for the wide-area assessments by pushing NERC to develop tools and processes for information gathering and storage that could then be used for the LTRA.
“The ITCS gave us that step change. It kind of elevated our capability,” Moura said. “If we had not had the ITCS … we would have [eventually] said, ‘Wait, we need to understand the interregional transfer capability between the regions.’ … But the ITCS actually gave us a step change up … allowing us now to do things in a simultaneous manner.”
The most important task for NERC in the coming years, Robb said, will be to preserve its reputation for independence and fact-based analysis, and to avoid any perception of favoring one side or another in the increasingly polarized political climate.
“We’ve had as good a conversation with the current committees of jurisdiction in the House and Senate that we would have had two years ago, [and] our relationship with DOE is as strong today as it was two years ago, because we’re not partisan,” Robb said. “We’re kind of the truth tellers. And while not everybody likes what we have to say, they at least respect it and pull it into their own thinking. I think that’s really important … that we don’t let ourselves ever be turned into a tool or start telling people what they want to hear, because once we do that, we’ve lost our power.”
Heading into 2026, the New England states, ISO-NE and energy industry stakeholders are counting on an increasingly collaborative approach to energy policy as federal opposition to renewable energy development threatens affordability, reliability and decarbonization objectives in the region.
As President Donald Trump ramped up his anti-renewable resource policy in 2025 — punctuated by the administration’s Dec. 22 order halting all U.S offshore wind construction — the New England states moved forward with multistate transmission and generation procurements intended to meet forecasted load growth and state clean energy goals.
ISO-NE forecasts power demand to roughly double by 2050, and the RTO has expressed concern about resource adequacy starting in the 2030s, especially in light of the offshore wind industry’s challenges.
How the region will meet growing demand in the coming decades is an unsettled question, and there is no certainty that the region’s offshore wind industry will be able to rebound after the end of Trump’s presidency. It also remains to be seen how effective the states’ collaborative approach will be at supporting the continued growth of the region’s power system.
While these questions may not be fully answered in the new year, 2026 will likely provide some important indications about the success of the states’ approach, including results from a pair of major transmission procurement efforts. 2026 is also poised to be a crucial year for ISO-NE’s ongoing effort to overhaul its capacity market, as the RTO has filed with FERC a potentially controversial set of resource accreditation and seasonal auction changes with a proposed effective date of March 31.
The recent political attention around energy affordability — which may be heightened by 2026 gubernatorial elections — likely will put pressure on ISO-NE and state officials to prioritize cost savings in all areas, including the capacity market changes and efforts to rein in spending by transmission owners on local transmission upgrades.
In an event in December, Gordon van Welie, who served as ISO-NE CEO from 2001 through the end of 2025, spoke about the improvements in stakeholder collaboration he saw during his 25 years at the RTO, saying, “Even when things do seem a bit tense, we’ve developed mechanisms to deal with those frictions.”
2026 is poised to be a substantial stress test for New England’s mechanisms to deal with energy policy frictions.
Accreditation Mad Dash
In 2026, ISO-NE and New England stakeholders face a heavy workload and a ticking clock in the effort to develop and build consensus around capacity accreditation changes and a new seasonal capacity auction design.
The changes are a major focus for a wide range of interests because of the potential effects on clearing prices and capacity revenues for individual resources.
The RTO first introduced its Resource Capacity Accreditation project in 2022 before expanding the project to include a wider array of changes, including to the timing of auctions and capacity commitment periods (CCPs).
On Dec. 30, ISO-NE filed the first phase of the Capacity Auction Reform (CAR) project, which proposes to drastically reduce the amount of time between auctions and CCPs and decouple resource deactivation from the auction process (ER26-925).
The RTO is poised to spend much of 2026 working to finalize the second phase of the CAR project, which includes accreditation changes and the development of a seasonal auction design splitting CCPs into six-month winter and summer periods.
Overarching affordability concerns may increase the stakes of the process. While the capacity market has not been a major driver of consumer costs in the region, state officials are eager to avoid the major capacity price spikes experienced recently in PJM and MISO. Some market participants in New England expect demand growth and Pay-for-Performance risks to push up prices in future auctions, and the proposed CAR changes add to the price uncertainty.
“Consumer affordability concerns and gubernatorial elections across the six states will heighten the political focus on all actions in this industry,” said Dan Dolan, president of the New England Power Generators Association.
He emphasized the importance of “a cooperative structure of government policies and regulations” to help strike the right balance between reliability, affordability and clean energy investment, adding that “the public spotlight to get this right will be extraordinary.”
The accreditation reforms would introduce several important factors into the capacity auction process, including gas supply constraints, on-site fuel storage, pipeline contracts, resource outage rates, battery duration and seasonal resource performance variability.
Resource accreditation values would be dynamic auction-to-auction, with changes in the region’s generation and demand profile affecting the value of each resource.
ISO-NE is aiming to complete the accreditation and seasonal auction changes by the end of 2026, which may be no easy task given the high-stakes and potentially controversial nature of the reforms. The RTO hopes to have the full suite of CAR changes in place for its 2028/29 CCP. (See NEPOOL Supports First Phase of ISO-NE Capacity Market Reform.)
The RTO will also have to navigate the rocky waters of accreditation under new guidance; longtime COO Vamsi Chadalavada took over for van Welie as CEO at the start of January.
Chadalavada’s appointment has been met with strong support from NEPOOL members, with some expressing optimism that he will build on the collaborative approach taken by ISO-NE in the first phase of the CAR project.
If ISO-NE is not able to complete the project and obtain FERC approval in time for the 2028/29 CCP, it may be forced to run the first phase of CAR changes as a standalone design, a circumstance that many stakeholders in the region hope to avoid.
Transmission, New and Old
Van Welie’s tenure at ISO-NE was characterized, in part, by a strong reliability record and a major shift in the region’s generation fleet as more efficient gas-fired plants replaced aging coal, nuclear, gas and oil generators. This transition was aided by investments in new transmission in the mid-2000s, which reduced congestion and allowed lower-cost resources to come online. (See Retiring ISO-NE CEO van Welie Reflects on 25 Years at the RTO.)
Chadalavada has assumed the leadership role amid another period of transition, characterized by demand growth and renewable power proliferation. The changing mix of demand and supply will likely require a large amount of new transmission investment over the next couple decades: A 2023 study by ISO-NE estimated that transmission upgrades needed to meet 2050 demand could cost up to $26 billion. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)
New England already has some of the highest transmission rates in the country, and long-term transmission needs could put significant additional pressure on transmission costs.
Given the anticipated long-term needs, consumer advocates are hoping to rein in some of the region’s transmission spending through added scrutiny on asset condition projects. These upgrades account for the majority of the transmission investment in New England and have been a topic of growing concern for states and ratepayer advocates in recent years. In spring 2025, ISO-NE agreed to take on a non-regulatory role reviewing asset condition projects.
While ISO-NE has emphasized it will not make judgments on the prudency of transmission investments, its findings on projects could be used by other third parties in FERC proceedings to challenge investments. As it works to develop these internal review capabilities, the RTO plans to rely on a hired consultant to conduct reviews for a subset of asset condition projects.
State officials also have gone directly to FERC to seek relief; in mid-December, the Maine Office of the Public Advocate asked FERC to initiate evidentiary hearing procedures to investigate the prudency of asset condition projects placed in service in 2022. (See Maine Public Advocate Asks FERC for Hearing on Asset Condition Costs.)
To address long-term transmission needs, ISO-NE and the states kicked off in 2025 the first transmission procurement under the new Longer-term Transmission Planning (LTTP) process. The solicitation is aimed at reducing transmission constraints in Maine to enable renewable development in the northern part of the state.
To be eligible for selection, each project’s estimated benefits must exceed its estimated costs. If no projects pass this threshold, the LTTP process allows states to opt to cover the extra costs, but it is unclear whether a state would assume this responsibility in the current environment of affordability concerns.
A successful first LTTP procurement could set a strong precedent for future procurements and other collaborative efforts among New England states, while a failed procurement would likely represent a significant setback for transmission development in the region.
In conjunction with the LTTP procurement, Maine has launched an additional solicitation of renewable energy and associated transmission in Northern Maine. The Public Utilities Commission published its RFP for the Northern Maine procurement on Dec. 19 and aims to select winning bids by the end of May 2026. (See Maine PUC Issues Multistate Transmission, Generation Procurement.)
Also in 2026, ISO-NE is slated to begin stakeholder discussions for its compliance with FERC Order 1920, which will likely build on the existing LTTP process.
“While our LTTP process is an excellent starting framework for planning and procuring regional-first beneficial transmission, Order 1920 will require further improvements that ISO-NE must incorporate into its practice, such as scenario-based planning, consideration of rightsizing and use of alternative transmission technologies,” said Alex Lawton, a director at Advanced Energy United.
Long-term Energy Adequacy and Resource Development
While ISO-NE expects to have adequate resources to meet demand in the coming year, it has expressed concern about potential supply issues in the 2030s.
If able to complete construction, the Vineyard Wind and Revolution Wind offshore wind projects would provide a combined 1,500 MW of nameplate capacity to the region’s grid. Vineyard is partially operational, and Revolution is nearing the completion of construction.
The Bokalift 1 and Bokalift 2 heavy lift vessels at the Revolution Wind site | Revolution Wind
Susan Muller, senior energy analyst at the Union of Concerned Scientists, emphasized the potential winter cost and reliability benefits of these resources.
The power from Vineyard and Revolution “should make a significant difference in the overall wholesale cost of energy supply, which will benefit all retail customers in New England on an ongoing basis,” Muller said, highlighting a study by Daymark Energy Advisors that found that 3,500 MW of offshore would have cut ISO-NE energy market costs by about $400 million in the winter of 2024/25. (See New Study Highlights Winter Benefits of OSW in New England.)
In a statement responding to President Trump’s suspension of offshore wind construction, ISO-NE wrote that the affected projects “are particularly important to system reliability in the winter when offshore wind output is highest and other forms of fuel supply are constrained.”
“While ISO-NE forecasts enough generation capacity is available for the current season, canceling or delaying these projects will increase costs and risks to reliability in our region,” the RTO added.
The New England Clean Energy Connect (NECEC) transmission project — itself delayed by multiple years because of political challenges in Maine — should be online for the winter of 2026. The project includes a 20-year power purchase agreement for baseload energy from Hydro-Quebec, and ISO-NE studies have indicated the line will provide significant winter reliability benefits to the region.
Beyond NECEC and the two offshore wind projects, there is a high degree of uncertainty regarding the next wave of supply into the region.
Experts are somewhat divided on what the long-term effects of Trump-era policy will be on the offshore wind industry in the U.S. While some have expressed optimism that the industry will rebound with a new administration in Washington and continued state support, others have expressed doubt that investors will return.
With the looming July 4, 2026, construction deadline for solar resources to receive the federal investment tax credit, solar developers and state energy officials are scrambling to push late-stage projects forward as quickly as possible.
NECEC project map | Avangrid
In a coordinated, expedited procurement led by Connecticut, four New England states recently selected a combined 173 MW of advanced-stage solar projects from across the region. (See New England Coordinated Procurement Nets 173 MW of New Solar.) Massachusetts also recently announced the selection of 1,268 MW of energy storage from a separate procurement.
“Our main focus next year is very tactical — working on project-execution-related matters for our portfolio, including asset financing, trying to advance some early-stage projects and looking for growth opportunities,” said Aidan Foley, founder of Glenvale Solar, which had two projects selected in the recent solar procurement.
“We need a continued pace of procurements and long-term policy initiatives, both to bring near-term assets online and to communicate to developers [and] investors that there will be paths to market in the future,” he added.
On the distribution side, solar developers are also working to start construction and bring projects online as quickly as possible.
“The first half of 2026 is going to be a sprint to get the last batch of projects in the door,” said Jessica Robertson, director of New England policy and business development at New Leaf Energy. “Then, the next several years are going to be a really hard focus on getting things online by those ITC deadlines, and in parallel, trying to develop our storage verticals.”
She noted there are several hundred megawatts of distributed solar in the various stages of Massachusetts’ interconnection queue.
To help expedite the development process, she said it will be important to increase the frequency of Affected System Operator studies and potentially enable rolling determinations of whether a project needs a study.
In the long-term, New Leaf is looking at “figuring out how to keep solar going without the ITC,” Robertson said. “That’s not going to work everywhere right away, but certainly states like Massachusetts don’t plan to stop after next July.”
The Extended Day-Ahead Market took center stage at CAISO in 2025 as the ISO tabled other long-term initiatives to ensure the market’s timely launch in May 2026 with PacifiCorp as its first participant.
And EDAM preparations continue to be the primary focus for the ISO and its stakeholders in the new year.
According to a December report from CAISO CEO Elliot Mainzer, 2025 saw thousands of stakeholders from California and throughout the West tune in to EDAM implementation workshops that enlightened and sometimes perplexed stakeholders, with the ISO trying to quickly address new critical problems to keep EDAM’s schedule intact.
The year started with a bang: In February, Powerex — which has committed to joining SPP’s competing day-ahead market Markets+ — published a paper contending that EDAM contained a “design flaw” that could result in $1 billion in unjustifiable charges for non-CAISO participants.
The paper said EDAM’s treatment of firm transmission rights and congestion would leave the market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while not providing them adequate ability to recover or hedge against those costs. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.)
About a month later, CAISO began an “expedited” initiative to decide how to allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes congestion in a neighboring BAA. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.)
In late summer, FERC approved CAISO’s new EDAM congestion revenue allocation design. The approved design is a short-term solution, and the ISO said it would propose a long-term design within the next two years. (See CAISO’s EDAM Scores Simultaneous Wins at FERC.)
Top EDAM Challenges
RTO Insider asked CAISO and a few of its stakeholders their views on EDAM’s top challenges in 2026.
CAISO Vice President of External Affairs Stacey Crowley said the ISO worked with vendors to deliver timely functionality for market simulation, supported participating entities in developing tariffs through the FERC process, and established a transitional congestion revenue allocation design informed by stakeholder input — all critical steps to enable EDAM launch.
PacifiCorp, which will join EDAM in May as the first participant, said it faced several key challenges while preparing for EDAM’s 2026 launch.
“Building and testing interconnected IT systems for PacifiCorp and CAISO required extensive coordination and design adjustments that had to be integrated into the development plans of both organizations,” PacifiCorp spokesperson Omar Granados told RTO Insider. “Additionally, managing communication and testing across numerous transmission customers and 14 neighboring utilities added significant logistical challenges.”
Priorities in 2026
The coming months in 2026 will see heightened activities around EDAM implementation, with stakeholders anticipating several challenges to ensure the market opens as planned in May.
PacifiCorp remains confident in the EDAM go-live timeline, but it must resolve issues that have never been encountered, Granados said.
For example, starting in February, PacifiCorp and CAISO will begin parallel operations for their respective market systems, staff and support processes. While the ongoing market simulations have suggested the utility is ready for EDAM, parallel testing likely will “reveal adjustments needed before launch,” the spokesperson said.
To address this concern, PacifiCorp is working closely with software partners and has established an internal issue-resolution team to quickly identify and resolve problems, Granados said. After starting in the market, further refinements and process optimizations are expected, he said.
CAISO’s Department of Market Monitoring (DMM) will be “closely watching and reporting on” critical areas as EDAM is implemented, DMM Executive Director Eric Hildebrandt said. One area is market efficiency and performance, such as pricing and volumes of self-scheduling versus supply/demand that is bid into and clears EDAM. DMM also will watch how EDAM affects the broader real-time Western Energy Imbalance Market.
DMM will monitor congestion within EDAM, specifically how much transmission is available in the day-ahead market for transfers between BAAs; the amount of “unscheduled flows” and congestion revenues created by schedules in one BAA on other BAAs; and how these congestion costs and revenues are allocated among BAAs, Hildebrandt said.
Two other focuses for EDAM: the day-ahead resource sufficiency requirement and evaluation, and the day-ahead imbalance reserve product, including the impact it has on EDAM prices, he said.
As for CAISO, Crowley said the ISO will work with vendors to test systems and procedures, and to ensure market participants have the training and practices needed to fully engage at launch.
Working Across Agency Lines
RTO Insider asked CAISO how it plans to work with the California Energy Commission and the California Public Utilities Commission as EDAM launches.
Crowley noted that EDAM is regulated under FERC, but “we have worked collaboratively with California agencies such as the CEC and CPUC — as well as regulators across the West — to ensure they are informed and able to provide input into the market design.”
“There is an important role for state regulators through the [Western Energy Markets] Body of State Regulators and the public stakeholder process,” she said. “While state agencies do not have direct oversight of EDAM, they have also been actively engaged in the development of legislation like Assembly Bill 825, which will establish an independent governance board, committee of state regulators and other public processes similar to what occurs at … CAISO now.”
DMM will publish quarterly, annual and other special reports on the performance of CAISO markets, with state regulators and policymakers being a primary audience for those documents and the recommendations they contain.
“We do outreach to key regulatory agencies in all the EDAM/WEIM states in order to highlight our reports and recommendations, answer questions and get any input state agencies have on what types of analysis and reporting they would find most useful,” Hildebrandt said.
While DMM’s recommendations often play a role in shaping market design, “we do not have any role in the actual implementation,” Hildebrandt added. Instead, the Monitor “will be focusing on quickly identifying and helping address any problems or unexpected issues that arise” with EDAM implementation, he said.
Batteries Provide Sneaky Reliability, Kinks to Work Out
While EDAM implementation demanded much of the ISO’s and stakeholders’ attention in 2025, CAISO weathered yet another year without needing to issue a flex alert or call for rolling blackouts. CAISO leaders repeated highlighted the addition of massive volumes of battery storage resources as a critical contributor to grid reliability.
By April 2025, more than 12,000 MW of battery storage capacity was online in the ISO — up from about 500 MW in 2020. An additional 15,000 MW of storage resources are expected by 2028, accounting for the majority of the 20,000 MW of new resources expected in that time.
The increase in batteries has kept CAISO focused on technical issues throughout the year, such as outage management enhancements, battery nonlinearity guidance and state of charge clarifications. The ISO also started an initiative to improve the visibility of distributed batteries, especially when they are needed for resource adequacy purposes.
CAISO will continue to lean on batteries in the coming year, specifically in the ISO’s resource adequacy program and qualifying capacity (QC) process. Stakeholders asked CAISO to provide more clarity on how battery durations will be counted in CAISO’s default QC counting rules, asking the ISO to avoid lumping all battery capacity together, including eight-hour batteries and four-hour batteries.
CAISO’s DMM early in 2025 raised concerns about the potential gaming and inefficient bidding behavior in CAISO’s bid cost recovery (BCR) process for battery storage resources. In an August report, DMM said the current BCR design creates gaming opportunities for battery storage units, “especially through manipulation of various biddable parameters used to manage state-of-charge.” (See CAISO Monitor Sees ‘Gaming’ Potential in Battery Storage Bid Cost Recovery.)
