ERCOT has told Texas regulators it’s completed its contractual work with LifeCycle Power, CenterPoint Energy and CPS Energy, clearing the way for 15 mobile generators to be moved from Houston to San Antonio and to provide more capacity in the area.
ERCOT General Counsel Chad Seely said at the Public Utility Commission’s June 5 open meeting that the first wave of generators is expected to arrive in the San Antonio area in July.
The mobile units, each capable of providing about 30 MW of power in about 10 minutes, will be interconnected to CPS substations in the city. Eight of the nine substations that will house the units are ready for delivery.
“I know LifeCycle has committed to move as quickly as possible,” Seely said. “A tremendous amount of work by everyone to get this across the finish line.”
ERCOT says the generators are necessary to mitigate emergency load-shed that may be necessary to avoid overloads of a generic transmission constraint. Staff have been working on the agreement since February 2025, when it became apparent they would not be able to extend reliability-must-run agreements to two aging CPS gas-fired units. (See ERCOT Board OKs Mobile Generators in San Antonio.)
The grid operator earlier entered into an RMR contract with CPS for V.H. Braunig Unit 3, its first. The San Antonio municipality said in 2024 that it was planning to retire all three Braunig units in March 2025. ERCOT said the plant’s retirement would lead to reliability issues until the transmission constraint is resolved. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.)
Under the agreement, ERCOT will be able to dispatch the units only during actual or expected emergency conditions. The costs (an estimated $51 million) will be uplifted to qualified scheduling entities representing load on an hourly load-ratio share basis.
The units are leased from LifeCycle by CenterPoint. The Houston utility made them available to ERCOT, without compensation, through March 2027.
ISO Gets Good-cause Exception
The PUC granted ERCOT a good-cause exception for the 2025 Regional Transmission Plan, allowing the grid operator to adjust load forecasts outside the protocols’ requirements.
Recent state legislation requires the grid operator to include any load in its projections that doesn’t yet have a signed interconnection agreement. The ISO’s staff have proposed a 49.8% reduction in data center loads and a 55.4% cut in these “substantiated loads,” which are support by an executed interconnection agreement, a credible third-party forecast, or attestation by a transmission and distribution service provider (55999).
The reductions bring the forecasts more in line with historical performance, ERCOT said.
approved CenterPoint’s request to securitize $396 million of system restoration costs from two storms in May 2024. The commissioners agreed with Chair Thomas Gleeson’s proposal to adopt a standard of negligence instead of gross negligence (57559).
adopted a rule that sets reporting requirements for transmission providers and establishes monitoring responsibilities as part of the plan to build 765-kV import paths into the petroleum-rich Permian Basin. The monitor will identify the schedule and cost components that may affect the project’s timely development and approval of necessary service requirements, while also shedding transparency of expenses. The transmission providers will bear the monitor’s costs (57602). (See Texas PUC Approves 765-kV Transmission Option for Permian Basin.)
The Organization of MISO States and MISO are confident the footprint will be resource-sufficient in the 2026/27 planning year but said anything from an 11.4-GW surplus to a 14.1-GW deficit could be in store by the 2030/31 planning year depending on how swiftly capacity can be added.
The two drew on more generous capacity construction assumptions than in years past to come up with the 2025 OMS-MISO Resource Adequacy Survey results. MISO said it likely would have a surplus anywhere from 1.4 GW to 6.1 GW for summer 2026 based on survey totals.
For summer 2027, the five-year resource adequacy projection showed the potential for a 5-GW deficit or a 6.4-GW surplus. From there, the possibilities for excesses or shortfalls widen further.
MISO Senior Resource Adequacy Engineer David Kapostasy said OMS and MISO used a range of build rates for this year’s survey, including a more promising replacement trend for retiring generation.
The two used a 3.5-GW/year assumption for capacity builds, based on a three-year historical average of new capacity constructed 2022 through 2024. Factoring in MISO’s historical, 1.2-GW rate of generation replacement projects brought the baseline average to 4.7 GW/year. MISO and OMS also used a more optimistic, 6.2-GW/year alternative projection based on MISO members’ responses to the survey regarding generation plans. Furthermore, MISO said high-end value could grow to 8.6 GW/year using a more generous, 2.4-GW/year replacement rate that reflects an emerging trend of utilities more reliably choosing to build replacement capacity or, better, using surplus interconnection service at existing sites.
Using the 3.5-GW/year build rate alone, MISO could experience a 12-GW shortage by summer 2028. At the 8.6-GW/year rate, however, the deficit dissolves into a 6.7-GW overage. While the 3.5-GW rate returns 12.2- and 14.1-GW shortages in planning years 2029/30 and 2030/31, respectively, the 8.6-GW/year rate could deliver 10.5 and 11.4 GW in extra capacity over summertime needs.
It’s not until MISO applies the 8.6-GW/year average that the possibility of any capacity shortfall is eradicated from the 2027/28 planning year onward.
MISO compared capacity estimates against 2.2% compound annual load growth, instead of last year’s 1.6%.
This year’s survey results are the first time in a few years that MISO and OMS are entertaining the possibility of double-digit gigawatt reserves in summer. The 2024 survey’s best-case scenario showed a 4.6-GW surplus by the 2029/30 planning year. Capacity deficits, according to the 2024 survey, also could top out around 14 GW.
At a June 6 teleconference to review survey results, Kapostasy said MISO reflected an acceleration in construction turnaround times among its membership when preparing survey totals.
“There’s a question of: Is this the queue starting to unclog itself, or is this a return to normal,” pre-COVID construction tempos, Kapostasy said.
Kapostasy said this is the first year MISO projected replacement capacity and new capacity that may result from surplus interconnection service, recognizing that many existing interconnection customers already replace generation or explore using their existing interconnection service to the fullest.
Replacement and surplus interconnection projects should account for 25% of new capacity additions over the next five years and blunt the impact of retirements, Kapostasy said. He also said retirement deferrals in MISO are providing a “short-term buffer” against seasonal capacity deficits.
MISO this year attempted to quantify in survey totals what it calls “stranded GIAs,” or projects with signed generation interconnection agreements that nevertheless won’t become part of MISO’s capacity expansion due to difficulties getting them built.
Kapostasy reminded stakeholders that MISO has about 54 GW worth of planned generation that has signed interconnection agreements but are not yet online. He added that MISO’s recent queue process alterations (read: an annual megawatt cap on project entrants, higher dropout fees and an automated study process) should attract generation projects that are more of a sure thing in the future, minimizing dropouts.
MISO said 91% of existing generation participated in the 2025 OMS-MISO Survey, representing 97.4% of MISO load.
Vice President of System Planning Aubrey Johnson said the bottom line is MISO appears to have sufficient resources for the next planning year.
“Beyond that, we have challenges that need to be met,” he said.
Joe Sullivan, president of the Organization of MISO States and vice chair of the Minnesota Public Utilities Commission, said past surveys seemed to help move the needle on improving MISO’s resource adequacy picture.
“Capacity margins have improved since last year,” he said.
Sullivan said the goal of the survey is to guide planning decisions, “not deliver definitive” projections. He said many variables, including load growth, electrification and fleet turnover, remain in flux.
“As the survey shows, we are continuing to meet the moment,” Sullivan said.
SPP and Hitachi have announced a strategic partnership to produce an integrated AI-based solution they say will reduce study-analysis times by 80% in the generator interconnection process, potentially resolving one of the key issues that has slowed the grid’s ability to meet escalating demand.
The companies said in a June 5 press release that end-to-end use of industrial AI and advanced computing infrastructure will help significantly speed up safe integration and use of additional resources supporting the central U.S. grid.
The U.S. Energy Information Administration said in January that the nation’s electricity consumption grew by 2% in 2024 and will continue to grow at that rate in 2025 and 2026. It will be the first three years of consecutive growth since 2005 to 2007, with much of the demand coming from battery manufacturing operations and data center consumption.
“Our nation’s demand for electricity has risen sharply in recent years following a long period of slow growth. Our industry has struggled to keep up with this sudden and significant shift,” SPP CEO Lanny Nickell said.
“There are a lot of would-be power producers out there waiting to connect to the grid, but yesterday’s systems and technology haven’t been sufficient to enable us to bring incremental capacity online fast enough. It’s time to fix that,” he added.
The grid operator’s GI queue currently includes 679 projects, 380 of which are active, and more than 161 GW of capacity. It still is working on study clusters that date back to 2018.
The integrated solution comprises multiple Hitachi capabilities that include an AI-based power simulation algorithm, accelerated calculations, augmented simulation modeling, predictive analytics, and design and engineering services.
Hitachi said the partnership intends to “reimagine” the electric sectors production and distribution process through “the lens of modern AI technology.” SPP then can make “significantly quicker, better-informed decisions,” said Frank Antonysamy, Hitachi Digital’s chief growth officer.
“Real-time data access is needed to create truly realistic scenarios caused by new generator introductions. The AI solution we’re all developing will provide that data, among other advantages,” Antonysamy said.
Along with NVIDIA, another AI provider, Hitachi and SPP will draw on Hitachi’s various competencies, including an integrated storage and computing platform built on NVIDIA accelerated computing, networking and AI software. The AI-driven technologies will be applied to process automation, predictive analysis, communication systems integration and other study areas.
The project’s first phase is expected to be completed by December 2025. The phase includes initial systems acceleration, data-management processes optimization and introducing AI-augmented simulation modeling.
SPP says as an RTO, it will guide the integration of technical solutions and services and ensure the project outcomes align with industry requirements and regulations. Later objectives will address alternative energy integration challenges and transmission constraints.
For most organized markets across most of their history, resource adequacy was relatively easy to handle, with supply long and demand growing slowly.
That has changed rapidly in just the past few years, with a spike in demand growth led by new data centers. FERC spent June 4-5 looking into the issue across the markets it regulates.
FERC Chair Mark Christie has been talking about a reliability crisis for years, as dispatchable generation has retired with replacements that at best do not offer the same characteristics.
“So now the crisis is really right on our doorstep,” Christie said. “But let’s not forget, while this conference is about the impending crisis of reliability from resource shortfalls, it really has another crisis connected to it, and that is the crisis of rising consumer power bills, because consumers have to pay for capacity, as we all know. And I know that in at least two states in PJM — Maryland and New Jersey — this very week consumers are seeing big jumps in their power bills because of rising capacity costs.”
The technical conference, along with pre-filed comments and another round after the conference, will build a record that FERC could use in future proceedings on the issues, he said.
The industry is facing a lot of uncertainty, including extreme weather, supply chain constraints, rising costs for equipment and how much it can really count on demand forecasts, Commissioner Judy Chang said.
“The compounded complexities around the regulatory and commercial structures deployed in various regions across the country make all of our jobs difficult, and that’s why we’re having this conversation today, to add to the record, but also to add an opportunity to discuss these questions,” she added.
NERC has been monitoring resource adequacy for decades, and, outside a few regions, it mostly was boring until 2018, CEO Jim Robb said.
“For the first time, in 2018, our long-term resource adequacy assessment showed a material expectation of long-term unserved energy, and 18 months later, that expectation, unfortunately, was realized with a significant load-shed event in California in August of 2020,” Robb said. “And since then, our analyses have shown growing risk of unserved energy across the continent.”
The theory around resource adequacy in wholesale markets was simple, with trading in spot markets producing price signals that would lead to bilateral deals that can support new entry of generation, ISO-NE CEO Gordon van Welie said.
“The construct assumed that society would be tolerant of occasional shortages and high prices to allow market incentives to work,” van Welie said. “In practice, we have learned that the theoretical construct made assumptions that were inaccurate. Specifically, it assumed the proper price formation in the energy market, which has been stymied by price caps and externalities that have not been priced. This has led to the need to replace the missing money.”
It also ignored the need for a reserve margin, and in that gap came the capacity markets. Both ISO-NE and PJM have used three-year forward markets, but van Welie said his RTO is working on a prompt, seasonal design that is better equipped to deal with the realities the system is facing.
A chart PJM filed for the FERC technical conference laying out changes in capacity by state over the previous decade. | PJM
“The seasonal pricing will reflect the dynamic changes and constraints in the regional power system, provide the economic stimulus to drive bilateral trading and discipline wholesale buyers who have not covered their share of the resource adequacy objective,” van Welie said.
The new construct would require support from the states, reduced barriers to entry and substantial bilateral trading to manage volatility and support investment, he added.
PJM’s markets generally have worked well in the past, with its capacity market helping to bring online 50 GW of new resources that includes significant renewables and 8 GW of demand response since it launched in 2007, CEO Manu Asthana said.
“So, it’s not something very lightly that we would want to move away from,” Asthana said. “I think they have worked, but — and there’s a ‘but’ — as you know, we’ve been expressing resource adequacy concerns for some years now, and they’re driven by generator retirements, slow new entry and accelerating demand growth.”
Artificial intelligence is effectively just a “toddler” at this point, with ChatGPT launching less than three years ago, Asthana said. The technology is only to grow, and Asthana said he believes it will change the world — and in the process lead to much higher demand for power.
Other regions have seen their once large reserve margins shrink down to their minimum targets, and that is likely to remain the case.
“We hit minimum planning reserve margins in 2022; we’ve been treading water to maintain that level ever since,” MISO Senior Vice President Todd Ramey said. “I think that’s the new normal for our region. All of the incentives do not point to excessive planning reserve margins.”
A key way MISO keeps track of resource adequacy is surveys it conducts with the Organization of MISO States, which represents states that largely are vertically integrated. The latest survey June 6 will show the industry in the region has work to do to maintain its reserve margin target next year and for the rest of the decade, Ramey said.
A longer-term 20-year assessment from a couple years ago showed only renewables coming online, which would have left the grid short of key reliability services. But Ramey said that has changed for the next long-term assessments as states have added more dispatchable resources to their plans.
For states that have ceded more control to FERC, the options to ensure reliability are more limited, with van Welie suggesting some kind of financial hit is needed, such as a penalty baked into the market, or just letting scarcity pricing occur in the spot market.
While restructured states have given FERC more control over resource adequacy, none of them under its regulation has gone as far as Texas, where the standard utility has been eliminated, leaving large parts of their customers still on utility service. Asthana suggested states could change the rules set for utilities to procure supplies for those customers to boost bilateral trading and supplement the wholesale market.
“Because a lot of the load clears through state-run auctions, I think our states have the ability to try to hedge their consumers through those auctions for capacity,” Asthana said. “And I think those hedges and those bilaterals will also incentivize new generation, and those are conversations we’re having with our states.”
State of PJM’s Markets
After an initial panel of ISO/RTO CEOs, the technical conference started focusing on regions, and PJM got the most attention, with three panels taking up more than half a day.
Commissioner Chang noted PJM has seen some of the largest concerns, but paradoxically, it has seen some of the lightest renewable power development, with 93% of its generation still conventional.
Given that PJM is going through more retirements of conventional generation, and most of the new developments are renewables, the mismatch in retirements and replacements is a concern for the near future, and the RTO already has to start planning for it, said Vice President of Market Design and Economics Adam Keech. On top of that, PJM has several hot markets for data centers, with the resulting demand growth acting as an accelerant to every other issue it faces.
Data centers are looking for highly reliable, 24/7 power, but a recent study from Duke University showed they can be flexible if they use on-site resources such as batteries to participate as demand response, said LS Power Senior Vice President of Wholesale Market Policy Marji Philips. (See US Grid has Flexible Headroom for Data Center Demand Growth.)
“It’s really only the times the system is stressed that you need the thermal generation,” Philips said. “The problem is when it’s stressed, you need it all. And PJM, as Adam said, is seeing a retirement of those resources.”
Renewables are dominating the queue, and the most economical of those are going to be built and will benefit the grid and consumers, PJM Independent Market Monitor Joe Bowring said.
“All I’m saying is that there’s a baseline level of dispatchable resources you need for reliability to meet the demand during the high expected unserved energy hours,” Bowring said. “So, I mean … low-marginal-cost energy is great for customers, but it doesn’t meet that same reliability.”
But PJM Power Providers President Glen Thomas doubted Pennsylvania will change course and said Ohio just reaffirmed its market-centric policy with a recent change in law. Illinois, Maryland and New Jersey all restructured, and they have moved to a middle path, relying on the markets while being more active in picking resources, which he argued led to the retirements of others.
“They’ve largely been able to do that because of the tremendous surplus that Pennsylvania has built up,” Thomas said. “And I would also add that Pennsylvania would never have been able to build that surplus under a vertically integrated [integrated resource plan] regime. There’s no way state regulators would allow the system to be that overbuilt.”
Now that excess capacity is bailing out even Virginia, which is a vertically integrated state that is dealing with massive demand growth from its world-leading data center market, he said.
Chair Christie, who was a regulator on Virginia’s State Corporation Commission for years before joining FERC and is a strong proponent of its regulatory setup, said traditional regulation worked for years there and only ran into the same issue around unexpected demand growth that is causing issues around the country.
“That was a decision driven by policies adopted by our legislature to give tax subsidies to data centers and other attractions, which the utility commission had nothing to do with,” Christie said. “So, the IRP system is not the reason, as Glen said, Virginia is now a big importer.”
The prices are getting too high even for Pennsylvania, PPL Chief Legal Officer Wendy Stark said. The capacity market cleared at $270/MW-day last time, which was enough for Gov. Josh Shapiro (D) to file a complaint. That led to a settlement capping the next two auctions at $325.
“That also is not enough to incent new generation, so customers will be paying even more than they are now,” Stark said, adding that prices need to be at $500 to $600/MW-day. “That’s a problem, and as a utility with that obligation to serve, we at this point are really dependent upon the PJM capacity market. I will tell you at this point that feels like a single point of failure for us.”
Pennsylvania and other states restructured because cost-of-service regulation proved inefficient, which meant high costs as well, Bowring said.
“The idea that a regulated generator, because it’s subject to a regulatory process, is going to do things more efficiently is questionable,” Bowring said. “The markets have demonstrated the reverse for quite some time. So, I didn’t think I’d be here jumping up to defend the PJM capacity market.”
Bowring also doubted that the mandatory market ever will be meaningfully substituted with bilateral deals because it effectively forces much of that activity into the capacity auctions.
“Cost-of-service regulation worked to provide reliability for 100 years,” Bowring said. “It could certainly do that. I think it did it at a higher cost than markets.”
Capacity is a political construct, and states should be given more say in how it is managed, said Jacob Finkel, deputy secretary of policy in Shapiro’s office. The 14 states that are in PJM are swamped by the sheer number of stakeholders in a process that does not give them major formal input, he said.
“Most of our ability right now revolves around whatever goodwill we can build with PJM around working with the board and working with management, and it should be more than that,” Finkel said.
With the disconnect between price signals and new supply as the balance is getting tighter, Finkel suggested PJM needs to embrace resources such as virtual power plants (VPPs) and grid-enhancing technologies (GETs) that can be added to the grid quickly.
“All the acronyms should be deployed,” Finkel said.
Getting such resources will help, but after the quip, Finkel said ultimately if the issues around the market cannot be resolved in a way that is fair for ratepayers, Pennsylvania could move back to its own planning.
IESO politely said “no” to many of the stakeholder-requested changes to the design of its proposed Local Generation Program, but noted it will include the raised concerns in its report to the Ontario government in July and signaled it was open to further discussing others before then.
The program is intended to maintain existing distributed energy resources whose contracts are expiring in the next five years and procure new facilities. However, several groups of stakeholders asked the ISO to consider changes to elements of the program before it submits its official recommendations to the minister of energy and electrification. (See Suppliers Call for Changes to IESO Local Generation Proposal.)
In a webinar June 5, IESO programs strategist Greg Bonser explained the ISO’s rationale for the program’s contract length, project size cap and competitive pricing.
Cooperatives and generators, among others, had requested a longer contract term than IESO’s five years for facilities renewing their contracts. While new facilities would be offered longer contracts, and the ISO is considering different terms for resources that need upgrades, “we have found that under our Medium-Term RFP, we recently offered a term for re-contracting for five years, and it worked quite well to re-contract larger, existing facilities that are connected to the transmission system, so we’re going to replicate that,” Bonser said.
Some stakeholders also had asked for generators over the proposed maximum of 10 MW to be included in the program; others asked for those under the minimum of 100 kW.
Bonser said IESO is firmly against raising the size cap.
“Under the current practices and regulations and whatnot, once you go over 10 MW, there’s a whole new set of rules that need to be followed around connection assessments and around the way in which our control room tries to manage those facilities,” he said. He noted there were other ways for participating in the ISO’s markets — a note he made several times throughout his presentation when talking about facilities not eligible for the program.
The ISO, however, is considering lowering the threshold for program participation.
“We’re open to having a discussion about what kind of value those facilities can bring and whether or not they’re a good fit for this program,” Bonser said. “We heard a lot of small facilities say they felt they might not be cost competitive, so we need to have a conversation with” them.
Not up for consideration is including facilities under 10 kW, he said. “We also do have to draw a line somewhere.”
That goes for standard offer pricing as well. Bonser called it “quite a costly and difficult thing to figure out, frankly. It’s hard to keep everybody happy, and it ends up being costly to the ratepayer. We take the position that the facility owners are best positioned to review their own systems, figure out the costs and tell us what you need to keep the facility running, or what you need to build a new facility.”
‘Spirit of Simplicity’
About 220 people attended the webinar. There were several questions seeking clarification about the re-contracting and new-build “streams,” specifically about how different fuel types will be treated in each.
IESO said existing facilities of the same type would be grouped together in the bidding process, which prompted some attendees to question whether the ISO was going against its fuel-agonistic policy. Bonser said the reason for this was to “provide continuity, and they can continue to generate after their contracts expire.”
When asked if this was “definitive,” Jonathan Scratch, IESO senior manager of market and system adequacy, chimed in to say the ISO was presenting only what it will recommend to the minister. He also emphasized that the fuel type grouping would apply only to the re-contracting process; new resources would all bid against each other, regardless of fuel type.
The new-build stream would begin six months after the re-contracting process began, but IESO officials declined to comment on when that would be. The program is expected to begin in 2026.
IESO is requesting more information from stakeholders or will seek guidance from the government on several requests, including:
how to integrate DER aggregations into the program in an “administratively simple” way;
how to allow behind-the-meter facilities to participate in the program;
whether municipal council resolutions or indigenous support should be required for participation;
how cooperative or indigenous ownership should be considered; and
how refurbishments, upgrades, expansions or repowering should be accommodated.
Officials repeatedly stressed that “simplicity” in the program is a high priority for the ISO. Eric Muller, the Canadian Renewable Energy Association’s director for Ontario, noted that the Medium-Term RFP “did not include rated criteria points and other policy considerations or land-use considerations or partnership factors. … It was a simple, straightforward competition on price. … I would just put forward that, in the spirit of simplicity, something similar be considered for re-contracting under this program.”
ERCOT stakeholders have advanced a protocol change that provides longer-duration ancillary services and state-of-charge (SOC) parameters in advance of real-time co-optimization’s deployment in December.
The ERCOT-sponsored protocol change (NPRR1282) updates duration requirements to 30 minutes for regulation service and responsive reserve service and one hour for ERCOT contingency reserve service (ECRS). It also revises reliability unit commitment studies’ requirement to a one-hour duration for all ancillary services, excluding fast frequency response.
Staff told Technical Advisory Committee members that longer-duration AS are needed to manage grid variability and uncertainty. The grid operator, the Independent Market Monitor and stakeholders were split on the appropriate duration for non-spin and ECRS.
Several renewable interests said ERCOT’s RTC dispatch or SOC enforcement requirements will be “unnecessarily and administratively restrictive” of the amount of megawatts energy storage resources can offer.
The IMM recommended setting the non-spin duration constraint to one hour instead of four, saying that would incent batteries to provide energy rather than reserves. It said the four-hour duration also would deplete batteries’ SOC.
“The operations posture we have is the operations posture we have,” said Nitika Mago, senior manager of balancing operations planning. “As things evolve, I’ve conceded again and again we are happy to revisit it. But today, with the way we operate the grid and with the type of risks we see for non-spin, a four-hour duration is appropriate.”
In the end, Mago’s commitment to review information generated during RTC’s market trials, which begin in July, and an analysis of duration in the 2027 AS methodology document won over many stakeholders with concerns.
A motion to approve the NPRR with comments filed by ENGIE and Jupiter Power, and its associated Nodal Operating Guide change (NOGRR277), failed 11-18. When the comments were removed, the measure passed 26-2, with one abstention. ENGIE and Jupiter Power cast the dissenting votes.
The NPRR was granted urgent status so its parameters can be installed for RTC’s market trials.
Members Table Curtailment Change
TAC’s members unanimously agreed to table NPRR1238 and NOGRR265 after a lengthy discussion on their merits. The changes introduce a new early curtailment load (ECL) category and also would establish a process allowing loads to operate as an ECL so they can be accounted for differently in load-shed tables.
The committee will take up the issue again during a special webinar June 12.
ERCOT legal staff recommended tabling the two measures pending the Texas Legislature’s final consideration of Senate Bill 6. The legislation, addressing large loads, was under consideration before the session’s expiration June 2; several parties agreed with the need to align with the legislative process. (See Growing Clean Energy Sector in Texas May Avoid Damaging Legislation.)
Staff said the grid operator generally supported the NPRR but said they had concerns over large-load curtailments before energy emergency alerts.
Stakeholders expressed concerns with mandating loads — primarily industrial — to register as curtailable. NPRR1238 is intended to cover flexible loads sensitive to high prices, not all large loads.
The Public Utility Commission’s Barksdale English agreed with the decision to table the changes, saying it would be “smart” after amendments had been added two days before.
Oncor $855M Project Endorsed
TAC endorsed staff’s recommendation to award Oncor Electric Delivery a $855.3 million project in West Texas by placing it on the combination ballot, which acts as a consent agenda.
Oncor submitted the proposed Delaware Basin Stage 5 project for the Regional Planning Group’s review in May 2024. Wind Energy Transmission Texas (WETT) submitted an alternative project in August 2024.
Staff said Oncor’s proposal addresses reliability concerns and accommodates “significant and rapid load growth” in the petroleum-rich Delaware Basin area and also was less costly and required the least amount of transmission lines requiring regulatory approval. Oncor’s project requires 220 miles of transmission approval, while WETT’s costlier proposal ($871 million) is 232 miles long.
The project was identified in a 2019 ERCOT study that found the need for an import path to serve load once the Basin’s peak demand is greater than 5,422 MW. Staff said the 2023 Regional Transmission Plan’s 2025 case exceeds that level.
The project is expected to be in service by December 2029.
Committee members also confirmed Longhorn Power’s Bob Wittmeyer and ERCOT’s Patrick Gravois as chair and vice chair, respectively, of the Large Load Working Group by adding the recommendation to the combo ballot. The group, which recently removed “Flexible” from its title, has scheduled a workshop July 11 for data centers and electronic loads, with a focus on behind-the-meter systems that can survive low voltage and stay on the grid or resolve low-voltage issues.
Outage Capacity Changes
Stakeholders unanimously approved staff’s revisions to the methodology used to calculate the maximum daily resource planned outage capacity (MDRPOC).
The revisions are intended to provide sufficient outage capacity compared to historical levels by applying a risk-based construct for outages more than seven days ahead. Staff created a new MDRPOC curve to better evaluate thermal resources, and they have incorporated minimum outage levels in winter and summer to spread outages throughout the year.
ERCOT plans to apply the first future year MDRPOC to subsequent future years, saying there is a higher risk of limited resource commitments and project load growth in later years. Renewable resources and storage units will have their MDROPC calculated based on 110% of the historical maximum planned outages from the previous three years.
The measure passed 17-0, with 10 abstentions. The independent generators, power marketers and retail segments each provided three abstentions.
ERCOT is accepting comments on its proposal through June 9. It will go before the board during its June 23-24 meeting.
TAC Endorses ADER Doc
TAC endorsed a governing document for the third phase of ERCOT’s Aggregated Distributed Energy Resources (ADER) pilot project by adding it to the combo ballot.
Staff proposed increasing participation limits to 160 MW for energy and 80 MW for non-spin reserve service and ECRS, respectively. Phase 3 will allow a new participation model similar to non-controllable load resource (NCLR) and will enable third-party qualified scheduling entity (QSE) aggregation under the NCLR model, regardless of load-serving entity affiliation.
The grid operator will continue to analyze ADERs’ effect on system reliability and market efficiency, focusing on shift factor discrepancies and telemetry validation improvements.
ERCOT said that as of May, three ADERs have been qualified. They offer 15.5 MW capability for energy, with 8.6 MW for non-spin and 8.8 MW for ECRS. Nine additional ADERs are in various stages of registration, it said.
The combo ballot also included the strategic objectives for the Retail Market and Wholesale Market subcommittees, three other NPRRs, one NOGRR, a single change to the Planning Guide (PGRR) and an Other Binding Document (OBDRR) that, with required board approval, will:
NPRR1226: Direct ERCOT to prepare and publish estimated demand response data showing aggregated state estimated load points selected by ERCOT. Loads selected for the report will be based on periodically updated off-line analysis of the frequency and magnitude of reductions observed in historical state estimator load data that is associated with LMPs, ERCOT-wide conservation appeals or other market signals.
NPRR1267: Require a large-load interconnection status report be published. The report won’t define “large load”, leaving that to NPRR1234 (Interconnection Requirements for Large Loads and Modeling Standards for Loads 25 MW or Greater). Confidential customer information on large loads will be aggregated.
NOGRR275: Align the guide with protocol changes to eliminate scheduling center requirements for QSEs that are not wide-area network participants.
OBDRR054: Create a process by which transmission and/or distribution service providers will require market participants to successfully test retail transactions before their data universal numbering system is activated in a TDSP’s production system.
PGRR125: Add language to that guide that allows an interconnecting entity or property owner to demonstrate compliance under the Lone Star Infrastructure Protection Act should it have a subsidiary or affiliate that falls under the act’s citizenship or headquarters criteria. The subsidiary must not have direct or remote access to or control of the project, the project’s real property, resource integration and ongoing operations, the market information system, other ERCOT systems or any confidential data from the systems.
Artificial intelligence may be helping employees streamline a variety of tasks, but AI also is making work easier for threat actors plotting cyber attacks against electric utilities, experts said during a WECC webinar.
And the AI influence comes as utilities are facing cyber threats from multiple directions.
“Sophisticated state actors” are trying to access electricity networks for future disruptive attacks, according to Phil Tonkin, field chief technology officer at cybersecurity firm Dragos. Tonkin was a panelist during the June 4 cybersecurity webinar, part of WECC’s Reliability in the West discussion series.
According to the federal Cybersecurity and Infrastructure Security Agency (CISA), cyber actors sponsored by the People’s Republic of China want to pre-position themselves on IT networks “for disruptive or destructive cyberattacks against U.S. critical infrastructure in the event of a major crisis or conflict with the United States.”
In addition, Tonkin said, there are activists looking for low-hanging cybersecurity fruit and criminals who are eyeing organizations to target in ransom attacks.
Dragos has been tracking a group called Voltzite that targets electrical infrastructure.
“This is not a hypothetical threat,” Tonkin said. “We have seen this organization knocking on the door of many power utilities across the U.S., and through the Pacific as well. On top of that, we’ve seen actual successful intrusions into utilities.”
Treigh Pedroche, senior security architect at WECC, said generative AI can help a threat actor figure out how to exploit a cybersecurity vulnerability that previously might have required advanced reverse-engineering software skills.
“Prior to these tools, I had to be maybe [an] expert-level software engineer,” Pedroche said. “Now I just have to be good at using a Gen AI tool.”
Another issue is when employees use AI for tasks such as summarizing data or writing executive summaries. The information provided to AI is loaded into public models, Pedroche said, and threat actors may then be able to extract it.
AI also can help attackers devise phishing emails, identifying employees to whom to direct the messages and crafting convincing language, which is especially helpful for foreign adversaries.
Tonkin gave an example of an email sent to a utility employee by a “customer” who was worried about a buzzing power pole in their yard. They even attached a photo.
“That’s the sort of thing people are going to fall for,” Tonkin said. “And that’s what’s happened in a number of countries around the world. There’s a European utility which was exploited just like that.”
In 2024, four cybersecurity intrusions in the Western Interconnection were reported through the Department of Energy’s Electric Emergency Incident and Disturbance Report, according to WECC’s most recent State of the Interconnection report.
In 2023, Dragos helped Littleton Electric Light and Water, a public utility in Massachusetts, root out Voltzite hackers who had gotten into the utility’s network. It was Voltzite’s first known intrusion into a U.S. electric utility’s computer system. (See Dragos Outlines Voltzite Electric Utility Breach.)
Working Together
Tonkin said the industry thus far has been keeping pace with cyber threats. But he noted that continuous efforts are needed to stay one step ahead of adversaries.
Electric utilities have an advantage in that regard, he said, because their service territories largely are distinct. Because they’re not competing against each other, it’s easier for utilities to share information and help each other out.
Pedroche pointed to resources available to utilities, such as intelligence reports from Dragos and CISA.
“For us, the defenders, we’re almost always on that back foot,” Pedroche said. “Utilizing those [resources] as best we can to the fullest is really going to be key.”
The Northeast Power Coordinating Council, the regional entity covering New York, New England and four Canadian provinces, said in its 2025 Summer Reliability Assessment that only the Maritimes provinces of New Brunswick and Nova Scotia show a significant likelihood of needing to implement operating procedures during the summer months under expected peak conditions.
However, the RE acknowledged that New York and New England also face the risk of loss of load expectation under more severe conditions, illustrating “a growing concern regarding resource adequacy under extreme conditions.” NPCC said utilities have “strategies and procedures … in place to manage potential operational challenges and emergencies as they arise.”
Coincident peak demand for the entire region was estimated in the report at 104,606 MW, occurring during the week beginning Aug. 3 with a forecast net margin of 9,279 MW, or 8.9%, in the RE’s 50/50 forecast (representing a 50% chance that the actual peak load will be higher or lower than the prediction). The net margin forecast in 2024 was 12,382 MW.
Overall, NPCC’s projected generation capacity has decreased by about 1,300 MW from last summer to 157,000 MW, with the biggest capacity reduction due to the planned retirement of the Pickering G1 and G4 nuclear units in Ontario.
The revised net margin, excluding bottled resources (calculated by subtracting the available transfer capacity between Quebec and the Martimes and the rest of NPCC from the total net margin for the two subregions), stood at 8,397 MW. NPCC’s lowest margin for the summer is projected as 4,675 MW, or 4.5%, during the week beginning July 13. By comparison, NPCC’s all-time coincident peak demand was 112,552 MW on Feb. 3, 2023, and its all-time peak for summer was 112,384 MW on Aug. 1, 2006.
Resource fuel type by reliability coordinator area for the coincident peak week beginning Aug. 3. | NPCC
In the 90/10 forecast, representing a 10% chance that peak load will exceed expectations, peak load was significantly higher, at 111,061 MW, resulting in a net margin of 2,825 MW and a revised net margin of 1,943 MW.
Finally, the RE’s above 90/10 forecast — “a low-probability, high-impact composite scenario [relying] heavily on individual area risk assumptions” — had demand even higher at 114,943 MW, with more than 5,000 MW of additional unplanned outages and derates, resulting in a revised net margin of negative 7,381 MW. A negative revised net margin “indicates a combination of imports and operating procedures will be necessary to mitigate potential resource shortages,” NPCC said.
The “single most important variable” affecting demand this summer is weather conditions, the report said, noting that despite the identification of the overall peak week, “summer peak demand could occur during any week of the summer period because of these weather variables.”
This fact could add to the reliability challenge if, for example, a widespread weather event causes multiple regions’ peaks to arrive at the same time. NPCC observed that peak demands in New England and New York already “have a high degree of correlation” historically, and Quebec’s summer peaks in recent years have begun to contribute to the coincident peak as well.
Generation resource mixes continue to vary widely across the RE’s footprint. In Quebec, hydro and tidal power are expected to make up 88% of all generation, with wind second at 9%, while in New England, hydro and tidal stand at just 11% and dual-fuel plants take the largest share at 31%, with gas close behind at 30%. In New York, dual-fuel dominates at 49%, and in Ontario, nuclear has the largest share, with 32%. Finally, in the Maritimes, no single generation source accounts for more than 25% of the mix; the largest share of generation is held by coal, at 22%.
NPCC noted its support for registered entities facing adverse system operating or weather conditions, outlining its ability to coordinate emergency communications including conference calls between affected entities. The RE also monitors weather conditions and supports information sharing and other coordination efforts between the natural gas and electric industries.
The “assessment indicates our region has spare capacity for this summer, which can be used to help mitigate reliability risks that may result from unexpected unavailability of key facilities, fuel supply interruptions, generation maintenance or higher-than-anticipated demand,” NPCC CEO Charles Dickerson said in a statement.
PORTLAND, Ore. — In their respective speeches during the annual meeting of the Western Conference of Public Service Commissioners, outgoing FERC Chair Mark Christie and former Colorado Gov. Bill Ritter both emphasized that the West controls the future of the Western Interconnection, not Washington.
Christie addressed WCPSC participants remotely June 2, a few hours before news broke that President Donald Trump would nominate Laura Swett of Vinson & Elkins to replace Christie on FERC. (See related story, Trump Replacing FERC Chair Christie with Laura Swett.)
Christie said in his speech that the “early days” of FERC trying to force states and utilities to join an RTO are over.
“It’s called standard market design, and I remember that, and I thought that was a horrible mistake. And fortunately, it didn’t happen,” Christie said.
“It’s not for us at FERC to tell you what to do,” he told the audience. “You’ve got to make that choice on what’s right for you.”
The chair said if the West decides to create an RTO, the industry should think of it “as a bundle of services,” functioning mainly as a grid operator.
An RTO is “not one single service. … I liken it to going through a cafeteria,” he said. “You can pick what you want and not pick what you don’t want.”
Christie’s comments come as many in the power industry in the West are deciding whether to join day-ahead markets offered by either SPP or CAISO.
“You’ve had the choice for years to go into CAISO’s energy market, the [Western Energy Imbalance Market], without even joining … the CAISO itself. So, you can even pick the market without the RTO, but you’ve got a choice of a real-time energy market,” Christie said. “You’ve got a choice of a day-ahead market now; CAISO has it; SPP offers it.”
SPP operates WRAP, and the program will provide a mandatory RA framework for participants in Markets+ in an effort to ensure members with a surplus generating capacity assist those with a deficit.
“Resource adequacy is a challenge everywhere,” Christie said. “And we’ve seen with the data center explosion … load forecasts that are just mind-boggling.”
In a similar vein, Ritter, founder of Colorado State University’s Center for the New Energy Economy, noted the energy industry is grappling with significant change, both politically and technologically.
For example, artificial intelligence will impact technologies that provide power to the grid, but also power demand on the grid, Ritter said during his WCPSC address June 4.
Another change is shifting views on the energy transition, Ritter noted. He pointed to the One Big Beautiful Bill Act that recently passed in the House of Representatives. The bill would extend tax cuts for individuals and render energy tax credits effectively useless. The proposed legislation is a sharp departure from the Inflation Reduction Act of 2022, passed by Democrats, which expanded clean energy tax credits. (See House Passes Reconciliation Package that Would End Energy Tax Credits.)
Long-term planning and near-term decision-making become difficult when “the politics of the moment can shift on a dime,” Ritter said.
However, the West still exercises control over how it chooses to modernize its grid, whether it’s through RTOs or day-ahead markets, but that requires bipartisan discussions over state lines, according to Ritter.
“We need to talk across political boundaries, within states, in order to solve this issue about how we should build out transmission of the West and what that should look like as we go forward, as we look at the things that are going to change,” Ritter said.
“It’s going to be difficult, but if we don’t do it, we’re going to wind up a little bit like Washington, D.C., sounds right now,” Ritter said. “A fairly toxic place — difficult to operate.”
The International Energy Agency is forecasting record energy investment worldwide in 2025, despite the present uncertainties and headwinds.
As it released the 10th edition of its annual report June 5, the IEA said investment in clean technologies is predicted to hit $2.2 trillion this year, or about two-thirds of the total energy investment. Both figures would be record highs — the $3.3 trillion total investment would be 2% more than in 2024.
Photovoltaic solar is drawing more investment than any other technology, IEA said, and China is investing more than any other country or bloc of countries.
“When the IEA published the first ever edition of its ‘World Energy Investment’ report nearly 10 years ago, it showed energy investment in China in 2015 just edging ahead of that of the United States,” IEA Executive Director Fatih Birol said in the news release. “Today, China is by far the largest energy investor globally, spending twice as much on energy as the European Union — and almost as much as the EU and United States combined.”
The 10-year stretch was marked by another change: a de-emphasis on fossil fuel investments. In 2015, investment in the fossil sector was 30% higher than in electric generation and grids. In 2025, electricity investments are expected to be 50% greater than in fossils.
The volatility seen in the global economy and trade so far has not had a major effect, Birol said: “The fast-evolving economic and trade picture means that some investors are adopting a wait-and-see approach to new energy project approvals, but in most areas, we have yet to see significant implications for existing projects.”
IEA also flagged a disconnect that has been apparent in some regions for some time: The investment in grids to transmit all this new electricity is not keeping up with the investments to generate and use that electricity.
Transmission investment stands at $400 billion annually but is being held back by cumbersome permitting processes and limited supply of transformers and cables.
There also remains a significant geographic disparity in all types of investment. Many emerging markets and developing economies lag far behind the advanced economies, IEA said, particularly in Africa, which is home to 20% of the world’s people but attracts only 2% of global clean energy investment.
Looking specifically at the United States, the IEA report contrasts its increasing production and export of oil and natural gas over the past decade with its decreasing percentage of electricity generation investments going to fossil fuels.
The International Energy Agency expects investment in renewable power generation to outstrip fossil fuel power by a wide margin in the advanced economies and China but a narrower margin in emerging markets and developing economies. | IEA
IEA also notes the surging investment in data centers and the interest in powering them with clean energy, and the resulting enthusiasm for next-generation nuclear power to fulfill that need non-intermittently.
With its deep financial resources and its long history in nuclear power, the United States could emerge as a leader in next-generation nuclear, as well as in other technologies, such as geothermal, IEA said.
But here again, interconnection delays and transmission constraints are a potential hurdle. Power availability is the top concern for 90% of data center developers, IEA said, and nearly 50% consider upgrading grid infrastructure to be the best possible mitigation for this.
Compounding the problem, data center operators are competing with generation and transmission developers for the already-inadequate supply of key grid components such as transformers, IEA said. As a result, while a data center can take three to six years from concept to completion, new grid infrastructure can run five to 15 years.
FERC Order 2023 and other grid reforms may prove to be critical tools to enable growth, it added.
