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December 15, 2025

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FERC Dives into Thorny Resource Adequacy Issues at Tech Conference

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.” 

The resource adequacy issue and consumer costs in PJM have caused some to question longstanding policies on the market. (See Utilities Pushing for a Return to Owning Generation in Pennsylvania.)  

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. 

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IESO Sticking with Local Generation Program Design

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.”

Written feedback from the webinar is due June 19.

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ERCOT’s TAC Extends Duration of Ancillary Services

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 pilot began in July 2022 and recently transitioned to ERCOT. (See “ADER Discussion Moved to WMS,” ERCOT TAC Opens Discussion on Proposed RTC Changes.)

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.
    • NPRR1276: Incorporate an OBD, “Emergency Response Service Procurement Methodology”, into the protocols to standardize the approval process.
    • 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.
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AI Adds New Dimension to Utility Cyber Threats, Experts Say

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.” 

In addition to its cybersecurity webinar, WECC will be hosting a Power Systems Security Conference on Aug. 12-14 in Salt Lake City.  

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NPCC Warns of Weather Impacts on Summer Margins

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.” 

NPCC approved its SRA on May 9 but released it June 4, following the release of NERC’s summer assessment on May 14. (See NERC Warns Summer Shortfalls Possible in Multiple Regions.) The assessment covers the week beginning May 4 through the week beginning Sept. 21. 

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. 

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FERC not in Charge of Modernizing Western Grid, Christie Says

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.”

Christie also heaped praise on the Western Power Pool’s Western Resource Adequacy Program (WRAP), saying, “I think the concept is great.” (See related story, Industry Needs ‘New Planning Paradigm,’ BPA Chief Tells Regulators.)

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.”

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IEA Predicts Another Record Year for Energy Investments

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. 

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MISO’s 2022 and 2023 Queue Study Cycles Delayed Again

MISO’s 2022 and 2023 generator interconnection queue cycles are lagging behind their stated timelines once again as the RTO continues working to produce study results in a new, automated process.

The grid operator said it now will post a final system impact study for the 2022 cycle July 8 and move those generation proposals to the second phase of the three-part queue by Aug. 6. It will move on to studying project applications submitted in 2023 on Aug. 20.

This is MISO’s second postponement for the 2022, 2023 and 2025 queue cycles. The grid operator skipped acceptance of a 2024 cycle while it tried to get a handle on study delays and design a megawatt-capped queue that could sort out projects over a one-year span instead of three to four years.

In January, MISO planned to begin studying the 2023 cycle in May and the 2025 cycle by the end of the year, a few months behind the schedule it announced in 2024. At the time, the grid operator envisioned all generation projects from the three cycles striking interconnection agreements over 2026, with the 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026. (See MISO Unveils Later Timeline for Queue Processing Restart.)

MISO’s Kyle Trotter said MISO would post a new schedule soon detailing when it will proceed with the 2025 cycle of projects.

Senior Manager of Resource Utilization Ryan Westphal said MISO wants to finalize the 2022 cycle’s system impact study after multiple rounds of adjusting modeling assumptions at stakeholders’ suggestions and presenting different drafts of the study for review.

“We’re ready to move forward at this point,” Westphal said during a June 3 teleconference focused on MISO’s interconnection process. He added that MISO will account for project withdrawals from the 2022 cycle in the screening process for the 2023 batch of projects.

MISO is using Pearl Street’s automated SUGAR (Suite of Unified Grid Analyses with Renewables) study software to screen generation projects and perform the first phase of studies in the queue. (See MISO: New Software Effective, Faster than Previous Queue Study Process.)

Westphal said MISO’s later, Aug. 20 study kickoff also would give the RTO time to seek FERC approval to include MISO and SPP’s $1.65-billion Joint Targeted Interconnection Queue (JTIQ) portfolio in its modeling for the 2023 cycle of generation projects. The move is unpopular among MISO’s generation developers, who are set to shoulder all JTIQ costs; they’ve said the cost allocation could attach high, unpredictable expenses to their projects. (See MISO Gen Developers Sour on RTO’s JTIQ Cost Allocation.)

“We want to make sure we have enough time to hear back from FERC,” Westphal said.

MISO has 1,273 projects totaling 237.8 GW in its interconnection queue.

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PJM Board Elects David Mills as Chair

The PJM Board of Managers has elected David Mills to serve as its chair.

“It is an honor to lead this board at a time when continuity and stability are critical to our mission of preserving the reliability and affordability of the grid,” Mills said in an announcement PJM published June 5. “Our stakeholders have made clear their desire to strengthen communication channels with the board, which we have already taken steps to accomplish. I look forward to working together to make the hard choices required of us to maintain the balance between electricity supply and demand.”

He was elected to the board’s chair-elect position in 2024, putting him in place to assume leadership if the prior chair, Mark Takahashi, left the role. Takahashi was not elected to another term on the Board of Managers during the May 12 Members Committee meeting and took his name out of the running before the vote was set to be reconsidered the following day. Mills was elected formally to be the board’s chair on May 14.

“David is a very capable leader,” PJM CEO Manu Asthana said in the announcement. “He understands the tradeoffs required to preserve reliability and affordability, and he has demonstrated his commitment to listening to and working in partnership with our stakeholders. I am confident that the reins of the PJM board are in able hands.”

During the May 12-14 PJM Annual Meeting, Mills said he supports the board taking steps to improve communications with stakeholders. He said he would seek to add agenda items to future Members Committee meetings for attending board members to speak with stakeholders during the meeting, as well as for them to remain accessible after the meeting and wait until the following day to return home.

Mills first was elected to the board in 2021. He has chaired the Competitive Markets Committee and is a member of the Nominating Committee. Prior to joining the board, he served as Puget Sound Energy’s chief strategy officer and previously worked for the Bonneville Power Administration. He earned a Bachelor of Science in economics from Portland State University.

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UPDATED: ‘Pathways’ Bill Passes California Senate on 36-0 Vote

The California bill to implement the West-Wide Governance Pathways Initiative’s Step 2 proposal to allow CAISO to relinquish market governance to an independent “regional organization” (RO) passed the state Senate on June 4 on a 36-0 vote, with four members abstaining. 

SB 540 was approved after 40 minutes of floor debate in which several senators expressed concern about the extensive amendments added to the original bill, particularly a provision creating a new Regional Energy Market Oversight Council responsible for ensuring CAISO’s participation in a regional energy market that “serves the interests of the state.” (See Amended ‘Pathways’ Bill Boosts — and Complicates — Calif. Protections.) 

The new council would be authorized to mandate withdrawal if those interests are compromised. 

Those senators sought assurances that the bill’s sponsors, Sens. Josh Becker and Henry Stern, both Democrats, would work with members of the state Assembly to return the bill to something closer to its original form. 

But other senators said they wanted to ensure preservation of an “off-ramp” from the RO, expressing worry that the ISO’s participation could compromise California’s environmental and clean energy policies, particularly in the face of the Trump administration’s efforts to support coal-fired generation. 

Becker assured his colleagues the bill would not increase California’s exposure to federal political interference, but did point to the risks of the state losing potential “partners” on the electricity grid to “a market out of Little Rock” — SPP’s Markets+, the competitor for participants to CAISO’s Extended Day-Ahead Market (EDAM). 

“Make no mistake: if we do not act, we will be worse off,” Becker said. 

‘Strong Coalition’

During the debate, Sen. Tony Strickland (R) called the recent amendments to SB 540 “very problematic” but expressed confidence that Sens. Becker and Stern would “work out some of these problems” as the bill advances through the lower house.  

Strickland pointed to the “strong coalition” backing the bill, including labor and business groups.  

“I haven’t seen a coalition like this in a long time, and I’ve been on [Senate] Energy Committee going back 13, 14, 15 years,” he said. “Because everybody understands status quo is not an option. We need to get this fixed. We need to move forward. We need to make sure energy is reliable for all California residents.”

Sen. Angelique Ashby (D) opened her comments saying she likes to “brag” about the publicly owned utility that serves her constituency, the Sacramento Municipal Utility District (SMUD), and voiced concern that SMUD had changed its position on the bill in light of the amendments.  

Ashby asked the bill’s authors how they will “get from where you are now back to a space where you can earn the support of the one of the most trusted entities in the state of California, which is SMUD.” 

“I know SMUD, other than [having] issues with the bill, would like to see it move forward, and I’m committed to working with them going forward,” Becker said. 

Sen. Christopher Cabaldon (D) said a small portion of his constituents are served by SMUD and echoed Ashby’s concerns, urging “less work” to be done on the bill. 

“Because the problem here is all of the benefits of this bill — and they are numerous and profound — depend on us actually joining with the region and the region joining with us,” he said. “I think the problem that I hope we will work on to resolve in the Assembly is that we cannot replicate all of the state rules and interests and what have you, as though the rest of the world is just waiting for California to allow them to be partners.” 

Sen. Rosilicie Ochoa Bogh (R) said she supported the bill in the Senate Energy Committee “because it reflected a bipartisan, holistic compromise. Literally every group, as mentioned earlier, related to energy, visited my office, and nearly all were in alignment. Not all were pleased, but they were aligned.” 

But Ochoa Bogh said the proposed oversight council in the amended bill “fundamentally alters the governance structure” by giving the body “extraordinary authority” over California’s participation in a regional market. She said that would “inject an uncertainty into what should be a technical, market-driven process” and compromise long-term resource planning if the state were “suddenly withdrawn,” threatening grid reliability and affordability for residents. 

‘Energy Island’

Sen. Thomas Umberg (D) said SB 540 is “a very difficult bill” because it brings up “a clash of interests that is very difficult to reconcile” — namely, the differing views on climate change between California’s leaders and the Trump administration. 

“The challenge is that, once we’re in [the RO], it may be very difficult to leave, either legally or practically, because we become so reliant on the grid. And it also vests California in a place where, potentially, the current administration can wreak havoc on California,” Umberg said. 

Sen. Suzette Martinez Valladares (R) recalled a previous visit to CAISO was a “phenomenal experience” before noting the ISO has “urged” for a “regional approach.” She warned that California faced risking becoming “an energy island” like Texas, but also said she wanted additional clarity around the role of the proposed oversight council. 

Sen. Ben Allen (D) added his voice to supporters of the bill but said inclusion of the oversight council was “bizarre” and represented a “bad direction,” in part because it would make withdrawal from the RO a “governor-dominated” decision. He pointed to a suggestion that the decision should come down to “some sort of supermajority vote in the legislature.” 

Sen. Aisha Wahab (D) expressed the greatest reservations about SB 540, saying creation of the five-member oversight council is “not enough” and that she was concerned “that we’re not going to bring it back to the legislature to have a full picture of what this regional organization will actually look like.” 

“If it is that we have a lot of confidence in a regional organization — the fact that it won’t impact the RPS and won’t take away green jobs and won’t force Californians to subsidize an organization they no longer have control over — then we should be able to review the facts once we have more concrete evidence,” she said, later abstaining from voting on the bill. 

Sen. Anna Caballero (D) said she favored “regionalism” because “I think our weather patterns and the energy that we can create regionally is diverse enough, so it’ll benefit California.” But she also called for the bill to include the option for an “off-ramp” from the RO to avoid tying the hands of a future governor and legislature. 

In his closing speech stumping for his bill, Sen. Becker reminded his Senate colleagues that SPP’s Markets+ has been able to attract more participants in recent months. 

“So, if they’re able to sort of pull something together, we’ll end up isolated — so we need to do this,” he said. “I appreciate everyone who’s had their input and wants to keep working on this going forward.” 

Reactions

Clean energy groups that have backed the Pathways Initiative commended the California Senate for advancing the bill while also urging changes to the bill as it moves through the Assembly. 

“California can’t afford to go it alone when it comes to meeting skyrocketing energy demand while tackling the energy affordability crisis,” Edson Perez, California lead at Advanced Energy United (AEU), said in a statement. “We need to be able to keep the lights on in the fourth-largest economy in the world without charging ratepayers an arm and a leg. Joining a robust Western regional energy market is essential to keeping energy costs under control while still spearheading the transition to clean energy.” 

AEU said bill supporters “remain committed to ongoing collaboration to ensure the final version reflects the shared priorities of the diverse coalition engaged in this effort for regional energy collaboration.” 

“Today’s Senate vote is an important step in a long process to ensure California is at the forefront of a fast-moving revolution in how electricity will be bought and sold across the West,” Katelyn Roedner Sutter, California state director at the Environmental Defense Fund (EDF), said in a statement. “California cannot keep the lights on or solve the climate crisis alone — we need an electricity system with diverse clean resources that can withstand simultaneous extreme weather events.” 

Roedner Sutter said EDF shares “significant concerns about recent bill amendments that undermine the benefits of California’s participation in a Western market and urge California leaders to act decisively to avoid losing more trading partners to a competing Arkansas market.”