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December 12, 2025

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What is the Outlook for Batteries in PJM?

The outlook for utility-scale batteries in PJM is more complex than it has been at any point in the past decade.

Ali Karimian

While PJM historically has been seen as a market with large demand and deep industrial bases, when it came to actual deployment of batteries, investors typically found themselves confronted with unfavorable economics and slow interconnection processes.

But after the radical shifts of the past 12 months and those on the horizon, PJM is entering a new phase, marked by sharply rising capacity prices, more acute reliability pressures and a growing recognition that storage will be central to keeping the lights on.

In this article, we explore the outlook for battery storage in PJM.

Front-of-the-meter Model

In PJM, the front-of-the-meter (FTM) model traditionally has been built around two revenue pillars: frequency regulation services and participation in the capacity market.

Frequency regulation services have long been a reliable, but shallow, pool of income. PJM procures only around 600 MW of regulation as of late 2025, and as more batteries enter the market, prices soften. Most sophisticated investors therefore treat regulation revenue not as the core of a project’s value but as a bonus: useful, but not bankable.

On the other hand, the capacity market has transformed dramatically. Large numbers of fossil fuel power stations host data centers on-site, which effectively takes the capacity of the power plant out of the generation stack (in all or selected hours, depending on the data center load shape).

Electrification, particularly the expansion of data center load across the mid-Atlantic, has caused demand forecasts to spike. The result is a system that needs new, fast-responding capacity and is willing to pay for it.

The implementation of effective load carrying capability (ELCC) also has redefined how PJM values the contribution of limited-duration resources such as batteries. While the ELCC multiplier for storage is expected to decline over time as more storage joins the system, the immediate impact has been positive. In the 2025/26 and 2026/27 auctions, clearing prices surged, reflecting both the new valuation methodology and a tightening supply–demand balance.

For investors, this creates a more predictable and meaningful revenue floor for battery assets than at any time in recent memory. But capacity revenues alone are not the full story.

One of the reasons arbitrage historically has been weak in PJM is the region’s modest penetration of variable renewables on the system. Unlike California or Texas, PJM does not yet experience deep mid-day solar troughs or abundant periods of near-zero marginal-cost generation.

Arbitrage opportunities in such markets are driven by predictable, repeated patterns of low prices (when renewables flood the system) and high prices (when that renewable output fades). Without this dynamic, PJM’s price spreads have been comparatively shallow, limiting the upside. But this, too, is beginning to change.

As demand volatility increases, the frequency and magnitude of price swings is increasing. While PJM may not yet have the solar-driven volatility of CAISO, it is experiencing more meaningful peak-period scarcity pricing, which creates valuable opportunities for well-optimized storage assets. Even so, arbitrage remains secondary to capacity in the current environment; it is not yet the engine that can justify a standalone FTM build.

For many, these dynamics raise an inevitable question: If regulation is shallow, arbitrage still is emerging, and ELCC eventually may decline, is the FTM model fundamentally flawed in PJM? The answer is no, but it is evolving.

FTM storage requires a diversified revenue stack and a careful understanding of regulatory timing. The surge in capacity prices has revived interest in the model, and interconnection reforms are clearing some of the historic backlog.

Even so, the risks remain real: Interconnection queues are long, drop-out rates high, and market design still lags the reality of the grid’s need for flexible, fast-ramping assets. Ancillary-service saturation is a threat. Investors must approach FTM with eyes wide open.

Behind-the-meter Storage Tells a Different Story

When batteries sit behind large industrial or commercial loads, they deliver guaranteed value through peak shaving, demand-charge reduction and resilience benefits. Behind-the-meter (BTM) economics for battery storage are not tied primarily to wholesale-market conditions.

A factory, data center or distribution facility with high load during PJM coincident peaks can materially reduce its future capacity and transmission costs by deploying a battery, even without ever participating in regulation or arbitrage. As capacity and transmission prices surge, these avoided costs become even more valuable.

For businesses that control meaningful load, the BTM business case can be compelling, and dependably so. For businesses with large industrial loads, this means batteries can function as financial instruments as much as technological ones: tools for cost avoidance, resilience enhancement and participation in high-priced wholesale services.

Hybrid Structure Most Interesting

But the most interesting model today is neither pure FTM nor conventional BTM. Substation-located batteries, sometimes described as non-retail behind-the-meter generation (NRBTMG), offer a hybrid structure that combines the strengths of both.

When placed at a substation, a battery can offset the substation’s load during peak periods, yielding predictable cost savings while also participating in PJM’s markets when capacity, energy or regulation prices create favorable conditions. This effectively creates a dual-revenue structure: part risk-protected through peak-load reduction, part exposed to wholesale upside. It is a model that makes intuitive sense in a region like PJM, where system needs are rising but market design still leaves certain storage services undervalued.

Although it requires more careful stakeholder engagement and interconnection planning, it ultimately may prove to be the most economically resilient approach for storage developers.

The Market Signal is Strong

For the first time in PJM history, the market signal for flexible capability is strong, consistent and grounded in clear system need.

Studies from The Brattle Group suggest PJM needs roughly 16 GW of new four-hour energy storage by 2032 simply to maintain reliability standards. Rising peak loads, extreme weather and the rapid proliferation of data centers are shifting PJM’s risk profile fast enough that storage no longer is optional; it is becoming essential.

The most recent PJM capacity auction results, which hit the price cap in many zones, reflect that urgency. Despite this, deployment remains slower than required. PJM’s interconnection queue contains many gigawatts of proposed storage projects, but attrition rates remain high.

A combination of lengthy studies, shifting cost structures and evolving rules continue to impede progress. PJM needs storage, but its market structures and regulatory processes still make it challenging to build. This tension between system need and market execution is one of the defining features of the storage landscape today.

But the trajectory is unmistakable:

    • Capacity prices have reset to a sustainably higher level.
    • Policy reforms are accelerating.
    • Renewable penetration is increasing.
    • Industrial electrification is proceeding faster than many expected.

PJM stakeholders increasingly are motivated to deploy storage not only for market participation but for cost management, reliability and energy security.

In short, the outlook for utility-scale batteries in PJM is one of cautious but tangible optimism. The optimal storage strategy in PJM is not to chase a single revenue stream, but to design assets capable of capturing multiple forms of value. The strongest projects will be those that can respond dynamically to capacity price signals, exploit emerging arbitrage opportunities, deliver ancillary services when prices spike and directly reduce peak load.

Ali Karimian is market optimization director of GridBeyond, which just released its Global Energy Trends 2026 report.

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RSTC Approves Leaders for Next 2 Years

NERC’s Reliability and Security Technical Committee will soon have new leadership, after members chose a chair and vice chair at the RSTC’s quarterly meeting Dec. 10.

Current Vice Chair John Stephens from City Utilities of Springfield will move up to replace departing Chair Rich Hydzik of Avista after his term expires Dec. 31, with Srinivas Kappagantula of Arevon Energy taking Stephens’ role. An RSTC chair and vice chair can serve only a single two-year term, so Stephens will step down Dec. 31, 2027, barring unforeseen circumstances.

NERC Senior Counsel Candice Castaneda  observed that, since the RSTC’s last meeting, industry stakeholders have chosen a new slate of members in an election that ended Nov. 21. The newly elected members — some of whom already are on the RSTC — will serve two-year terms beginning Feb. 1, 2026, and ending Jan. 31, 2028.

    • Sector 1 (Investor-owned utility): Vinit Gupta, ITC Holdings
    • Sector 2 (State/municipal utility): David Grubbs, City of Garland
    • Sector 3 (Cooperative utility): Nathan Brown, Georgia System Operations
    • Sector 4 (Federal or provincial utility/federal power marketing administration): Wayne Guttormson, SaskPower
    • Sector 5 (Transmission-dependent utility): John Lemire, North Carolina Electric Membership Corp.
    • Sector 6 (Merchant electricity generator): Brett Kruse, Calpine
    • Sector 7 (Electricity marketer): Jodirah Green, ACES Power
    • Sector 9 (Small end-use electricity customer): T. David Wand, New Jersey Division of Rate Counsel
    • Sector 10 (ISO/RTO): Aaron Markham, NYISO
    • Sector 12 (State government): Cezar Panait, Minnesota Public Utilities Commission

Sector 8 (Large end-use electricity customer) had two open seats, for terms expiring Jan. 31, 2027, and Jan 31, 2028. Venona Greaff of Occidental and Mike Della Penna of Google were elected for this sector, and a sector election will be held to determine who will serve out which term.

Nominations are underway through Dec. 19 for the open at-large RSTC members, five of whom will serve two-year terms ending Jan. 31, 2028, and two of whom will serve out the terms of departing members that expire Jan. 31, 2027. The chosen representatives will join the three other at-large members whose terms end in 2027.

NERC’s Board of Trustees must approve the RSTC leadership changes and membership at its next meeting, scheduled for Feb. 11, 2026, in Savannah, Ga.

White Papers, Guidelines and Reference Documents

Following the leadership election, members approved the RSTC’s 2026-2027 Strategic Plan. The document sets expectations and deliverables for the RSTC in the coming year while guiding coordination with other standing committees.

Next, members approved a security guideline for addressing cybersecurity incidents affecting vendors of grid equipment. The RSTC’s Supply Chain Subcommittee developed the guideline in recognition of the risk cyberattacks on vendors could pose to the security of the electric grid. While following the guideline is not mandatory, it does present “key practices and information” to maintain reliable operation.

The SCS presented another guideline for approval offering “an industry-standard guide for … the development of procurement language to mitigate supply chain security risks that may be introduced by vendors.” The document provides key considerations for procurement language and suggestions for supply chain risk mitigation requirements.

Another guideline on the use of cloud computing for grid management came from the Security Working Group, which wrote that “understanding security in these complex environments is a common challenge in industry.” The document “presents basic cloud concepts, including the principles of information protection,” and is meant to supplement previous guidance on using encryption in cloud environments.

RSTC members then approved a research paper from the System Planning Impacts from Distributed Energy Resources Working Group on the impact of distributed energy resource aggregators and DER management systems on the working group’s DER modeling framework. The paper’s recommendations touch on collection and management of DER data.

Finally, the committee approved updates to a technical reference document on dynamic load modeling, intended “to reflect the current state of the art.” The new document includes updates to industrial load parameters, recommendations for use of the complex load model and changes to the load modeling data tool.

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ANOPR Reply Comments Offer Differing Paths for FERC Action on Large Loads

Reply comments to the Department of Energy’s Advance Notice of Proposed Rulemaking to FERC on large loads were in general agreement that the interconnection process needs to be improved while preserving reliability and affordability (RM26-4). (See Parties Warn that Jurisdictional Fight Could Slow Data Center Connection Effort.)

The National Association of Regulatory Utility Commissioners noted that states have come out against FERC taking jurisdiction over large loads, and that position was shared by others, including the Edison Electric Institute, Meta, the Data Center Coalition and Talen Energy. But the association also argued that FERC should convene a technical conference in January to discuss the areas on which the commission can act without sparking any jurisdictional fights.

“A technical conference will provide relevant entities with the opportunity to provide insights to the commission as well as the opportunity to exchange ideas with each other and coalesce regarding solutions,” NARUC said.

State regulators and ISOs/RTOs already are dealing with the issues, and NARUC urged FERC against any action that would derail those efforts.

The National Association of State Utility Consumer Advocates reminded FERC that while it is important to weigh the views of industry participants, it also must consider end-use consumers. Their interests might be contrary to what industry wants, and consumers’ interests in reliability and affordability need to be the lodestars that guide FERC’s actions, it argued.

“FERC should avoid taking any action in this proceeding that undermines the important progress that states and FERC have been able to make by coordinating their efforts and maximizing their respective abilities to effectively regulate within their jurisdictional bounds,” NASUCA said. “Following directly from principles of cooperative federalism, the ANOPR’s proposed reform should confirm the emerging policy development embodied in state-level large load retail electric tariffs and rules.”

The tariffs contribute to better management and pacing of large load interconnections, including weeding out speculative large load interconnections and mitigating cost shifts to other customers, it added.

The Pennsylvania Office of Consumer Advocate, Delaware Division of Public Advocate and Illinois Attorney General’s Office agreed on the cooperative federalist approach. They also argued that because residential consumers have paid for capacity for years and are not stressing the system, if rolling outages caused by a lack of resource adequacy are ever required, then grid operators should focus them on the new large loads stressing the system.

“Given the unique issues that large loads create for grid reliability, treating new large loads differently from other load is reasonable and necessary to ensure reliable service and just and reasonable rates for existing consumers, especially residential consumers,” they said. “FERC can and must appropriately treat new large loads attributable to data centers differently from other kinds of load because: (1) data centers are creating unique difficulties for the grid and impacting a uniquely vulnerable market at a uniquely expensive level; and (2) investments in data centers can be speculative and uncertain in nature, increasing the risk of a severe market correction that would create stranded costs.”

PJM’s Independent Market Monitor said that the ANOPR recognizes the need for a new large load queue at the RTO, which does not need to impinge on state jurisdiction.

“The criteria for the PJM queue could be focused on the very specific question of whether the load when interconnected can be served reliably,” the Monitor said. “Reliable service means that there is adequate capacity to meet the load, including a reserve margin. The current failure to impose a reliability requirement has led to large increases in capacity market prices but also in energy market prices and in transmission costs.”

The IMM also brought up a recent complaint that it filed seeking greater flexibility for PJM to deal with large load issues, by finding it can require that they are able to be served reliably before agreeing to connect them. It was one of many comments that focused on issues in PJM. (See Market Monitor Files Complaint Over PJM Large Load Interconnections.)

Constellation Energy Generation urged FERC to act on the pending show-cause proceeding on co-located load in PJM.

“On jurisdiction, the only immediate call the commission must make in PJM is whether to exercise jurisdiction over hybrid facilities’ shared point of interconnection to the grid,” Constellation said. “This is an easy call since the commission already exercises jurisdiction over the generator’s interconnection, and jurisdiction over the same shared facilities does not bifurcate between state and federal authority depending on the services of the moment.”

Constellation reported that the issues in PJM have gotten worse, with some transmission owners blocking hybrid facilities, in which a large load is built near a new generator, by making net billing impossible.

The Electric Power Supply Association likewise urged FERC to act on the long-pending issues in PJM and to avoid taking actions that threaten competitive markets.

“Regrettably, this proceeding is being utilized as an opportunity to press unwarranted attacks on our nation’s competitive power markets in an attempt to hijack this critical emergent concern to dismantle competitive mechanisms and allow monopolistic behavior to flourish further,” EPSA said. “Ignoring years of market price signals that justified generation retirements, transmission owners — particularly in PJM — now argue this crisis can be resolved by state-led processes that would allow these transmission owners to build and rate base new generation.”

Ultimately the issues the ANOPR raises will be dealt with only by adding more generation, along with the transmission required to bring that to market, American Electric Power said.

“AEP’s proposal in its initial comments achieves this goal by focusing on long-term, proactive solutions to generator interconnection, transmission planning and cost allocation,” the utility said. “AEP’s proposal supports the expedited connection of data centers and large industrial loads to the electric grid by effectively combining short-term speed-to-power solutions, with longer-term generator interconnection reforms and proactive transmission planning, which address the root causes of the current slow pace of large load interconnection.”

Google argued the root of the issue is more infrastructure, though its comments focused on transmission, which is squarely in FERC’s jurisdiction.

“The combination of aging infrastructure, decades of underinvestment and fragmented, highly localized planning practices have resulted in a transmission grid that is struggling to keep up with the demands of this new growth, including from data centers,” Google said. “As a result, it takes too long to interconnect new large loads and new generation, and the cost of doing so is too high. Lengthy interconnection delays are directly driving up energy prices. When new supply remains locked in a queue, it cannot meet rising demand in time, which puts upward pressure on all prices, including for energy, capacity and ancillary services. Resolving those bottlenecks by building the necessary transmission infrastructure is one of the principal steps our nation can take to solve all of those challenges.”

Talen said the only path forward is to develop new generation through transparent, market-based mechanisms that provide clear investment signals and maintain regulatory certainty.

“The fundamental underlying issue of resource adequacy will not be solved solely through a rulemaking process addressing large load interconnection,” Talen said. “Supporting market-based mechanisms designed to ensure sufficient generation resources are available to serve load demand is more pressing (and within the commission’s jurisdiction) than the issues raised by the ANOPR.”

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ISO-NE Talks CAR Gas Constraints, Seasonal Risk Split, Impact Analysis

ISO-NE continued work on the second phase of its Capacity Auction Reform (CAR) project with NEPOOL members Dec. 9 and 10, discussing modeling of the region’s gas constraints, seasonal auction design and its approach to evaluating the impacts of the auction changes.

Discussions around the CAR project are poised to take up a large portion of NEPOOL technical committee meetings throughout 2026. The second phase of CAR centers around resource accreditation changes and splitting annual capacity commitment periods (CCPs) into six-month winter and summer seasons.

The accreditation changes likely will be the most controversial aspect of the project, as the changes would directly affect how much capacity each resource can sell in the market. ISO-NE aims to complete the seasonal and accreditation design by the end of 2026.

Steven Otto, manager of economic analysis at ISO-NE, discussed the RTO’s thinking regarding the development of a gas capacity demand curve, which would be intended to account for the “shared physical constraints” limiting gas resources’ ability to access gas during cold periods.

As envisioned by ISO-NE, the gas demand curve would reduce how much gas resources are paid for their capacity relative to other resources during the winter season. Gas capacity backed by firm supply contracts would not be subject to the curve but likelywould affect the amount of gas available to remaining non-firm capacity.

The RTO “will construct a non-firm gas capacity MRI [marginal reliability impact] curve by measuring the reliability impact of substituting incremental megawatts of non-firm gas capacity with other capacity in the system,” Otto explained.

He added that, “in conjunction with the simultaneous clearing of the systemwide demand curve, the intersection of the gas capacity supply and demand curves determines how much non-firm gas-only [capacity supply obligations] will be awarded and how much less that CSO will be paid.”

The gas demand curve process would be separate from the accreditation process for gas resources; gas accreditation values would be determined largely by forced outage rate, maximum capacity and deliverability.

To determine how much gas is available to gas-only generators, ISO-NE plans to rely on modeling by the Analysis Group, which presented the initial results of its study of the region’s winter gas constraints at the meeting. The consulting firm estimated the hourly energy supply for gas resources based on 10 modeled winters intended to represent the full range of supply scenarios.

On cold days, defined as heating degree days (HDDs) at or above 45 — which equates to temperatures at or below 20 degrees Fahrenheit — the amount of available gas-only capacity averaged 4,516 MW, with a minimum of 469 MW and a median of 4,416 MW. On warmer days, available capacity averaged 6,794 MW, with a minimum of 776 MW and a median of 7,013 MW.

Gas resources did not face constraints during most days with an HDD below 45. Generation capacity equaled 8,384 MW during these days.

Responding to stakeholder questions, Todd Schatzki, principal at the Analysis Group, said the company did not find major geographic differences in access to fuel, noting there is a complex array of supply inputs to the gas system during tight system conditions.

He said it is difficult to accurately quantify local constraints, adding that constraints on the Algonquin G-Lateral appear to affect just two gas-only plants and about 5% of gas-only capacity.

ISO-NE’s proposed gas demand curve would apply equally to all non-firm gas capacity, but some stakeholders have argued that some resources are better situated geographically to access pipeline gas during tight days and should not be treated as equal to more constrained gas capacity.

The RTO plans to update the gas constraint modeling annually to account for changes in the amount of gas available to generators.

Seasonal Market

In the shift to a seasonal capacity market, ISO-NE proposes to “employ a similar approach to setting seasonal NICR [net installed capacity requirement] values and the corresponding demand curves” to the approach it uses in the current annual capacity auction format, said Chris Geissler, director of economic analysis at ISO-NE.

ISO-NE plans to split its loss-of-load expectation (LOLE) of 0.1 days per year into seasonal LOLEs set at 0.05 days per year. This is intended to maintain the one-day-in-10-years standard.

The RTO would calculate the seasonal NICR based on the amount of capacity needed to meet the LOLE requirement.

“This means, at the corresponding NICR values, the resource adequacy model predicts the same number of expected loss-of-load events in summer and winter,” Geissler said. Although the frequency of events would be the same, the severity and duration of events likely would differ, he noted.

Several stakeholders expressed concern that evenly splitting LOLE between winter and summer seasons could cause the region to under-procure capacity in the summer and over-procure in winter.

Geissler said ISO-NE does not expect the proposed LOLE distribution to skew demand curves, saying the risk split should not have significant impacts on seasonal capacity costs. He said ISO-NE will work to provide more examples in future discussions on the topic.

Impact Analysis

Geissler introduced ISO-NE’s proposed approach to evaluating the market impacts of the proposed suite of CAR changes. He said the impact analysis will focus on identifying differences between modeled results using current auction rules and CAR auction rules.

ISO-NE presented an initial impact analysis for its Resource Capacity Accreditation project in May 2024 before the RTO suspended the project, incorporating it into the broader CAR effort. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.)

ISO-NE plans to split the impact analysis into two main focuses: changes to the amount of capacity resources can sell, and changes to market clearing outcomes, he said. The RTO plans to look at metrics including clearing prices, capacity costs, cleared capacity by resource type and season, and revenues by technology type.

He noted it will be difficult for ISO-NE to predict supply offers for all resource classes amid the changing market design and broader changes in the energy landscape, including a potential increase in pay-for-performance risk.

To address the issue of uncertainty, the RTO plans to rely on a “consistent set of assumptions to derive offer prices,” which should “help to provide an apples-to-apples comparison between the current rules and CAR cases and reduce the impact of over- or underestimating offer prices,” he said.

ISO-NE plans to evaluate “multiple sets of offer prices to reflect the uncertainty of how resources may offer going forward and clearly articulate the basis for each to help participants develop their own expectations about market outcomes,” he added.

Geissler said ISO-NE will try to incorporate stakeholder-requested scenarios and analyses, but he noted “the considerable stakeholder interest and the resource-intensive nature of this work” may make it hard to follow through on all requests.

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SPP Board OKs Updated 2025 Transmission Plan

SPP’s Board of Directors has approved an updated assessment of the RTO’s 2025 transmission plan that corrects two minor errors and will re-evaluate a third project recently designated as a competitive upgrade.

Staff told the board during its Dec. 9 virtual meeting that two projects were inadvertently left off a list of approved construction permits: a new 345/115-kV transformer embedded in a larger Southwest Public Service project in West Texas, and a North Texas Electric Cooperative zonal planning criteria (ZPC) project that had an incorrect lead time when the assessment was drafted. (ZPC projects are not eligible for regional funding.)

The projects have been reviewed, verified for inclusion and recommended for notifications to construct (NTCs), staff said. The board agreed and approved the NTCs, along with the updated 2025 Integrated Transmission Plan.

The approval will add $48.1 million in costs to the ITP, amounting to a rounding error given its $8.6 billion price tag. The board approved the original plan in November after trimming several of its proposed 765-kV projects. SPP has said the portfolio’s regional benefit-to-cost ratios are between 12:1 and 18:1, the highest in the RTO’s planning history. (See SPP Board Approves 2025 ITP with 4 765-kV Projects.)

The board also approved staff’s recommendation to re-evaluate a 115-kV competitive upgrade out of the same ITP in the SPS service territory. Staff said SPS requested a re-termination of the project from a line tap to a substation about “2 miles down the road.”

Casey Cathey, vice president of engineering, also asked for a pause in the project’s request-for-proposals process, saying SPP has “worked through” some of the facilities through the RFP framework.

“This re-evaluation does not change the [FERC] Order 1000 classification. It doesn’t change the needs that are addressed, and it does not change the need date either,” Cathey said. “It is simply a termination refinement.”

He said SPS will submit updated cost estimates for the project’s noncompetitive portions. SPP designated portions of the project as competitive upgrades Dec. 3.

“It should be quite cost competitive compared to the original project, but we would like to go through that re-evaluation process,” Cathey said.

The Members Committee unanimously endorsed both recommendations, with two combined abstentions.

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CAISO, SPP Explore Using Existing Tools to Manage DAM Seams

CAISO and SPP have made “significant progress” on adapting existing tools to tackle seams between the two entities’ respective day-ahead markets, according to a CAISO representative.

Anna McKenna, vice president of market design and analysis at CAISO, discussed seams between SPP’s Markets+ and the ISO’s Extended Day-Ahead Market (EDAM) during a technical session at the WECC quarterly meeting on Dec. 9.

CAISO’s EDAM and SPP’s Markets+ are scheduled to go live in 2026 and 2027, respectively. One concern with having two separate day-ahead markets is the potential for friction at the borders of the two markets as entities join one market or the other. These seams arise from differing policies and separate dispatch between neighboring markets, which can result in additional costs for transferring energy across the boundary. (See ‘Islanded’ BAs Face Tough Choices in Western Market Future, Experts Say.)

CAISO has met with SPP, transmission owners and providers, and other partners in the West to discuss seams, according to McKenna. She said those discussions are in the early stages, noting that system reliability is the overarching principle as EDAM evolves.

Still, SPP and CAISO’s joint work as Western reliability coordinators (RCs) can help, McKenna said.

“Significant progress has been made in adapting some of the RC-based tools,” McKenna said. “And one you might have heard about is the enhanced curtailment calculator.

“This is a pretty powerful tool for us to be able to use in the Western Interconnection, so that we can ascertain what curtailments might have to happen on the system, should limits be exceeded, in a collaborative and coordinated and reliable manner. This will be foundational for some of the discussions we’ll have on the market side as to how we deal with these challenges coming up with the seams.”

The West has a history of collaboration and already has in place “a series of robust network models, real-time data sharing with each other and state estimators that we rely on,” McKenna added.

“We want to maintain and continue to use these tools as part of our engagement in the seams discussions,” McKenna said. “And of course, these things have to evolve over time. But we’re hopeful that with the work that we’ve done in the West and collaborative nature of how we do business in the interconnection will drive and will guide those discussions.”

‘Come Together and Find Solutions’

Meanwhile, SPP has launched separate efforts, including the Markets+ Seams Working Group (MSWG) and other working groups as it develops the market. At the direction of the Markets+ Participant Executive Committee, the MSWG in 2024 began developing the Seams Strategy and Roadmap, designed to identify focus areas for policies and governing documents related to seams issues with neighboring areas.

SPP also is expanding its RTO into the Western Interconnection, and the plan is to optimize Markets+ with the RTO in 2028, Carrie Simpson, vice president of markets at SPP, said during the WECC meeting.

SPP is “committed to working on seams,” Simpson said. The RTO wants to help “coordinate transfers amongst different parties, whether it’s EDAM, [Western Energy Imbalance Market], CAISO, Markets+” or non-market participants, Simpson added.

SPP plans to host a symposium on Western seams in Tempe, Ariz., on Feb. 26. (See SPP Markets+ Cruising Through Early Development.)

A recent report by FERC urged Western electricity industry stakeholders to get ahead of seams before the launches of Markets+ and EDAM. The paper highlighted seams coordination in the Eastern Interconnection. (See FERC Report Urges West to Address Looming Market Seams Issues.)

McKenna noted that solutions in Eastern markets are not necessarily compatible with the reality in the West.

“We think there’s going to have to be some extraordinary and important efforts between, not just the market operator to market operator, but those who are within these markets, such as the transmission owners, the transmission providers, the balancing areas,” McKenna said. “We all have to come together and find solutions.”

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MISO Launches 2nd Review of Long-range Tx Project for Cost Overruns

INDIANAPOLIS — MISO has opened another review of a second project from its first long-range transmission plan (LRTP) portfolio, prompted again by construction cost overruns.

MISO Executive Director of Transmission Planning Laura Rauch announced that MISO is conducting a variance analysis on the 345-kV Iron Range-Benton County-Big Oaks project in Minnesota. Joint developers Minnesota Power and Great River Energy have revised costs to build the line from an originally estimated $970 million to $1.39 billion. MISO’s Board of Directors approved the project under the first LRTP portfolio in 2022.

The Minnesota project review joins MISO’s ongoing variance analysis on the planned 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana, which has climbed from an estimated $261 million to $675 million. That project was also approved in 2022 under the first LRTP portfolio. Northern Indiana Public Service Co. is handling the upgrade.

MISO uses its variance analysis to re-evaluate transmission projects that experience significant cost increases or other obstacles. Once it completes a variance analysis, MISO can decide either to let projects stand as-is, develop a mitigation plan for them, cancel projects or assign them to different developers if possible.

MISO Director Mark Johnson asked what timeline the stakeholder community can expect on MISO’s most recent variance analysis. He said it seemed that the variance analysis on the Indiana project had run long and noted that MISO began it in early 2024.

MISO Director Mark Johnson | © RTO Insider 

“At the end of the day, I don’t think this is a good look for any of us if this drags on,” Vice President of System Planning Aubrey Johnson told MISO leadership during a Dec. 9 meeting of the System Planning Committee. Johnson said MISO plans to accelerate the process overall and deliver more timely outcomes.

“We expect to do that at a faster rate next year than we have with the current project,” Johnson said. He added that MISO’s review on the Indiana project was out for “executive review” and that MISO would deliver a verdict publicly before the end of 2025.

Industrial customers across MISO have repeatedly asked MISO to enact stronger cost containment boundaries on transmission projects. They’ve said MISO’s variance analysis should have a 20% overbudget threshold to trigger the study (instead of 25%) and that MISO should consult with third-party experts and its Board of Directors on projects’ fate.

MISO staff have said they don’t see a need to alter the process but that the RTO will create more public notices when it must conduct a variance analysis. (See MISO to Make Transmission Re-evaluation Process More Public and MISO TOs Oppose Tx Cost Containment Suggestions.)

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Louisiana Gen Co. First to Lodge Complaint Over MISO Auction Error and Price Corrections

Louisiana-based power generator Pelican Power is the first to register a complaint over MISO’s yearslong miscalculation in its capacity auctions in an effort to stop the RTO’s retroactive pricing corrections.

Pelican Power filed the complaint with FERC in mid-November regarding MISO’s settlement adjustments to the 2025/26 Planning Resource Auction (PRA) (EL26-26).

The utility said MISO’s retroactive pricing corrections run “directly counter to the commission’s longstanding policy of not disturbing auction outcomes.” It called the “after-the-fact tinkering with auction outcomes” unlawful and in violation of the filed rate doctrine. It asked FERC to order MISO to cease resettlements.

Comments and interventions are due in the complaint Dec. 15. MISO leadership during its Dec. 9 Markets Committee meeting acknowledged they may have to undo the pricing adjustments if the complaint is successful.

Pelican argued that nothing in MISO’s tariff allows it to make wide-ranging changes to capacity prices in the 2025/26 auction. It said MISO “has taken a series of ad hoc actions not authorized by, or consistent with, the terms of the MISO tariff and applied rules never reviewed or approved by the commission.” Pelican said MISO appeared to be attempting to expand its remedial authority beyond “straightforward corrective measures” and its duty to enforce a filed rate.

“MISO’s desire to right its wrong does not excuse its further violations of the filed rate, any more than a bank robber’s heartfelt remorse excuses his breaking back into the bank to replace the money he stole,” Pelican wrote.

Pelican added that MISO began taking steps to remedy the error in mid-August, with most of summer 2025 — and therefore the planning year’s highest capacity prices — behind it.

“While it may have been difficult, if not impossible, for MISO to actually re-run the 2025/26 PRA, particularly with the 2025/2026 planning year already underway, the fact remains that the MISO tariff does not authorize any, much less all, of the foregoing steps, and that MISO has simply invented and applied a whole new set of settlement rules to be found nowhere in the MISO tariff,” Pelican said.

For eight years, MISO used a technically incorrect “all hours” approach to calculate its loss of load expectation (LOLE), which according to MISO’s tariff, theoretically should occur only on a day’s peak hour. The error caused the auction to function as if a loss of load event could strike at any non-peak hour, raising the supply MISO secured for nearly a decade. The grid operator discovered in summer that an unnamed vendor since 2017 miscalculated the RTO’s LOLE. The coding error caused a $280 million impact on market participants in the 2025/26 auction, with some owing more money and some getting refunds. (See MISO IMM: Capacity Prices Efficient Despite Yearslong Error and MISO Discloses $280M Error, Over-procurement in 2025/26 Capacity Auction.)

As previously defined, a day with a loss-of-load event is counted in MISO’s LOLE calculations only if the event happens during the hour with daily peak load. MISO received FERC permission to officially use an “all-hours” loss of load approach in its capacity auctions beginning with the 2026/27 planning year.

The Independent Market Monitor has said the error was a good thing and made MISO more reliable as it traded thermal baseload generation for renewable generation.

Independent Market Monitor David Patton said it’s “disturbing” that MISO essentially must resettle the 2025/26 auction to reflect a reliability standard lower than one day in 10 years. “From our perspective, we think these resettlements … are extremely destructive to the integrity of the market,” Patton said during MISO’s September Market Subcommittee meeting.

MISO has been resettling the 2025/26 auction at estimated prices under its continuing error procedure. It’s the only auction where MISO has made pricing corrections. MISO has claimed it’s “not rerunning or resettling the [Planning Resource Auction], taking new bids or establishing a new auction clearing price.”

MISO made the first of three rounds of settlement adjustments Sept. 18. The first set of corrections totaled nearly $77 million. MISO warned market participants that if the adjustment should exceed their credit limit, it would trigger a margin call to cover losses within two business days.

Following discovery of the mistake, MISO Director of Resource Adequacy Neil Shah has said MISO will attempt to make its loss of load expectation calculations more transparent. MISO is working to develop a “masked” model for stakeholders to review, Shah said at the October Resource Adequacy Subcommittee.

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Judge Tosses Trump’s Halt on Wind Projects

A federal judge ruled that President Donald Trump’s executive order halting onshore and offshore wind power leasing and permitting was unlawful, finding that it violated the Administrative Procedure Act.

Judge Patti B. Saris, of the U.S. District Court for Massachusetts, found that both Trump and the executive agencies charged with carrying out the order failed to provide a reasoned explanation for the change, as required by the APA.

“Even assuming … that the [order] itself could be characterized as the [agencies’] own explanation for their manner of implementing it, the [order] does not provide adequate explanation: It merely includes a single sentence citing ‘various alleged legal deficiencies underlying’ wind permitting, ‘potential inadequacies in various environmental reviews’ and the possibility that these vaguely defined issues ‘may lead to grave harm,’” Saris wrote in a ruling issued Dec. 8.

“Whatever level of explanation is required when deviating from longstanding agency practice, this is not it.”

In ruling against the administration, Saris sided with 18 Democratic state attorneys general who challenged the order in May. (See State Attorneys General Sue Trump for Executive Order Halting Wind Approvals.)

Along with the halt, Trump had ordered a review of the government’s permitting processes for both types of wind resources. The states argued this also violated the APA, as the president did not set a deadline for the review, and there was no indication that the relevant agencies were even working on it. Saris agreed.

“More than 10 months after the wind order instituted a ‘temporary’ pause on the issuance of wind energy authorizations, no end to the comprehensive assessment appears to be in sight,” she wrote. “The agency defendants neither included a timeline for that assessment in the administrative record nor provided an anticipated end date during the course of this litigation.”

Trump’s order effectively halted development of the U.S. offshore wind industry: Multiple projects were canceled, and international companies such as Ørsted have shifted their focus to building in more favorable regulatory environments. (See Ørsted to Slash Workforce, Refocus on European OSW.)

“Overturning the unlawful blanket halt to offshore wind permitting activities is needed to achieve our nation’s energy and economic priorities of bringing more power online quickly, improving grid reliability, and driving billions of new American steel manufacturing and shipbuilding investments,” Oceantic Network CEO Liz Burdock said in a statement.

But while stocks for Ørsted and other energy companies with offshore wind holdings rose on news of the ruling, ClearView Energy Partners said it was skeptical new offshore wind projects would proceed, at least while Trump is still in office.

“We view the ruling as positive for offshore wind proponents, but we are not convinced the decision sufficiently supplants the actions the Trump administration has taken to constrain offshore wind,” ClearView said in a note Dec. 9. “We are skeptical that this loss in court can inspire the administration to change its oppositional posture.”

“The court expresses no view on whether the agency defendants should issue or withhold any particular permit,” Saris wrote. “But, while a president may direct a reappraisal of permitting practices after a change of administration, the agency defendants may not, as they have done here, decline to adjudicate applications altogether, for an unspecified time, pending the completion of a wide-ranging assessment with no anticipated end date.”

Saris’ ruling, if upheld, may be a boon to projects that already have been approved. In a filing with the U.S. District Court for D.C. on Dec. 2, the Bureau of Ocean Energy Management asked for a voluntary remand of its approval of New England Wind, off the coast of Massachusetts. It cited Trump’s executive order and its ongoing “re-evaluation” of its permitting process.

While the administration had issued stop-work orders on two projects, they were later lifted. Five projects still are under construction in the U.S.: Vineyard Wind 1, off Massachusetts; Revolution Wind, off Rhode Island; Coastal Virginia Offshore Wind, off Virginia; and Sunrise Wind and Empire Wind 1, off New York.

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NERC Standards Committee Pushes Projects Forward

Members of NERC’s Standards Committee dealt with multiple action items in what Chair Todd Bennett, of Associated Electric Cooperative Inc., called a “healthy agenda,” despite agreeing to delay action on one item until its next meeting in January.

In the Dec. 9 teleconference, Bennett told the SC he was “proud of what this committee has been able to accomplish over the past year,” reminding members that more than 50 outstanding FERC directives were being resolved through the standards development process as of mid-2025.

Trustee Sue Kelly, the committee’s liaison to NERC’s Board of Trustees, echoed Bennett’s remarks, praising the SC, along with NERC’s standards development staff, for working hard “to shovel the work out the door and yet maintain high quality.”

The action items for the committee’s final meeting of the year were relatively simple and approved with little debate, with the exception of a proposal to add four members to the standard drafting team for Project 2022-05 (Modifications to CIP-008 reporting threshold).

The SC authorized soliciting nominees from industry to replace four departing members of the project team at its Aug. 20 meeting, receiving 10 nominations. (See NERC Standards Committee Tackles Final Order 901 Tranche.) NERC staff recommended four of these candidates to join the team.

However, during the meeting, several SC members expressed confusion that the background material they were given about at least two of the candidates — who were not identified by name, in accordance with NERC’s policies — did not match their oral description by Alison Oswald, a manager of standards development. Oswald examined the material and determined that NERC staff had copied the wrong information into the file.

Rather than try to sort out the confusion during the meeting, Oswald suggested removing the item from the meeting’s agenda and returning to it at the committee’s January meeting. Asked by Terri Pyle of Oklahoma Gas and Electric how this decision would impact NERC’s standards development schedule, Oswald said the project was low priority and delaying action would cause the new members to miss only one SDT meeting. After Bennett endorsed the proposal, the rest of the committee agreed to delay action.

The next item similarly concerned appointing the chair, vice chair and eight other members to the SDT for Project 2025-06 (Supply chain risk management). This project is intended to address FERC’s September order directing NERC to develop standards addressing registered entities’ SCRM plans within 18 months. (See FERC Tackles Cybersecurity in Multiple Orders.)

NERC received 14 nominations in the 14-day solicitation period, Manager of Standards Development Sandhya Madan said, and it recommended 10 for SDT membership. Committee members approved all members without objection.

Members then turned to a proposal to authorize drafting new reliability standards for Project 2021-03 (CIP-002), a necessary step to moving forward with a standards development project. The committee again approved the proposal without opposition, along with subsequent authorizations of standards development for Project 2025-03 (Order No. 901 operational studies) and Project 2025-04 (Order No. 901 planning studies).

The latter two projects address the final milestone of FERC Order 901, covering operational and planning studies for inverter-based resources. Members also approved a proposal to reassign two standards authorization requests to update TPL-001-5.1 (Transmission system planning performance requirements) from Project 2022-02 (Uniform modeling framework for IBR) to Project 2025-04.

Aside from the action items, Oswald also shared with members a planned change to NERC’s SDT reference manual that would allow staff to remove team members for lack of attendance at meetings. The new language would specify that if a team member missed three consecutive meetings without notifying staff, the developer assigned to the project would reach out to the member to see if they would like to continue to serve.

If no response was received and the member missed two additional meetings, the developer would email asking again if they wished to continue serving. Continued lack of response after an additional three weeks would cause the member to be reassigned as an observer. The changes would take effect in 2026, Oswald said.