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December 8, 2025

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30+ Projects Under Consideration in MISO-SPP Joint Tx Effort

MISO and SPP said they will study more than 30 project suggestions — some estimated to cost more than $1 billion — in a four-state area in their pursuit of major, regionally cost-shared transmission projects.

The grid operators said they received 46 stakeholder-originated ideas for projects along their seam in Arkansas, Louisiana, Oklahoma and Texas. The two RTOs have culled the projects to 32 proposals and said they will test their potential and may build business cases for some under their coordinated system plan. (See MISO, SPP Still on Hunt for Joint Transmission Under CSP.) MISO and SPP ruled out most of the eliminated projects for focusing on local — not interregional — issues.

The 32 project contenders are concentrated along:

    • Northeastern Oklahoma to northern Arkansas, where stakeholders submitted multiple greenfield 765-, 500- and 345-kV project ideas alongside reconductoring and additional transformer suggestions.
    • Eastern Oklahoma to central Arkansas, which drew 500- and 345-kV line ideas.
    • The Oklahoma-Texas eastern border to northeastern Louisiana garnered 765- and 345-kV proposals with ideas for new transformers, substations and transformer upgrade submissions.
    • The Oklahoma-Texas eastern border to southwestern Arkansas, which could host new 500- and 345-kV lines and reconductoring, electrical reactor and double-circuit work.
    • Eastern Texas to central Louisiana, where stakeholders recommended 500-kV work.

Ashleigh Moore, of MISO’s interregional planning division, said MISO and SPP will analyze the candidates’ performance in terms of adjusted production cost savings, mitigation of reliability issues and transfer capability improvements.

At the Oct. 24 MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC), MISO and SPP said they would have draft recommendations ready to share by the Dec. 12 IPSAC meeting. Staff said they will have more data, maps, and benefit estimates and adjusted production cost savings estimates then.

The projects’ price estimates range from $54 million to nearly $4 billion for one HVDC idea in northeastern Oklahoma and northern Arkansas. Eight projects on the list are estimated to cost more than $1 billion.

Moore said MISO and SPP are encouraged by the “valuable project ideas” from their stakeholders and that they were glad to see some of the projects zeroing in on key reliability paths between the RTOs. She said MISO and SPP will narrow the 32 “good ideas” to “high-performing, feasible and cost-effective” projects.

MISO’s Jon George said the projects may culminate in a portfolio of interregional projects, with benefit-to-cost ratios calculated among a group of projects rather than individually.

The RTOs still are working on their 15-year modeling to build studies on and said it would be complete in November.

MISO and SPP said they may use the seven transmission benefits established in FERC Order 1920 to develop business cases for projects. If the two find beneficial projects, or a portfolio of projects, they would need to propose an interregional cost allocation plan for FERC approval. The two RTOs said cost sharing could be tackled in late 2026.

Southern Renewable Energy Association Executive Director Simon Mahan said while MISO and SPP’s coordinated system plan studies in the past have been disappointing, this fresh list of project candidates seems promising.

“I think this is going to be getting us closer,” Mahan said. He said some of the projects appear to be able to help outages that occurred earlier in 2025 in the Shreveport, La., area and previous voltage problems in northwestern Arkansas and southwestern Missouri during Winter Storm Elliot in late 2022.

MISO and SPP have never recommended a major, interregional cost-shared transmission project through their coordinated system plan study, despite five previous attempts. The RTOs’ $1.6 billion Joint Targeted Interconnection Queue transmission portfolio is to be paid for by interconnecting generation and is considered separate from their coordinated system plans.

Mahan said some of the project ideas appear to potentially boost transmission capacity to allow more MISO Midwest-South power flows. He asked if MISO would examine some projects for that value.

Moore said while MISO and SPP are time-constrained for this study, MISO plans to keep the list of projects ideas to draw on in future planning studies.

MISO-SPP TMEPS in the Works

Meanwhile, work will continue into 2026 on MISO and SPP rules to create a smaller, congestion-relieving interregional transmission project category.

MISO and SPP are in the process of drafting rules for a targeted market efficiency project (TMEP) type, modeled after the MISO and PJM existing interregional study that produces less expensive transmission projects that can be built quickly.

SPP Senior Interregional Strategist Jill Ponder said MISO and SPP plan to file new language to their joint operating agreement and an RTO-to-RTO cost allocation for TMEPs in either the first or second quarter of 2026.

Speaking at MISO’s August Planning Advisory Committee meeting, Moore said MISO and SPP view TMEPs as a “bridge in our planning toolbox” and said any MISO-SPP TMEPs will not “undermine or duplicate planning efforts.”

MISO stakeholders in written feedback expressed a concern that TMEP planning could risk overlapping with the existing MISO and SPP regional and interregional studies.

So far, the MISO and SPP draft TMEP study process would rely on historical data to weed out congestion on the seam and advance small transmission projects that can be built quickly to alleviate it. Moore said TMEPs are intended to supplement — not replace — long-term planning initiatives like MISO’s long-range transmission planning and the MISO and SPP Joint Targeted Interconnection Queue. Moore said TMEPs would solve only issues not expected to be “substantially alleviated by system changes” on a five-year horizon, including known upgrades.

Moore also said the two RTOs are striving to make the new process as transparent as possible. She said the RTOs will post historical congestion data annually and will commit to documenting the screening of potential projects in study reports “to explain why some move forward while others don’t.”

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NV Energy Files Request to Join EDAM

NV Energy has asked Nevada regulators for permission to join CAISO’s Extended Day-Ahead Market — a request that, if approved, would fill in a central piece of the market’s footprint.

The company filed the request with the Public Utilities Commission of Nevada on Oct. 22 as an amendment to its 2025-2027 Energy Supply Plan. NV Energy’s target date for EDAM entry is fall 2028.

The PUC is expected to issue an order within 135 days.

Factors in NV Energy’s decision include its positive experience with CAISO’s Western Energy Imbalance Market (WEIM), the company said in its filing.

And larger economic benefits are expected from joining EDAM rather than SPP’s Markets+. A Brattle Group study, updated in October, projected that NV Energy would save $93.1 million a year by joining EDAM, relative to participating in WEIM alone. In contrast, joining Markets+ would increase annual costs by an estimated $7.3 million.

NV Energy also pointed to better transmission connectivity with the anticipated EDAM market footprint compared to that of Markets+.

Another factor the company cited was the governance of EDAM as enhanced by West-Wide Governance Pathways Initiative and California’s AB 825, “including CAISO’s ability to respond more expeditiously to events with targeted, expedited stakeholder processes.”

California Gov. Gavin Newsom signed AB 825 into law in September, allowing CAISO to transition the governance of its markets to an independent “regional organization.” (See Newsom Signs Calif. Pathways Bill into Law.)

NV Energy also said it prefers certain EDAM market design features, including its resource sufficiency test, congestion rent allocation, virtual bidding, greenhouse gas accounting and voluntary participation in Western Power Pool’s Western Resource Adequacy Program (WRAP).

The company announced in August that it plans to withdraw from WRAP and revealed on Oct. 21 that it has been working with other EDAM participants on a potential alternative Western resource adequacy program. (See related story, EDAM Participants Exploring Potential New Western RA Program.)

In October 2023, the Nevada PUC opened a docket regarding regional market activities in the Western Interconnection. As part of the proceeding, the commission approved a report outlining the criteria to be addressed in a utility’s application to join a regional market. NV Energy’s application to join EDAM follows its announcement in May 2024 that it planned to join EDAM rather than SPP’s Markets+.

Other entities on board with EDAM are PacifiCorp and Portland General Electric, which have formally committed to joining in 2026. The Balancing Authority of Northern California, Los Angeles Department of Water and Power, Public Service Company of New Mexico (PNM) and Turlock Irrigation District have signed agreements to join in 2027; Imperial Irrigation District plans to join in 2028.

Arizona G&T Cooperatives, BHE Montana and Idaho Power have indicated they’re leaning toward EDAM.

NV Energy’s entry would add a substantial chunk of territory to the EDAM footprint, between California entities and PacifiCorp West to the west and PacifiCorp East to the east. Idaho Power would be directly to the north, while PNM extends the footprint deeper into the Southwest.

“Joining [EDAM] positions Nevada at the heart of the Western grid, connecting the Southwest and the Northwest to efficiently share affordable, reliable and flexible power across the region,” said Emilie Olson, Nevada lead at Advanced Energy United.

Olson said that joining a robust regional energy market is essential to NV Energy for controlling costs while tapping into a diverse regional energy mix.

CAISO said NV Energy’s filing is “a significant step forward” in its plans to join EDAM.

“We are eager to work with NV Energy and all the EDAM entities to deliver the full range of benefits, including improved resource sharing and meaningful cost savings for consumers across the West,” the ISO said in a statement.

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Trump Appoints Swett to Chair of FERC

President Donald Trump has named Laura Swett chair of FERC, the commission announced Oct. 24.

Swett was sworn in as a commissioner Oct. 20. Her term expires June 30, 2030.

“I am honored to serve as chairman of FERC and grateful for President Trump’s confidence in me to advance America’s energy priorities at such a critical moment in our nation’s history,” Swett said in a statement. “I look forward to working with my colleagues and FERC’s excellent staff to continue the commission’s crucial mission of ensuring reliable and affordable energy for all consumers.”

Swett takes over from David Rosner, who said at FERC’s open meeting the previous week that he would be happy becoming a commissioner again. Rosner was something of an interim chair, holding the office for only a few months after Mark Christie left the commission in August.

Swett was confirmed alongside David LaCerte to open seats on the commission Oct. 7. The two are Trump’s first nominees in his second term in the White House. (See Senate Confirms Swett, LaCerte to Open Seats on FERC.) LaCerte has not yet been sworn in as of press time.

Swett is no stranger to FERC, having been a staffer for former Chair Kevin McIntyre and Commissioner Bernard McNamee. She has been litigating FERC law for 15 years, which includes representing utilities, transmission owners and pipelines, most recently at Vinson & Elkins.

She received her bachelor’s degree from the University of Virginia and law degree from Georgetown University. She lives in Virginia with her family.

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NERC Seeks Feedback on Standards Modernization Recommendations

Eight months after launching the Modernization of Standards Processes and Procedures Task Force (MSPPTF), NERC is seeking feedback from industry on the task force’s draft recommendations to help the ERO’s standards development meet the pace of change on the grid.

NERC’s Board of Trustees created the MSPPTF in February in light of the rapidly evolving risk environment, which ERO leaders said has made it increasingly difficult for the organization’s consensus-based approach to keep up with new threats to grid reliability. (See NERC Leaders Highlight Canada-US Collaboration.) Trustees directed the task force to submit its final recommendations at the board’s February 2026 meeting in Savannah, Ga.

The draft recommendations, published Oct. 21, were developed by the MSPPTF with the help of comments received on a draft white paper released in July. (See NERC Task Force Members Share Standards Modernization Progress.) In the introduction, Chair Greg Ford and Vice Chair Todd Lucas explained that the team followed three guiding principles when developing the proposals:

    • Transform and modernize the process of standard development.
    • Find opportunities to save time and remove redundant steps.
    • Ensure due process is followed, competing interests are balanced and stakeholders are able to provide input.

When drafting the recommendations, the MSPPTF divided the standards development process into three stages. The team’s proposals were organized around these divisions.

Structuring the Initiation Phase

First is the standard initiation phase, which begins when a request to develop a standard is submitted to NERC and ends when the request is approved to begin drafting. Currently such standard authorization requests (SARs) may come from any entity or individual, including NERC committees or staff. SARs may be received and processed at any time of year.

NERC’s Standards Committee reviews SARs to determine if they are ready for development and may accept them, reject them for good cause, remand them for further work or delay action for consultation with other committees. Accepted SARs are posted for industry comment; following this, a drafting team is appointed to revise the SAR and resubmit it to the SC. If the committee approves the revised SAR, drafting may begin.

The MSPPTF found that this process is unclear, lacking requirements for the information needed to initiate development. The current process also lacks a clear framework for prioritizing and vetting SARs and does not provide opportunities to build industry support for the project early on. These shortfalls mean the initiation phase takes too much time and resources, the task force said.

To address these issues, task force members proposed a four- to six-month review and prioritization process to take place twice a year. This process would involve:

    • an open period to request new standard development projects;
    • review of requests by NERC’s Reliability and Security Technical Committee;
    • workshops and stakeholder feedback by a new subcommittee of the Reliability Issues Steering Committee (RISC);
    • production of a document outlining all standard requests received by the new subcommittee; and
    • development of term sheets for each project outlining the risk to be addressed and basic elements of the standard to be developed.

Standard initiation requests involving directives from FERC or NERC’s board would follow this process in a compressed time frame.

Streamlining Drafting

The second phase is drafting, which begins when an SAR is approved and ends when the standard drafting team proposes a first draft standard.

Drafting teams currently are composed of volunteers from industry and other stakeholders, with support from NERC staff. Drafting often overlaps with the third phase — balloting — because if a draft standard fails to pass a ballot round, it is returned to the drafting team for revisions.

Task force members said the current process is inefficient, with drawn-out timelines leading to lack of urgency, and that it is a substantial time commitment for volunteers. The use of multiple ballot rounds can also overwhelm drafting team members who lose focus on the overall goal while responding to individual comments and questions, and they slow down the drafting process with frequent stops and starts. Members even said some stakeholders vote “no” on the first draft standard unnecessarily, because they believe this is the only way to have their comments fully considered.

Under the task force’s draft recommendation, the new RISC subcommittee from the initiation phase would drive the drafting stage. This subcommittee would form a panel of subject matter experts covering a wide range of topics to help review and refine draft standards, thus reducing the need to recruit outside talent for standard drafting teams.

The MSPPTF also recommended giving NERC staff a greater day-to-day role in standards development. Possible tasks include creating “version zero” draft standards, with technical justification and supporting compliance elements, to help the drafting team get started. Artificial intelligence could be used to assist with this process, though the authors acknowledged that “human oversight will be essential to ensure that any AI-generated output meets quality expectations.”

The final key part of the task force’s drafting recommendations is to improve the stakeholder feedback process, which currently revolves around balloting and comment periods. Task force members envisioned a process that begins with the “version zero” draft standard; this draft would be posted for a 45-day comment period with a nonbinding straw poll to gauge initial industry support. NERC staff and the SME panel would then review comments with the help of an AI summary and analysis tools and prepare a written response.

If needed, a second draft of the standard would be posted for a 30-day comment period and straw poll. This time period could be shortened for high-priority projects. After a “good-faith effort” by the project team to address all concerns, the draft would be posted for a ballot to confirm industry consensus.

Greater Clarity in Balloting

The last set of draft recommendations concerns the balloting phase, in which proposed standards are voted on by the registered ballot body (RBB), comprising representatives from NERC’s 10 industry segments. A separate ballot pool is created from the RBB with each draft standard.

MSPPTF members found that this process does not provide enough accountability; individual voters may take positions opposed to their companies’ positions as expressed by management. The short signup period for ballot pool members also forms a barrier to stakeholder participation, as does the growing number of standards projects, each of which needs its own ballot pool.

Draft recommendations for this process, in addition to implementing a single 30-day ballot period, include limiting voting eligibility to persons or entities that participated in one or more comment periods for the draft standard and are active members of the RBB. Failure of the ballot to confirm consensus would lead to review by the RISC subcommittee, which may send it for further revisions and another ballot; alternatively, the subcommittee could end all further work on the project or recommend other action.

The MSPPTF also suggested restructuring the RBB to rebalance the influence of each industry segment, for example by expanding the weight of Segment 2 (RTOs and ISOs) while combining the “chronically undersubscribed” Segments 7 and 8 (large and small electricity users). This would result in six segments:

    • transmission owners;
    • RTOs and ISOs;
    • load-serving entities and transmission-dependent utilities;
    • electric generators;
    • electricity end users; and
    • governmental and nonprofit public interest entities.

The task force called for comments to be submitted via NERC’s draft recommendations feedback form. Responses must be sent by 12 p.m. ET on Nov. 10.

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Republicans Celebrate Changed Energy Policy at AFPI Summit

WASHINGTON — It has been almost a year since President Donald Trump won a second, nonconsecutive term, and that election’s impact on energy policy was evident at the America First Policy Institute’s Global Energy Summit.

AFPI Vice Chair of Energy & Environment Oliver McPherson-Smith proclaimed the meeting — held at the Waldorf Astoria Washington DC (formerly a Trump International Hotel) — “the anti-COP,” in that it was celebrating fossil fuel and not the talk about net-zero emissions that will dominate the U.N. Climate Change Conference in November in Belém, Brazil.

“I won’t be at COP 30 this year,” Energy Secretary Chris Wright said at the AFPI event Oct. 22. “I think there’s a reasonable chance I will be at COP 31 because we want to bring our arguments to our opponents.”

Wright argued that the Trump administration is starting to push back against maximalist climate arguments that have been used to try to control entire industries.

“It’s real; it’s an issue,” Wright said. “But it’s just not remotely close to a top five or top 10 issue in the world, but we treat it like this existential threat to the planet. Nothing, nothing in the data says as much, but no one calls that out.”

Major U.S. allies have said they agree that the focus should be on energy security and affordability, but they tell Wright they cannot say that aloud, he claimed.

“They’re realizing this justification for big government and the replacement for religion — it isn’t unchallenged anymore, and it doesn’t stand up under challenge,” Wright said.

Wright said the other side of the argument on climate change is still winning, but he predicted that would not last.

“We’ve got the minority, but we’re right, and it’s easier to win an argument when you’re right than when you’re wrong,” Wright said. “They have more people; they have more momentum; but they don’t have math and facts and humans on their side. We do, and we’re going to win.”

Wright celebrated that the Trump administration was recently able to stop the International Maritime Organization from implementing the first global carbon tax when it adjourned before voting on a measure that would have mandated decarbonization of international shipping. The group had agreed to the standard in April, but then the administration found out about it, Wright said.

“I remember I talked to one of the energy ministers from a big, allied country of ours (might even speak the same language as us), and as I spoke to this great gal, she said, ‘Well, we know it’s a forgone conclusion. It’s going to pass anyway. We want to be in the tent, because that’ll be better than out of the tent.’ Well, I wouldn’t assume that’s going to pass.”

Wright worked the phone and eventually Trump posted on Truth Social slamming the proposal. In the end, the effort was enough to spike the tax for a year at least.

The change is being felt in domestic policy as well, with Continental Resources founder and Trump donor Harold Hamm saying at the event that the Biden administration wanted to put the oil and gas industry out of business, but now Trump is taking the opposite approach.

“We’ve got an administration that is actually leading,” Hamm said. “Making all these changes that are necessary to get America back on track, to make America great again.”

Going forward, Hamm said he would like to see the permitting process changed so that eminent domain for pipelines is handled by the federal government and the requirements to perform environmental impact statements are slashed.

He also warned that the oil and gas industry was oversupplied by foreign competitors in OPEC, mainly Saudi Arabia.

“They are doing it all for market share,” Hamm said. “We’ve seen this before, right? It’s not going to last very long, folks. You’re looking at about a 10-year window here that suddenly will change, and once you peek out and start over the hill, guess what? It’s going to be a little tough to get it turned around next time.”

Horizontal drilling gave the world cheap energy, but that was a one-time event, and going forward, getting more supply from new technologies will not be easy, he said. As in the power sector, the next big thing for oil and gas is growing demand from data centers.

“Their fuel of choice, what’s going to drive them, is natural gas,” Hamm said. “That’s the best thing. So, we’re a little bit early on that curve. They’re building them, and when they get online, folks, they’re going to be the hell to draw on gas. And, so, you know that’s going to be a big bright spot.”

While Congress has already enacted major changes using Republican votes alone, House Energy and Commerce Committee Chair Brett Guthrie (R-Ky.) said he hoped to move bipartisan permitting legislation. That will be important to winning the artificial intelligence race because the U.S. already has the brain power and the capital to compete.

“What’s holding it back is the regulatory side,” Guthrie said. “We have to get the right regulatory side, but also, more importantly than anything, access to energy. Energy is everything in AI.”

The issues around permitting have limited the impact of Democrats’ policies, with Guthrie noting that the Inflation Reduction Act allocated $42 billion for broadband, but not one cent had been spent when Trump re-entered office. Now, with the “abundance agenda” taking root in Democratic politics and aimed at actually building infrastructure, Guthrie said he sees a possible opening.

“Maybe there’s an opportunity, we’re hoping, for us to come together to do a bipartisan permitting reform so that we can move electrons,” he said.

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Texas AG Opens Civil Investigation into ERCOT

ERCOT has told its market participants that the Texas attorney general’s office has served the grid operator with a civil investigation demand (CID) in connection with an ongoing investigation.

The CID seeks market and operations data that includes protected information and ERCOT critical energy infrastructure information necessary for the AG’s office to “evaluate potential violations of applicable law,” the grid operator said in an Oct. 22 market notice.

ERCOT said it will immediately disclose the requested information “as required by applicable law.” It assured market participants that it will “take steps to maintain confidentiality” by labeling confidential information and relying on statutory information protection requirements.

In an emailed statement, ERCOT said it would not comment on pending legal matters.

This is not the first time AG Ken Paxton’s office has issued a CID to ERCOT. His office launched investigations into the grid operator and several other entities that he said “grossly mishandled” the grid during the disastrous Winter Storm Uri in 2021.

“We will get to the bottom of this power failure, and I will tirelessly pursue justice for Texans,” Paxton said at the time.

The AG’s office did not respond to questions about the current CID or results of the 2021 investigations. It also hasn’t posted a news release about the new investigation.

RTO Insider contacted several market participants. None of them were aware of the investigation.

One theory is Paxton is conducting a “fishing expedition” to bolster his U.S. Senate campaign with some positive news.

The investigation could be linked to a recent lawsuit the Public Utility Commission filed in June against Paxton. The PUC was seeking to block the release of data on cryptocurrency miners, saying public disclosure could lead to acts of terrorism against the facilities.

A 2023 state law required cryptocurrency loads greater than 75 MW to register with the PUC by February 2025. The PUC rebuffed several media outlets when they asked for data on the registrations; the outlets then appealed to the AG’s office.

According to The Texas Tribune, the AG’s office in May sided with the media outlets. An assistant said the PUC “failed to demonstrate” the requested information was specific enough to aid terrorists.

Like ERCOT, the PUC said it would not comment on “pending legal matters.”

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PSE Launches DLR Pilot Project with Norwegian Tech Firm

Puget Sound Energy announced a partnership with Norwegian tech company Heimdall Power to install monitoring devices on 100 miles of transmission lines, stating the technology will help optimize the capacity of existing equipment.

PSE and Heimdall Power have installed 75 monitoring devices called “Neurons” on the utility’s transmission lines in western Washington under a dynamic line rating (DLR) pilot project that will run through summer 2026. The sensors can help increase grid capacity and power delivery for PSE’s 1.2 million customers by collecting real-time data on electrical current, line temperature, sag, wind speed and weather conditions, according to an Oct. 22 news release.

“This is an exciting first step for PSE to understand and capture the value of dynamic line ratings,” Alex Brotherston, principal engineer on PSE’s grid modernization team, told RTO Insider in an email. “With load growth, rising costs, aging infrastructure and long project timelines, it is critical that we leverage this kind of technology to increase the safety and efficiency of our grid.”

The pilot project “will allow us to observe the real-time conditions around our system and, when conditions are right, transfer more power through existing lines,” Brotherston said. “This in turn can ease congestion and give our operators more flexibility to respond to market or system constraints.”

Citing numbers from the U.S. Department of Energy, Brotherston said DLR can increase transmission capacity by 10% to 30%. PSE conducted a preliminary study using historical weather data, which showed that the utility’s pilot lines could see a capacity increase of up to 50% under the right conditions, Brotherston added.

Heimdall installed the DLR devices using both autonomous drones and traditional installation methods, according to the news release.

The partners said this is the largest deployment of DLR sensors in the U.S. and they will provide a continuous data stream, allowing PSE to increase transmission capacity “based on actual operating conditions rather than conservative estimates.”

Brotherston said the sensors can provide insights on line conditions during extreme weather scenarios, which can assist PSE in understanding how much power each line can safely handle.

“This allows us to proactively adjust load ahead of adverse conditions or avoid overloading lines during emergency rerouting,” Brotherston added.

PSE also hopes the devices can assist in incorporating more renewable energy on the grid.

“When we are armed with more knowledge about the capacity of our lines, we can more strategically route power around our system, which gives us the necessary flexibility to site new renewable energy sources, or more efficiently utilize the renewables already on the system,” Brotherston said. “In the future, this could look like a wind farm being able to generate at full power instead of being constrained by the capacity of the transmission system, or fewer infrastructure upgrades required to site a new solar facility.”

PSE declined to disclose the financial details for the pilot project, saying sharing costs could affect future contracts “as we move toward full-scale implementation or work with vendors on similar future projects.”

PSE said the pilot project is part of the utility’s efforts to modernize the grid and enhance resilience on its network. The utility will test the technology through summer 2026, then analyze the data to determine how to implement dynamic line ratings using the devices.

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ISO-NE Discusses Resource Deliverability Under CAR

ISO-NE presented a high-level overview of how it plans to account for resource deliverability in its updated capacity accreditation framework at the NEPOOL Reliability Committee on Oct. 22.

Resource deliverability calculations are intended to reflect system constraints that limit a resource’s output during key periods.

“Final capacity accreditation values must consider resource megawatts and the capability of the transmission system to deliver megawatts from resources to the load,” said Alex Rost, director of transmission services at ISO-NE.

He noted that the capacity auction reform (CAR) project will not change the process of determining deliverability through the interconnection process.

However, the new accreditation process will need to update how it accounts for deliverability, which will be used as a model input instead of an “ex-post adjustment,” Rost said.

“The ISO proposes to account for resource deliverability in accreditation calculations through an ex-ante adjustment to the size of a resource to be modeled in the RAA [resource adequacy assessment],” said Marianne Perben, director of planning services at ISO-NE.

ISO-NE proposes to rely on a scaling factor to account for deliverability limits, which would equal the lower value of either 1.0 or the ratio of deliverability value to “dependable capability,” Perben said.

Dependable capability “is an audit-based value reflecting a resource’s expected energy contribution under high load conditions,” Perben said. “The greater a resource’s deliverability value is above its DCap value, the more likely it will be able to provide its capacity to the system without transmission limitations.”

Each resource’s DCap value will be calculated based on its median performance during peak hours, which ISO-NE plans to define as the top 500 load hours from the relevant season from the prior year.

The value will be calculated for all resources except “demand capacity resources participating with energy efficiency measures,” said Jennifer Engelson, supervisor of resource qualification at ISO-NE. She added that energy efficiency resources “report a single seasonal performance estimate and therefore, hourly performance values are not available.”

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PJM Board of Managers Approves Quadrennial Review Proposal

The PJM Board of Managers has directed staff to proceed with a Quadrennial Review design that reworks the capacity auction price curve and sets the reference resource as a combustion turbine for all zones. (See PJM MIC Endorses 2 Quadrennial Review Proposals.)

“The board believes this proposal strikes the appropriate balance of reliability and cost implications,” it said in an announcement posted Oct. 22. It also noted that the proposal, jointly sponsored by PJM staff and Pennsylvania Public Utility Commission Vice Chair Kimberly Barrow, was the only one to be supported by the Markets and Reliability Committee.

Six proposals were considered by the Market Implementation Committee over the past year, with two being endorsed in September. The PJM/Barrow proposal received 75% sector-weighted support at the MRC. PJM spokesperson Jeff Shields told RTO Insider that staff intend to file the proposal within the next few weeks.

The proposal aims to improve the stability of the variable resource requirement (VRR) curve by reducing reliance on multipliers of the cost of new entry (CONE) parameter; the curve defines the clearing price to be procured in a Base Residual Auction (BRA) and at what cost.

It would shift the design of the VRR curve to set the maximum price at the larger of either 20% of the gross CONE, or 115% gross CONE minus 75% of the net energy and ancillary services offset. The formula establishes a floor meant to prevent high energy market revenues lowering the maximum capacity price to zero. The curve approved by the commission in 2023 set the maximum at the greater of gross CONE or 1.75 times net CONE, which subtracts the EAS offset from gross CONE. (See FERC Approves PJM Quadrennial Review.)

The midpoint on the curve would procure 101.5% of the reliability requirement at half of the maximum price, which is also meant to improve the stability of the curve. The midpoint for the prior curve was set at 75% of net CONE and 101.5% of the reliability requirement.

The curve would reach zero at 106% of the reliability requirement, shifting further to the right from the 104.5% anchor used in the previous curve shape.

During the Sept. 25 MRC meeting, PJM’s Skyler Marzewski said there is little difference in the maximum price when the curve is based on a combined cycle reference resource, the RTO’s preference, and a CT. The maximum would fall between $483/MW-day of unforced capacity in CONE Area 3 and $785/MW-day for ComEd. Some areas would see a lower maximum using a CC reference resource, such as a $463/MW-day maximum for CONE Area 3, while it would be higher in ComEd at $841/MW-day.

PJM’s original proposal sought to use a four-hour battery electric storage system as the reference resource in the ComEd region and a CC in all other CONE areas. Marzewski said a curve based on storage for ComEd would reflect environmental restrictions in Illinois that would reduce the lifespan of new gas generation. Instituting a CC for the other regions would reflect development trends in the region, with several CCs in the interconnection queue. (See “Stakeholders Divided on Reference Technology,” PJM Stakeholders Discuss Quadrennial Review Proposals.)

PJM had intended to shift to a CC in the last Quadrennial Review but backtracked when it determined that high estimated energy prices could cause capacity prices to fall to zero, along with disruptions to other parameters based on the reference resource. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

PJM’s proposal adopted Barrow’s recommendation to use the 67th percentile of the net EAS offset for each CONE area, which Marzewski said is meant to reflect that developers will seek to maximize their potential revenues when siting projects.

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ISO-NE Gives Update on Asset Condition Reviewer Role

ISO-NE has identified nine projects to include in an interim asset condition review process starting in October, which will proceed as the RTO works to stand up internal condition review capabilities by the start of 2027.

The asset condition reviewer is “envisioned to provide an independent review and opinion of asset condition projects submitted for review by the TOs [transmission owners],” Al McBride, ISO-NE vice president of system planning, told the ISO-NE Planning Advisory Committee (PAC) on Oct. 23.

ISO-NE agreed to take on the role following pressure from states and consumer advocates, who have expressed concern about a lack of oversight and transparency on spending by transmission owners to upgrade existing assets. Asset condition spending has increased significantly in recent years, which transmission owners say is due to escalating costs associated with maintaining aging grid infrastructure. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

The RTO has emphasized that it will not take on a regulatory role or comment on the prudence of investments; asset condition spending is under FERC jurisdiction and is processed through formula rate procedures.

The new role, McBride said, “would inform states, stakeholders and PAC attendees” with “holistic information and much more insight on these projects.”

While ISO-NE will not comment on “the question of whether the costs of any given asset condition project are prudent,” it plans to offer opinions on whether transmission owners have adequately demonstrated project needs, and whether they adequately evaluated alternatives.

ISO-NE is seeking feedback on the proposal by Nov. 21 on the objectives of the role, governance structures, criteria for project review, stakeholder involvement and how reviews would fit in with transmission planning processes.

Asked whether ISO-NE plans to employ a cost threshold for reviewing projects, McBride said, “at this point, we expect that there would be a threshold, but that has not been decided, and we’re open to feedback.”

Several stakeholders said they are eager to get into discussions about how the new role could inform efforts to right-size transmission projects.

“Those discussions will come, but they will come in the right order, which we think is after we’ve had some time to establish the asset condition reviewer itself,” McBride said.

ISO-NE plans to rely on consultants to evaluate projects prior to the official rollout of the new asset condition reviewer role. It has selected nine proposed projects to review during this interim period:

    • Eversource’s rebuild of Line 1670/1771 in Connecticut, estimated to cost more than $120 million.
    • Eversource’s rebuilds in the West Medway/West Walpole Corridor in Massachusetts, estimated to cost more than $75 million.
    • Eversource’s underground cable modernization plan in the Boston area, a multiphase project the New England States Committee on Electricity has estimated will cost in the range of $8 billion to $9 billion.
    • Avangrid’s cable replacements on a line in southern Connecticut, estimated to cost more than $100 million.
    • Rhode Island Energy’s rebuild of Line 332, estimated to cost more than $75 million.
    • National Grid’s rebuild of Line 323 in eastern Massachusetts, estimated to cost more than $75 million.
    • National Grid’s partial rebuild of Line 394/397 in northeastern Massachusetts, estimated to cost more than $100 million.
    • VELCO’s partial rebuild of Line F206 in Vermont and New Hampshire, estimated to cost more than $50 million.
    • VELCO’s Highgate converter replacement, estimated to cost more than $500 million.

“The ISO is targeting a three-month review period for each project, except for the underground cable modernization plan,” McBride said. “These interim projects would be reviewed between early November 2025 and the end of 2026, as the TOs bring those selected projects forward to present and discuss at the PAC.”

ISO-NE has asked for comments on the interim project list by Nov. 7.

Asset Condition Project Presentations

Also at the PAC meeting, several representatives of transmission owners discussed asset condition project proposals.

From Eversource, Chris Soderman presented a $143 million project to fully rebuild a 115-kV line in central Connecticut. He said a full rebuild, instead of targeted structure replacements, would address the immediate needs along with “future asset condition needs by replacing structures that are deteriorating and likely to require replacement in the near future.”

The project is included in the interim review list presented by ISO-NE at the meeting.

Soderman said the project is needed to address “multiple structure concerns including foundation damage, structure deterioration and rust.”

Of the 83 structures on the affected lines, Eversource estimated about half require planned replacement or emergency replacement. He said the condition of the other structures warrants consideration of replacement “in conjunction with other structure replacements.”

Soderman added that, without a full rebuild, the company likely would have to return to the PAC with a follow-up project “within two or three years” to replace the remaining structures.

Eversource plans to bring the proposal for a follow-up presentation at the PAC in the second quarter of 2026, with construction scheduled to begin in early 2027.

Multiple PAC members expressed concern about the high per-mile costs of the project, and Sheila Keane of the New England States Committee on Electricity (NESCOE) asked for more granular information on cost drivers for the project.

Rafael Panos of National Grid presented a cost update on a transformer replacement project in Bridgewater, Mass. The project includes replacing a transformer, refurbishing a transformer, replacing multiple circuit breakers and upgrading associated equipment. The project cost has increased from the 2022 estimate of about $26 million to nearly $38 million. The higher cost estimate is driven by inflation, escalation and a longer construction duration, Panos said.

Fabio Dallorto, lead engineer for transmission planning at ISO-NE, presented an update to the asset condition database.

He said transmission owners have added 21 new projects totaling $228 million since the last update in June. (See New England Transmission Owners Add $95M to Asset Condition List.) He added that 12 projects totaling $443 million have been placed in service since the last update.

Copperweld Shield Wire Replacements

Dave Burnham of Eversource discussed the company’s strategy for replacing Copperweld shield wire in its service territory. He said the company has found Copperweld shield wire to have a failure rate about six times higher than other types of shield wire.

“Copperweld shield wire was once an industry standard but has been prone to failure, and it is increasingly difficult to obtain replacement equipment,” he said.

“Since 2018, Eversource’s primary strategy to address Copperweld shield wire concerns has been to replace Copperweld shield wire in conjunction with projects that also address other asset condition needs,” Burnham said. “Eversource estimates that most Copperweld shield wire will be removed by 2030.”

Eversource’s practice is to replace copper wire with Alumoweld and optical ground wire (OPGW).

“In most cases, OPGW is preferrable to Alumoweld because it has similar costs and provides additional telecommunications capabilities,” Burnham said.

He noted that Eversource mistakenly presented incorrect data on Copperweld shield wire in 11 asset condition presentations to the PAC between 2021 and 2023.

“These presentations incorrectly provided results from testing of copper conductor and [extra-high strength] steel shield wire performed in 2018,” Burnham said. “Test results from Copperweld shield wire performed in 2022 showed failure of tensile elongation test, not rated breaking strength test, corrosion or signs of overheating.”

Keane of NESCOE said it is “concerning that we were presented incorrect evidence to support a certain approach,” and expressed her hope “that this is the type of thing that an asset condition reviewer will be looking at.”