A virtual power plant program with an indeterminate future set a record in 2025 for the capacity the plant contributed to California’s electricity grid.
The California Energy Commission’s VPP program has seen a big increase in available capacity since the end of the 2024 season, CEC analyst Brian Vollbrecht said at an Oct. 15 workshop.
About 38,000 customers participated in the program in 2024, providing about 288 MW to the grid. In August, the program’s capacity exceeded 400 MW.
The VPP program is part of the demand side grid support (DSGS) program, which is within the state’s strategic energy reliability reserve. The reserve provides electricity supply and load reduction and has a goal of 7,000 MW by 2030.
The DSGS program has four options. Most of the workshop focused on VPP Option 3, which rewards battery owners who provide capacity to the grid during energy emergency alerts or when market day-ahead prices go above $200/MWh. Option 3 participants provide this capacity during extreme weather and grid events from May to October.
No residential resources with durations beyond two hours participated in the VPP, and nearly half of the VPP capacity was in the Pacific Gas and Electric region, with the rest in the Southern California Edison region and the San Diego Gas & Electric region.
At the workshop, Robert Castaneda, board president of the Low-Income Oversight Board of the California Public Utilities Commission, asked if the CEC had a socio-demographic breakdown of VPP participants.
Vollbrecht said that this type of data was not a part of the analysis “this time around.”
“But if you have questions about that, feel free to follow up with us,” Vollbrecht said.
DSGS’s funding has experienced “various shifts since its inception due to state fiscal pressures,” Deana Carrillo, director of the CEC’s Reliability, Renewable Energy and Decarbonization Incentives Division, said at the workshop.
“And I recognize that this is challenging for private industry that is participating in the program, because while we’re attesting approaches to grow demand and incorporating the lessons learned, there’s also a need for consistency and a glide path to inform your business models,” she said.
There are, however, “active, ongoing discussions about the program’s budget,” Carrillo added.
“Staff is having conversations with leadership to identify stable funding beyond 2026 and continue the program’s growth into test concepts,” she said.
In total, DSGS’s budget is $109.5 million, with about $30 million remaining at the end of 2025, CEC program manager Payam Narvand said at the workshop.
CEC staff proposes continuing the DSGS program into the 2026 program season. Any changes to the program will be informed by a public engagement process and approved at a CEC business meeting, Narvand added.
Data center-fueled demand growth continues to soar while reserve margins continue to shrink. Meanwhile, the timelines for building load versus building generation and transmission are wildly out of sync.
Large loads can stand up in one to two years or less when co-located with generation, while new generation interconnection routinely takes years, and major transmission lines average about a decade from conception to energization.
Because data centers can be developed significantly faster than the generation and transmission required to serve them, NERC has flagged the speed and scale of data center buildout as a near-term reliability challenge. Large loads also pose risks to long-term planning, operations, grid stability, balancing, power quality, forecasting, modeling and grid security.
In light of the rising operational and resource adequacy risks, federal agencies, regional organizations, power system operators and utilities are scrambling to analyze and address the impacts related to emerging large loads.
The Department of Energy (DOE) has launched the Speed to Power initiative to accelerate the large-scale generation and transmission additions needed to support data center buildout and the AI race. FERC has held technical conferences and written letters around these issues, while NERC and other regional reliability organizations have created task forces and studied the risks of these emerging large loads.
ERCOT, SPP and PJM are paving the way with large load interconnection and participation initiatives.
Just How Big is Large Load Growth?
U.S. data center electricity use rose from 58 TWh in 2014 to 176 TWh in 2023 and is estimated to reach 325-580 TWh by 2028. That translates into roughly 6.7 to 12% of U.S. electricity by 2028 (up from about 4.4% in 2023), according to DOE, underscoring how quickly this new class of demand is growing.
Growth is highly geographic, with PJM, the Western Interconnection and ERCOT leading the way due to the major data center hot spots in Virginia, Texas and the Northwest.
Since 2020, PJM has added about 26.5 GW and ERCOT about 13.2 GW of load‑center capacity, with more in the queue but significant uncertainty on what actually will be built. SPP also has positioned itself to capture a meaningful slice of data center growth. (See this for more information on current and future data center hot spots.)
ERCOT and PJM’s load capacity additions are projected to skyrocket in the coming years, but it’s still uncertain how much load will get built out.
Characteristics and Risks of Large Loads
Large loads today differ from conventional commercial loads. Large loads can be either large individual consumers or collections of smaller loads that create significant demand and strain on the power grid. Most talked about are data centers, including AI hyperscale data centers, but NERC categorizes large loads as follows:
Data centers: These include traditional data centers, AI training facilities, AI inference facilities and cryptocurrency mining facilities.
Industrial load: This includes semiconductor and electronics manufacturing, mining and mineral processing, oil and gas production, metals and heavy manufacturing, and chemical and petrochemical processing.
Hydrogen production (electrolyzer) facilities.
Aggregate loads: These are primarily EV charging centers and electrified heating and cooling. Large loads are being built quickly, at large unit sizes, in tight geographic clusters. Many of them, particularly data centers, can shift their computational demand rapidly in response to changing energy pricing, emission intensity and currency pricing.
Compared to traditional electricity load growth, today’s large loads are far more location-constrained (e.g., loads need available grid capacity, access to robust fiber optic networks and water access or a suitable climate for cost-effective cooling). They’re also far more schedule‑driven by corporate road maps and much less interruptible than conventional commercial load.
high-priority risks: long-term planning for resource adequacy, operations of balancing and reserves, and grid stability.
medium-priority risks: short‑ and long-term demand forecasting, real‑time coordination, transmission adequacy, frequency stability, cybersecurity, manual load‑shed obligations and automatic under-frequency load shed programs.
low-priority risks: power quality (harmonics, voltage fluctuations) and system restoration following load shedding events.
Consequently, large loads are characterized not only by their MW capacity but also by their behaviors that pose grid reliability risks. The consensus defines large load capacity as greater than 75 MW, but voltage level, local system strength and relative size to the area matter as much as raw MW. Their behaviors include ramp rates, ride‑through behavior, power‑electronics content, voltage sensitivity, predictability and internal segmentation.
Existing ISO Large Load Constructs
Before September 2025, ERCOT and NYISO were the only ISOs to have requirements for large load interconnection and preliminary definitions and programs for large loads. In 2022, NERC modified its requirements and measures for facility interconnection studies (FAC-002-4), but it didn’t have any megawatt threshold or special process for large loads.
NPRR1234 updated ERCOT’s definition of a large load to be one or more facilities at a single site with an aggregate peak demand greater than 75 MW behind one or more common points of interconnection or service delivery points. NPRR1234 also formalized interconnection and modeling standards for large loads, set standards for loads of more than 25 MW, set requirements for a reactive power study requirement for resource entities adding more than 20 MW of load at a site with existing generation, and established a standardized large load interconnection study. The study is conducted by the transmission service provider with ERCOT review and is described in PGRR115.
In NYISO, interconnection studies are required for loads greater than 10 MW at more than 115 kV or greater than 80 MW at more than 115 kV. Smaller projects are handled entirely by the applicable transmission operator’s interconnection procedures.
Federal Activity
Demand growth outpacing the grid buildout, alongside several executive orders relating to energy dominance and AI, have led DOE to launch the Speed to Power initiative.
The initiative kicked off Sept. 18, 2025, with a request for information. It aims to accelerate large-scale additions of generation and transmission so the U.S. “has the power needed to win the global artificial intelligence race” and can continue to serve fast-growing loads.
The RFI seeks details on infrastructure projects that would quickly enable 3 to 20 GW of incremental load, such as new interregional transmission of at least 1,000 MVA, reconductoring of existing lines of at least 500 MVA, restarts of retired thermal plants using existing interconnections and construction of new generation portfolios. MVA measures the apparent power in an AC transmission system, essentially the combined voltage and current capacity a line or transformer can handle. The RFI also asks how DOE should best deploy existing tools and funding programs.
RFI responses are due Nov. 21, 2025.
Texas Senate Bill 6, PUCT and ERCOT Action
ERCOT is seeing some of the largest forecast load growth from data centers, with 138 GW of large loads expected on its grid by 2030.
To address the reliability concerns this raises, the Texas state government pushed the envelope with its Senate Bill 6, which passed on June 20, 2025. It directs the Public Utility Commission of Texas to adopt large‑load interconnection standards for new or expanded large loads greater than 75 MW at a single site in ERCOT, along with study fees ($100,000 minimum initial interconnection fee), site control, uniform financial commitment rules, grid infrastructure cost allocation and a requirement to disclose to utilities any duplicate interconnection requests in Texas.
SB6 also directs the PUCT to develop one mandatory and one voluntary demand management program. The mandatory program requires protocols to curtail large loads of greater than 75 MW that are interconnected after Dec. 31, 2025, during firm load shed (with some exceptions for critical load).
The voluntary program, the Large Load Demand Management Service, requires ERCOT to competitively procure demand reductions from loads greater than 75 MW in advance of anticipated emergency conditions.
The PUCT projects for SB 6 are PUCT filings 58317 and 58479.
SPP recognizes how much uncertainty there is with the load of the future and subsequently has designed a three-phase project that aims to set SPP up for success in all likely electricity load growth scenarios. SPP’s three future large load services are:
a high-impact large load generation interconnection assessment (HILLGA)
a conditional high-impact large load service (CHILLS)
a price adaptive load (PAL) service.
The new services aim to reduce interconnection times with a 90-day study-and-approval process for HILLGA and CHILLS, provide flexibility for connection or operation of large loads within system limits and reduce transmission upgrade cost uncertainty. This will offer a clear path to interconnection agreements while maintaining SPP’s reliability standards and transparency in cost allocation.
The first phase of the project began with SPP’s revision request (RR696), which was approved by SPP’s Board of Directors on Sept. 16. It defines high-impact large loads (HILLs) and introduces a generation-supported HILLGA. A HILL is a non-conforming load facility interconnected to the grid that can pose reliability risks.
Actual and projected large load capacity additions by ISO | Yes Energy using Yes Energy’s Infrastructure Insights data
The HILLGA service offers HILLs two paths for studying and interconnecting associated generation: the common bus path and the local area path.
The common bus path is for HILLs with supporting generation behind the same point of interconnection as the HILL, where generation won’t be injected into the grid.
The local area path is a five-year service term for HILL-supporting generation that’s within two buses. With the local area path, energy flows on the grid are limited by the HILL’s needs and system capacity.
RR696 initially had designs for a third HILLGA path, deliverability area and for a CHILLS. They were removed from RR696 following feedback from stakeholders, who wanted more time to review and revise the deliverability area and CHILLS designs. The CHILLS service was introduced later with RR720, which was voted on and failed to pass in SPP’s Market Working Group meeting Sept. 23-24. This will delay SPP’s timeline, which initially sought to vote on RR720 in the Oct. 14-15 MOPC meeting.
The CHILLS will be a new curtailable transmission service available to HILLs that don’t have sufficient transmission capacity or generation to serve all their energy requirements. The portion of a HILL’s energy needs that can’t be served on a firm basis will be acquired on a conditional basis, so CHILLS is interruptible as needed to maintain reliability.
Conditional HILLs don’t need to be supported by generation, but they are required to transition to firm service by the end of the term. In a notable change from its old design in RR696, conditional HILLs must begin the process of establishing firm service within the first year. The CHILLS term now is up to seven years long, increased from five years.
SPP also has discussed a price adaptive load service for any load willing to take price‑responsive withdrawal based on real‑time pricing. SPP aims to create the revision request by January 2026 and get it approved in April 2026. This timeline may be delayed due to the recent failure to pass RR720 in the September Market Working Group.
SPP’s load-centric interconnection lane compresses the study cycle by pairing load with proximate generation and using conditional service while enduring solutions catch up.
While Texas’ SB 6 is the most comprehensive legislative package to date specifically aimed at large loads, SPP is leading the way among ISOs and RTOs with its large load interconnection lanes.
PJM’s Critical Issue Fast Path for Large Load Additions
This initiative was motivated by PJM’s high capacity prices and looming resource adequacy crisis. PJM’s independent market monitor, Monitoring Analytics, found in its analysis of PJM’s 2026/27 capacity auction that data center load growth was the primary reason for high capacity prices. Nearly 100% of the offered supply was committed in the auction, and data center load drove a $7.2 billion, or 82.1%, increase in capacity market revenues.
PJM’s 2025 long-term load forecast showed PJM still may face unmet demand even if everything is built in the generation interconnection queue.
PJM is targeting a FERC filing by December 2025 and aims to implement in time for the 2028/29 capacity auction.
The CIFP for large load additions is evaluating criteria for large‑load interconnection and coordination with load-serving entities/electric distribution companies (critical for data centers). It’s also addressing alignment of large loads connecting to the power grid with the obligation to also provide some generation capacity to contribute to ensuring resource adequacy in the grid, rather than relying on others to do so.
PJM’s Stage 1 meeting was held Sept. 15, and the initial proposal centered around three large load interconnection options: BYOG (“bring your own generation”) credits for load that arranges new supply, demand response pathways and a transitional non‑capacity‑backed load (NCBL) service that lets incremental large loads connect quickly but assigns them a lower curtailment priority during emergencies if capacity is short.
After listening to stakeholder feedback, PJM’s current proposal has three components:
Price-responsive demand (PRD) and demand response: PJM removed the mandatory NCBL concept and instead will use existing DR and modified PRD products to facilitate a process similar to voluntary NCBL. PJM proposes replacing the dynamic retail rate requirements seen in PRD with an energy market offer price. Load could elect not to take on a capacity obligation, requiring it to reduce demand during stressed system conditions rather than pay for capacity.
Load forecasting enhancements: These include allowing state commissions to review and provide feedback on large load adjustments prior to finalizing load forecasts, and add a duplication check in load analysis subcommittee submissions. Each annual large load adjustment submission must inquire and report whether customer interconnection requests are duplicative (inside/outside PJM) and quantify the duplicated megawatts.
Expedited Interconnection Track (EIT): Introduce a 10-month EIT for “sponsored” generation that operates outside and in parallel to the PJM cycle process (the standard generation interconnection process). The EIT would be limited in volume and have strict entry requirements to minimize impact on PJM’s cycle process.
Alternative approaches for procuring new resources on a longer-term basis still are in discussion and may be included in the CIFP for large load additions. PJM also mentioned that the manual load shed allocation mechanism needs to be reviewed following the conclusion of this CIFP.
Conclusion
Unprecedented data center-driven demand growth requires unique solutions to address the rising resource adequacy and grid operations risks. There is a timing gap with large loads arriving in months to a few years, while new generation and transmission take far longer.
Besides being large, these loads ramp quickly, are electronics-heavy and location-constrained, and can be price-adaptive, so treating them like conventional commercial growth will miss real reliability and planning risks.
ERCOT, SPP and PJM are leading the charge, creating large load-specific programs to speed up the interconnection and offer unique participation models for large loads and the necessary accompanying supply and transmission capacity.
The path forward includes standardized definitions and studies across ISOs/RTOs, improved participation models and forecasting for high-impact large loads, price-responsive operation, improved time-to-connect, conditional service, curtailment performance and progress to firm capacity.
Tim Hough is a market analyst on the market monitoring team at Yes Energy. RTO Insider is a wholly owned subsidiary of Yes Energy.
State regulators approved an accounting order for Public Service Company of New Mexico’s participation in CAISO’s Extended Day-Ahead Market, in a case that rekindled the debate over which day-ahead market PNM should choose.
The New Mexico Public Regulation Commission voted 3-0 on Oct. 16 to approve the order, which allows PNM to create a regulatory asset for its EDAM costs. That means PNM will track its EDAM costs separately from other expenses and later seek to recover the costs in a rate case.
PNM estimated its EDAM implementation costs will be $11.1 million in capital costs, $3.1 million in one-time operations and maintenance expenses, and $1.4 million to $1.6 million a year in ongoing costs from 2028 to 2030.
PNM’s request for an accounting order sparked filings from those who supported the request and those who believe the company should have chosen SPP’s Markets+ instead of EDAM.
“To me, it’s kind of nuts that this case became a referendum on market choice, or parties tried to make it so,” Commissioner Pat O’Connell said before the vote.
O’Connell said keeping EDAM expenses in a separate account would make it easier to later inspect the costs and compare them to benefits of market participation.
The commission found that it is “reasonable” for PNM to “expend costs in joining EDAM.” The prudency of the expenditures will be evaluated during a future rate case, when the amount of spending is known.
The commission didn’t authorize PNM to include carrying charges in its regulatory asset, saying that doing so would constitute “ratemaking treatment in advance.”
Parties have until Nov. 17 to file a motion for rehearing.
Regional Market Proceeding
In a Sept. 11 filing, Tri-State Generation and Transmission Association asked the commission to deny PNM’s application. Tri-State pointed to PNM’s 2018 request for an accounting order for the costs of joining CAISO’s Western Energy Imbalance Market. In that case, the commission granted the order without making a reasonableness determination.
Commission Chair Gabriel Aguilera said PNM’s new request was unique because it followed a lengthy commission proceeding that examined the potential benefits of regional market participation by the state’s investor-owned utilities. The proceeding included a series of workshops where studies on projected benefits of market participation were presented. Utilities and stakeholders weighed in with numerous filings.
Utilities were not required to obtain commission approval for their day-ahead market participation. But the commission issued a set of guiding principles in November 2024 intended to guide the utilities’ market decisions. (See NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation.)
“PNM’s decision to join EDAM is not a decision that was made quickly or without thorough consideration,” the commission said in its order. Rather, it is a result of “the time, effort and investigation put in by multiple entities that participated in [the docket].”
EDAM Decision Questioned
In its filing, PNM pointed to a Brattle Group study that projected benefits from joining EDAM would be $20 million a year vs. $8 million a year for joining Markets+. PNM said the difference in benefits was a key factor in its decision to choose EDAM.
Tri-State argued that the $20 million and $8 million figures are based on PNM and El Paso Electric participating in the same market. But El Paso Electric has announced its intention to participate in Markets+, while PNM is going with EDAM. (See El Paso Electric to Join SPP’s Markets+ in 2028.)
Tri-State said the benefit difference “is not actually driven by the adjusted production cost but is instead driven by different expectations of congestion revenues and bilateral trading revenue.” A presentation on the findings in August 2024 did not say “with any level of certainty how likely these benefits are to materialize,” Tri-State added.
Tri-State said that key considerations from the commission’s guiding principles — including greenhouse gas tracking, fair governance, seams management and market design — favor PNM’s participation in Markets+ or SPP’s RTO rather than EDAM.
PNM countered by saying its choice of EDAM was a discretionary action.
“PNM’s decision to join the EDAM is not properly before the commission in this proceeding; it is a decision PNM made 10 months ago and informed the commission of at that time,” PNM wrote in a reply to Tri-State.
Western Resource Advocates (WRA) also weighed in on PNM’s accounting order request, saying PNM had acknowledged the commission’s guiding principles for choosing a day-ahead market and presented “a reliable cost-benefit analysis study performed by the Brattle Group.”
WRA recommended the commission approve PNM’s request for an accounting order with the addition of certain reporting requirements before and after it enters EDAM.
The commission’s order directs PNM to provide updates on any “substantive changes to the market” and to file quarterly reports after its EDAM participation begins. The reports will detail cost savings to customers, transmission availability and use, renewable resource curtailment, resource planning impacts and market performance during extreme weather, among other issues.
After two years, PNM must file the reports annually.
The NYISO Operating Committee voted to approve the ISO’s draft Comprehensive Reliability Plan (CRP), though environmental groups and the Market Monitoring Unit voiced concerns with the wide range of predictions, the lack of identification of needed market changes and the potentially growing disconnect between other planning studies.
An early draft of the CRP, issued Oct. 7, called for “several thousand megawatts of new dispatchable generation by the 2030s,” based on a broad range of possible scenarios for load growth and supply. (See NYISO Reliability Plan Calls for ‘New Dispatchable Generation’.)
The newest draft, which will go before the Management Committee on Oct. 29, accounts for the third-quarter Short-Term Assessment of Reliability (STAR) and its identification of an immediate reliability need for New York City. (See related story, NYISO Again Identifies Reliability Need for NYC.) It was approved over the opposition of the Natural Resources Defense Council.
“The way this is all being presented in this reliability report is going to create great levels of alarm and confusion,” NRDC’s Chris Casey said at the committee’s meeting Oct. 16. “The technical experts understand it’s informational, but I don’t think it’s going to be interpreted that way.”
In a newly added sentence to the draft, the ISO acknowledges that, “as demonstrated by the study-by-study fluctuation in the system conditions and associated risks, the NYISO’s current approach in evaluating the reliability of the system is no longer sufficient for future planning studies.”
Casey argued that while the CRP talked up the importance of a strong market to meet reliability needs, parts of the report gave the impression that markets will not be able to solve the need. Some of the recommendations would exacerbate the disconnect between reliability studies and the Installed Reserve Margin on which prices are based, he said.
“Your point is really well taken,” said Ross Altman, senior manager of reliability planning for NYISO. “We need to discuss with stakeholders which specific range of forecasts or any of these factors we should consider an actionable reliability determination. What we are trying to say strongly is that it shouldn’t just be based on one. Combine that with the narrowing margins, and we are on a knife’s edge with every analysis we do.”
Much of the committee’s discussion centered on how to quantify reliability risks on the grid and how this would interact with existing planning processes.
“I definitely share some of the concerns that were shared by previous commenters,” said Pallas LeeVanSchaick, vice president at Potomac Economics, the grid operator’s MMU. He said NYISO’s analysis acknowledges a broad range of supply and demand outcomes but treats them as “random events.”
“The reality is the role of the market is to help moderate excess supply or insufficient supply,” LeeVanSchaick said. “The reality is when you look at the risks of aging generation and lack of supply, by far the biggest factors for those outcomes are not the age of the resources but a mix of environmental policies and market incentives for maintaining the generation and repairing significant failures.”
Liam Baker, senior vice president of regulatory affairs at Alpha Generation, weighed in as “the owner of the largest aging fleet.”
“When these things break … they break in such a manner that they need to be completely rebuilt,” Baker said. “The replacement parts we use nowadays are bespoke. We are … cannibalizing our existing fleet. … We are literally cannibalizing Gowanus 1 and 4 to keep Gowanus 2 and 3 and Narrows 1 and 2 running.”
Baker said NYISO was “wise” to highlight aging generation, but he wanted to make sure the ISO and other stakeholders understood how dire the situation was: Replacement parts for the plants often have to be custom made — or even purchased on eBay.
Matt Schwall, director of regulatory affairs for Alpha Generation, said this point was “critical.” The retirement dates for Gowanus and Narrows, which drove the reliability needs findings in the Q3 STAR, were not based solely on environmental rules, he said.
“We are proposing to retire these units because they are no longer economic to operate,” Schwall said. “There are other things driving generator retirements other than being unable to comply with state regulations.”
[EDITOR’S NOTE: A previous version of this story’s headline incorrectly said that $3.8 billion had been trimmed.]
LITTLE ROCK, Ark. — It took six votes during more than four hours of discussion — over the course of two days of meetings — before SPP stakeholders endorsed the 2025 10-year transmission plan and some of its proposed 765-kV lines, trimming about $2.5 billion in costs from the portfolio.
Members of the Markets and Operations Policy Committee on Oct. 13 first rejected their own proposal to defer the three southern legs of a proposed 765-kV overlay that would have shaved $3.83 billion in costs off the portfolio. They then shot down a motion to endorse the plan and the assessment report as modified by two stakeholder groups.
Neither motion received more than 57.5% approval, far short of MOPC’s 66.7% threshold.
After a night’s rest, SPP staff regrouped Oct. 14 during MOPC’s second day with three new proposals. They asked members to endorse:
the 2025 Integrated Transmission Planning assessment report as having been completed according to the tariff;
construction permits for the report’s 345-kV projects and three 765-kV reliability projects on the eastern and western legs of the RTO’s southern extra-high-voltage overlay; and
permits for the three 765-kV economic projects looping the overlay’s two legs together. The Crawfish Draw-Minco-Seminole-Anthem segments total about 515 miles and are estimated to cost $3.83 billion.
Referring the previous days’ voting “failures,” Casey Cathey, SPP vice president of engineering, asked MOPC for a “more clear and granular” direction for the Board of Directors to better prepare it for its consideration of the ITP when it meets in November.
SPP’s southern 765-kV backbone, including the Seminole-Anthem project | SPP
Staff have been studying about $18 billion in transmission projects as part of the 2025 assessment. The grid operator has proposed deferring $7 billion in 765-kV projects, reducing the portfolio to $11.16 billion for up to 50 construction permits to meet reliability and short-term needs. It has projected benefit-cost ratios of between 10:1 and 15:1. (See SPP Wants to Defer $7B in 765-kV Projects to 2026.)
Cathey reiterated the RTO’s cost-control measures and outlined several recent and in-flight tariff changes that improve the SPP’s cost-estimate process. He said the 2025 ITP’s 765-kV economic projects will have more control measures and conditions, including alignment with the 2026 ITP 765-kV overlay.
The grid operator was stung recently when cost estimates for its first 765 project, Southwest Public Service’s 345-mile Potter-Crossroads-Phantom transmission line that was part of the 2024 ITP, more than doubled from $1.69 billion to $3.62 billion. It took several more months of meetings for SPP to secure the project’s approval after SPS staff refined the RTO’s project projections. (See SPP Board Approves 765-kV Project’s Increased Cost.)
“We just went through that with the Potter-to-Crossroads-to-Phantom facility, so everybody has kind of a clear understanding of how that might work,” Cathey said, calling it a “good example” of SPP’s existing cost-control measures. “That project obviously came in higher for a number of reasons, but it also helped from benefits, cost-ratio and reliability needs perspective.”
MOPC members provided the “granular” feedback with their concerns on affordability, cost allocations, inequitable benefits and uncertainty about moving too fast or whether load growth slows. They questioned staff about the lack of analysis in the two motions to approve transmission projects and raised concerns about reliability concerns when 765-kV projects are set aside.
NextEra Energy Resources’ Jeff Wells objected to voting on separate construction permits rather than the entire portfolio.
“It was designed as a whole. It was studied as a whole, a complete portfolio. It works in concert,” he said. “Piecemealing it apart, simply because maybe we don’t like the designation, potentially, of reliability or economic [projects] … when you piecemeal that, you run the risk of losing the benefit that the portfolio has as a whole.”
“SPP has a really tremendous opportunity for growth with the industrial and technological developments that we’re seeing in this country; load growth as a result is also predicted to be tremendous,” said Jennifer Solomon, also with NextEra. “If we don’t build this portfolio as a whole, the development may not come, because what we’re seeing is that there may not be room for it. MISO, ERCOT and PJM are all moving aggressively forward with 765-kV lines just to keep up with the loads that they’re seeing.”
MOPC easily endorsed the first two motions. However, the motion to endorse the three 765-kV economic lines fell woefully short at 43.8% approval.
As staff mulled next steps, Director Steve Wright weighed in. He pushed for compromise among stakeholders and called for a better understanding of mitigating risks with large transmission facilities.
“One of the things that’s been ingrained in me in the three years on the board is it’s a hallmark of the board that we really want a high level of consensus,” he said. “We don’t have it here. The question is, what’s going to happen over the next couple of weeks? I really hope the Members Committee vote [an advisory ballot that precedes board votes] will not be the same vote as what we just had, because that just basically punts the issue to the board and is something that clearly there’s not much agreement around.”
American Electric Power’s Richard Ross echoed Wright in calling for a separate vote on the Seminole-Anthem portion of the 765-kV southern loop in the utility’s eastern Oklahoma service territory. The project is fast becoming a reliability project, Ross said, with 2.5 GW of load added to transmission service agreements after the 2025 ITP models were locked.
“That further solidifies that this will be a reliability project in the 2026 ITP,” Cathey said.
“I don’t want us to get away from this meeting without addressing that issue and mitigating the risk that we delay beginning work on that project as soon as possible,” Ross said, “begging” for one more vote “so that that message is clear to the board that we as a group agreed on moving forward with that particular project.”
MOPC endorsed the project’s approval and its projected $1.2 billion price tag, giving it 72.5% approval. Transmission owners voted 11-6 in favor, with one abstention, while transmission users approved the motion 45-11, with eight abstentions.
The committee’s actions reduce the 2025 ITP’s costs to $8.7 billion, SPP said. That still exceeds the record 2024 assessment, which approved permits for more than $7.6 billion in projects. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)
SPP COO Antoine Lucas promised staff will provide more information on cost-containment measures and risk mitigation as staff takes the ITP before state commissioners and the board, saying he understood the concerns being expressed. He said staff will continue to evaluate the $7 billion in deferred projects as load forecasts continue to evolve.
“This [2025 ITP] comes in the context of increasing strain on the existing transmission network,” he said. “The challenges that we’ve had to interconnect new generation and load without the need for tremendous new upgrade costs is a pretty good signal that the transmission system is at its limits. What we see every day in our [markets] is increasing levels of congestion, another very clear metric of very limited and — in some areas and cases — insufficient transmission.”
Staff have scheduled an education session for the Regional State Committee on Oct. 24. The state commissioners do not have any say over the ITP, but Cathey said the RTO will use the session to support any regulatory concerns or necessary additional policy.
The board will take up the package during its Nov. 4 quarterly meeting in Little Rock.
IESO hopes to curtail 100 MW of commercial HVAC load in 2026 under a new program targeted at resources available during system peaks, but not for the full six-month commitment of the capacity market.
The grid operator outlined the Save on Energy Commercial HVAC Demand Response Program in an engagement session Oct. 16. IESO hopes the program, expected to launch in June 2026, will scale to 230 MW at commercial and institutional facilities (e.g., retailers, offices, universities) in 2027.
Program participants will be required to respond to up to 10 events of up to three hours on business days between June 1 and Sept. 30. The events will be “typically between 3 and 7 p.m.,” IESO said in a presentation.
They will be paid based on the average megawatts curtailed per season. Settlement will be based on local distribution company revenue meter data, using the average megawatt reduction from the top eight of 10 events.
Requirements
Program participants must aggregate at least 500 kW of demand response load capacity and be able to monitor and verify load reductions, collect metering data and communicate with “program contributors” — the end-use facilities reducing demand.
Following the ISO’s first engagement session June 24, stakeholders called for flexible load eligibility and onboarding support for participants. The program will offer an incentive of $20/kW to offset contributors’ costs for metering, monitoring and control systems.
Stakeholders also identified LDCs as “key partners for coordination [and] visibility,” IESO said.
IESO’s Mohammed Yousif said LDCs also can participate as aggregators. “We’re not … limiting who participates into the program” other than the minimum 500-kW load, Yousif said. “LDCs may decide [on] different approaches.”
Stakeholders supported a day-ahead standby notice with same-day activation by midday. A standby notice will be issued no later than noon the day before the event, with activation notices sent no later than noon on the day of the event.
Non-HVAC Resources
Yousif said the program rules will specify non-HVAC measures that also will be eligible for participation. “The program will be predominantly HVAC — maybe 75% comes from HVAC and 25% comes from non-HVAC,” he said. “Battery energy storage … related to curtailment of HVAC systems could be considered as well.”
Antoni Paleshi, senior energy performance specialist for WSP, asked how owners of new buildings can estimate their contributions without any energy history.
“This is a pay-for-performance program,” Yousif said. “We could use the first few events as a way to … assess the estimate that is provided and adjust accordingly.”
IESO expects to issue the program rules by the end of November and complete program readiness by April.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Oct. 23. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will cover the discussions and votes.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
The committee will be asked to endorse as part of its consent agenda:
B. proposed revisions to Manual 3A: Energy Management System Model Updates and Quality Assurance drafted through periodic review of the document. The proposed language reflects the sunsetting of the Data Management Subcommittee and its replacement with the Modeling Users Forum, which was intended to allow for a long-term perspective. (See “Stakeholders Endorse Manual Revisions Reflecting Creation of Modeling Users Forum,” PJM OC Briefs: Oct. 8, 2025.)
Endorsements (9:10-10:10)
Wind and Solar Resource Dispatch in Real-time Market Clearing Engines (9:10-9:30)
PJM’s Vijay Shah will present a proposal to rework how wind and solar resources are dispatched in the real-time energy market. It would establish an Effective EcoMax parameter meant to more accurately capture how renewable resources are forecast to operate. It also would limit their ramping to 20% of their installed capacity per minute to reduce system volatility. (See “Renewable Dispatch Proposal Endorsed,” PJM MIC Briefs: Aug. 6, 2025.)
The committee will be asked to endorse the proposal and corresponding revisions to the tariff and Operating Agreement.
Resource Scheduling Prior to the Day-ahead Energy Market (9:30-9:50)
PJM’s Phil D’Antonio will present tariff and OA language to implement the offer capping of resources scheduled in advance of the day-ahead energy market by committing them on their cost-based offers. The proposal was approved by the Market Implementation Committee during its Sept. 10 meeting with the intention of subsequently developing governing document language.
The committee will be asked to endorse both the proposal and the corresponding tariff and OA language. PJM would seek same-day endorsement by the MC if approved by the MRC.
PJM’s Michael Herman will present proposed revisions to Manual 14D: Generation Operational Requirements to codify FERC-approved requirements for resource owners seeking to deactivate their units (ER25-1501). If the resource intends to participate in capacity auctions, it must provide at least a year’s notice ahead of its desired deactivation, while those not participating would follow the must-offer exception process. The changes also would revise elements of the deactivation avoidable cost credit and increase the number of documents that would be posted publicly. (See “1st Read on Manual Revisions Detailing Generation Deactivation Process,” PJM OC Briefs: July 10, 2025.)
The committee will be asked to endorse the proposed manual revisions.
The committee will be asked to endorse as part of its consent agenda:
B. proposed revisions to the tariff and OA to allow demand response resources to offer regulation-only service at sites where energy may be injected onto the grid, so long as the arrangement is reflected in a net energy metering agreement with their electric distribution company. (See “PJM Reviews Proposal on Regulation Resources at NEM Sites,” PJM MRC/MC Briefs: Aug. 20, 2025.)
A new Department of Energy strategy seeks to accelerate progress toward the long-sought, long-elusive goal of commercially viable nuclear fusion power.
The “Fusion Science and Technology Roadmap” seeks to coordinate and align public and private efforts and is part of the Trump administration’s broader energy dominance initiative.
The roadmap identifies research, materials and technology gaps that must be bridged before a fusion pilot plant can be built. It sets out three primary ways to accomplish this that boil down to build, innovate and grow: construction of critical infrastructure; innovation through advanced research, high-performance computing and artificial intelligence; and growth of a fusion ecosystem incorporating public-private partnerships, regional manufacturing hubs and workforce development.
The roadmap identifies six core challenge areas to be tracked with milestones and metrics: structural materials; plasma-facing components and plasma-material interactions; confinement approaches; the fuel cycle; blankets; and fusion plant engineering and system integration.
The goal is to build the public infrastructure needed to support the scale-up of private-sector fusion generation in the 2030s.
DOE formally announced the roadmap Oct. 16, after it was unveiled earlier in the week during events centered on fusion energy in D.C.
Energy Secretary Chris Wright spoke enthusiastically about fusion and the new roadmap at the Special Competitive Studies Project’s AI+ Fusion Summit in D.C. on Oct. 14.
“We’re going to get the fusion ball moving,” he said. “I think we will see more progress in the next five or 10 years, much more progress than in all of the history before on fusion. We’re finally going to see the reality of fusion come, first in the electricity grid, ultimately in industrial process heat to make things, and hopefully we can rapidly scale that up.”
The new roadmap is aligned closely with and builds off the Fusion Energy Sciences Advisory Committee Long-Range Plan, issued in 2020. The roadmap combines the earlier plan’s science drivers with a revamped Fusion Energy Science public program in DOE’s Office of Science in hopes of bringing to fruition what has been a very lengthy effort.
As skeptics like to point out, fusion research and development efforts have not yet lived up to the hope and hype surrounding them. A running joke is that the world has been 20 years away from perfecting commercial fusion for 50 years.
Wright addressed this at the Oct. 14 summit: “I worked on it 40 years ago. It isn’t that we’ve gotten nowhere in 40 years. It’s just a hard problem to replicate the sun on Earth. … We’ve made progress over the last 40 years, and we’re about there.”
What is different now, Wright said, is that artificial intelligence presents the need for large amounts of new electrical generation capacity, such as through fusion, and a tool to help develop fusion generation; fusion R&D is attracting private capital, which is less patient than public funding; and the U.S. wants to lead the world on fusion, rather than see the leadership role go to China, which is making massive investments to do just that.
“What China doesn’t have is the commercial sector we have,” Wright said. “We have billions of dollars of private money in different companies, backing different strategies, with different biases. We’re going to naturally get a broader choice.”
DOE’s network of national laboratories can complement these private-sector R&D efforts in key areas such as developing the materials needed to withstand the intense environment of a fusion reactor, he said.
Wright said one of the obstacles facing this initiative is budget cuts. While he agrees with President Donald Trump’s push to reduce spending, he said cuts should be targeted at subsidies for existing technologies, not directed broad stroke at everything in DOE’s budget.
“And I’ve had the political challenge to sell ‘not everything,’” he said. “In fact, there’s things we spend money on today that we should spend more on, not less on, even though we have a big budget deficit, and basic fundamental science is absolutely one of those.”
The U.S. needs to come closer to matching China’s investment of state funds in AI, Wright said: “My God, the upside of it is just — it’s hard to imagine. So we need to continue to bring confidence and private money into it, but we need to bring more government money into it.”
DOE in its roadmap notes the billions of dollars of private-sector investment pouring into fusion.
The Fusion Industry Association reported in July that the 53 fusion companies it surveyed had raised a combined $9.77 billion in funding, a fivefold increase over their total four years earlier. More than $2.5 billion of that was secured just in the past year, it added. The great majority of the capital has been private, with not even $800 million in public finding reported.
But 83% of companies said they still consider investment a major challenge, and their estimates of funds needed to bring their first pilot plants online were a combined $77 billion.
They remain optimistic, however: 84% expect to deliver power to the grid before 2040 and 53% by 2035.
Twenty-nine of the 53 companies surveyed for the association’s 2025 “Global Fusion Industry Report” are based in the U.S., and all three of the companies reporting more than $1 billion in funds raised are based here as well.
Commonwealth Fusion Systems of Massachusetts has claimed a leadership position in the pack, with nearly $3 billion raised as of late August, or approximately 30% of the total reported by private fusion companies worldwide. It has announced plans to build what it promotes as the world’s first grid-scale fusion plant in Virginia in partnership with Dominion Energy, and has announced power purchase agreements with Google and Eni that would account for more than half of the facility’s planned 400-MW nameplate capacity.
NEPOOL members have proposed several amendments to the first phase of ISO-NE’s capacity market overhaul prior to the scheduled Markets Committee vote on the RTO’s proposal in November.
The amendments presented to the committee Oct. 16 include proposals to allow generators to submit capacity offers reflecting physical limitations during hot weather; adjust the methodology for calculating the capacity offer price threshold (COPT); and extend the length of time resources can hold onto interconnection rights while undergoing major repairs.
The first phase of ISO-NE’s Capacity Auction Reform (CAR) project is centered around shifting the Forward Capacity Market to a prompt design and updating the resource retirement process. The second phase is focused on accreditation changes and instituting a seasonal market. Both phases are intended to take effect in the 2028/29 capacity commitment period. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)
Ambient Air De-list Bids
Bruce Anderson of the New England Power Generators Association (NEPGA) argued that ISO-NE should extend existing rules and practices allowing generators to submit capacity offers reflecting reduced generating capabilities at temperatures above 90 degrees Fahrenheit.
The RTO’s current proposal requires all qualified resources to offer all available capacity in annual auctions and would not maintain the option for generators to de-list capacity during periods of high temperatures.
“Without carrying forward the exemption, a resource will unnecessarily be required to submit a cost workbook for megawatts it is physically unable to produce at those high ambient temperatures,” Anderson told the committee.
To address the issue, NEPGA has proposed adding language allowing participants to “identify and submit a price-quantity pair(s) in a capacity offer specifically attributable to and up to the megawatt amount that the lead market participant expects will not be physically available due to ambient temperature effects.”
Several members of the generation sector expressed support for the amendment, while some stakeholders said it ultimately will be important to address temperature effects in the accreditation phase of the CAR project.
Chris Geissler, director of economic analysis at ISO-NE, said the RTO does not yet have a firm position on the amendment and still is considering the proposal. He added that ISO-NE’s existing proposal to not carry forward ambient air exemptions was motivated by a desire for more consistency across different segments of capacity.
Capacity Offer Price Threshold
Ben Griffiths of LS Power proposed a transitional methodology for calculating the COPT for the 2028/29 commitment period that he said would help address issues related to outdated price inputs.
The price threshold is intended to protect against market power; participants offering above the threshold price are required to submit a cost workbook to the Internal Market Monitor.
ISO-NE plans to maintain its methodology for calculating the threshold as it transitions to a prompt auction. Under the existing methodology, the 2028/29 threshold would be based in part on the prices from the last Forward Capacity Auction, which will have been held about four years prior to the first prompt auction.
Griffiths said he’s concerned this will lead to an outdated threshold value, especially after capacity shortfall events over the past two summers caused some generators to accrue costly performance penalties, which has caused some participants to speculate that capacity costs will increase in the future to account for these risks.
He proposed that ISO-NE set the threshold for the 2028/2029 commitment period at “at a fixed price of $4.984/kWm,” which “represents the simple average of observed clearing prices in the summer 2025 ARAs [annual reconfiguration auctions] and theoretical common value component estimates derived from the same auctions.”
The common value component equals “the expected value of scarcity revenues under [Pay-for-Performance],” Griffiths noted in a memo published prior to the meeting.
He said the close alignment of the ARA and common value component prices “supports a strong case for using this value.”
Responding to the proposal, Geissler said the RTO’s current proposal is to extend the existing methodology for the threshold. However, he said ISO-NE is amenable to considering transitional changes to address a time lag in the data, especially if there is broad stakeholder support.
Geissler said ISO-NE plans to consider changes to the threshold during the accreditation phase of CAR. However, if the RTO cannot finish the accreditation phase in time for the 2028/29 commitment period, and it identifies issues related to stale data used in the COPT, the RTO would look to address the issue prior to the auction, he said.
Also at the meeting, Andy Gillespie of Calpine reiterated his proposal for ISO-NE to base the threshold strictly on the common value component. He acknowledged that this could lead to a threshold value significantly higher than the clearing price of past FCAs but stressed that the threshold should be a forward-looking metric.
“This method is based on ISO-based, forward-looking, objective data” and is “often cited by ISO as the basis for calculating PFP opportunity cost,” Gillespie said, adding that the methodology could “be used regardless of auction format or accreditation methodology.”
Geissler said ISO-NE is not supportive of a broader change to the COPT methodology, which it considers to be outside the scope of work for the first phase of the CAR project.
3-year Rule
Griffiths also advocated for a change to ISO-NE rules that automatically deactivate resources that do not run for three straight calendar years. He expressed concern that recently proposed changes to the RTO’s repowering rules could cause resources facing extended repairs to lose their interconnection service.
Three- to seven-year wait times for turbines and transformers “make compliance with the strict three-year clock unrealistic for facilities facing catastrophic outages,” Griffiths said.
While resources could seek a waiver from FERC to ISO-NE’s three-year rule, “FERC’s waiver process is uncertain and ill-suited to this situation,” he argued.
Griffiths proposed introducing “a bounded extension” of up to six years for resources making “good-faith restoration efforts.”
To be eligible for such an extension, resources should have to demonstrate “due diligence, including at-risk expenditures, in pursuit of permitting, licensing and construction necessary to restore the resource to commercial operation,” he proposed.
Several stakeholders said they are open to the change but would want to ensure there is language to prevent resources from using the extension simply to hold onto interconnection rights and prevent other resources from entering the market.
ISO-NE agreed the issue warrants additional discussion but said it should be done outside of the CAR process.
Griffiths also offered an amendment to clarify ISO-NE’s authority over the interconnection rights of state-jurisdictional resources that have been inactive for more than three years. He advocated for new tariff language “to protect jurisdictional integrity” and to “enable equal treatment for state resources under the proposed deactivation language.” ISO-NE, however, said that is outside the scope of the CAR project.
Accreditation Updates
Also at the meeting, ISO-NE outlined its plans to calculate seasonal forced outage rates in the new accreditation framework.
Equivalent forced outage rate on demand (EFORd) is intended to quantify resources’ likelihood of having an outage when called upon and is a key input into resources’ overall accreditation value, noted Steven Otto, manager of economic analysis at ISO-NE.
The RTO plans to calculate EFORd values based on data from the previous five years. For resources that lack enough data, it plans to use class averages from the New England generation fleet to fill in any gaps, Otto said.
“Conceptually, the mechanics of seasonal EFORd calculations will be identical to the existing mechanics for annual EFORd calculations, except that the calculation will be done for a given season with historical data only from that season,” Otto said.
He added that “for most resources, the differences between their annual and estimated seasonal EFORd values are small.”
Maximum Capability
ISO-NE also discussed its methodology for calculating resources’ maximum capability, which “represents a resource’s physical supply capability and reflects changes in a resource’s capability due to changes in its physical attributes.”
To generate accreditation values for each resource, ISO-NE plans to multiply resources’ maximum capability by their marginal reliability impact ratio, which compares the reliability benefits of the resource to a hypothetical “perfect” capacity resource.
Maximum capability would be calculated seasonally in the summer and winter. In the summer, it would equal each resource’s maximum recorded hourly net output from the past three years when temperatures are over 80 F. Winter maximum capability values would be based on maximum hourly output when temperatures are below 32 F.
ISO-NE also plans to allow resources to schedule an audit to determine their maximum output.
For active demand resources, the maximum capability will be based on maximum hourly performance in the winter and summer from the previous three years. The temperature constraints would not apply to these resources, as they do not self-schedule, and are not guaranteed to run at their full capacity at a certain temperature in any given season, ISO-NE said.
The maximum capability for energy efficiency resources would be based on performance estimates from ISO-NE’s efficiency database.
ISO-NE said the three-year lookback period for maximum capability values should give resources that run infrequently enough time to demonstrate their full performance capabilities while also capturing recent performance trends.
FERC has ruled that MISO must name a point in development and describe how it will consider merchant HVDC lines in its transmission planning; however, the commission declined to order a more complete incorporation of the Grain Belt Express HVDC line in MISO’s recent transmission planning.
The directive to MISO was the sole issue FERC granted from Invenergy Transmission’s 2023 complaint, which sought to force MISO to consider the Grain Belt Express in its transmission planning (EL22-83).
FERC said Invenergy successfully argued that MISO’s tariff is unfair “insofar as it does not address when and how [merchant] HVDC transmission projects are incorporated into MISO’s transmission planning models.” The commission told MISO to decide on a juncture and explain how it would account for merchant HVDC lines in transmission planning and add it to the planning protocol section of its tariff within 90 days.
Elsewhere in its Oct. 16 order, FERC decided that Invenergy did not meet its burden to prove that MISO fumbled on its planning practices regarding the proposed 800-mile, 5,000-MW line.
Invenergy argued that MISO has an obligation to incorporate “advanced-stage” merchant transmission facilities in its base case analysis performed under the annual MISO Transmission Expansion Plan (MTEP) and in long-range transmission planning.
The company claimed MISO is forcing ratepayers to foot the bill on regionally planned transmission projects that could be redundant alongside planned merchant HVDC projects. Invenergy said MISO should not be able to ignore merchant transmission in its MTEP and long-range transmission planning exercises when MISO’s tariff prescribes that MISO should assess a “quantifiable benefit” of an “enhancement to the MISO transmission system.”
Invenergy had asked FERC to order MISO to edit its tariff so that it incorporates all advanced-stage merchant transmission projects in its annual and long-term transmission planning. It also asked FERC to direct MISO to perform an after-the-fact sensitivity analysis for MISO’s two long-range transmission portfolios that considers Grain Belt.
MISO said it performed such a sensitivity analysis for the second long-range portfolio and found no reason to change any of its project recommendations. FERC accepted MISO’s analysis and declined to mandate more studies.
Invenergy said MISO’s second long-range portfolio contains a 765-kV line in Missouri that duplicates some of Grain Belt’s capabilities. It said MISO planned the line over 2024 even though Invenergy had a transmission connection agreement with MISO. Invenergy also said MISO’s first long-range transmission portfolio from 2022 included three projects at a combined $1.46 billion in northern Missouri that would return just 40 cents for every dollar spent on them once Grain Belt is transporting power.
Invenergy argued that MISO’s interpretation of its tariff “leads to an absurd result and unjust and unreasonable rates” and that MISO’s decision not to account for Grain Belt betrays optimized transmission planning.
FERC said Invenergy did not demonstrate that MISO’s evaluation of the trio of projects was incompatible with its tariff requirements. The commission also noted that MISO assesses the benefit-to-cost ratio on a portfolio basis and doesn’t produce ratios for individual projects. FERC also pointed out MISO does not assess a line’s ability to cancel out lower voltage upgrades of 230 kV or below, per its long-range transmission planning procedures.
Commissioner Lindsay See, while concurring with the order, put MISO on notice that additional analyses are a smart move to prove the worth of several billion-dollar transmission portfolios.
“When billions of dollars in infrastructure projects are at stake, more confidence in the accuracy of MISO’s planning and cost-benefit assumptions is not too big an ask. Judiciously using sensitivity analyses to help ratepayers get the most value for their money may be one tool well worth its weight,” See wrote.
See said it’s unclear whether MISO “is providing stakeholders and the MISO Board with the best information possible to assess true grid needs” when it unveils a long-term transmission portfolio. She cited the pending North Dakota-led complaint questioning the value of MISO’s $22 billion, mostly 765-kV second long-range transmission portfolio. (See MISO States Split on FERC Complaint to Unwind $22B Long-range Tx Plan.)
Invenergy representatives have said for years in MISO public meetings that the RTO’s transmission planning modeling is deficient because it didn’t factor in Grain Belt Express operations. (See “The Grain Belt Express Question,” Members Call for More Tx Expansion Following MISO’s $20B LRTP Blueprint.)
MISO did not include impacts from the Grain Belt Express merchant HVDC line in any of its 30-plus annual models under its 2024 Transmission Expansion Plan. MISO said Grain Belt Express did not sign its transmission construction agreement until about three weeks after the Feb. 1 cutoff date for members to submit projects for inclusion in MTEP 24 planning models. (See FERC OKs Grain Belt Express Connection Agreement with MISO; Invenergy Displeased with 2030 Target.)
MISO said it would include only approved segments of Grain Belt in its MTEP 25 planning modeling. Some MISO stakeholders have said Grain Belt Express stands to deposit substantial wind energy from Kansas into MISO.
Earlier in 2025, the U.S. Department of Energy Loan Programs Office revoked a $4.9 billion conditional loan commitment for Grain Belt. (See DOE Pulls $4.9B in Funding for Grain Belt Express.) Invenergy has vowed nevertheless to move ahead with the project.
