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December 8, 2025

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Voltus, Mission:data Seek Changes to PJM Data Requirements for DR

Curtailment service providers Voltus and Mission:data have filed a complaint with FERC against PJM, alleging its rules are unjust because they require the companies and other demand response providers to submit load-reduction meter data for their customers when they have little to no meaningful access to them (EL26-4).

Utilities have access to those data because of their investments in smart meters, the companies argued in their complaint filed Oct. 8. The companies requested that PJM be required to change its rules so that CSPs can use the RTO’s statistical sampling method (used when smart meters are not available) if they submit a sworn declaration, with appropriate notice to the relevant state regulator, certifying that interval meter data are not available from the utility.

State regulators would be notified of the issue and then could require changes from their utilities to allow the use of actual meter data, the companies argued.

The issue already has come before FERC, when CPower filed a complaint in 2023 asking to use statistical sampling to measure its customers’ DR. FERC denied the complaint, finding that the DR aggregator had not offered enough support that it and other CSPs were unable to procure the data.

Before CPower’s complaint, it tried to get changes through PJM’s stakeholder process, but it said it was thwarted by entities that benefit from the status quo. (See “Stakeholders Narrowly Reject Demand Response Problem Statement and Issue Charge,” PJM MRC Briefs: Oct. 24, 2022.)

Part of the issue is that the RTO’s rules were developed for large commercial and industrial customers, Voltus and Mission argued, but CSPs work with residential customers by aggregating home automation systems and devices like smart thermostats to build DR aggregations and bid them into PJM’s capacity markets.

“For meaningful participation in the PJM market to occur for residential customers, CSPs must have scalable, efficient and meaningful access to differentiated interval meter data that will accommodate concurrent registration of thousands of residential customers if there is to be effective participation by these classes of customers,” the companies said in the complaint.

Getting those data from utilities is either not possible, or it comes with impractical requirements that make it infeasible, they argued. Voltus also prepared a position paper, filed with the complaint, that purports to show the validity and accuracy of aggregated load data are as accurate as high-quality individual meter data.

“Accordingly, requiring the submission of hourly interval meter data when access to that data is not readily available and when statistical sampling or aggregation is sufficiently accurate is unjust and unreasonable,” the complaint said. “The requirement is also discriminatory when utilities do not have the same barriers to accessing hourly meter data and under the PJM tariffs can and do participate as direct competitors to competitive aggregators acting [as] CSPs.”

Voltus said it reached out to some major utilities in the RTO about using the Green Button Connect or Electronic Data Interchange, or otherwise getting 18 months of interval data, peak load contributions, and capacity and energy loss factor values when customers authorize it to get their data.

A chart from the complaint showing the lack of availability of meter data from utilities in PJM. | Voltus and Mission:data

Commonwealth Edison offers online tools for retail suppliers to access customer data, but it limits the requests to 10 accounts at a time. The use of third-party tools to access larger numbers of accounts does not work because of an irreversible two-factor authentication process, Voltus found.

“In other words, every time any party needs to access the data, the customer him- or herself must complete the two-factor authentication, and if a customer initially chooses two-step verification when establishing online registration with ComEd, the customer cannot reverse it or disable it on a go-forward basis to permit third-party access and would have to reauthenticate a dozen or more times a year,” the companies said in the complaint.

A successful lawsuit required changes to how ComEd shares customer data, but so far, the utility has yet to implement any changes. Voltus signed up 20,000 customers in the utility’s territory, but it got only enough data for 4% of them to bid into PJM, meaning 23 GW of new capacity were unavailable to the RTO.

The complaint explains similar experiences with other utilities and lays out the basic findings in a table.

Access to utility data on residential customers could be accomplished by changes to state rules, but the complaint argues numerous proceedings at that level “will not result in a uniform, efficient and effective approach to a regionwide issue applicable to the entire PJM market and will deprive PJM of needed and beneficial resources during a time of unprecedented load growth, increasing capacity constraints and concern for reliability.”

Allowing statistical sampling when the retail customer is not practically available does not infringe on state jurisdiction and would give the market a uniform and efficient approach to the issue, the companies argued. The statistical method becomes more accurate the more meters are included in an aggregation and with enough of them, it “can far exceed the effective accuracy of existing standards,” they said.

The companies noted that FERC has recognized that with enough evidence, it could be proved that lack of access to meter data is a barrier to meaningful participation in wholesale markets, citing a concurrence in the CPower complaint by Commissioner Judy Chang.

“Voltus has now provided such evidence above,” the companies said. “FERC precedent has consistently emphasized the removal of unnecessary barriers to demand response and distributed resource participation in wholesale markets, particularly noting the benefits of removing barriers that prevent smaller resources from providing services to the grid when larger resources can more easily meet certain requirements.”

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ERCOT’s GRIT Program Marries Grid, New Technologies

ERCOT has introduced a new initiative to advance research and evaluate emerging concepts and solutions in the face of an evolving grid and new technologies.

Through the Grid Research, Innovation and Transformation (GRIT) approach, ERCOT says it will collaborate with public and private sector experts to identify and address emerging grid issues, research them and then prototype the solution — in other words, create an experimental model or a basic version of a product to test its functionality, then refine the design before mass production.

Prashant Kansal, director of grid transformation, told the grid operator’s stakeholders recently that the GRIT initiative is a proactive look at a future problem. The grid and its supporting operational technologies are evolving rapidly, requiring deliberate focus and specialized expertise to ensure future readiness.

“The grid is changing a lot, and it’s both on the grid side … and the operations side,” Kansal told members of the Technical Advisory Committee in August. He cited the increased growth of inverter-based resources, large loads, grid-enhancing technologies and distributed energy resources on the grid side and artificial intelligence, data and computation capabilities on the operations side.

“Combine those two things together and there is definitely a need for ERCOT to be proactive in understanding what problems we are facing,” Kansal said. “That the core mission for the grid transformation initiatives that we’re carrying on.”

“We are seeing greater interest from industry and academia to collaborate on new tools and innovative technologies to advance the reliability needs of tomorrow’s energy systems,” ERCOT CEO Pablo Vegas said in a statement. “These efforts will provide an opportunity to share ideas and bring new innovations forward as we work together to lead the evolution and expansion of the electric power grid.”

Staff will take proposed initiatives from ERCOT stakeholders and regulators, the national labs, vendors, universities and other grid operators and funnel them through various internal processes. Bi-weekly meetings with business directors and bi-monthly meetings with subject-matter experts will consolidate the different problems and solutions before the proof-of-concept test of the initiative’s feasibility.

“Once we have those initiatives and we look at the problem statement, we are categorizing them into two things,” Kansal said. “One, do we understand the problem or not? And if we have a problem, do we understand the solution or not? If we understand both the problem and the solution, that fits within the business team. If you don’t have either of them, then that belongs in the transformational realm, where our team can work with different partners within ERCOT and different partners outside ERCOT to help understand the problem or the solution.”

The initiatives then will be brought back into the operational realm and go through the stakeholder process, Kansal said.

The GRIT program opened with 14 initiatives identified through internal and external discussions. ERCOT has deployed a website to help stakeholders track the initiatives and to read and comment on white papers as they are drafted. The first five papers include topics on AI and machine learning, DERs’ operational data and the case for multi-interval security constrained optimal power flow.

The website also includes a portal to apply for the ISO’s Research and Innovation Partnership Engagement (RIPE) program, enabling partners with “transformative ideas” to engage with ERCOT on new technologies, and information about the grid operator’s annual Innovation Summit. The third such summit is scheduled to be held March 31, 2026, in Round Rock, Texas.

As part of the GRIT efforts, ERCOT said in early October it selected GE Vernova to participate in a proof-of-concept implementation of the ERCOT Distribution Awareness Platform (EDAP). The technology is designed to “talk to” DERs or energy storage batteries at the distribution level or behind the customer’s meter to provide real-time situational awareness to the ISO’s operations and planning teams.

The grid operator says EDAP will deliver the tools needed to improve visibility into DERs, strengthen reliability and ensure the grid evolves to meet growing demand and increased DER penetration.

Kansal told TAC members that ERCOT is partnering with Texas A&M University to deepen its knowledge of the architecture of data centers, crypto mines and power supplies and better model them.

“This is going to be a changing world in next few years because this architecture is evolving,” he said.

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PJM OC Briefs: Oct. 8, 2025

Stakeholders Endorse Manual Revisions Reflecting Creation of Modeling Users Forum

The Operating Committee endorsed revisions to Manual 3A: Energy Management System Model to reflect the committee’s sunsetting of the Data Management Subcommittee (DMS) to be replaced by the Modeling Users Forum. The forum allows for discussions on the “challenges and opportunities with model information,” how new technology can be employed on the grid and improvements to the energy management system (EMS). Ahead of the February vote to establish the forum, PJM said it would allow for a focus on long-term goals and initiatives. (See “Other Committee Business,” PJM OC Briefs: Feb. 6, 2025.)

The manual revisions replaced references to the DMS, updated links and replaced the subcommittee’s email list.

September Operating Metrics

PJM observed an hourly load forecast error rate of 1.18% during September, with the rate for peak hours at 1.84%, according to the monthly operating metrics. There were eight days where the error rate for the forecast peak exceeded the RTO’s 3% benchmark. On Sept. 29, the peak was 5.28% over forecast; the peak on the 30th and 24th came in around 4% lower than expected; and the 15th and 16th were 3.23% and 3.02% over forecast, respectively. Sept. 26 saw the highest under forecast at 4.84%, followed by the 28th at 4.6% and the 18th at 3.73%. The error on each of the days was attributed to temperatures deviating from expectations.

The month saw four spin events, three high system voltage actions, two geomagnetic disturbance warnings and 22 post-contingency local load relief warnings. Six shortage cases were approved: one on Sept. 1 due to a primary reserve shortage while hydro resources were pumping, two on Sept. 4 attributed to a spin event following loss of generation and three on Sept. 25 due to low area control error following a spin event caused by loss of generation.

The Sept. 1 spin event lasted eight minutes, 59 seconds and had 2,421 MW of generation and 542 MW of demand response assigned, with 69% and 89% responding, respectively. Another deployment on Sept. 25 lasted 10 minutes, 29 seconds and had 2,754 MW of generation and 589 MW of DR assigned, of which 75 and 83% responded; a second event that day lasted 7 minutes, 43 seconds and had 2,810 MW of generation and 589 MW of DR assigned, with 60 and 56% responding. The fourth event was on Sept. 29, lasting 6 minutes, 45 seconds and seeing 2,910 MW of generation and 496 MW of DR assigned, of which 49 and 86% responded.

First Read on Manual 14D Revisions

PJM’s Ray Lee presented revisions to Manual 14D: Generation Operational Requirements related to how transmission owners might be required to submit resource proposals under the reliability backstop, PJM’s EMS communications and generator data reporting requirements. Staff plan to seek endorsement of the language during the Nov. 6 OC meeting.

The changes seek to clarify the third step in the black-start, black-stop process, when PJM would open a request for proposals soliciting solutions to reliability needs from transmission and generation owners. The backstop has become an increasing focus over recent months as PJM has shined more detail on the resource adequacy constraints it believes will accompany rising data center load.

Generation owners would be required to report possible start-up issues to the limits they are required to report during a cold weather advisory. Guidelines on the data resource owners must provide PJM were updated to reflect the cold weather advisory drill and cold weather operating limit data requests.

A section that was deleted inadvertently was added back into the manual to describe how communications between control centers will be conducted through the inter-control center communications standard.

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FERC Approves PG&E’s Cost Recovery Request for Abandoned Battery

FERC approved PG&E’s request to recover more than $600,000 in costs for an abandoned battery plant in California, saying the company sufficiently demonstrated it meets the requirements for cost recovery as established under previous commission orders (ER25-2238).

In an Oct. 10 order, FERC allowed PG&E to recover $602,472, or 50% of about $1.2 million, for planning and scoping the now abandoned 7-MW Dinuba Battery Storage System in Fresno, Calif.

CAISO approved the project after identifying several reliability concerns with transmission systems in Tulare and Fresno counties between 2010 and 2013. The ISO proposed resizing the battery facility from 7 MW to 12 after identifying more issues in 2019 because of the retirement of a local generator, according to FERC. It would have been CAISO’s first storage project fully dedicated as a transmission asset. (See Storage Week: Hairless Cats, Rising Stats and Skeptics.)

However, in its 2023/24 transmission plan, CAISO said it found an alternative solution that would address the reliability concerns “more comprehensively and effectively” than PG&E’s battery storage system, leading to the cancellation of the project, according to the order.

PG&E filed a request for cost recovery May 15 for the scoping, engineering, feeder, switchgear, control building and relay design, and material procurement associated with the abandoned project. It also requested authorization to amortize and recover the abandoned plant costs over a one-year period.

The company contended it was entitled to cost recovery because CAISO considered the battery storage system as a transmission asset as required for cost recovery under Opinion 295, which instituted the abandoned plant policy in 1988. The abandoned plant costs should be evenly split between customers and shareholders, PG&E argued.

FERC agreed, saying CAISO selected the project as a transmission asset to address thermal overloads. The commission also noted that PG&E would have operated the project under the direction of CAISO, similar to other wholesale transmission facilities, it said.

“We find that PG&E has demonstrated that it qualifies to recover 50% of the prudently incurred project costs based on the facts and circumstances presented in this proceeding, consistent with Opinion No. 295,” the order stated.

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CEC Approves 5 Offshore Wind Projects at California Ports

The California Energy Commission has approved $42 million for five offshore wind projects at ports in the state, despite recent federal policy changes that have left the future of the renewable resource in limbo.

Existing port infrastructure in California is “insufficient” to support the offshore wind industry because of long development timelines and high investment costs, one of the commission’s grant awards said.

The largest funding amount went to the City of Long Beach, which received $20 million to build a 400-acre offshore wind terminal at the Port of Long Beach. The funding will go toward the completion of engineering calculations, environmental assessments and community engagement activities. Engineers on the project also will determine whether the port can be designed to be a zero-emissions terminal. Construction is planned to start in 2027 and be completed by 2035.

In 2022, the CEC set a goal to install up to 5 GW of offshore wind capacity by 2030 and 25 GW by 2045. That amount of capacity requires 15-MW turbines, which have components that are “so large that the only feasible way to transport them is by waterborne transit; road and rail transit are not feasible,” the grant says.

Also in 2022, California passed Assembly Bill 209, which created the Offshore Wind Waterfront Facilities Improvement Program and directed the CEC to develop plans to improve California’s ports, harbors and waterfront facilities for floating offshore wind purposes.

“The wind [energy] resource offshore is significantly better and stronger, and actually more enduring than the wind on land,” Chair David Hochschild said at the CEC’s Oct. 8 business meeting. “One of the key steps is the port investment and the port infrastructure.”

At the national level, offshore wind projects are expected to see a sharp decline in construction over the next five years and beyond, a BloombergNEF analyst reported to the CEC. (See Renewable Construction Slump Starts in 2028, Forecast Shows.) This decline is due to recent federal policy changes that eliminated some tax credits for renewable energy construction projects.

CAISO, however, in May selected Viridon, a transmission engineering firm, to build about 400 miles of new transmission lines for two planned offshore wind facilities in Humboldt County. The transmission projects could cost an estimated $4.1 billion. (See CAISO Chooses Viridon to Develop Humboldt OSW Transmission Projects.)

At the CEC meeting, the commission also awarded $18.2 million to the Humboldt Bay Harbor, Recreation and Conservation District to convert an existing industrial site into a heavy-lift terminal for the manufacturing of large offshore wind components. Humboldt Bay can provide a “critical role for offshore wind development in Central California, Northern California and Oregon,” the award says.

Three smaller grants approved at the meeting were as follows:

    • The Port San Luis Harbor District: $3 million to continue the design of port upgrades to receive offshore wind equipment and to fund community engagement activities about offshore wind energy off the Central Coast.
    • The City of Oakland: $750,000 to design upgrades to the Port of Oakland that would prepare the port for offshore wind equipment delivery and fabrication purposes.
    • The City of Richmond: $750,000 to complete 30% of a design to upgrade port infrastructure on up to 216 acres at the Point Potrero Marine Terminal. These sites offer “extensive berth availability, access to deep-water navigation channels and a strategic location within the San Francisco Bay, close to the five current California offshore wind lease areas,” the grant award
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MISO Mulling New Way to Convey Spate of Advisories in South

MISO is contemplating a better way to communicate generation shortfalls in its Southern load pockets than continuing to send out repeat capacity advisories. 

The RTO also announced it would introduce transmission system warnings to convey that space on the system is critically low. 

Senior Director of Reliability Coordination John Harmon said the RTO has fielded a “steady increase” of emails and requests to stakeholder relations for reasons behind the every-other-day capacity advisories issued for MISO South. 

Stakeholders told MISO in early October they needed a better explanation for the advisories, which have become standard since the beginning of summer. They said the nonstop nature of the alerts has made it easier to disregard them. (See Stakeholders Demand Answers on Repeat MISO South Capacity Advisories.) 

MISO issued capacity advisories regularly in its South region a few weeks after it was forced to order load shedding in Greater New Orleans over Memorial Day weekend. (See MISO Says Public Communication Needs Work After NOLA Load Shed.) The grid operator has shown no signs of slowing its flurry of capacity advisories so far this fall. 

At a Reliability Subcommittee meeting Oct. 9, Harmon confirmed that the advisories are a corollary of the Memorial Day weekend load shed event. But he also said the frequent advisories don’t represent a change in the risk parameters MISO uses. He said MISO instead has been disclosing publicly the risks that it used to communicate privately with affected utilities’ control rooms. 

“The only change from MISO’s process perspective is we’re communicating these externally,” Harmon told stakeholders. 

Harmon said the advisories concentrate mostly on Downstream of Gypsy and Amite South load pockets in southeastern Louisiana. He said the area has a lack of quick-start generation and MISO often is forced to line up more supply through its Voltage and Local Reliability (VLR) generation commitments. 

MISO issues capacity advisories when five or more hours in an operating day are predicted to have a capacity deficit of any size or when any hour of the operating day is predicted to have a deficiency of 100 MW or larger. 

Harmon said that lately, abnormal loads and forced outages paired with the limited import capability of the South load pockets mean that “available generation in those load pockets is less than the requirement spelled out in operating guides.” 

As Harmon spoke, MISO issued conservative operation instructions for the South region because of scheduled transmission and forced generation outages in southeastern Louisiana. 

Harmon said MISO has been “borrowing the capacity advisory template to communicate” the risk in the load pockets. He said the corporate communications team is examining whether it could “improve messaging” of the advisories and differentiate load pocket risk from regional shortages. 

Jim Dauphinais, an attorney for multiple industrial end-use customers in MISO, said members typically keep an eye out for capacity advisories, but the onslaught makes them seem inconsequential. 

“I think we need to explore calling these new notifications as something else. The concern is these are so frequent that they’re lowering the situational awareness,” Dauphinais said. 

Bill Booth, consultant to the Mississippi Public Service Commission, asked if there is any required action that utilities should take when the advisories are in effect. 

“It’s difficult to get warnings and not know what’s expected of you. … It’s the ‘cry wolf’ thing,” Booth said. 

Harmon said the advisories are more to create situational awareness and signal utilities to run their own risk evaluations. 

MISO Senior Manager of Unit Commitment Amber Alewine also said the RTO is shifting to more forward-looking capacity advisory and conservative operations declarations using a forecast model that predicts uncertainty on the system multiple days in advance. She said it’s a “change in posture” for MISO when declaring capacity advisories. 

The RTO also has begun employing more capacity advisories on a Friday when resource sufficiency on the following Monday is questionable, she said. And “especially over the last couple of weeks,” it has been reaching out to market participants to make sure generation offers are correct and reflect actual capability, she added. 

MISO to Roll out Transmission Warning System

MISO said it would add more nuance to its warning system and debut transmission warning notifications. 

Clayton Umlor, North region manager of reliability coordination, said MISO understands there is a need for more clarification around transmission risk. The new warning is meant to communicate elevated risk beyond conservative operations declarations but not quite to the level of a local transmission emergency or transmission system emergency. 

MISO’s conservative operations apply to generation and transmission assets alike and request that utility operators return offline assets to service where possible to produce megawatts and open flow capability. 

Umlor said MISO would issue a transmission warning when it and members have exhausted many or most of congestion management procedures and “post-contingent load shed becomes the primary mitigation plan.” He said MISO would issue the warning when it has “reasonable confidence that load shed will be required.” 

MISO is in the early stages of updating procedures and would have to ensure operators are ready for the change through added training, Umlor said. The warnings would be ready to use in 2026. 

Louisiana Public Service Commission consultant Lane Sisung said he didn’t see how the new warning would have helped during the Memorial Day weekend blackouts. 

“I don’t believe that load shed became the primary option until the [transmission system emergency] was called,” Sisung said. He said MISO should focus on working more advance warning into its temporary interconnection reliability operating limit (IROL). 

MISO’s Harmon disagreed and said the warning would have been sent out prior to the May 25 emergency. He said the warning serves to “communicate when we see risk emerging on transmission-related items.” 

Dauphinais asked MISO to reassess the events of May 25 and tell stakeholders at exactly what time the RTO would have published the warning. Harmon made note of the request. 

David Shaffer, adviser to the New Orleans City Council, said he wasn’t sure the warning would provide timely information. WEC Energy Group’s Chris Plante also said he didn’t see how the warning would work when it’s issued only when load shed is the last remaining option. 

Umlor said transmission warnings might not escalate into emergencies and that MISO doesn’t have to be in system operating limit (SOL) or IROL exceedance to issue the warning. 

Harmon said the warning would signify that MISO is out of options before load shed but that doesn’t have to mean transmission flows are in violation or load shed is imminent.  

“The intent is: ‘It’s getting tight. We’re running out of redispatch room.’ … It’s a credible threat. The intent is not to issue this and then, five minutes later, we’re in an emergency,” Harmon said. 

Harmon said MISO’s capacity warning escalations are well understood among market participants and that MISO wants to use a similar escalation with transmission capability. However, he said, it doesn’t want to use an advisory-level notification for transmission because it would run the risk of becoming too frequent. 

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MISO Says JTIQ Tx Portfolio Stands — for Now

The $1.6 billion Joint Targeted Interconnection Queue transmission portfolio of MISO and SPP remains in play even though the U.S. Department of Energy has reneged on almost half a billion dollars in funding.

DOE in early October revoked the $464.5 million from the department’s Grid Resilience and Innovation Partnerships (GRIP) program that it awarded the JTIQ portfolio in 2023. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

“MISO is monitoring this developing situation,” MISO Director of Expansion Planning Jeanna Furnish said at an Oct. 8 Planning Advisory Committee meeting.

Furnish said MISO has not yet received a cancellation notice from DOE for the funding nor has it heard from its project partners that any projects should be excised. The Minnesota Department of Commerce led the application for federal funding with assistance from the Great Plains Institute.

Mississippi Public Service Commission consultant Bill Booth asked if MISO still is moving ahead with the JTIQ, at the Oct. 7 meetup of the Entergy Regional State Committee Working Group.

“At this point, the projects are still approved, so we’re still including them” in modeling for planning, Furnish replied. She declined to answer questions on whether MISO and SPP would consider a change to their cost allocation due to the federal government withdrawing funding.

MISO and SPP received approval from FERC in late 2024 to allocate the costs of the JTIQ portfolio 100% to interconnecting generation assessed on a per-megawatt basis. The two RTOs initially planned to use a split involving 90% to generators, 10% to load, but abandoned the approach after DOE announced the portfolio would receive federal money. (See MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant.)

When FERC approved the allocation, it said it did so “based on the unique set of facts and circumstances of the proposed JTIQ framework.” It cited the $464.5 million DOE GRIP funding that would cover about 25% of project costs, the “massive amounts of interconnection requests,” the lack of transmission system capacity at the seam to accommodate this volume of interconnection, and the significant incremental cost of constructing network upgrades under the RTOs’ old affected system study process. (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)

Booth asked whether the same amount of renewable energy is anticipated to connect at the seams, considering that the Trump administration terminated renewable energy tax credits. The JTIQ portfolio is expected to enable 28 GW in mostly renewable generation additions. Furnish again declined to answer.

In May, National Grid Renewables warned MISO that the “certainty of this funding has come into question under the current presidential administration.” The company was voicing concerns over what it called a “lopsided” cost allocation of the JTIQ portfolio, where generation pays 100% of line costs and load isn’t charged anything. National Grid said the allocation solely to generation was approved only because the grants would fund a good portion of the JTIQ portfolio. It predicted challenges in cost allocation and construction timelines if grant funding is revoked and generators are left to pay significantly more than what they estimated.

The Southern Renewable Energy Association similarly predicted that MISO and SPP’s cost allocation method “could further complicate cost recovery if DOE funding were not to materialize.”

MISO responded at the time that it wasn’t expecting JTIQ funding changes and said DOE had not indicated that GRIP funding is in jeopardy. However, the RTO added that “JTIQ is not contingent upon the receipt of GRIP funding.” The Trump administration has initially paused and is reviewing all GRIP funding awards doled out under the Biden administration.

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MISO Debuting Pilot for Better Long-term Load Forecasting

MISO is taking load updates and stakeholder suggestions as part of a pilot program to improve its long-term load forecasting.

MISO Strategic Insights Manager Dominique Davis said MISO will use stakeholders’ ideas and data to perform an annual refresh of the long-term forecast that it first published at the end of 2024.

Speaking at an Oct. 8 Planning Advisory Committee, Davis said the load forecasting pilot will help refine how MISO collects load data that informs its long-term transmission planning and resource adequacy projections. The RTO launched a stakeholder survey Sept. 25 that will stay open through Oct. 31.

Davis said MISO eventually hopes to create a “24/7 repository” of load data. However, she added that’s an “ambitious goal,” so for now, it is open to hearing how often it should collect load estimates.

The grid operator plans to publish an updated load forecast in the first quarter of 2026.

MISO’s efforts come as forecasting large loads has garnered national attention.

In mid-September, FERC Chair David Rosner requested MISO and other RTOs’ perspectives on large load forecasting. (See FERC Focusing on Large Loads, Clearing the Decks Under Rosner.) Rosner issued a letter request to CEO John Bear using the same docket as Republican states’ complaint seeking to scale down MISO’s second long-range transmission plan portfolio (EL25-109). MISO has said data center load growth makes the nearly $22 billion transmission portfolio more relevant than ever.

Rosner posed a series of questions to MISO, asking the RTO to describe how it, its utilities and state regulators obtain commercial operation estimates for large loads; how it screens large load requests before including them in forecasts; how it estimates actual electricity consumption compared to a load’s requested level of interconnection service; and how the RTO coordinates with utilities at the regional or interregional level to share best practices and avoid double-counting.

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Nebraska AG Sues Largest Utility to Block Coal Retirement

Nebraska’s attorney general is suing the state’s largest electric utility in an attempt to block partial retirement of an aging coal- and gas-fired power plant. 

Attorney General Mike Hilgers (R) said the plan would increase cost and decrease system reliability. 

The Omaha Public Power District converted three of the five generating units at the North Omaha Station from coal to gas in 2016. It is preparing to retire those units, which date to the 1950s, and perform a coal-to-gas conversion on the other two units, which date to the 1960s. 

Hilgers sued OPPD in Douglas County Court on Oct. 9, saying the move would reduce output of the plant by 40% at a time when demand is rising and would boost prices for ratepayers who now enjoy some of the least expensive electricity in the nation. 

Maintaining the status quo at the North Omaha Station would save OPPD and its ratepayers more than $40 million over the next five years and nearly $440 million over the next 15 years, Hilgers said in a news release. 

The plan therefore directly conflicts with the legislative vision for public power in Nebraska, Hilgers said. 

“Public power providers should not achieve their self-imposed environmental goals by raising prices for Nebraska consumers,” he said. “The proposed changes at North Omaha Station do not align with the fundamental objectives outlined by the Legislature, undermining the promise of public power.” 

OPPD did not respond to a request for comment for this story. 

Nebraska’s Largest

With 413,000 retail customers and annual sales of 17.1 million MWh, OPPD is the largest of 166 utilities in the only state served entirely by publicly owned utilities, serving approximately 45% of Nebraska’s residents. The 563-MW North Omaha Station is the second-largest generation asset in OPPD’s over-3.2-GW portfolio. 

The station’s location on the edge of a neighborhood with a higher poverty rate and a higher percentage of Black residents than the rest of Douglas County has led to complaints of environmental racism as the process of conversion and retirement stretched over more than a decade. 

OPPD initially had targeted completion in 2023, but in 2022, its board voted to postpone the move until two new natural gas facilities finished construction and completed the SPP interconnection process. That has happened: The 450-MW Turtle Creek Station started operation in June, and the 150-MW Standing Bear Lake Station apparently is complete. 

The move runs counter to the pro-coal stance of President Donald Trump and some other Republicans. Nebraska Gov. Jim Pillen (R) applauded the lawsuit, saying: “It’s foolish for any power district to turn away from the single-most affordable means of energy production known to mankind. Nebraska is blessed to have readily available coal reserves in Wyoming and the railroad infrastructure to get it here.” 

Hilgers’ lawsuit draws heavily on OPPD’s own statements and data. It states and asserts: 

    • The mission of Nebraska’s public power utilities as dictated by unambiguous state policy is to provide reliable electricity at the lowest cost consistent with sound business judgment. 
    • OPPD policies — notably the decision to end coal at the North Omaha Station — prioritize other considerations. 
    • By OPPD’s own admission, the retirement/conversion plan for North Omaha Station was based primarily on environmental considerations, in contravention of state policy. 
    • OPPD has formally incorporated environmental justice into its decision-making process and placed “environmental sensitivity” on par with affordability and reliability, which are “enshrined” as the central pillars for Nebraska’s public policy regarding electricity generation. 
    • OPPD itself has said retiring capacity will make it more difficult to serve existing and new customers, and that rising demand means that without generation capacity additions, it will face a deficiency in its ability to serve new large load requests in the next 10 years. 
    • OPPD said it expects approximately 2,000 MW of new customer requests over the next decade, a much faster rate of growth than previously anticipated. 
    • Replacing coal-fired dispatchable baseload generation resources such as North Omaha Station with intermittent resources will increase the cost of electricity for Nebraskans. 
    • OPPD has announced an aspirational goal of net-zero carbon emissions by 2050; its “Pathways to Decarbonization” calls for the end of coal generation by 2045 but also recognizes that baseload generation still is needed. 
    • OPPD’s decisions indicate it considers environmental justice to be a policy consideration of at least equal and arguably greater importance than the core considerations set forth by the state Legislature: reliability and cost. 
    • The North Omaha Station complies with all national ambient air quality standards; its coal-fired units have a low-emitter status under the federal Mercury and Air Toxic Standards; and OPPD is unaware whether the facility might be making anyone sick. 

OPPD Explains

In letters attached as an appendix to the lawsuit, OPPD President Javier Fernandez said the units to be retired — 1, 2 and 3 — are the oldest in the fleet and are used less than they once were. 

The North Omaha Station’s generating units’ service date, nameplate capacity and average output in the past five years are: 

    • Unit 1: 1954, 63 MW, 6,929 MWh; 
    • Unit 2: 1957, 71.8 MW, 10,423 MWh; 
    • Unit 3: 1959, 92.5 MW, 66,555 MWh; 
    • Unit 4: 1963, 117.7 MW, 612,678 MWh; 
    • Unit 5: 1968, 216.2 MW, 878,663 MWh. 

Fernandez said the system is expected to meet federal and regional grid reliability regulations after the retirement and conversion is complete but acknowledged it would have more margin and better reliability/resiliency if maintenance and life-extension work were performed and North Omaha remained in service in its current configuration. 

Fernandez said OPPD has taken steps to replace the loss of supply from North Omaha. But he also said eastern Nebraska peak growth has increased 500 MW in the past five years, and if sustained load growth continues, OPPD would expect sustained challenges in securing resources to ensure affordable, reliable and timely electric service. 

He estimated OPPD could face a deficiency of anywhere from a few hundred to nearly 2,000 MW in its ability to serve new large load requests over the next 10 years without new capacity beyond assets OPPD already has or is planning. (Present-day system peak load is 2,810 MW.) 

Along with the two new gas-fired stations totaling 600 MW, OPPD has the new Platteview Solar farm, which has a nameplate capacity of 81 MW but SPP accreditation for only 42 MW in the summer and 29 MW the rest of the year. OPPD will buy or build four more 225-MW gas- or oil-fired units that are targeted for 2029 grid operation, as well as a 420-MW solar+storage facility that would go online in 2027 and have summer accredited capacity of 400 MW. 

In May, Sen. Jared Storm introduced and Sen. Tom Brandt co-sponsored Legislative Resolution 234, an interim study to “examine the impact of the net-zero plans and goals of public power utilities.” One of the stated purposes of LR234 is to evaluate the cost and impacts of net-zero initiatives, and the questions Brandt and Storm posed to Fernandez drill down on this. 

What state and federal laws prompt this transition at the North Omaha Station? There are none beyond EPA greenhouse gas regulations, Fernandez wrote in response, and the Trump administration has expressed intent to repeal those. 

Why is North Omaha being partly shut down if OPPD needs more generation? Because that is the plan the board of directors approved in 2014, primarily for environmental reasons, Fernandez said. 

Will the retirement make it harder to serve OPPD’s load? Yes, Fernandez responded. 

Storm asked: “In your professional opinion, should OPPD shut down [North Omaha] at this time?” 

Fernandez replied: “I respectfully must reserve that for our publicly elected board that has hired me to provide direction and implementation of the board’s strategic goals and policies.” 

Hilgers names OPPD, Fernandez and six of the eight OPPD board members as defendants in his lawsuit. 

He’s asking the court to declare that OPPD’s prioritization of factors other than cost or reliability directly contravenes state policy; to deem action under such prioritization invalid; and to enjoin all efforts, initiatives or actions that do not prioritize the cost and reliability of the electricity OPPD delivers. 

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SPP Wants to Defer $7B in 765-kV Projects to 2026

SPP staff have reiterated their position to defer part of the RTO’s planned 765-kV transmission overlay, setting aside about $7 billion in regional projects from its 2025 transmission assessment.

Instead, they plan to seek approval of up to 50 projects with an estimated cost of $11.16 billion, a 45.9% increase over the record 2024 $7.65 billion assessment. That does not include more than $1 billion for 22 stakeholder-submitted zonal planning criteria (ZPC) projects that also were studied in the 2025 Integrated Transmission Plan for system impact.

“This particular ITP has been a big lift,” SPP’s Casey Cathey, vice president of engineering, told state regulators during an Oct. 10 education session for the Regional State Committee. “It’s probably the most comprehensive study that SPP and its members have ever done, and it reflects where the system is and where our region is growing. Load is growing faster than we’ve ever seen, and our grid is feeling the strain.

“So, the question is, how do we stay ahead of it responsibly and cost effectively?” he asked. “This is a challenging situation for everyone.”

Cathey said deferring $7 billion of transmission projects “that we do believe is necessary” will allow staff to refine termination points for the upper part of a proposed 765-kV overlay in the southern portion of the footprint. He said staff are trying to better understand the full buildout that will be needed to meet the load growth they see ahead in 2026.

“It’s indicating load growth from all of Kansas state all the way up through North Dakota that will necessitate additional EHV [extra-high-voltage] and possibly ultra-high-voltage facilities in the 2026 time frame,” Cathey said.

The southern 765-kV overlay builds on the RTO’s first EHV project, Southwest Public Service’s 345-mile Potter-Crossroads-Phantom transmission line that was part of the 2024 ITP. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.)

Staff said subsequent analysis using 2025 data demonstrated that a single 765-kV facility would not provide adequate energy delivery or voltage support for a region where load has increased from 4,700 MW to 11,500 MW between the 2023 and 2025 ITP forecast cycles. They said the SPS region’s isolation from the broader SPP grid makes it critical to use 765-kV solutions to establish “highly efficient” bulk power delivery.

The portfolio includes four 765-kV projects totaling $7.55 billion in costs, comprising the first phase of SPP’s 765-kV backbone. It connects SPS’ grid with the broader SPP network through Oklahoma and back down to Shreveport in northwestern Louisiana.

The Markets and Operations Policy Committee heard much the same presentation during a September education session. (See SPP Considers Deferring 765-kV NTCs to 2026.)

Staff’s presentation to the RSC included two 765-kV segments that they propose to defer while they refine termination points. By deferring a construction permit for the Potter-Woodward segment, a 471-mile facility in western Oklahoma predicted to cost $1.35 billion, SPP preserves the flexibility to evaluate whether more strategic or cost-effective alternatives could be achieved, they said.

SPP says the 2026 ITP will evaluate the need for a complete regional 765-kV network, including areas to the north in the footprint where spot loads were submitted for study for the first time. The Consolidated Planning Process transition assessment that follows also will consider additional EHV lines.

SPP says there’s a fine balance when deferring projects. | SPP

Staff cautioned the RSC that deferring costs may lighten the burden for the 2025 ITP but have unintended consequences for future assessments.

“What we don’t want to do is defer too much where we increase the burden of future ITPs and actually disrupt models,” said Kirk Hall, manager of transmission planning. “If there’s not enough transmission in the model because we’ve deferred too much, then it makes it really difficult to perform studies. It makes it difficult to explain what is going on in the models because in some cases, they may not even solve appropriately.”

Oklahoma Corporation Commission Chair Kim David said new legislation in her state requires the commission to consider an “extensive list” of criteria before approving construction permits for any transmission lines.

“I can just see the writing on the wall with some of this: that there could be a lot of delays; there could be some certificates [of convenience and necessity] not granted,” she said. “When I’m looking at that, I’m just seeing costs rising and costs rising and costs rising. I have some real concerns about it actually coming to fruition.”

“It’s going to be challenging,” Minnesota Public Utilities Commissioner John Tuma agreed, calling 765-kV projects “different animals.”

MISO’s second long-range transmission plan portfolio includes several 765-kV projects that the Minnesota PUC is grappling with. (See MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops.)

“I hope estimates are being reworked for 765,” Tuma said. “They’re going to be a challenge for us to site.”

It took SPP several meetings with the RSC, Board of Directors and stakeholders to get SPS’ 765-kV project formally approved. The project had a cost estimate of $1.69 billion when it was approved in 2024, but SPS filed a revised estimate of $3.62 billion in June. (See SPP Board Approves 765-kV Project’s Increased Cost.)

The 2025 portfolio, excluding the ZPC projects, has a benefit-to cost ratio between 6:1 and 10:1, preserves reliability and mitigates rising energy costs because of increasing demand, SPP said.

During a joint meeting Oct. 1 between the Transmission and Economic Studies working groups, the TWG endorsed the assessment 10-9, with four abstentions, and the ESWG voted 6-4 in favor, with three abstentions.

The 2025 ITP now goes before MOPC during its Oct. 14-15 meeting in Little Rock, Ark.