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December 9, 2025

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New Faces at IESO, OEB Amid Outreach to Indigenous Communities

IESO and the Ontario Energy Board have added three new members to their governing bodies — including two Indigenous female mayors — while the ISO is seeking candidates for its Technical Panel.

Wendy Landry, mayor of the municipality of Shuniah and a member of the Red Rock Indian Band, was appointed by the minister of energy and mines as the newest member of the IESO Board of Directors. Landry is vice president of Indigenous Leadership, Strategies and Partnerships at Confederation College, her alma mater, and formerly worked for Enbridge as senior adviser for Indigenous initiatives.

“Wendy joins us at a time when Indigenous voices and partnerships are playing an increasingly vital role in shaping our energy future,” IESO said in a press release. “Her leadership in municipal governance and extensive experience in First Nation and Métis relationship building will be instrumental as we work to advance reconciliation and build out Ontario’s electricity system.”

With IESO planning its largest transmission expansion in two decades, First Nations partnerships will be essential to building transmission across tribal lands, Hydro One’s interim CEO, Harry Taylor, said earlier in October. (See IESO Seeking to Stay ‘Two Steps Ahead’ of Need and Overheard at the 2025 Ontario Energy Conference.)

Recusal from Battery, Peaker Projects

Commenting on her appointment to IESO, Landry cited her former role as president of the Northwestern Ontario Municipal Association (NOMA).

“Everybody in the region is excited [that] we have a Northwestern voice at that table, and … I have the Indigenous” perspective also, she told RTO Insider in a phone interview Oct. 13 after a morning moose hunt. “I know that [IESO is] working on a reconciliation action plan, and some of that work with our communities is vital to [their ability to transition from] diesel,” which is used both in electric generators and home furnaces.

“An average person born and raised in Southern Ontario doesn’t understand … the geography and just the distance between our towns, where a transmission line can make a huge difference,” she added.

Michael Liebrock, OEB | Ivey Business School

Shuniah’s council has been asked to pass resolutions notifying IESO of their support for two electric projects in the municipality: Powerbank’s proposed two 200-MW battery energy storage systems, and Current H2’s proposed 100-MW peaker plant, which could burn natural gas, hydrogen or a mixture of the two.

Landry told TBnewswatch in September that the projects are an economic development opportunity for the community. Now that she’s been appointed to IESO, however, she said she will not participate in meetings on the projects to avoid a conflict of interest.

NOMA released a study last year that said IESO’s existing and proposed transmission was insufficient to support nearly 1,500 MW of demand from planned mining projects. The organization requested six transmission upgrades, including doubling sections of the Waasigan and Watay transmission projects and improvements west of Thunder Bay.

“There hasn’t been a commitment [to NOMA’s requests], but there’s been a lot of discussion, both with the IESO as well as with the minister of energy,” current NOMA President Rick Dumas said in an interview. “With Wendy now being on the board, she could bring the concerns that were written in that [study] to the government and to the [IESO] board.”

Landry is one of six independent board members. The board charter requires between eight and 10 independent members in addition to the ISO’s CEO.

OEB

The newest members of the OEB’s Board of Directors are Cheryl Fort, mayor of the township of Hornepayne, and Michael Liebrock, managing director at The Stronach Group, a private investment company with interests in horse racing, gambling, technology and real estate development.

Fort, a graduate of Athabasca University, is the first woman and the first Indigenous person to serve as mayor of Hornepayne. A former conductor and locomotive engineer for Canadian National Railway, she is a member of the railway’s management team for locomotive engineer training and compliance. She is also president of the Northern Ontario Women’s Association and the Ontario Good Roads Association.

Cheryl Fort, OEB | Cheryl Fort

Liebrock, a former management consultant with The Boston Consulting Group, worked in politics at the provincial and federal levels from 2003 to 2006. He holds an undergraduate degree from the University of Western Ontario, an MBA from Ivey Business School and a Master of Laws from the University of Toronto.

Fort and Liebrock did not respond to requests for comment.

With the addition of Fort and Liebrock, OEB’s board has six members. Per the Ontario Energy Board Act of 1998, the board is composed of five to 10 members appointed by the Lieutenant Governor in Council, acting on behalf of the premier and his ministers. New members, who must meet six criteria, receive two-year terms and may be reappointed to subsequent terms of up to three years.

Technical Panel Seeking Candidates

IESO is seeking candidates to join its Technical Panel, which reviews proposed changes to market rules. (See What to Know About IESO.)

IESO’s announcement highlighted the need for members to represent generators, consumers and energy-related businesses and service providers.

Per the IESO’s Terms of Reference, the Technical Panel comprises one chair, one IESO member, up to 10 members representing “core market” participants (generators, transmitters, distributors, importers/exporters, consumers, demand response, and energy storage) and up to six other members. The panel currently has 14 members.

Nominations should be submitted to engagement@ieso.ca with a resume and signed Declaration of Nominee.

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PJM MIC Briefs: Oct. 9, 2025

Stakeholders Endorse Manual Revisions on DR and DERs

The Market Implementation Committee endorsed a package of revisions to Manual 18: PJM Capacity Market to eliminate the availability window and rework how the winter peak load (WPL) for demand response resources is determined and detail how distributed energy resources will participate in the capacity market under the RTO’s implementation of FERC Order 2222.

The proposal to model DR in all hours was approved by the MIC during its Feb. 5 meeting, replacing a ruleset that looked only at the reduction capability of DR resources between 6 a.m. and 9 p.m. in the winter and 10 a.m. to 10 p.m. in the summer under the effective load-carrying capability modeling.

Curtailment service providers argued that limiting the time in which a customer is considered available doesn’t account for those with flat load profiles and the resource class’s ability to react to risk being concentrated across a wider range of winter hours. Skeptics said the change could result in DR participants being paid to curtail overnight, when they are more likely to already be offline.

There also was disagreement over when the change should be implemented; CSPs advocated for targeting the 2026/27 Base Residual Auction to allow them to respond to an expected spike in clearing prices, while others argued there was little time before the start of pre-auction activities. The MIC endorsed implementation for the 2027/28 BRA. (See “Expanded Demand Response Modeling Endorsed,” PJM MIC Briefs: Feb. 5, 2025.)

The changes also redefine the WPL to measure each DR participant’s load at 9 a.m., which is the hour PJM argued best matches DR performance with system needs. The RTO argued that continuing to derive the class-wide WPL from each customer’s peak at any hour within the availability window overstates the curtailment capability since those peaks are not expected to coincide. (See PJM Stakeholders Endorse More Detailed Demand Response Modeling.)

PJM Plans to Request 1-year Extension of RMR Resources Participating in Capacity Market

Associate General Counsel Chen Lu told stakeholders that PJM is preparing to ask FERC to extend tariff language allowing it to model the output of Talen Energy’s 1,289-MW Brandon Shores coal plant and 843-MW H.A. Wagner oil-fired units as supply in the capacity market. The commission approved including the units as price-takers in the 2026/27 BRA and the subsequent auction, which would be extended to apply to the 2028/29 auction under PJM’s proposal.

The two generators have been operating on reliability-must-run agreements compensating them for continuing to operate past their desired deactivation dates while transmission upgrades are completed to allow the units to deactivate reliably. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

As the capacity market has tightened, several stakeholders argued that if resources operating on RMR agreements are being paid to be available to mitigate transmission violations, their reliability contribution should be reflected in the capacity market.

The temporary nature of the filing and its focus on two generators was intended to allow PJM’s Deactivation Enhancements Senior Task Force more time to draft a pro forma RMR agreement that explicitly allows the RTO to dispatch them in response to a capacity emergency. A draft of such an agreement was presented at the Sept. 18 task force meeting.

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Outgoing Mass. DPU Chair Van Nostrand Discusses Gas Transition

Jamie Van Nostrand’s tenure as chair of the Massachusetts Department of Public Utilities has been defined, in large part, by the department’s effort to align gas utility regulation with the state’s decarbonization laws and targets.

Prior to his appointment in 2023, the DPU faced significant criticism from public advocacy groups over a gas decarbonization planning process largely dominated by the long-term vision put forward by the state’s investor-owned gas utilities.

Following the election of Gov. Maura Healey (D) in 2022, Energy and Environmental Affairs Secretary Rebecca Tepper appointed Van Nostrand and fellow Commissioner Staci Rubin, tasking them with building “a 21st-century DPU” centered around “a commitment to transparency, equity and innovation.”

At the time, Van Nostrand was a professor focused on energy issues at the West Virginia University College of Law. Earlier in his career, he represented utilities in regulatory proceedings in the Pacific Northwest, and nonprofits and public interest groups in proceedings in New York and Virginia.

After 12 years at WVU, “I had the opportunity to come to Massachusetts, and couldn’t say no to Secretary Tepper,” Van Nostrand said in a recent interview with RTO Insider. “It was a dream job.”

Two and a half years after taking the helm at the DPU, Van Nostrand will leave the department Oct. 17 after leading it through a series of major changes in its approach to natural gas regulation.

In December 2023, the DPU published Order 20-80-B, which concluded the department’s contentious multiyear investigation into the decarbonization of the state’s gas network. While utilities had pushed for a framework centered around partial electrification and alternative fuels like hydrogen and renewable natural gas (RNG), the DPU largely sided with climate and consumer advocacy groups in its assessment that gas system decarbonization must focus on electrification.

The order marked a significant step toward an eventual transition away from natural gas, setting the stage for the challenging technical and political questions the DPU has been working on over the past two years. (See Massachusetts Moves to Limit New Gas Infrastructure.)

It required gas utilities to consider non-gas alternatives before investing in new gas infrastructure; directed the utilities to submit climate compliance plans every five years; mandated integrated planning with electric utilities; banned the companies from promoting natural gas expansion; and prevented them from including in the rate base the costs of procuring hydrogen or RNG.

With the order and the proceedings that followed, “I think we pretty much staked out the position as the No. 1 state in the country on the gas transition,” Van Nostrand said.

The Obligation to Serve

Following the order, the DPU has taken more steps to amend its line-extension policies, which would limit the utilities’ ability to spread the costs of connecting new gas customers across their rate base; minimize spending on pipe replacement projects and update the utilities’ “obligation to serve” gas customers.

The obligation to serve, the companies have argued, would prevent them from decommissioning entire sections of pipe if any customers refuse to give up their gas service. In 2024, the legislature amended the statutory basis for this obligation, authorizing the DPU to “order actions that may vary the uniformity of the availability of natural gas service” to enable emissions reductions and compliance with the state’s climate laws.

In early October, stakeholders submitted comments to the DPU on how it should interpret the legal definition. The gas companies argued that the DPU cannot require them to disconnect existing customers, while climate advocates, the Massachusetts Attorney General’s Office and Sen. Mike Barrett, the top senator responsible for drafting the 2024 legislative changes, argued that the DPU does have this authority (D.P.U. 25-40 through 25-45).

The obligation to serve “is a tough nut to crack,” Van Nostrand said.

“How do you shrink the system if you identify a decommissioning possibility and not all the customers want to electrify?” he said. “That would completely thwart the ability to decommission the pipe, so your throughput is going to go down, but your fixed costs aren’t going to go down.”

He said addressing the obligation to serve is part of a broader need to carefully manage the transition to prevent customers who cannot afford to electrify from being saddled with an increasing share of the gas system’s fixed costs.

“An unmanaged transition results in much, much higher rates for customers who can least afford to pay them,” Van Nostrand said. “I think we’re leading the nation on it, but I’ve learned a lot from regulators in the other states who are struggling with the same issues.”

The Coal Trap

While teaching at WVU, Van Nostrand wrote “The Coal Trap,” a book about how the close alignment of the coal industry and top West Virginia politicians prevented the state from taking advantage of clean energy opportunities between 2009 and 2019, hurting the state’s economy and environment.

He said he sees some parallels between the Massachusetts gas industry’s resistance to electrification and the West Virginia coal industry’s pushback against emissions regulations under the Obama administration.

For the coal industry, “there was a resistance to giving it up,” Van Nostrand said. “The coal industry tended to want to just put their head in the sand and say, ‘Oh, everything would be fine if Obama’s job-killing EPA would just leave us alone.’”

In Massachusetts, Van Nostrand said, he has faced some frustration in his effort to bring the utilities to the table to work through challenging aspects of the gas transition.

“I’ve encouraged the LDCs [local distribution companies] to work with us to try to figure out how we can incentivize the LDCs so they will be on board with electrification and not necessarily hide behind the obligation to serve and customer choice,” he said.

“At the end of the day, we have to maintain the financial viability of the utilities, and we’ve got to make sure that, as long as there’s gas going through the pipes, it’s going to be safe,” he added.

He praised a recent filing by Eversource Energy (D.P.U. 25-86) proposing a new regulatory framework to develop networked geothermal heating in new construction projects. Networked geothermal offers significant efficiency benefits over standalone heat pumps, and Eversource already is operating a networked geothermal pilot project. (See Networked Geothermal Breaks Ground in Framingham.)

“I think good utilities get out in front of it, they see the direction things are going, and they plan accordingly,” Van Nostrand said. “There are great workforce transition benefits with network geothermal, because you’ve got the pipes running down the middle of the street and laterals going out to houses, just like what a gas company does. And I think Eversource gets that.”

New Leadership at the DPU

On Oct. 20, Van Nostrand will be replaced as DPU chair by Jeremy McDiarmid, former general counsel for Advanced Energy United, while Liz Anderson, former chief of the energy and ratepayer advocacy division at the Massachusetts Attorney General’s Office, will take over for DPU Commissioner Cecile Fraser.

Representatives of multiple public interest groups active in the state expressed optimism that the new DPU will carry on Van Nostrand’s work to implement a managed transition away from gas.

But challenging questions remain for the incoming commissioners about the role of the state’s gas network and the need for new investments in the system.

While the DPU has directed the gas utilities to reduce their reliance on supply from the Everett LNG import terminal, some industry experts have expressed skepticism about whether the state will be able to eliminate its need for the facility when existing utility supply contracts expire in 2030. (See Gas Industry Sees Political Opportunity in New England and Massachusetts DPU Approves Everett LNG Contracts.)

The uncertain future of Everett, coupled with the utilities’ continued addition of gas customers, leaves regulators in a difficult position as they work to affordably meet existing needs for gas while attempting to avoid larger-than-necessary investments in long-term gas infrastructure.

Eversource recently filed a supply agreement to support a limited expansion of the Algonquin pipeline in the state. While the utility claims this proposal would reduce costs for its own customers, it is unclear whether the proposal would shift costs to customers of other utilities that rely on Everett if the facility remains open beyond 2030.

As regulators in Massachusetts continue to grapple with the existential questions of the gas transition, Van Nostrand plans to live full time in Philadelphia, where his wife teaches. He said he hopes to continue working on issues related to the clean energy transition but is looking forward to taking on a slightly less stressful gig.

“It’s probably more likely to be on the gas side, because that’s where the challenge is the greatest,” he said.

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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.