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December 7, 2025

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PJM TEAC Briefs: Oct. 8, 2025

PJM Presents Non-competitive RTEP Projects

PJM presented several non-competitive projects it plans to recommend be included in the 2025 Regional Transmission Expansion Plan Window 1, with a first read on the competitive selections planned for the November TEAC meeting.

A $58.5 million project would rebuild 11.9-mile segments of the College Corner-Collinsville and College Corner-Trenton 138-kV lines in the DEOK zone and adjust relays at the three substations to avoid an overload on the College Corner-Collinsville line. The project has a required in-service date of June 2030.

A $45.8 million project would install a 765/345-kV transformer at the Wilton Center substation in the ComEd zone to resolve two overloaded transformers at the site, with a required in-service date of Dec. 1, 2030.

A $23.9 million project in the APS zone would construct a 138-kV substation, named McCanns Road, to be cut into the Redbud-West Winchester and Bartonville-Stephenson 138-kV lines. The segment between McCanns Road and Redbud also would be reconductored. It would mitigate a potential load drop exceeding 300 MW in the winter case under N-1-1 contingencies. It has a required in-service date of June 1, 2030.

A $9.15 million project in the APS and PN zones would rebuild 1.9 miles of the Garrett Tap-Garrett 115-kV line, install optical ground wire and adjust relaying at surrounding substations to alleviate overloads identified on the line.

A $9.93 million project in the PSEG zone would reconductor the 230-kV corridor between the Roseland, Livingston Avenue and Laurel Avenue substations to resolve overloads on lines. The project has a required in-service date of June 1, 2030.

Many of the competitive submissions proposed expanding the 765-kV backbone. Several large load adjustments in the PPL region, including around 2.7 GW of load expected near the Susquehanna switchyard by 2030, are driving need for additional transmission between the Mid-Atlantic Area Council and PPL. Generation growth in southern Dominion also will require upgrades across the region. (See “PJM Presents RTEP Update,” PJM TEAC Briefs: Sept. 9, 2025.)

Supplemental Projects

FirstEnergy presented a $156.7 million project in the Penelec zone to rebuild around 34.1 miles of its Fores-Glade 230-kV line, which it said is nearing the end of its life at 65 years old. Inspections found deteriorating wood poles and broken insulators along the line and one outage was caused in the past five years by a pole failure. The project also includes reconductoring a bus at the Glade substation. The project is in the conceptual phase with a projected in-service date of May 31, 2029.

The utility also presented a $50.2 million project in the JCPL zone to mitigate the risk of 52 MW being taken offline under N-1-1 contingencies by rebuilding its Leisure Village substation and replacing equipment at the Manitou and Lakewood facilities. Leisure Village would be reconfigured as a breaker and a half (BAAH) with nine new 230-kV breakers, an additional 230/34.5-kV transformer, attached to two high side breakers, and two new 34.5-kV transformers. Line relaying at South Lakewood, Silverton, Drum Point and Cedar Bridge also would be adjusted. The project is in the conceptual phase with a possible in-service date of June 1, 2029.

AEP presented two needs to serve load growth in New Carlisle, Ind., and Madison County, Ohio. The Indiana customer seeks to expand the load connecting to the proposed Navistar 345-kV substation by 692 MW, with a requested in-service date by June 2029. The Ohio customer wants a new 345-kV delivery point with an initial load of 100 MW on Aug. 14, 2029, which is expected to grow to 750 MW.

PPL presented a $231.7 million project to serve a customer seeking to bring 290 MW to the Frackville, Pa., region in 2027, with the intention of growing to around 600 MW by 2029. The project would construct a new 230-kV BAAH substation, named Gordon, cutting into the Eldred-Frackville 230-kV line. The 36.5-mile, 230-kV corridor through Sunbury, Eldred and Frackville would be upgraded from single- to double-circuit, with more terminal equipment installed at each substation. Gordon would be connected to the customer with three 0.1-mile 230-kV lead lines. The project is in the conceptual phase with a projected in-service date of May 30, 2027.

A $74.9 million PPL project would serve a new customer seeking 230-kV service for 200 MW near Lackawanna, Pa., projected to grow to 1,400 MW by 2031. The project would construct a new BAAH 230-kV substation, named Sturges, cutting into the 230-kV Summit-Lackawanna No. 1 and No. 2 lines, as well as the Lackawanna-Callender Gap No. 1 line. Sturges would connect to two customer substations with six, 230-kV lead lines. The project is in the conceptual phase with a possible in-service date of July 30, 2028.

Exelon submitted a need to serve a new customer in the PECO region seeking to bring 250 MW to the Fairless Hills, Pa., region in 2027, which is expected to ramp to 600 MW the following year.

The utility revised a supplemental project to serve a new large load in the ComEd zone, changing the planned lines and increasing the cost from $175 million to $215 million. The substation now will connect to the 138-kV network at Waterman-Crego Road and Line No. 11106, as well as the 345-kV Line No. 15502. The project originally was presented at the Feb. 6, 2024, TEAC meeting and is in the engineering phase with a projected in-service date of Dec. 31, 2027.

Dominion presented 26 needs for data center growth in its zone, several of which are to serve data centers in the growing cluster around Dulles International Airport. Six projects also were presented to serve data centers in Prince William, Stafford, Henrico and Hanover counties, totaling $125 million.

A $30 million project would construct a new substation, named Flamingo, cut into the Elmont-Short Pump 230-kV line.

A $33.5 million project would construct a new substation, named Tropical, cutting into the Techpark Place-Darbytown and Portugee-Chickahominy 260-kV lines.

A $16.5 million project would serve a 213.7-MW data center with a new substation, named Alto, which would cut into the Spartan-Centreport and Aquia Harbor-Allman 230-kV lines.

A $15.5 million project would construct a substation, named Baritone, which would cut into the Alto-Centreport and Alto-Allman 230-kV lines.

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OPSI Panels Discuss Data Center Load Growth

WASHINGTON — The challenges of meeting soaring forecasts of data center load growth dominated the Organization of PJM States Inc. (OPSI) Annual Meeting on Oct. 6-7.

PJM CEO Manu Asthana said much of the discussion has centered around reliability and affordability, but what is at stake is national competitiveness over the next century as the U.S. races to keep pace with China in developing artificial intelligence technology. Electricity supply is proving to be a significant bottleneck, he said, as China brought 428 GW of new supply online last year compared to the 49 GW completed in the U.S.

Senior Director of Market Operations Tim Horger laid out PJM’s latest proposal in the Critical Issue Fast Path (CIFP) process focused on large load growth: expediting interconnection studies for large generators, tinkering with voluntary load flexibility through price-responsive demand (PRD) and demand response, and creating more of a role for state utility commissions in reviewing the RTO’s load forecasts. He spoke on the first panel during the meeting, titled “Data Center Load Growth: Is further adaptation at the wholesale level needed?”

The expedited interconnection track (EIT) is designed to create a parallel study process for projects that carry a high certainty of reaching commercial service in a time frame that allows them to address the reliability gap, while minimizing the impact to the wider queue by limiting participation to 10 resources annually.

PJM also is considering requirements for large loads to provide financial commitments before they can be included in the load forecast, a proposition Horger said has been welcomed by data center developers. He said that builds on recent requirements that large loads obtain firm service agreements from their utilities three years in advance before their load can be included in the capacity market. Beyond those three years, he said the ability to have certainty that a particular service request will result in actual load growth becomes murkier.

Data Center Coalition Vice President of Energy Aaron Tinjum said the industry is supportive of expanding commercial readiness verification, such as requirements for electricity supply agreements; permitting reform for construction of new supply; standardization of submitting utility forecasts; and construction milestones for large loads. He said forecasting is foundational to the conversation, as it allows projects to proceed more quickly and with more confidence.

Independent Market Monitor Joe Bowring said he is amazed PJM has not attempted to exercise more authority over requests to adjust the load forecast it publishes, arguing that its stance abdicates the role of maintaining reliability to instead managing unreliability. He said PJM should implement a load interconnection queue that prevents large loads from coming online until they can be served reliably, with an expedited pathway for those bringing their own generation — a concept the Monitor is to present at the Oct. 14 CIFP meeting. He questioned whether it makes sense for PJM to allow large loads to sign up to receive service the RTO cannot provide.

While Bowring said improving the forecast is an important step in understanding the scale of the problem, he cautioned against spending too much time focusing on solutions that do not move the needle on ensuring new load is matched by capacity. He said Monitoring Analytics has been working to improve its own load forecasting, which has long relied on a bottom-up look at the next three years; that has been supplemented with a longer-term, top-down layer looking at the amount of large load that is reasonably expected to come to fruition across the U.S.

Looking at the availability of the chips used by the most power-hungry data centers and the amount of capital expenditure available to the industry, Bowring said about 60 GW of data center growth is expected across the country by 2030. That can be further divided across regions with sensitivities that assume that the share of large load growth will continue along existing projects or following trends in construction or announced projects, which creates a range of 22 to 26 GW of growth within PJM.

Horger said it’s not PJM’s place to call “balls and strikes” on which large load facilities are likely to be built and incorporated into the load forecast. Expanding the RTO’s role in developing the forecast would be complicated by the disparate requirements that states and utilities have on when large loads can be included in the forecasts submitted to PJM, with some requiring contracts and financial commitments.

Arnie Quinn, Vistra senior vice president of regulatory policy, said the Monitor’s proposal would effectively prevent new load growth until the 2030s and faulted PJM’s EIT proposal for requiring new resources to be sponsored by state utility commissions to qualify, which he said could put regulators in a precarious position. He said more focus should be put on who is bearing the risk associated with load growth, suggesting that more of it should be placed on load-serving entities signing up large loads by requiring them to procure capacity or pay a penalty.

He said ensuring the forecast is accurate would guide what forms of load flexibility PJM should pursue, arguing it would be a very different prospect for a consumer to enroll in a program when curtailments are to be expected every few years or much more regularly.

The Needs of AI vs. Cloud Computing

Aroon Vijaykar, Emerald AI senior vice president of strategy and commercial, said data centers appear as inelastic demand while investment in processing power remains high, but that is likely to moderate down the road and create more of an incentive for flexibility as power prices remain high. The large complexes expected to come online also have more of an incentive to explore the range of flexibility options available to them when compared to small consumers. Emerald develops software to allow AI load to be shifted across data centers to manage power consumption based on signals from LSEs and electric distribution companies.

The training phase of AI load tends to be less interruptible because of the risk of introducing errors to complex calculations, but reducing the response time on inference queries can deliver outsized reductions in load, Vijaykar said.

Bowring said the focus on load flexibility is an opportunity to rethink PJM’s market structures, arguing the PRD model isn’t well suited to the task, and the flexibility Vijaykar outlined could be the starting point for new market structures. He has often advocated for shifting DR to the demand side of the capacity market.

Tinjum said hyperscalers represent a small subset of data center usage compared to the shift to cloud computing, which often gets conflated with AI load growth. He said it can be difficult for data center operators who contract server capability out to smaller users, such as with cloud computing, to participate in load flexibility when their contracts require minimum uptimes. Backup generation can provide some curtailment capability, but diesel units can create a flood of noise and air quality complaints when operated for extended or regular periods in populated areas, such as Data Center Alley in Northern Virginia. The optionality and incentives for flexibility should reflect the diversity of data center users, he said.

For most data center developers and operators, the capacity and energy market revenues from DR participation are nice to have, but not a core focus, Tinjum said. If the program could be tied to interconnection timelines, that could provide much more value, he said.

During the OPSI Market Monitoring Advisory Committee meeting Oct. 7, Bowring said data centers should be required to bring their own generation and not be allowed to outbid regular consumers for capacity resources. He said it’s become a regular refrain to say the markets should be allowed to work to bring the generation needed to serve data centers, but some of the outcomes that could produce, such as blackouts or capacity being taken out of the market through bilateral contracts, are not functional solutions.

PJM CEO Manu Asthana speaks at the 2025 OPSI Annual Meeting. | © RTO Insider LLC

“The market can’t solve the problem of having 30,000 MW of capacity drop out of the sky,” he said.

Bowring said his statements should not be taken as advocacy for lower prices, but instead as an effort to find ways of applying cost-causation principles to the risks associated with data center load. He said those impacts already are being seen, with an analysis from the Monitor finding that the $175/MW-day price floor implemented in the 2026/27 Base Residual Auction (BRA) — which cleared at the $329/MW-day maximum — would have been relevant if data center load had been removed. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

David Mills, chair of the PJM Board of Managers, said the RTO is trapped in a “multidimensional Gordian knot” of trying to solve for price and hold reliability constant, while adding 20 to 30 GW of supply to serve data centers and controlling the associated emissions. That also is caught in a political challenge where some of the same voices advocating for lower prices are encouraging the economic development from data center development.

He suggested the impact to residential and commercial ratepayers could be controlled by states implementing bifurcated ratemaking systems.

New Jersey Board of Public Utilities Commissioner Zenon Christodoulou questioned if high energy prices and the rush for generation and interconnection equipment could be crowding out investment in the infrastructure required for electric vehicles, reshoring industry and electrification.

Mills and Bowring both said load growth outside data centers and some heavy industry remains fairly limited and unlikely to outpace the ability for the electric industry to respond without the added pressure from large loads.

“This is an outlier event in the sense that we’ve got all this new load coming in a short period of time, and your question is a valid one because it might eat up that surplus,” Mills said.

Future of the Capacity Market

The impact of large load growth also weighed on a pair of panels focused on speeding pace of new supply and the future of the capacity market.

Denise Foster Cronin, East Kentucky Power Cooperative vice president of federal and RTO regulatory affairs, compared the scale of data centers to adding a new zone to PJM, but without the requirement that a new entity seeking to join PJM demonstrate that it can procure the capacity it needs. She said LSEs should be active servers of their load and capacity auctions should return to their residual nature.

PJM Vice President of Market Design and Economics Adam Keech said the reliability backstop procedures may be worth revisiting. He said the trigger for the backstop — three consecutive BRAs that clear short of the reliability requirement — was designed at a time when the scale of load growth and reliability degradation was not envisioned. The backstop allows PJM to conduct a procurement process for transmission and generation owners to submit solutions to the reliability issue, including new generation to receive a multiyear commitment.

PJM Executive Vice President of Operations, Planning and Security Aftab Khan said the RTO is on pace to complete its transition to a cluster-based interconnection study process in April 2026, clearing tens of gigawatts worth of projects to proceed to development. There has been a slowdown in the pace of new generation coming online, with developers reporting issues around financing, permitting, siting and policy changes.

The majority of the resources in the queue and with interconnection service agreements that have not yet entered service are solar, which does not carry a high effective load-carrying capability rating. He said the RTO has major concerns if that is the only resource type coming online over the next few years.

“It’s important for PJM that we have the right generation portfolio mix,” he said.

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Power Play: Extreme Rains Take a Heavier Toll on the Grid

Dej Knuckey

Floods have been top of mind in 2025, mainly because of the tragic Central Texas flash flood, which took more than 130 lives over the July 4 weekend. The Texas disaster came less than a year after Hurricane Helene dumped more than 20 inches of rain far inland, causing massive floods that caught residents off guard and destroyed areas in the Carolinas, Tennessee and Virginia.

For grid operators, power generators and utilities, the rise in extreme rain events causes immediate damage and requires long-term planning to minimize future damage.

This is the second in a series on how climate extremes are impacting the grid; the first looked at how extreme heat impacts the full length of the electric supply chain.

It’s Raining, It’s Pouring

If you think you are hearing about heavier rain events more often, it’s because you are. Most areas of the United States are experiencing heavier rainfall, according to Climate Central. Earlier in 2025, four 1-in-1,000-year rain events hit Texas, North Carolina, New Mexico and Illinois.

By the end of July, 2025 had broken records for the most flash flood warnings issued by the National Weather Service in the first seven months of a year, with nearly 4,000 issued. Most flash floods occur between May and September each year when the warmer atmosphere carries more moisture and the drier soil is unable to absorb the rain.

Houston has seen a substantial increase in the intensity of rain events. | Climate Central

Like many flash floods, the Texas floods this year were caused by a tropical storm or hurricane: the remnants of Tropical Storm Barry. There have been deadlier flash floods in the United States, but the Texas event had the highest flash flood death toll in nearly 50 years. While cell phone alerts and real-time tracking usually enable faster reaction to rapidly evolving weather events, the Texas storm became a disaster in part because of failure to send timely warnings, incompatible first responder communication systems and inadequate local emergency manager training.

Flash floods aren’t the only type of flood that impact the grid: river floods and storm surge floods also are dangerous, but without the surprise factor. They also tend to have fewer fatalities, and without the rapidly moving debris carried by the water, property damage differs. Sunny-day flooding, when high tides inundate seaside neighborhoods, will be explored in a future column on sea-level rise.

La Niña, Meet Bombogenesis

As extreme precipitation events have become more common, colorful meteorological terms have crept their way into the lexicon. Even if you don’t understand the nuances, there’s a good chance you’ve added derechos, microbursts, atmospheric rivers and bomb cyclones to the long list of more common wet weather events you grew up with: thunderstorms, tropical storms, hurricanes and La Niña, which officially has arrived.

They are all variations of the water cycle we all drew in elementary school, and all are getting worse and more common for the same reason. Climate change causes more extreme precipitation events: for every degree Fahrenheit the atmosphere is warmer, it holds 4% more moisture. So when, say, a hurricane forms over the Gulf during a marine heat wave, it will carry significantly more water than if it had formed in normal temperatures, and that extra moisture means heavier rains along the path of the storm.

Warmer air carries significantly more moisture, leading to more extreme precipitation. | Climate Central

Sometimes, extreme precipitation arrives as a solid, not a liquid. Hail is formed when updrafts push raindrops into freezing areas of the atmosphere where they collide and join. If the trip down to earth isn’t warm enough, they hit, still frozen. Hailstone size is determined by the speed of the updraft: A 60-mph updraft can create walnut-sized hail, while a 100-mph updraft can produce grapefruit-sized hail, large enough to kill someone.

Extreme weather doesn’t happen only on the hotter side of the temperature scale. While hailstorms are more likely in spring and summer, in winter, there are risks of heavier snow or ice storms, which can take down power lines and make it challenging for repair crews to reach the damaged lines. In fact, winter is the fastest-warming season of the year, meaning more moisture in winter storms as well.

Mapping the Wetter Climate Future

The Texas Hill Country is known as flash flood alley due to the mix of topography and soil types that can lead to heavy rainfall moving quickly into gullies and gaining speed. Sophisticated software can model where and how fast water will flow, but as climate change increases the frequency and severity of events, meteorological and climate science professionals need up-to-date data to better predict the impact of storms. Without it, emergency services and utility crews will have less chance to prepare for storms.

Even with great models, damage from extreme rain can be larger than predicted, such as when a hurricane stalls like 2017’s Hurricane Harvey that dumped 60 inches of rain on Nederland, Texas, 90 miles east of Houston, or when one detours further inland like Hurricane Helene.

In First Street’s report on extreme precipitation, its climate data team said the past precipitation maps from NOAA are losing relevance as they were generated with inconsistent time periods and do not reflect the most recent and relevant rainfall data. The NOAA Atlas 15 map of precipitation risk, intended to address the problems in old maps, was at risk of being shelved during recent budget cuts. However, funding for the project was reinstated after the devastating floods in Texas. For utilities and grid asset owners, the National Water Prediction Service’s Flood Inundation Mapping tool offers planning teams insight into where they are most at risk.

The Perfect Storm of Storms

Floods cause more deaths than any other type of natural disaster. Residents, first responders and utility crews face immediate danger from rising or fast-moving water; downed wires or inundated underground systems add the potential for electrocution. Outages of power, communication and traffic systems exacerbate these risks. And once the rain stops, they all face the (sometimes lengthy) task of living with damaged infrastructure while it’s being rebuilt.

In terms of the grid, the distribution network is most at risk of poles and wires being taken down by falling trees or fast-moving debris. Where heavy rains follow a fire, mudslides up the ante.

“A debris flow is like a flood on steroids,” Jason Kean, a research hydrologist with the U.S. Geological Survey told the New York Times after the Palisades and Altadena fires in Southern California earlier in 2025. “It’s all bulked up with rocks and mud and trees.”

The transmission system is more likely to be harmed by extreme weather events that include high winds, but even without winds, fast-moving water can erode pylon foundations and inundate underground assets. A 2019 report by Oak Ridge National Laboratory noted: “Water from inundation or flooding may follow electrical lines back to underground conduits and vaults, damaging underground substations.”

The power generation system is at risk as well. Power plants are at risk of flooding, the Oak Ridge report said, “a consequence of the need for most thermoelectric plants to be close to sources of cooling water,” though there is little research quantifying it. After Hurricane Harvey, ERCOT said about 7,500 MW of generation capacity was out of service, with other units operating at reduced capacity. And Texas’s 2021 disastrous deep freeze showed how vulnerable the gas generation system was to extreme cold.

Hydro generation — which you would expect to benefit from more precipitation — is vulnerable if dam levels aren’t properly managed during a flood. Michigan’s Edenville Dam, which was built in the 1920s for hydroelectricity but had its license revoked by FERC in 2018 due to safety issues, failed in a 2020 flood, which overwhelmed its mile-long embankment.

Hail can damage grid assets such as solar farms, though solar panels are designed to handle a significant impact. At a SolarWorld event in 2015, I shot panels with a hail gun that sent ice pellets at 50 miles an hour, and the modules were unscratched. But I’ve also seen images of acres of broken panels following severe hail. Today, solar farms with trackers that tilt the modules to face the sun have software that uses hyper-local weather data to know when a hailstorm is approaching and stow panels vertically to minimize damage.

All for One, and One for All

As the prevalence and severity of extreme weather events rises, utilities’ ability to respond quickly and effectively will become even more critical. Part of that response is ensuring coordination with first responders and utilities in neighboring areas.

Utilities help each other out when disasters strike, often crossing state borders and staging ahead of a storm. The mutual assistance networks, coordinated by groups like the Edison Electric Institute and the American Public Power Association, speed up recovery. But as extreme weather events become more common, we’re more likely to run into challenges where crews will be too busy in their own area to help out nearby.

The cost of climate disasters also comes into play. Earlier in 2025, the firefighters union in Austin, Texas, voted no confidence in the city’s fire chief for withholding participation in the mutual aid effort following the Kerrville floods. He claimed the city budget meant they could not afford to support the neighboring area in its time of need.

Building Resilience for a Wetter Future

For utilities, grid owners and operators, planning for a wetter future requires hardening the physical infrastructure and readying other resources.

For the physical infrastructure, what seems over-engineered today may be just right in a future where larger and more common floods may erode foundations, and debris may try to take power poles with it. And before undergrounding wires, transformers and substations — an oft-requested upgrade in fire-prone areas and high-end developments — check those all-important precipitation and inundation maps to understand the potential for those assets to be inundated the next time extreme rain hits.

It is easy to understand why utilities are stockpiling key components to make future rebuilding easier, even though it may exacerbate shortages nationwide. The industry already is facing shortages and extended lead times for transformers, distribution poles and substation equipment. Tariffs have exacerbated the issue, as 80% of transformers, for example, are imported.

As far as human resources go, mutual assistance networks will be critical as neighboring utilities call on each other to respond to a rising number of floods and other extreme weather events. And utilities and asset owners will need to build larger contingencies in their budgets for the extra overtime and asset replacement that goes along with that response.

Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience. 

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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.