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December 12, 2025

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Stakeholders Frustrated by Lack of Details on Toronto DSM Study

IESO officials say they will release more information on how the ISO constructed its study of the potential for incremental energy savings in Toronto after stakeholders complained they lack enough details to comment meaningfully on the analysis.

At a webinar Aug. 21, IESO said it and Toronto Hydro could cost-effectively secure 219 MW of incremental summer demand savings and 50 MW of incremental winter demand savings through energy efficiency, demand response and behind-the-meter DER programs.

The savings are in addition to the forecast 847 MW (summer) and 757 MW (winter) of future electric demand side management (eDSM) program savings already reflected in the Toronto Integrated Regional Resource Plan (IRRP), according to the study, which was conducted with consulting firm ICF.

The results from the ISO’s draft Local Achievable Potential Study will affect recommendations for how non-wire alternatives can defer or reduce the need for more electric infrastructure. “The results show that incremental eDSM alone is not able to meet Toronto’s needs,” the ISO said in a presentation.

IESO asked for feedback on the results by Sept. 11. The final report is set to be published on the Toronto Regional Planning website in October.

But several stakeholders said they would be unable to respond intelligently based on the information the ISO has released to date.

“It would be very helpful if you could provide us with the draft report that you’ve got so we can look at your input assumptions, look at your analysis and give you meaningful feedback,” said Jack Gibbons, chair of the Ontario Clean Air Alliance. “Because some of your assumptions may be wrong. Some of your analysis may be wrong. And we don’t want to just take your findings that you’ve given us today on faith.”

IESO’s Tom Aagaard noted that the ISO received feedback on its input assumptions in a webinar in December and said the ISO still was refining its conclusions. “We’ll have to take back [to see] what we’re able to share sooner.”

“You’ve got a draft report from ICF. I don’t see why you can’t just share it now and be transparent,” Gibbons persisted. “What harm is it going to do to give us what you’ve got now?”

The study uses a bottom-up approach to estimate the total electricity savings at the station level. It employs a “digital twin” of Toronto’s building stock, to which eDSM measures are applied. The resulting savings are simulated at the building level and aggregated to the transformer station for each scenario. | IESO

Keith Brooks of Environmental Defence, Chris Caners, general manager of renewable energy co-op SolarShare, and David Robertson, of Seniors for Climate Action Now, agreed with Gibbons.

“Without an understanding of what the final assumptions are in more detail, it’s really, really impossible to give meaningful feedback,” Caners said.

IESO responded in an email the day after the webinar, saying it would work with ICF “to expedite the release of more detailed information on methodology and assumptions, including measure characterization and more information on achievable potential established from economic potential results.” The information will be posted on the Toronto Regional Planning engagement website.

Methodology

The study used two load forecasts:

    • A reference scenario assuming a steady increase in demand based on current policies and growth in EVs and electrified heating and “low/steady growth” of data centers.
    • A high-electrification scenario that assumes Toronto will meet its net-zero targets for buildings by 2040 (with 30% EV adoption by 2030 and 100% by 2040) and see “elevated” data center growth.

For each scenario, the study identified three levels of potential electricity savings:

    • Technical Potential. Savings from implementing all technically feasible measures regardless of cost-effectiveness and customer awareness.
    • Economic Potential. Savings from technically feasible measures that are cost-effective based on avoided generation (capacity and energy) and transmission costs and forecasted retail rates.
    • Achievable Potential. Savings that realistically can be acquired based on expected adoption rates considering market barriers and customer awareness.

The study used “digital twins” of Toronto’s building stock, to which DSM measures were applied. The resulting savings were simulated at the building level and aggregated to the transformer station for each scenario.

Draft Results

In 2045, the study concluded that achievable savings under the reference scenario were 1,066 MW in summer and 806 MW in winter:

    • Demand response (including EV charging, HVAC equipment and water heaters) had an achievable potential of 440 MW in summer and 324 MW in winter under the reference scenario. IESO said the difference in achievable potential between the reference and high-electrification scenarios is modest because the reference case includes significant heating electrification and because of the poor cost-effectiveness of EV demand response programs due to time-of-use pricing.
    • Energy efficiency (heat pumps, HVAC, lighting, appliances, weatherization and hot water) could save 605 MW (summer) and 471 MW (winter).
    • Behind-the-meter distributed energy resources (including battery storage and solar) could save 21 MW (summer) and 11 MW (winter). The low winter potential reflects the “limited value of solar to meeting winter needs,” the ISO said. Technical and economic potential match because measures in current Save on Energy programs including solar and solar-plus-storage were judged cost-effective. The reference and high scenarios had identical potential because the technical potential is affected by factors like usable rooftop area for solar rather than load.

Robertson and Brooks questioned the gaps between economic and achievable potential.

“It’s hard for us to give feedback on the results if we don’t understand how you arrived at them,” Brooks said.

“It would be really helpful and useful if there was something in your reports and presentations that talk about how do you close the gap,” said Robertson.

Existing Measures

IESO said the achievable savings in the study were muted because the Toronto IRRP already assumes 847 MW (summer) and 757 MW (winter) of new peak demand savings in 2045 from eDSM programs. In January, the Ontario government announced it would spend up to $10.9 billion on its eDSM programs through 2036.

The IESO and Toronto Hydro’s EE programs already have reduced peak demand by 800 MW in the past 15+ years.

The city’s Green Standard’s high energy performance requirements reduce the amount of additional cost-effective efficiency opportunities in new construction.

“Robust” participation in net metering, microFIT and other DER programs reduce the remaining rooftop solar potential, the ISO said.

Vehicle-to-grid

Another point of contention was the ISO’s decision to exclude bidirectional charging measures (vehicle-to-grid) from the study. The ISO said it could not properly model V2G based on current information and lacked confidence “that a program of meaningful scale could be delivered cost-effectively in the near future” because of the limited availability of vehicles capable of bidirectional charging, uncertain customer acceptance, costs and technological barriers.

Robertson questioned the ISO’s conclusion, saying “a study [with a] horizon to 2045 should anticipate developments” such as V2G.

Aagaard said it would be “kind of reckless” to include savings from V2G based on current information.

“We have very, very limited core data [to make] really important modeling assumptions to understand how much technical potential is actually out there. How many vehicles are actually going to have bidirectional charging capability? Do customers actually want this? Will [they] be willing to participate in programs when they’re called upon?” he said. “There’s just a million kind of consumer choice factors that come into play. … To include it in the modeling would be like really pulling numbers out of a hat.”

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PJM: Baltimore Load Shed Caused by Tx Equipment Failure

VALLEY FORGE, Pa. — An Aug. 11 load-shedding event in Baltimore was caused by equipment failure at the Brandon Shores substation, causing all breakers to open and cutting the city off from a major transmission feeder. (See PJM Initiates Load Shed in Baltimore Region After Substation Disconnect.)

Isolated from the 230-kV network passing through Brandon Shores, increasing strain was placed on the 115-kV lines running into the city until PJM issued a load-shed directive at 3:52 p.m. The load-shed directive was preceded by a voltage reduction action initiated at 2:15 p.m.

About 20 MW of load was shed for 28 minutes to mitigate an identified N-5 cascading outage risk that could have taken 1,200 MW offline, PJM Director of Operations Planning Dave Souder said at the Aug. 20 Markets and Reliability Committee meeting. He said PJM worked closely with Baltimore Gas and Electric (BGE) to identify regions where load shedding would be most valuable.

“We knew early on that we were going to have to go into emergency procedures,” Souder said.

Exelon Director of RTO Relations and Strategy Alex Stern said PJM worked extremely closely with BGE to limit the impact.

Six transmission lines intersect with the Brandon Shores substation, and two generators are tied into it: the 1,289-MW Brandon Shores and 843-MW H.A. Wagner, both owned by Talen Energy. The generators are running on reliability-must-run (RMR) agreements to maintain transmission security while network upgrades are constructed to facilitate their deactivation. (See FERC Approves $180M Annually for RMR Deals with Brandon Shores and Wagner Plants.)

Stakeholders questioned why the emergency procedures page and PJM Now mobile app incorrectly showed that the load-shed directive initiated a performance assessment interval (PAI), which would place capacity resources at risk of penalties if they failed to underperform.

PJM Senior Vice President of Operations Mike Bryson said staff took a broad stance on sending notifications that a PAI had been initiated to allay stakeholder concerns that capacity resources could be penalized without owners realizing an event had begun. Based on feedback since the Baltimore load shed, PJM is open to reconsidering how it sends those notifications and can add a discussion to the Sept. 11 Operating Committee agenda.

Souder added that the localized nature of the incident and its basis in a transmission emergency, rather than generation, precluded it from being a PAI. Responding to questions of whether a PAI would have been declared if load shedding were initiated across the BGE zone, he said they are declared for reserve zones, not transmission owner (TO) zones or subzones.

Bruce Campbell, of Campbell Energy Advisors, said the distinction between reserve and TO zones during emergency operations may not be widely known across stakeholders and may warrant further education. He added that there is only one reserve zone, which covers the full RTO, and one reserve subzone, Mid-Atlantic Dominion.

Several questions were raised about whether the two Talen generators were on outage during the event or if their availability contributed to the emergency. Souder said PJM does not publicly post information about generation outages and reiterated that the substation itself was unavailable. All available generation in the area was dispatched, but Brandon Shores was disconnected from the grid by the substation outage, and Wagner’s start-up time prevented it from coming online until the next day.

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First-of-its-kind Hydrogen Trial Set for Linear Generator

One of New York’s largest fossil-burning power plants will host a pioneering test run by a non-combustion hydrogen generator.

National Grid Ventures and Mainspring on Aug. 21 announced the project as the world’s first commercial installation of a linear generator operating on 100% hydrogen. September 2026 is the target date to start generating electrons.

The hope is that a year of rigorous testing on the grounds of National Grid’s Northport Power Plant will provide important lessons for potential larger-scale applications in commercial power generation. Along the way, its low-temperature, non-combustion process will produce minimal emissions and up to 250 kW of power for internal operations at the plant.

The project also could become a building block for the dispatchable emissions-free resources that are central to New York state’s clean-energy strategy in the 2030s and 2040s. No DEFRs have been identified that exist in scalable form.

“We were really drawn to the technology that Mainspring has to offer,” Will Hazelip, U.S. president of National Grid Ventures, told NetZero Insider. “This was really about seeing how that works and how it could potentially be a DEFR.”

The New York State Energy Research and Development Authority (NYSERDA) is contributing $2 million to the project.

The Long Island Power Authority also supports the effort. The Advanced Energy Research and Technology Center at nearby Stony Brook University will design the framework and methodology for the testing and then evaluate the results.

National Grid Ventures, the energy business arm of the UK-based utility, is confident it can obtain enough green hydrogen for the test program.

“So what we really want to be able to do is show that it’s fully capable of utilizing hydrogen as a fuel, and what that looks like in very specific generation technology terms,” Hazelip said, “so that specifically New York state has a better idea of how this particular type of technology could be a part of the energy mix in the future.”

The total project budget was not disclosed.

Mainspring’s linear generator is a 250-kW modular unit the size of a shipping container; it is compact enough that as much as 18 MW of capacity plus external inverters could be sited on a single acre. It operates at slightly more or less than 46% efficiency, depending on whether it is fueled with biogas, hydrogen, natural gas or propane.

The selling points are its simplicity (there are only two moving parts, and they do not need to be lubricated); its black-start and rapid-dispatch capacity; its versatility (it can switch from one fuel type to another, or use a blend, or use impure fuel); and its reduced emissions.

Nitrogen oxide emissions are near zero, because the fuel is being compressed rather than burned, and with carbon-based fuels the carbon emissions are lower than they would be in combustion systems.

Spokesperson Kevin Hennessy told NetZero Insider that Mainspring has deployed dozens of megawatts of capacity in the past five years for applications such as agriculture, landfills and wastewater treatment, the majority fueled by natural gas or biogas, and has hundreds more megawatts in various stages of its pipeline.

The Northport Power Plant was built by LILCO in phases starting in the 1960s as an oil-burning facility and later was converted to dual gas-oil capability. Its four main turbine-generator units are rated at a combined 1,516 MW and once provided more than a quarter of Long Island’s electricity.

National Grid has owned the facility since 2007, and while the plant is operated at a lower capacity factor than it once was, it remains an important grid asset. It recently reached its highest-ever output — 1,564 MW — during the July heat wave.

New York has had some other hydrogen firsts in the past few years, when the New York Power Authority ran the first gas-hydrogen blend in the state at a Long Island power plant and Constellation generated the first pink hydrogen in the nation at one of its upstate nuclear plants. (See NYPA Reports Successful Hydrogen Test at Natural Gas Power Plant and Constellation Gives Details on First-in-nation Pink Hydrogen Production.)

The state presents ambitious objectives and then creates an ecosystem to support these types of new applications, Hazelip said.

Mainspring, meanwhile, hopes to take what is learned in Northport and apply it nationwide, Hennessy said: “From our perspective, New York’s on the vanguard, leading the way with some thoughtful policy initiatives — certainly on the East Coast, but I think nationally — so it’s a great, great market to prove it out.”

NYSERDA President Doreen Harris said the project “represents a pivotal frontier in building a resilient electricity grid to power Long Island homes and businesses. This first-of-its-kind project will demonstrate how clean hydrogen can serve as a dispatchable resource to help maintain grid reliability while supporting an affordable energy transition.”

The $2 million grant for the Northport project comes through the Advanced Fuels and Thermal Energy Research Program administered by NYSERDA. The other grants announced Aug. 21 were:

    • GTI Energy, over $220,000 to evaluate New York’s geological hydrogen storage potential;
    • Plug Power, $2 million to partner with Verne to co-develop new hydrogen distribution trailers with cryo-compressed storage technologies;
    • Stony Brook University, over $4.9 million for a low-pressure, ambient-temperature hydrogen storage system at Northwell Health Hospital; and
    • SWITCH Maritime, $2 million to develop and demonstrate New York’s first hydrogen fuel cell-electric ferry.

A spokesperson said NYSERDA hopes to gain insight from the Northport project about the technology being used: “NYSERDA will analyze the project data throughout the demonstration, assessing the technical and economic viability of linear generators. The research will inform NYSERDA’s future work on clean hydrogen, and findings will be shared with the public and utilities to help determine potential pathways for broader adoption in New York state.”

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FERC Responds to ERO’s INSM Clarification Filing

FERC has replied to a request for clarification from NERC on its directive that the ERO revise the recently approved reliability standard requiring utilities to implement internal network security monitoring (INSM) at some grid-connected cyber systems. 

FERC provided NERC the information it requested while denying a request from several trade organizations for a technical conference to provide further clarity (RM24-7). 

The commission approved CIP-015-1 (Cybersecurity — INSM) on June 26, 2025; the standard requires utilities to implement INSM for all high-impact grid-connected cyber systems with or without external routable connectivity (ERC), as well as medium-impact systems with ERC. (See FERC Approves NERC’s Proposed INSM Standard.) FERC directed the standard’s development in response to the SolarWinds hack of 2020, in which malicious actors infiltrated the update channel of a common network management tool to push malicious code to customers worldwide. 

Along with its approval of the new standard, FERC directed NERC to make further changes, due 12 months after the effective date of the final rule, requiring that utilities extend the implementation of INSM to electronic access control or monitoring systems (EACMS) and physical access control systems (PACS) outside their electronic security perimeter, the electronic border around their internal networks. 

However, NERC later filed a request for clarification seeking to “eliminate ambiguity regarding the intended scope of the commission’s directive.” (See NERC Requests Clarity on FERC’s INSM Order.) At issue was the term “CIP-networked environment,” which FERC had used in an earlier notice of proposed rule-making (calling on the ERO to protect “all trust zones of the CIP-networked environment”) without defining it.  

FERC said in its order approving CIP-015-1 that the CIP-networked environment “does not cover all of a responsible entity’s network” but does include “the systems within the [ESP] and network connections among and between [EACMS] and [PACS] external to the [ESP].” 

NERC asked the commission to explain whether the term refers only to communication paths between CIP devices, or if it means “all communications on the network segment.” It also requested that FERC specify whether communication between PACS and non-PACS controllers are part of the CIP-networked environment.  

The request for a technical conference came from the American Public Power Association, Edison Electric Institute, and the National Rural Electric Cooperative Association, which sought to confirm that FERC’s order “does not require monitoring of network traffic between non-CIP assets and intermediate systems that are classified as EACMS.” 

In its Aug. 21 filing, FERC explained that the term “is not intended to capture non-CIP assets” and that the assets specified by NERC — non-CIP cyber assets, non-PACS controllers and non-EACMS firewalls — are all out of scope. This means that “for shared network segments located outside the electronic security perimeter containing both CIP (i.e., EACMS or PACS) and non-CIP assets (e.g., corporate devices), only the east-west traffic for access monitoring of EACMS and PACS is within the scope of the term CIP-networked environment.” 

Regarding NERC’s second question, FERC confirmed that because non-PACS controllers are not CIP assets, “CIP-networked environment” therefore does not include “communication between PACS and non-PACS controllers.” On the other hand, communication between PACS and PACS controllers is in scope because such communication “is considered internal traffic of the PACS.” 

In light of its clarification, FERC determined that its order “is sufficiently clear on how NERC should implement [FERC’s] directives” and that a technical conference is not required. However, the commission said NERC could hold its own conference if the ERO and industry stakeholders consider it appropriate. 

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Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months

Nearly four months after the launch of Ontario’s nodal market, IESO officials say they are shifting from correcting implementation problems to seeking improvements to ensure the new model meets the goals of increasing market efficiency, transparency and competition.

“We’re getting … pretty close to what I would call more of a steady state … where we’ll be able to start to move from … addressing the day-to-day issues that come up for things that didn’t quite get implemented exactly as planned, to [looking at] the longer term,” Candice Trickey, director of Market Renewal Plan readiness, said in a briefing Aug. 21, the first in a promised quarterly series of updates. “How are things progressing? Are we seeing the things we wanted to see? … And where we aren’t, what do we need to [do to improve] that?”

The Renewed Market, which launched May 1, created a financially binding day-ahead market (DAM) and about 1,000 LMP nodes. (See Ontario Nodal Market Operating as Expected at 1-month Mark.)

Despite some implementation problems, IESO said the market has been working well, with prices strongly correlated to demand.

Data Points

Some data points as the market nears the four-month mark:

    • Nearly 30 traders have registered to transact in the virtual market, which allows them to submit hourly bids and offers in nine zones. Problems completing traders’ authorizations delayed the launch of the virtual market from May 8 to May 13. One large consumer has registered as a price-responsive load. Other organizations have begun the process of registering for the two new participation types.
    • All required participants have registered reference levels under market power mitigation rules, with some refining their values based on their experience in the market. Reference levels include energy and operating reserve prices and resources’ energy ramp rates and lead times. The Market Power Mitigation Working Group has reduced its meeting frequency to monthly, with “no significant issues” identified.
    • IESO said it has been issuing settlement statements and invoices within the required timelines, although increased processing times have resulted in invoices being issued later in the day than preferred by participants, an issue the ISO is working to address. The ISO created a Settlements Notifications webpage to advise participants of updates.
    • Participant inquiries have increased under the new market. IESO said its Customer Relations unit has answered 80% of inquiries within two business days, although more complex questions have taken “much longer.” The ISO said 40% of market participants responded to its final market readiness survey, with nearly 90% saying IESO’s Customer Relations or Marketplace Training were “very” or “somewhat” effective. About 63% of respondents reported they generally are “comfortable operating,” and 35% said that “non-critical” operations still are incorporating changes. Only a few organizations reported they were “struggling to operate effectively,” IESO said.

‘Defects’

As expected, Notices of Disagreement have increased since the market launch. The ISO has confirmed its initial statements in two-thirds of cases and attributed one-third to defects that have been corrected. The grid operator is working through a backlog of disagreements.

Most of the defects affected small groups of participants, such as price responsive loads and resources eligible for generator offer guarantees — non-quick-start resources that commit to economically scheduled hourly generation commitments in advance of real-time (RT) dispatch.

Candice Trickey, director of Market Renewal Plan readiness | IESO

But one defect, caused by a calculation error regarding residual uplifts, had a widespread effect. Although the two-settlement energy settlement amounts were calculated correctly, the day-ahead and real-time residual uplifts were calculated incorrectly and distributed to loads and exporters, resulting in adjustments to four uplift charge types. The ISO issued a notice Aug. 12 identifying the issue, the affected charge types and how resettlement will be completed.

Trickey said the rate of new defects in market systems has fallen from the first few weeks and that most were addressed with interim “workarounds” to avoid market effects.

One of the workarounds involved the five-minute interval Ontario Demand values reported in real time, which were overstated in some “limited circumstances.” IESO’s workaround “effectively adjusted forecast demand to largely mitigate this defect,” it said.

The ISO said some defects had no effect because workarounds were implemented, while others affected market outcomes briefly and required it to administer prices or correct schedules before settlement.

More complex defects required “extensive assessment” to determine if there was a material effect and could not be completed prior to settlement.

Real-time prices have been more volatile than the day-ahead market, with prices converging when actual conditions matched forecasts, and diverging when there were large load forecast errors or unexpected outages. | IESO

Thus far, the ISO said, two of those assessed had material effects necessitating the issuance of dispatch scheduling errors (DSEs): an incorrect calculation of the external congestion and net interchange scheduling limit price components for May 1-4; and an incorrect limit considered in the DAM for the ONT-PQAT interface on May 6. DSEs are issued when problems are discovered after settlements are issued; they allow the ISO to provide compensation to harmed parties but do not change prices.

Another five issues requiring extensive assessment are outstanding; the ISO said it likely will take another three to six months to determine whether these had material effects requiring DSEs.

Market Results

IESO officials said market results generally have been in line with expectations.

The market began during the “freshet,” the annual influx of water from spring rainfall and melting snow. Many hydropower projects must exit the operating reserve market and operate as “must-run” generators in spring because they have to flow the excess water through their turbines. (See Operating Reserve Prices Surge in Ontario.)

Joseph Ricasio, a member of IESO’s control room team | IESO

Summer brought its own challenges, Joseph Ricasio, a member of IESO’s control room team, said during the webinar. Hot weather sent the province’s demand soaring above its 2024 peak of 23,852 MW on seven occasions, with peaks as high as 24,862 MW. “I don’t remember the last time we received a lot of successive heat waves,” he said.

Between June 23 and 24, Ontario shifted from a net exporter during peak hours — as strong wind generation allowed it to ship energy to New York and Michigan — to a net importer as wind diminished.

It was a net importer on July 14-16 due to economic conditions and on July 27-29 as two large generators were “forced offline.”

“The generation and transmission performed very well this summer,” Ricasio said. “One advantage [of] being a net exporter is that it gives us a lever to address any adequacy concerns, and that’s because if it’s needed, we can curtail those exports.”

Despite the challenges, Ricasio said, the financially binding DAM has improved IESO’s ability to commit adequate generation for the next day. Some Level 1 Emergency Energy Alerts — a notice that all available generation resources are committed — have been identified based on day-ahead results, IESO said. “This gives advance notice to your neighbors that we may need their help,” Ricasio said.

‘Non-intuitive’ Results

Trickey said numerous participants have questioned “non-intuitive or unusual” market results. Some identified defects, while others were a result of the challenging summer temperatures and the new market’s multi-interval optimization.

“In an LMP market, the [offer] price is certainly an important determinant. But because we’re looking at optimizing over many, many intervals, [there can be] a difference in what the scheduling algorithm and the pricing algorithm are looking at,” she said. “So, you might see an offer close to the margin that appears uneconomic that gets scheduled.”

Director of Markets Darren Matsugu | IESO

Director of Markets Darren Matsugu said the market had produced prices “reflective of system conditions and efficient resource schedules” with real-time and day-ahead prices converging when actual conditions matched forecasts, and diverging when there were deviations in real time due to large load forecast errors or unexpected outages. Although real-time prices were more volatile than day-ahead, more than 95% of load was met by day-ahead schedules, minimizing the price effect on consumers, the ISO said.

“Moving from the mild temperatures in May — where we saw … seasonally low demands and abundant supply — into what’s turned out to be a very hot summer, we’ve seen an associated increase in entry market prices, which is exactly what we would expect,” Matsugu said.

“We also observed higher natural gas prices over the summer, and as gas is often the marginal resource during these two periods, that also has upward pressure on market clearing prices,” he added.

Prices have consistently separated between the north, where bottled hydro supply can suppress prices, and the transmission-constrained south.

“This past May when demand was relatively low and we had substantial baseload generation available, we had very few intermediary peaking resources that were already online and available to increase output immediately,” he added. “But what we have seen is demand has increased over the summer, and more and more of those resources are being committed ahead of real time, either in day-ahead or in pre-dispatch. This increases the amount of incremental flexibility that can be dispatched on the system, if required.”

Prices have consistently separated between the north, where bottled hydro supply can suppress prices, and the transmission-constrained south. | IESO

An average of 80 to 90% percent of non-quick start gas generators dispatched in real time — units that need one to six hours to start up and synchronize with the grid — were scheduled in the DAM over the first three months, providing grid operators and market participants “a clearer view and financial certainty for the next day’s operations while also leaving room to adjust to forecast uncertainty and outages in real time,” the ISO said.

Challenges in Scheduling of Pseudo Units

While the experience generally has been positive so far, “it isn’t perfect,” Ricasio said, citing IESO’s difficulties with pseudo unit (PSU) configurations, which model the mechanical interdependencies of combustion turbines and steam turbines.

Under the Renewed Market, PSU modelling is applied for DAM, pre-dispatch and RT timeframes for commitment, scheduling and dispatch.

IESO notified affected generators of workarounds to address the issues and said it is working on permanent fixes.

No Major Changes Expected

Matsugu said the market thus far has worked as designed to reduce out-of-market payments and increase efficiency.

“I do expect that over time, there’ll be some fine tuning that may be eventually required on these things, as is to be expected with any market — and particularly given the significance of the change that we’ve introduced with Market Renewal,” he said. “But at this point, there are no major design issues that require immediate fixes, just something that we’ll continue to pay close attention to.”

Matsugu cautioned that IESO had only two seasons of experience with the new market rules, saying it will gain valuable knowledge in the coming fall and winter.

“It is premature, I think, to draw too much based upon the still very short time frame that we’ve been operating,” he said. “We are still working toward … a steady state, where we can see the market performance under a diverse set of outcomes and conditions. [And] the participants themselves are still establishing their own competitive bid and offer strategies.”

Participants’ Questions

ISO officials answered several questions from stakeholders during the Aug. 21 presentation. Aaron Lampe, of Workbench Energy, asked about the effect of the market on pre-dispatch prices.

Matsugu said comparing PD prices before and after May 1 is “really comparing apples to oranges [because] in pre-market, our pre-dispatch was doing a one-hour optimization and not looking out across the balance of the day.”

“The only thing in common between pre-market pre-dispatch and our current pre-dispatch is really just what it’s called,” he added.

Rob Coulbeck, of Red Jar Energy Partners, said the ISO’s pre-dispatch three-hour look ahead was restrictive and asked if it could add another hour for import and export transactions that don’t clear in the DAM.

“I think that probably falls in the bucket of future design enhancements,” responded Matsugu. “There’s probably a whole bunch of different things that we can start to consider once we’re satisfied that the current market is performing.”

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EDAM Implementation Team Reveals New Intertie Scheduling Approach

CAISO staff on Aug. 21 showed how the grid operator plans to implement certain parts of its Extended Day-Ahead Market (EDAM) next year, with stakeholders asking for more time to comment on what they said crossed into potential policy revisions. 

CAISO began the workshop by discussing changes to intertie scheduling processes. In the ISO’s current day-ahead market, intertie schedules occur at an intertie scheduling point, George Angelidis, CAISO executive principal of power systems and market technology, said at the workshop. 

But under EDAM, intertie schedules will be taken at a Generation Aggregation Point (GAP) in the corresponding source or sink balancing authority area (BAA), Angelidis said. This change will increase the accuracy of power flow on the grid and improve power flow congestion, and more closely aligns with actual flow by reducing phantom congestion, Angelidis said. 

CAISO broke down the GAPs into three types: a Default Generation Aggregation Point (DGAP), a Custom Generation Aggregation Point (CGAP) and a Generic Generation Aggregation Point (GGAP). Each type is used to determine intertie participation categories. 

Under EDAM, there will be “specific GAPs for balancing authority areas that are the source or the sink of the energy for the import or the export,” Angelidis said.  

“We want to have more accuracy in the power flow calculations and market solutions,” Angelidis said. “In the current market, at the intertie scheduling point … there is no resource actually at that location, so modeling energy of the import or the export at that location is inaccurate.” 

CAISO is therefore moving the intertie scheduling location under EDAM to “somewhere where it is more reasonably representative of the energy being generated or consumed,” Angelidis said. 

“Of course, accurate market solutions for power flow translate to accurate congestion management and also accurate locational marginal prices,” Angelidis said. 

Some stakeholders at the workshop said they were concerned that some of the implementation processes presented by CAISO were in fact policy-related issues, which should be discussed further in other workshops with comment periods. 

“We need some form of formal comment period,” said Dan Williams, principal adviser with The Energy Authority. “Being someone who has been involved with this initiative since 2018, I was under the understanding from the EDAM design and discussions during that time that EDAM implementation was primarily about the CAISO BA and its interaction with the EDAM BAs.” 

Williams said he thought CAISO’s interties, other bilateral intermarket activity in the West and the EIM were “not going to be fundamentally impacted in the way that it is to me being described here.” 

“There is, for me, a large impact here to the market in general and contracting that is a lot for folks to absorb in one workshop,” Williams added. 

CAISO also discussed how it plans to implement congestion revenue rights and settlements under EDAM. CAISO is looking to phase in its implementation of its CRR model, which could improve the accuracy of the model, said James Lynn, CAISO principal. 

When EDAM begins, CRRs will not be paid based on constraints where the CAISO BAA does not receive congestion revenue from integrated forward market flow on that constraint, Lynn said. 

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Texas PUC Approves $240M in Energy Fund Grants

Texas regulators have selected the first four projects eligible for more than $240 million in grants outside the ERCOT region as part of the state’s Texas Energy Fund. 

The Public Utility Commission approved staff’s recommendation during its Aug. 21 open meeting. It gave Executive Director Connie Corona authority to approve the applications and enter into grant agreements, contingent upon a final review (58492). 

The four projects under the TEF’s Outside ERCOT Grant Program (OEGP) include two from North Plains Electric Cooperative (NPEC) and one from Southwestern Electric Power Co. SWEPCO’s $200 million proposal to replace 700 miles of aging copper wire and utility poles in northeastern Texas hits the program’s cap. 

The other approved projects are: 

    • $20.4 million to NPEC for a 115-kV transmission loop in five northeastern Texas counties. 
    • $1.9 million to the cooperative to expand its Ochiltree Interchange, increasing service capacity in its northeastern and Panhandle regions. 
    • $17.7 million to El Paso Electric to deploy a continuous online monitoring project that will provide real-time analytics to improve generation availability and operational resilience. 

“While it’s critically important to add more power to the electric grids that serve Texas, we must also do everything we can to enhance and strengthen the systems we have in place, and that’s what these four projects will do,” PUC Chair Thomas Gleeson said in a statement. 

The Outside ERCOT program is one of four under the TEF. It has been allotted $1 billion by Texas lawmakers. To be eligible for awards, projects must modernize infrastructure, improve weatherization, make reliability and resiliency improvements, or address vegetation management. 

PUC staff said the program has received more than a dozen applications, representing almost 50 separate projects and totaling $1.5 billion, since it was launched in May. An additional 35 applications have been started but not yet submitted. 

Grants are contingent on OEGP funding availability, mutual agreement to the terms and conditions in their respective grant agreement, and their adherence to the terms and conditions set forth in their respective grant agreements. The PUC will enter into grant agreements with applicants for selected eligible projects until the program’s funds are exhausted. 

The commission already has granted two loans under the TEF’s centerpiece, the in-ERCOT program created to build dispatchable generation. The program is allocated half of the TEF’s $10 billion funds. (See NRG Energy Secures $216M Loan from TEF.) 

CenterPoint Resiliency Plan Approved

The PUC approved a modified version of CenterPoint Energy’s $3.18 billion system resiliency plan, directing the utility to defer $217 million in cost recovery until 2029 for several resiliency measures related to strategic undergrounding, distribution pole replacements and vegetation management (57579). 

CenterPoint originally proposed a $5.75 billion resiliency plan. However, it reached a settlement with commission staff, the Office of Public Utility Counsel, several Houston-area cities and other intervenors that reduced the plan’s costs. 

A new state law requires Texas utilities to file annual resiliency plans. CenterPoint drew anger from residents and politicians last year after Hurricane Beryl left 2.2 million of its customers without power. 

The commission also: 

    • Approved an amended rule that removes the exemption currently preventing a generation company controlling less than 5% of ERCOT’s total installed capacity from being considered to have market power (58379). 
    • Agreed with staff’s recommendation to hold two workshops Sept. 2. The morning workshop will involve a rulemaking for net metering arrangements for large loads co-located with an existing generation resource. The afternoon workshop will take on a rulemaking that establishes large-load forecasting criteria. 
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Louisiana PSC Approves 3 Controversial Gas Plants Ahead of Schedule for Meta Data Center

The Louisiana Public Service Commission voted two months earlier than initially planned to approve 2.3 GW in new Entergy gas plants to supply a new, $10 billion Meta data center. 

The PSC voted 4-1 to allow Entergy to build three gas generators to power the Meta facility at a cost of $3.2 billion, drawing boos from the audience at the Aug. 20 meeting. (See Entergy La. Confirms Meta Data Center Behind 3 Proposed Gas Plants.) Entergy requested the early vote.  

Larry Hand, Entergy Louisiana’s vice president of regulatory and public affairs, said the electric service agreement for the next 15 years ensures Meta will pay to cover the new generation costs, mitigating impacts on other customers.  

“Entergy’s goal, and I believe I can safely speak for Meta, was not to come to Louisiana and cause costs to be shifted to other customers,” Hand said. He said while Entergy took pains to strike the most sensible deal it could, there nonetheless would be risks associated with the project.  

“It’s a 15-year deal, so we can’t predict everything,” he said.  

Hand estimated that net ratepayer impacts will be “plus or minus a dollar” per month. He also said if Meta doesn’t renew the contract after the first 15 years, then the MISO South region will have “a gift” of half-paid-for, relatively new gas plants among the region’s other aging thermal plants in 2041.  

According to the contract, should Meta exit the contract early, the generating assets would become wholly owned by Entergy. Louisiana PSC staff said while Meta’s abandonment of the project is a remote possibility, Meta likely would have paid for the most expensive start-up years of the project by the time it leaves.  

Hand said it was necessary for Entergy to circumvent commission procedure — forgoing conducting a request for bids on the plants — and self-build the generation to meet Meta’s aggressive timeline. He said opening an RFP would have added a second year to the project.  

Entergy Louisiana ratepayers are set to cover an additional $550 million in transmission costs that are necessary to connect the data center’s generation to the grid.  

Hand acknowledged not all who protested the deal agreed with the final, settled version of the contract. Louisiana PSC staff, Entergy, Sierra Club and the Southern Renewable Energy Association signed off on the settlement deal.  

The finalized deal contains more consumer protection, including a provision that Meta’s minimum bill payments would cover 100% of the costs of the trio of generating units, including cost overruns. Meta also agreed to fund development of 1.5 GW of solar generation under the state’s Geaux Zero program and to provide up to $1 million per year for Entergy’s Power to Care, which is a bill assistance program for low-income, elderly and disabled Entergy Louisiana customers. 

Meta, which has a goal to be carbon neutral by 2030 both in operations and suppliers, also expressed a willingness in a separate corporate sustainability rider to help fund carbon capture and sequestration at Entergy’s existing Lake Charles Power Station.  

Entergy plans to submit the gas plants to MISO’s newly approved expedited interconnection queue. Hand said it wasn’t efficient to try to build the generation behind the meter, noting that the data center likely would need twice as much generation as planned to run at a more than 99.9% load factor behind the meter.  

The data center is slated for a 2,250-acre state-owned site known as Franklin Farms. Two of the new gas plants will be named after Franklin Farms. 

Commissioner Eric Skrmetta called the deal groundbreaking because Entergy found a way not to burden the public with new generation builds. He said the contract “sets a new standard to develop power resources to the advantage of our ratepayers.”  

Davante Lewis — who provided the sole “no” vote — said he liked the contract’s strong consumer protection and Meta’s assistance with solar expansion but said he ultimately struggled with Entergy’s claim that it needed to bypass a competitive bid process and self-build generation.  

“The truth is there are a lot of things that I just cannot verify at this moment,” Lewis said. “I cannot say with enough certainty that this deal and its power agreement serves the greater good, has the public in interest, with the least-cost revenue.”  

Lewis said he hoped that future deals with data center hyperscalers contain competitive bidding, battery storage, possibly flexible load provisions and “a full suite of front-end customer protections.”   

Commissioner Foster Campbell, whose northeast Louisiana district will host the plants, said the development was something his community was “waiting a long, long time for.” Campbell said he had been “pulling for jobs” in those poverty-stricken parishes for more than 50 years. Campbell said he was supporting the project despite being a Democrat. He explained that it’s easier to be against everything than support something.  

“This is something we drastically need in North Louisiana; it’s a shot in the arm,” he said, noting the area was hemorrhaging residents to Dallas, Houston, Baton Rouge and New Orleans.  

Campbell also said there’s no such thing as a “bulletproof” contract.  

Residents at the meeting voiced concerns ranging from Meta’s potentially massive water use, the lack of permanent jobs created by the facility and doubts that Entergy wouldn’t raise rates because of the project. A few said they considered the project speculative because no one knows how AI would function in 15 years. Multiple residents asked the commission to consider delaying their vote. 

Logan Burke, executive director of the Alliance for Affordable Energy, told the commission there are many people living in Louisiana who “cannot handle another dollar on their bill.” She said she was concerned the contract could shift costs and risks onto ratepayers. Burke said ratepayers would foot maintenance costs of the plants, which are poised to deepen the state’s overdependence on gas. 

The Union of Concerned Scientists said the vote was rushed. The organization said the project would further tax Louisiana’s grid, which is considered unreliable when compared to other states because of its shortage of transmission capacity, an overreliance on methane gas and the state’s commonplace extreme weather.  

“Observers inside and outside the state have undoubtedly taken notice of this pattern of fast-tracking utility proposals with very little public notice and transparency for the residents most impacted,” UCS energy analyst Paul Arbaje said in a statement.  

Entergy Sticks by Gas Choice

At the Aug. 19 Midcontinent Energy Summit in Indianapolis, Kurt Allen, director of industrial accounts at Entergy, said the utility is trying to build generation “as fast as they want it.”  

Allen said developing renewable energy to meet large load customers remains difficult for Entergy.  

“The price is not really coming down on those. There’s a challenge there, and I think it’s going to be a challenge for the next several years,” Allen said. He said it’s tough to convince large customers to pay the resulting prices from Entergy’s requests for proposals on renewable energy. He also expressed doubt over Entergy’s ability to install carbon-capture technology.  

Allen said the Meta project is labor-intensive and getting the three generating units and associated transmission built fast enough for Meta’s timeline will be challenging. He said Meta representatives commended Entergy on its swiftness in assembling the deal.   

Despite the Meta’s Louisiana plans relying on natural gas, Allen predicted decarbonization likely will be driven by hyperscalers that have the money and the will. 

Allen declined to answer an audience question on whether Entergy is thinking about how to bring down the costs of network upgrades so it’s more cost-effective for renewables to connect in MISO South.   

At the same event, Entergy’s Wyatt Ellertson said the utility believes natural gas generation is the most reasonable solution for high-load factor customers. 

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BOEM Slaps Stop-work Order on Revolution Wind

The Trump administration has slapped Ørsted with a stop-work order on Revolution Wind, a 704-MW project off the New England coast that is 80% complete. 

The Aug. 22 order by the Bureau of Ocean Energy Management cites national security interests and potential interference with reasonable uses of territorial waters. 

It is the latest move by the administration to thwart renewables development, and one of the harshest. 

President Donald Trump delivered a pro-fossil, anti-renewable message during his campaign but reserved a particular contempt for “windmills.” Hours after his inauguration Jan. 20, he delivered on his rhetoric, directing a halt to future offshore wind leasing and a review of existing offshore wind permits. 

Acting BOEM Director Matthew Giacona cited that Jan. 20 memorandum in his letter to Ørsted North America on Aug. 22. He forbade further activity on the Offshore Continental Shelf until BOEM completed a review. 

Ørsted said later Aug. 22 it would comply with the order and is evaluating all options in a range of scenarios, including legal action. 

It said the multibillion-dollar project was 80% complete, with 100% of turbine foundations and 45 of 65 of turbines installed. It had been targeting start of commercial operation in the second half of 2026; the 704-MW facility would send emissions-free electricity to Connecticut and Rhode Island. 

During an Aug. 11 conference call with financial analysts, CEO Rasmus Errboe was asked if he was certain the Trump administration would not try to block Revolution or Ørsted’s other active project, the 924-MW Sunrise Wind, which is targeted for completion in 2027. 

Errboe declined to speculate. 

The administration slapped a similar stop-work order on Empire Wind 1 in April, causing hundreds of millions of dollars in losses for its developer, Equinor. (See Feds Move to Halt Construction of Empire Wind 1 and Equinor Takes $1B Impairment on U.S. Offshore Wind.) 

The move against Empire, a project that was fully permitted after years of review, sent shock waves through the renewables industry. There was widespread speculation that it was an attempt to twist the arm of New York’s governor to allow permitting of two natural gas pipeline projects the state previously had rejected, as New York is counting on Empire (and Sunrise) as part of its decarbonization strategy. (See BOEM Lifts Stop-work Order on Empire Wind.) 

But the Empire stop-work order never really was explained, other than a vague mention of flawed science and rushed approval. Journalists who requested a copy of a study that purportedly justified the move were repeatedly rejected, then were provided a fully redacted copy four months later. 

Errboe cited the Empire stop-work order as a turning point — it immediately made Ørsted’s attempts to land a financial partner for Sunrise untenable, causing Ørsted to announce a need to raise $9.3 billion, causing its stock value to plunge. (See Ørsted to Raise $9.3B, Self-finance Sunrise Wind.) 

The company said in a news release Aug. 22 it will in due course update the markets on the potential impact of this latest setback. 

Giacona in his letter said BOEM is seeking to address “concerns related to the protection of national security interests” and “interference with reasonable use” of the offshore waters. 

He did not elaborate, but both points speak to some of the many policy moves the Trump administration has taken to stop wind power development: 

The Department of Commerce on Aug. 13 initiated an investigation to determine the effects on national security of imports of wind turbines and their parts and components. 

BOEM’s parent agency, the Department of the Interior, announced a sweeping overhaul of offshore wind rules Aug. 7; an order to rein in wind and solar projects Aug. 1; cancellation of wind energy areas designated on 3.5 million acres of seabed on July 30; and an end to preferential treatment of wind energy July 29, among other steps. (See Dept. of Interior Launches Overhaul of OSW Regs, Trump Administration Takes Another Swing at Wind Power, and Feds Pile on More Barriers to Wind and Solar.) 

Late Aug. 22, the National Ocean Industries Association decried this latest attack: “Revolution Wind is already under construction and nearly complete, representing years of planning, billions in private investment and significant progress for America’s offshore energy supply chain. Any pause or uncertainty at this stage could ripple across jobs, contracts and communities already benefiting from the project.” 

The Oceantic Network called it an illegal move that threatened American jobs and energy dominance: “This dramatic action further erodes investor confidence in the U.S. market across all industries and undermines progress on shared national priorities — shipyard revitalization, steel and port investments, and energy dominance. In fact, halting work on Revolution Wind will drive up energy costs for consumers, idle Gulf Coast vessel operators that have invested hundreds of millions of dollars in new or retrofitted vessels and jeopardize the livelihoods of union workers.” 

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SPP MOPC Passes Revised Large Load Policy

SPP stakeholders have approved a revised version of the grid operator’s fast-track study to integrate high-impact large loads (HILLs) during a special virtual meeting of the Markets and Operations Policy Committee.

MOPC members resoundingly shot down the proposal during their July quarterly meeting, giving it only 53.7% approval. They said the fast-track study policy was a rushed process outside of the normal stakeholder structure and didn’t give them enough time to review the revision request (RR696).

Since then, staff have stripped out conditional high-impact large load service (CHILLS) and the design associated with dispatch, study and charges for the service from its original proposal. It also removed one of three paths for high-impact large load generation assessment (HILLGA).

The changes met with success. MOPC members complimented staff on the revisions and then gave the measure 95.7% approval. The transmission owner and transmission user sectors each had one dissenting vote, with 15 total abstentions.

“We’re reviewing an improved product compared to what we discussed in July, so appreciate all the time and effort to get here today,” Southern Power’s Chase Smith said during the meeting.

“I know … there was a desire for members just to have a little bit more time to get more comfortable,” SPP COO Antoine Lucas said. “Today, we’ll do what we can to close out that effort and be able to move this forward to the next stage.”

SPP’s Board of Directors delayed consideration of RR696 during its August meeting to allow a follow-up session for MOPC to discuss the issue further. (See SPP Board Sets Aside 765-kV Costs, Large Load Policy.)

The board and the RTO’s state regulators now will take up the HILL proposal. SPP has scheduled an education session for the board, its Members Committee and the Regional State Committee for Sept. 3. The board then will hold a call Sept. 4 to consider HILLs and Southwestern Public Service’s out-of-bandwidth 765-kV project, which also was set aside by the directors.

MOPC approved a design focused on HILLs and HILLGA paths as revised by staff’s latest comments, filed Aug. 14. Approval is contingent upon SPP modifying the tariff to reinstate a 60-day study under Attachment AQ, which governs upgrades or other changes to delivery point facilities.

HILL studies will remain on a 90-day timeline. Changes include a revised HILL definition that clarifies its transmission service study process and its independence from non-conforming load.

A HILL is defined as a new commercial or industrial load or an increase to existing load at a single site, connected through one or more shared interconnection or delivery points. Load can be either 10 MW or more if connected to the system at a voltage level less than or equal to 69 kV, or 50 MW or more if connected at a voltage level greater than 69 kV.

SPP says its HILL proposal will result in more robust study analysis, with large loads and their support generation studied together. It still includes load forecasts and ride-through requirements, with two HILLGA paths: a common bus or a local area.

Costs will be allocated to the cost-causers:

    • HILLs using a delivery point assessment will have their upgrades base-plan funded.
    • Upgrades from HILLs using a provisional load process will be directly assigned until the customer acquires firm service for new generation.
    • Upgrades from HILLs bringing supporting generation to a local area will be directly assigned to the generation customer.

The CHILLS policy will be taken up during the MOPC, RSC and board meetings in October and November. Staff will hold education sessions before then with various working groups and the RSC.