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July 29, 2025

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PJM Stakeholders Reject 2027/28 Capacity Auction Parameters

VALLEY FORGE, Pa. —Stakeholders rejected the installed reserve margin (IRM) and forecast pool requirement (FPR) values recommended by PJM staff, with some opposed arguing that the inputs remain nebulous.

The July 23 Markets and Reliability vote received 65% sector-weighted support, just short of the two-thirds threshold; a second vote at the Members Committee also failed with 63% sector-weighted support.

The proposal would increase the IRM to 20% for the 2027/28 Base Residual Auction (BRA), up from 19.1% in the auction prior, while the FPR would increase from 0.9170 to 0.9260. PJM’s Josh Bruno said both are increasing due to PJM’s risk modeling skewing more heavily toward the winter. (See “Stakeholders Discuss Revised IRM and FPR Values for 3rd Incremental Auction,” PJM PC/TEAC Briefs: Jan. 7, 2025.)

Paul Sotkiewicz, president of E-Cubed Policy Associates representing J-Power USA, said the effective load-carrying capability modeling behind resource accreditation and risk modeling is poorly understood by market participants, and its results are unreproducible.

“This is a black box — people still don’t understand how anything is put together, and you can’t run a market … by doing this as a black box. So, we really need to consider taking our time and really hearing out what needs to be done here,” he said.

Exelon’s Alex Stern noted that few of the 500 eligible voting members voted on the proposal, with the final MC vote reflecting 45 ballots cast in favor, 25 cast in opposition and 15 abstentions.

Bruno said 198 GW of installed capacity is expected to be available, up 4.6 GW, equating to 163 GW of solved load, a 2.5 GW increase. The increase comes from transmission headroom being allocated to existing resources through transitional capacity interconnection rights, new wind and solar resources, and increased demand response accreditation driven by the resource’s availability window being expanded. (See “PJM Announces Transitional Headroom Allocations,” PJM PC/TEAC Briefs: May 9, 2023 and PJM Stakeholders Endorse More Detailed Demand Response Modeling.)

Most resource classes would see their accreditation remain within three percentage points of their ratings for the 2026/27 BRA. Demand response, however, saw its rating increase 23 points, and storage resources of all durations saw their ratings increase between six and nine points.

Much of the increased winter risk is due to the steady pace of anticipated data center growth. Because winter falls toward the end of the delivery year, Bruno said more large loads are expected to have come online by that time.

James Wilson, PJM | © RTO Insider  

Rebecca Stadelmeyer, of Gabel Associates, said there is a disconnect between the load forecast and the delivery year and raised the request to all companies conducting their analysis now to take a more granular look at data center milestones and ensure the online months align more accurately.

James Wilson, a consultant for several consumer advocates, said data center growth and its relation to seasonal risk is a short-term phenomenon PJM should prevent from causing distortions to the investment signals sent by the capacity market. He acknowledged that capacity auctions print one-year price points but argued that should not be incongruent with the goal of guiding long-term investment.

Greg Poulos, CAPS | © RTO Insider  

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said most of the advocates planned to vote against the proposal due to endorsement being sought on the same day as the values were brought for a first read. That left little time, he said, to review and ask questions, particularly about the cost impacts of the increase to the reserve margin. He also questioned whether it is appropriate for PJM to increase the IRM given the tightening supply and demand in recent auctions. Raising the prospect that not doing so could result in more frequent DR deployments, he argued that curtailment service providers are being paid to be available and not using them undermines their value.

Susan Bruce, representing the PJM Industrial Customer Coalition, said consumers and DR participants have gotten a lot of questions about the parameters presented for the 2027/28 auction just a day after the results for the 2026/27 auction were posted. She said it’s unfortunate the membership is being asked to make decisions on a topic so dependent on the results of the 2026/27 BRA with so little time to consider the implications.

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New York Issues 1st RFP for Energy Storage

New York Gov. Kathy Hochul announced the first of three solicitations for bulk energy storage July 28 as part of the state’s goal of deploying 6 GW by 2030.   

Each solicitation aims to procure 1 GW of energy storage. The awarded projects must have an in-service date of Dec. 31, 2030. 

The New York State Energy Research and Development Authority is administering the request for proposals through its Bulk Energy Storage Program. The procurement is technology-neutral, but projects with durations of less than eight hours must use technologies that previously have been commercially deployed and interconnected, though not necessarily within the state. 

Projects over eight hours must score an 8 or higher on NYSERDA’s “technology readiness level” scoring system, indicating that demonstration-scale projects or technologies near commercialization are eligible to apply. They also must submit a plan that includes a “reasonable pathway” to securing an interconnection agreement. 

NYSERDA will compensate project owners with Index Storage Credits, each representing 1 MWh of energy storage capacity that is operational and available to discharge. Projects will be credited and compensated based on the operational capacity they achieve each month over the course of 15- to 25-year contracts. 

No ISCs will be paid out for a project until it is permitted, installed and operating. The projects also must pass a peer review process and quality assurance inspections.  

NYSERDA-supported energy storage projects will be contractually obligated to meet new safety codes adopted recently into the Uniform Code by the State Fire Prevention and Building Code Council. The codes do not go into effect until next year, but NYSERDA already has adopted them into all of its storage programs. Each project also must submit a safety and security plan. 

“Battery energy storage is key to keeping New York’s electrical grid reliable, storing power for when it’s needed most, especially during peak demand and extreme weather,” New York City Fire Department Commissioner Thomas Von Essen and other former fire officials said in a press release released the same day as Hochul’s announcement. “With proper oversight, clear protocols and continued training for emergency responders, battery energy storage can and should be safely integrated into our communities.” 

The state seeks a minimum of 35% of the procured capacity to be deployed in New York City, its upstate suburbs and Long Island, with 30% in the city. 

Developers have the option to submit an analysis of whether their projects will provide “electricity system value”: how they impact the grid in terms of current reliability, future reliability, renewable integration, renewable curtailment and peaker plant displacement.  

Project developers also need to conduct an analysis of their sites for flood risk, sea-level rise and extreme weather. If a climate risk is identified, the developer needs to address reliability and performance in the face of climate hazards. 

“Today’s action is another example of New York’s ongoing commitment to strengthening our grid, ensuring the state continues to have a more affordable and reliable electricity system now and well into the future,” Hochul said. 

“Energy storage will provide many benefits to a modern power grid, including the ability to fully harness our most cost-effective energy solutions in wind and solar,” Alliance for Clean Energy New York Executive Director Marguerite Wells said in a statement. “We thank Gov. Hochul for putting ratepayers first by prioritizing this safe and important technology.” 

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ERCOT Adds Industry Vet to Board of Directors

ERCOT said July 28 that its Board Selection Committee has tabbed industry veteran Bill Mohl to fill one of three independent director vacancies. 

Mohl has 40 years of energy industry and risk management experience in electric and gas utilities, commodity trading, merchant generation, wholesale markets, electric power service companies and gas processing operations in public and private companies. He retired after 15 years with Entergy in 2017, having helped wind down the company’s ownership of merchant nuclear plants.  

Mohl also has spent time at Xcel Energy’s Public Service Company of Colorado. He currently is executive chairman of Shermco Industries, an electrical testing organization, and president of WMM Enterprises. 

He holds a master’s degree in business administration and a bachelor’s degree in science from Regis University in Denver. Mohl also completed a nuclear operations board of directors course from Goizueta Director’s Institute at Emory University. 

Bill Mohl | Analysis Group

“As the electric grid evolves to meet rapid growth and change, Bill’s extensive expertise and leadership in the energy sector will support ERCOT’s commitment to delivering industry-leading grid reliability and fostering efficient market operations,” Board Chair Bill Flores said in a statement. 

Two independent director vacancies remain after the recent resignations of Alex Hernandez and Sig Cornelius to pursue “new opportunities” in the ERCOT market. (See “Board Loses 2 More Directors,” ERCOT Board of Directors Briefs: June 23-24, 2025.) 

The 12-person board, with eight independent directors, governs ERCOT and is subject to oversight by the Public Utility Commission and the Texas Legislature. By law, all board members must be Texas residents. 

The board’s selection committee was created by state law in 2021. It is composed of three members appointed by the governor, lieutenant governor or the speaker of the Texas House of Representatives. 

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Opponents Take DOE to Court over J.H. Campbell Retirement Delay

The fight over the U.S. Department of Energy’s order requiring Consumer Energy’s J.H. Campbell power plant to keep running past its planned retirement in May is in the courts now that opponents have filed lawsuits. 

Michigan Attorney General Dana Nessel and nine organizations, including Earthjustice and Sierra Club, filed separate lawsuits July 24 at the D.C. Circuit Court of Appeals after DOE failed to respond to rehearing requests filed at the agency. (See Order to Keep Campbell Plant Running Challenged at DOE and FERC.) 

“This unprecedented order by the Department of Energy declares an emergency without evidence, completely ignores state and federal regulators that approved the plant’s retirement, and will potentially put enormous costs onto utility customers who receive no real benefit,” Nessel said in a statement. “I will continue to fight to protect Michigan customers from unreasonable costs imposed by the federal government.”  

The retirement of the plant has been planned for years, first proposed by Consumers in 2021 and approved by the Michigan Public Service Commission in 2022. The utility had procured replacement capacity and expected its closure would save consumers nearly $600 million, the attorney general said. 

“The Trump administration’s extension of the J.H. Campbell plant has already harmed local Michigan communities and now could raise energy costs for millions of Americans across the Midwest,” Sierra Club Senior Attorney Greg Wannier said in a statement. “We are more than halfway through the so-called ‘energy emergency’ the administration invented to justify its unlawful order, and as expected, the grid has not needed Campbell around to provide reliable power, even during last month’s extreme heat.” 

The filings are preliminary and ask the court to open a case on the issue, with more substantive briefs coming after that happens. 

The petition from Nessel argues that the case is another example of the Trump administration declaring a false emergency as a pretext for advancing its policy agenda outside the means of its normal authority. DOE’s initial order will continue to run through August, but Nessel said it could be extended. 

In the past, DOE has used its authority to keep plants running under the Federal Power Act’s Section 202(c) only when it received a request from the utility running the plant or a local governmental body. Those past orders also were in response to concrete emergencies and subject to limits, so they kept the plants running no longer than needed to address the situation, Nessel’s petition argued. 

“It was the reasoned judgment of the utility, state regulators, the Michigan AG and a wide array of ratepayer and environmental interests in Michigan that this old jalopy of a power plant should be retired,” Earthjustice attorney Shannon Fisk said in a statement. “While the administration might not like that fact, a fabricated energy emergency does not give them the authority to saddle Michiganders with the costs and pollution of a coal plant that the utility has already replaced with other resources. The only energy emergency is the one being created by this unprecedented power grab by federal authorities.” 

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Around the Corner: Insufficient Data Center Load Forecasting Likely a Big Part of PJM’s Problem

Mid-Atlantic grid operator PJM has had a rough couple of weeks. On July 16, it received an open letter penned by nine bipartisan governors of the 13-state region it serves, citing a “crisis of confidence from market participants, consumers and the states.” Admonishing PJM for its “multiyear inability to efficiently connect new resources to its grid and engage in long-term transmission planning,” the governors called for fundamental changes and new leadership.

From Bad to Worse: The July Capacity Auction. That was bad enough. But then things got worse, with the release of record high results from the Base Residual Auction for capacity addressing the 2026/27 delivery year.

Last year’s auction results already had caused an uproar, as the clearing price for most of PJM was set at $269.92/MW-day, up dramatically from $28.92/MW-day the prior year. Baltimore Gas and Electric and Dominion fared even worse, at $466.35/MW-day and $444.26/MW-day. Total costs paid for capacity by all energy consumers soared from $2.2 billion to $14.7 billion in just one year.

 

Comparison of BRA clearing prices by delivery year by LDA | PJM

In response and in an attempt to limit future costs to customers, Pennsylvania Gov. Josh Shapiro (D) negotiated a floor and cap with PJM — eventually blessed by FERC — that would create a price band between $177.24/MW-day and $329.17/MW-day for the following two delivery years. (See FERC Approves PJM-Pa. Agreement on Capacity Price Cap, Floor.)

Many feared the July 2025 auction would hit the new cap, and it did just that, pegging out in all delivery zones at the same price (good news only for BG&E and Dominion) of $329.17/MW-day. Total estimated cost to load increased as well, from $14.7 billion to $16.1 billion. (See PJM Capacity Prices Hit $329/MW-day Price Cap.)

 

Comparison of BRA clearing prices by delivery year by LDA | PJM

Without the cap, it could have been worse. PJM noted in its BRA report that an uncapped simulated auction likely would have cleared at over $388/MW-day. Capacity prices now may be costing customers up to 25% or more of their total bill, raising the questions, “How did we get here?” and “What does this imply for future energy costs?”

The answers to those questions are not simple (though some politicians will try to paint them that way), but they generally come down to the balance between expected supply and forecasted demand.

Supply: An Increasingly Bleak Scenario. Among major issues affecting supply, in 2024 PJM revised the way it accredited generation resources for their ability to provide capacity during critical peak periods. Nearly every type of resource in PJM’s portfolio took a significant hit.

For example, every nameplate MW of gas combined-cycle capacity was reduced from 96% to 79%, while that for simple-cycle peakers fell from 90% to 62%. Solar and storage capacity contributions also were revised downward considerably, and even nuclear and coal units were de-rated (from 99% to 95% and from 88% to 75%, respectively). Meanwhile, little additional capacity has been added to the grid recently, with much of that from renewables. Add to that the retirement of several coal units, and dispatchable supply capacity has not kept pace with demand.

Cleared MWs (UCAP) by new generation/uprates/imports by delivery year | PJM

Forecasted Rapid Demand Growth: An Unexpected Surprise. The perfect recipe for creating more pricing pressure when supply is limited is to add large amounts of potential new demand, and the addition of data center load does just that. These facilities are large (often well over 100 MW), disconnected from the general macroeconomic environment, and extraordinarily difficult to forecast, especially when the majority of current interconnection requests to utilities may never actually be served with power. Existing and forecasted data center load clearly had the potential for a significant impact on the past two auction results. The question is, how much?

In fact, it likely may have resulted in billions of dollars of unnecessary costs to consumers. PJM’s Independent Market Monitor (IMM) ran alternative scenarios earlier this year to evaluate this issue and concluded, “data center load growth is the primary reason for recent and expected capacity market conditions, including total forecast load growth, the tight supply and demand balance, and high prices.”

The IMM attributed $9.3 billion of the $14.7 billion from last year’s auction to data centers, noting, “the inclusion of forecasted data center load increased total revenues by $7,742,157 or 115 percent.” (emphasis added). The IMM further commented, “the role of data center load does not mean that PJM would not have eventually reached a point where supply and demand were tight, but that trajectory was relatively slow and would have resulted in more time to permit market reactions to address the balance of supply and demand.”

Phantom loads and poor forecasting are likely to create a political firestorm. What the IMM report implies is that if that forecasted future data load is incorrect, then everybody else ends up paying for a mirage that does not exist. That leads immediately to the more obvious multibillion-dollar question: “How accurate is PJM at forecasting data center loads?”

An analysis of how PJM arrives at its forecast is not very comforting. The grid operator arrives at its number by taking very imprecise utility forecasts that are based on interconnection requests from data center developers and speculators who buy land and place interconnection requests with the eventual goal of selling the projects.

Both types of entities place multiple applications with utilities in multiple states. Their behavior is similar to that of generation asset developers prior to FERC Order 2023 (which required them to put more financial skin in the game, with required deposits and penalties for withdrawing from interconnection queues).

Many developers placed multiple chips on the board, knowing that if one project succeeded, they eventually would withdraw the others. This resulted in highly inflationary supply numbers. In fact, Lawrence Berkeley Laboratory’s 2024 analysis of interconnection delays reported that for supply assets seeking interconnection between 2000 and 2018, only 19% actually flowed power by the end of 2023.

The data center dynamic is similar enough that some lawmakers and regulators are catching on. For example, recently passed Texas legislation SB 6 requires developers of large loads to disclose whether they are seeking similar requests for service elsewhere in Texas (note, that’s only in Texas).

It’s difficult to say how much inflated load actually exists, but one report characterizes this approach of developing multiple requests as a “low barrier, low cost, low risk strategy” employed by developers to access power wherever they can get it. That report also quoted a former Google senior director as saying the numbers could result in “five to 10 times more interconnection requests than data centers actually being built.”

Despite this inflationary dynamic, PJM’s 2025 large load forecast only minimally reduced the numbers supplied to it by the utilities in its service territory. While the problem already shows up in the capacity auctions for 2025/26 and 2026/27, this lack of rigor gets worse in the out years when projected data center growth skyrockets.

Not surprisingly, some consumers are worried, especially the more sophisticated and large users with the most to lose. A May 30 open letter to FERC from a number of large industrial groups urges the commission to “initiate an independent examination of current load forecasting practices and potential improvements to those practices.” That letter cites “the uncertainty and lack of transparency surrounding current load forecasting practices across the country,” and the impact it can have on costs.

What’s Next? The latest auction signals tough sledding for consumers, with little end in sight. Given the magnitude of the costs related to potentially inaccurate demand forecasts, combined with the red-hot politics surrounding the global race to dominate artificial intelligence, it’s not hard to imagine PJM’s capacity auction results becoming intensely and increasingly politicized.

The action to address this issue is to employ far more rigor in the forecasting process at the utility level (while ensuring that each utility uses similar processes) and employ a higher level of rigor within PJM’s forecasting approach. The second is to do everything possible to accelerate deployment of new capacity in the system.

However, with the next auction less than six months away, don’t expect the cavalry to arrive anytime soon. They haven’t even saddled up their horses.

Around the Corner columnist Peter Kelly-Detwiler of NorthBridge Energy Partners is an industry expert in the complex interaction between power markets and evolving technologies on both sides of the meter.

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Equinor Takes $1B Impairment on U.S. Offshore Wind

Equinor is taking a nearly $1 billion impairment on its U.S. offshore wind development efforts and is blaming the Trump administration’s anti-wind power crusade for the impact.

A federal stop-work order on the Empire Wind 1 project cost Equinor millions, but that is not the only factor in the impairment, nor even the largest.

The company began building an offshore wind hub in New York City in 2024 to serve Empire Wind 1, the future Empire Wind 2 and other developers’ operations in the New York Bight. The assumption was that the over-$850 million price tag would be amortized across multiple future offshore wind projects, yielding cost-saving synergies in the process.

Now, Equinor said, there may not be any future projects.

This, combined with rising tariffs, the shelving of Empire Wind 2 and the delays on Empire Wind 1, led to a $955 million impairment announced July 23 as part of the second-quarter financials for the Norwegian oil and gas producer.

“The main driver for this is the changes in regulations for future offshore wind projects in the U.S.,” Chief Financial Officer Torgrim Reitan said during a conference call with analysts.

“Part of the impairment is related to the undeveloped Phase 2 of Empire Wind. However, the largest portion is related to the South Brooklyn Marine Terminal. The development of the terminal assumed future projects that would use it. This is now unlikely with the current framework conditions, and this new reality is reflected in the updated book value for Empire Wind 1 and the South Brooklyn Marine Terminal.”

The new U.S. policy framework will lead to a lower lifetime rate of return on Empire Wind 1, Reitan said, but continuing with construction was determined to be the best way to protect shareholders.

Even with the U.S. losses factored in, the company still expects a double-digit return on its offshore wind portfolio as a whole, he added.

Equinor was formed in 1972 as Statoil, a state-owned oil company. Norway still owns a majority stake in the company, which in 2018 was renamed Equinor.

It still is a major fossil fuel producer, with $104 billion in 2024 revenue from operations in more than 20 countries, including the United States. In the first half of 2025, it reported $2.2 billion in revenue and $694 million in net income on its U.S. exploration and production activity.

However, Equinor has set a goal of being a leader in the clean energy transition and becoming a net-zero company by 2050. One of the ways it plans on doing this is by leveraging its offshore fossil fuel expertise to become a global offshore wind developer.

It has had varying degrees of success with that.

In the United States, it holds seabed leases off the New York, Delaware and California coasts, each with about 2 GW of wind power potential.

Nothing is likely to be built in the Delaware and California lease areas any time soon.

But Empire 1 and 2 were early movers. They won offtake contracts from New York in 2019 and 2022 and obtained full federal approval in early 2024.

In early 2024, Equinor placed Empire 2 on hiatus due to market conditions. But it pressed ahead with Empire 1, making the final investment decision on the $7 billion project just weeks before Trump returned to office. Subsequent events have shown offshore wind developers were justified in their worries about Trump 2.0.

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CPUC OKs New PG&E Rule to Speed Tx Connections for AI Data Centers, Others

The California Public Utilities Commission (CPUC) on July 24 partially approved a new rule that will make it easier for artificial intelligence data centers and other large customers such as EV charging stations to complete transmission connection projects in Pacific Gas and Electric’s territory.

PG&E in November 2024 applied to the CPUC for approval of the new retail tariff, Electric Rule 30, saying it had received 40 transmission connection applications since 2023. These new applications have increased PG&E’s retail customer transmission interconnection demand by more than 3,000%, utility representatives said.

“Given the unprecedented number of pending transmission-level service connection applications received between 2023 and 2024 that are awaiting negotiations with PG&E for retail service at transmission-level interconnection, it is reasonable to consider an interim implementation of Electric Rule 30,” the CPUC said in its decision, which temporarily approves the rule for transmission customers willing to foot the costs for needed upgrades ahead of a final decision by the agency (24-11-007).

The rule will allow transmission customers who provide advance payments and voluntarily commit to prefunding up to 100% of their needed network upgrades to bypass previously required procedures, speeding up their interconnection times.

In its application to the CPUC, PG&E contended that, without the new tariff, it must engage in lengthy one-on-one negotiations with those customers, often leading to “non-typical/exceptional” case filings that require the time and resources of the utility, the customer, the commission and other stakeholders.

The CPUC historically has required PG&E to complete an advice letter and case filing process for large transmission connection projects.

PG&E said the new rule would eliminate those negotiations, standardize the process and provide faster service for large load customers, while providing rate benefits and lower monthly bills for existing customers.

“This decision allows for interim implementation [of Electric Rule 30] for transmission-level customers who provide advance or actual cost payments and voluntarily prefund up to 100% of specific transmission network upgrades,” CPUC Administrative Law Judge Manisha Lakhanpal said in a June proposed decision recommending the agency approve the rule. “The decision requires new transmission-level customers seeking retail services to be responsible for the initial costs of all transmission facilities, rather than those costs being borne by ratepayers.”

The new rule applies to large transmission customers sized 50-230 kV and the following types of transmission facilities:

    • Type 1: Transmission Service Facilities
    • Type 2: Transmission Interconnection Upgrades
    • Type 3: Transmission Interconnection Network Upgrades
    • Type 4: Transmission Network Upgrades

Eligible transmission customers must provide advances and cost payments for Type 1-3 facilities and a 100% pre-funded loan for Type 4 facilities, the decision says.

The decision deferred PG&E’s request for refunds on Type 1-3 facilities; repayment of pre-funded loans and interest provisions; and repayment of loans for Type 4 facilities. A decision on these matters will be included in the CPUC’s final decision.

PG&E had said if the CPUC denied its application, pending connection applications regarding service requests would not be directly affected.

Cal Advocates, The Utility Reform Network (TURN) and the Joint Community Choice Aggregation group opposed the decision, saying PG&E’s proposal is “unjustified, premature and rushes the procedure without fully evaluating the impact on ratepayers.”

PG&E shareholders, rather than ratepayers, should be responsible for Electric Rule 30 costs because PG&E has not substantiated prospective benefits, Cal Advocates, a public agency, said about the decision.

TURN said the massive size of the data center load “increases the likelihood of causing or accelerating the need for expensive transmission system upgrades, which would be recovered primarily from other customers under PG&E’s proposal.” About 70% of the transmission-level service connection applications are data center load, the decision says.

The CPUC rebuffed the consumer groups’ concerns but agreed the cost implications of the new Electric Rule 30 are unknown.

Robert Mullin contributed to this article.

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IESO Seeks to Fill Growing Regulation Needs

IESO will seek to fill its growing need for regulation services through competitive bids but will resort to bilateral procurements if there is insufficient interest, officials told stakeholders July 24.

IESO’s most recent Annual Planning Outlook found the ISO will need 30 MW of additional regulation as soon as next year — with needs growing to 100 MW by 2029 — as a result of expected increases in industrial loads such as electric arc furnaces.

Regulation is one of several capabilities IESO uses to keep its supply and demand in balance, including inertial response, the stored kinetic energy of rotating equipment tapped immediately following a system event; primary frequency response, the automatic adjustment of energy output by generators within seconds of an event; and operating reserves, which the ISO calls on within 10 minutes or 30 minutes of an event.

Regulation resources respond to IESO instructions within five minutes of an event, after primary frequency response and before operating reserves.

Requirements

Generators providing regulation must be dispatchable, able to follow automatic generation control signals every two seconds or less and have an energy ramp rate of at least 50% of the offered regulation capacity per minute. A resource offering 20 MW of regulation, for example, would be required to move at least 10 MW/minute to reach its setpoint. IESO proposes a minimum regulation capacity of ±10 MW.

The ISO is seeking regulation only from facilities located south of Hanmer because severe weather in the Northwest zone and transmission congestion in the Northeast can restrict generation.

The ISO is only seeking regulation from facilities located south of Hanmer because severe weather in the Northwest zone and transmission congestion in the Northeast can restrict generation. | IESO

Storage currently is not eligible to provide regulation, but the capability will be added in future market rules under IESO’s Enabling Resources Program, the ISO said. (See IESO Seeks Feedback on Revised Storage Model.)

In addition, IESO’s dispatch scheduling software is unable to simultaneously schedule operating reserve (OR) from a resource providing regulation. As a result, resources providing regulation will receive real-time OR lost opportunity costs to make them whole for the OR revenue they would have received.

Because regulation is a reliability service, IESO does not need a government directive to procure it. The ISO could enter bilateral negotiations with facilities meeting technical requirements, or seek competitive bids, said Natalia Perdomo, an adviser in IESO’s market and system adequacy team.

“The ISO’s preference is a competitive procurement, as we believe it can provide better value for the ratepayer,” she said. “However, if there isn’t enough interest, the ISO can engage in bilateral negotiations.”

Next Steps

The ISO asked for written feedback by Aug. 8 via engagement@ieso.ca. It expects to decide on its procurement mechanism in the fourth quarter.

“If we do an RFP, the hope is that it would commence in 2026,” IESO’s Dina Shoukri said in response to a question about the timing and duration of the procurement.

“[The] duration of the contract, that is something we would have to determine,” she added. “A lot of the answers to those questions are going to be informed by the feedback we get. So, once we understand availability, readiness to deliver, how much is out there, it will help to inform the answers to those questions.”

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IESO Sees Improved ‘Trust’ Ratings in Survey

IESO is gaining ground in its “trust” ratings, ISO officials say.

The ISO’s 2024 stakeholder and community engagement survey saw “across the board improvement” over 2023, Marko Cirovic, director of sector engagement, told the Strategic Advisory Committee at its July 16 meeting.

“Every key metric in the survey improved versus the previous year,” Cirovic said. “Notably, 82% of stakeholders and communities said that our engagements met or exceeded expectations. This is a 6% increase from last year. This is not only the highest score in six years, but it is also the largest year-over-year gain since we started tracking this measure. And this really tells me one thing: Our efforts to listen, to learn and to collaborate are resonating across the sector.”

IESO solicited responses from individuals who participated in engagements and conferences such as the First Nations Energy Symposium, along with those who worked on initiatives such as procurements and system planning. Respondents included distribution and transmission companies, generators and storage facilities, large consumers, municipal officials and Indigenous communities.

IESO described the results in a memo and appendix but declined RTO Insider’s request to release the full survey results.

Among those attending the Strategic Advisory Committee meeting July 16 in Toronto were Marko Cirovic, IESO director of sector engagement (top left); IESO Board Member David Collie (bottom left) and Carla Nell, IESO executive VP of corporate relations, engagement and strategy (lower right). | IESO

The only negative cited in the ISO’s presentation of survey results: “Confidence in the IESO slightly decreased this year, with about one-quarter (26%) of respondents indicating that they would speak highly of the organization in comparison to one-third (34%) in 2023.”

The ISO noted that the 2024 question was updated from six answer options to four.

10-Point Scale

Some questions, including those measuring the trust respondents have in the ISO’s ability to deliver on its three core strategies, used a 10-point rating scale, with 1 being very negative and 10 being most positive.

Asked “how much do you trust the IESO” to “drive and guide the sector,” 73% ranked the ISO between 6 and 10, up 10 percentage points from 2023.

The ISO also reported gains in trust for “ensuring system reliability while supporting cost-effectiveness,” with 78% giving “top 5” ratings, up from 70%, and 65% giving top 5 ratings for trust in the ISO’s ability to “drive business transformation,” up from 55% in 2023.

Shifting Priorities

Cirovic said the survey also indicated a shift in respondents’ priorities.

“In 2023, sustainability was top of mind. In 2024, the focus has moved to future planning [cited by 51% of respondents], to affordability [also cited by 51% of respondents] and to reliability [cited by 46%],” Cirovic said. “This signals a growing emphasis on long-term resilience and growth.”

Sustainability/clean energy ranked as the third most pressing issue in 2023, following planning/design for the future and cost/price/affordability, respectively.

Factors Influencing Trust

The ISO said the five factors with the greatest influence on respondents’ trust in the IESO are: (1) transparency/information sharing; (2) long-term planning; (3) a track record of performance delivering reliable, affordable, sustainable electricity; (4) knowledgeable staff; and (5) communication and listening.

“There was also a positive correlation between the number of interactions with the IESO and respondents’ trust in the organization,” Cirovic said.

Almost nine in 10 respondents (89%) engaged with the IESO over the past year: 39% had between five and 25 interactions; 36% engaged fewer than five times; and 14% more than 25 times.

What’s Next?

The 2025 engagement survey will open in August. Respondents can opt in at engagement@ieso.ca.

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BPA Customers to See Increased Power, Transmission Rates

Bonneville Power Administration customers’ power rates will increase by about 8 to 9% over the next three years, while transmission rates will jump by an average of nearly 20%, the agency said July 24.  

The agency published the rates in its final record of decision (ROD) for the BP-26 rate period covering the 2026/28 interval, which BPA says will be a one-time deviation from its typical two-year interval for rate-setting. 

“Lower than initially anticipated, the final rates for fiscal years 2026, 2027 and 2028 follow more than a decade of holding increases at or below the rate of inflation — an accomplishment that stands out among the rising rates of regional utilities during the same period,” the agency said in a statement announcing the decision. 

“We appreciate the incredible collaboration with our ratepayers across an array of power-, transmission- and tariff-related matters,” BPA Administrator John Hairston said in the statement. “We’ve developed a bedrock of support for the programs, projects and initiatives we’re implementing as Bonneville continues to meet the power and transmission needs of our utility customers, and to provide reliable, affordable and safe electricity to Northwest communities.” 

BPA’s power rate schedule consists of multiple categories of primary rates for federal energy sales, which include the: 

    • Priority Firm power rate, or “Tier 1,” which applies to firm power sales to BPA’s public body, cooperative and federal agency customers; 
    • Industrial Firm power rate, which is applicable to firm power sales to direct service industrial customers; and 
    • New Resource Firm power rate, which applies to firm sales to investor-owned utilities and public customers serving new large loads. 

Tier 1 “non-slice” contracts represent most of BPA’s power sales. “Non-slice” refers to a type of contract in which the customer is guaranteed a specified volume of energy regardless of conditions on the hydro system; in contrast, total volumes delivered to “slice” customers can vary based on availability.   

In its statement, BPA said the “average effective increase” for Priority Firm Tier 1 power rate will be 8.9%, compared with an initial proposed increase of 9.8%, while transmission rates will increase by an average of 19.9%. 

An appendix in the ROD provides greater detail, saying BPA staff will work to deliver a Tier 1 “non-slice” effective power rate no higher than $38.59/MWh, representing an increase of about 8.3% above current rates.  

For other categories, the appendix says, BPA “commits to produce rates no higher than $0.5/MWh above” the “indicative rates” of $37.96/MWh for Priority Firm Tier 1, $45.92/MWh for Industrial Firm and $111.99/MWh for New Resource Firm.    

“These rates will also enable the advancement of critical initiatives to meet our customers’ needs and support national priorities for more abundant, reliable and secure energy,” Hairston said in a preface to the final decision. “From implementing new long-term power sales contracts to pursuing day-ahead market participation and advancing major power and transmission investments, the work we accomplish over the next three years will be critical to the long-term success of BPA, our customers and the region we serve.”