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December 6, 2025

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FERC Approves SPP’s New Provisional Load Process

FERC has approved SPP’s tariff change to offer a provisional load interconnection process so the grid operator can study potential data centers and other large loads when there isn’t available power for the new facilities.

In an order issued Oct. 10, the commission accepted SPP’s proposal and directed the RTO to submit a compliance filing within 30 days. The order is effective retroactive to Aug. 4 (ER25-2430).

FERC said the new study process to evaluate requests for new loads when a transmission customer lacks sufficient existing “designated resources” to cover its 10-year load forecast (Attachment AX) will ease efforts to “appropriately and more expeditiously plan to serve their future loads.”

The tariff change will also allow the RTO to identify and address the effects of load additions by finding the resulting network upgrades on its system before sufficient designated resources are available, the commission found. It said the proposed pro forma provisional load process agreements for customers seeking network integration and point-to-point transmission services will provide just and reasonable terms and conditions for how SPP will study new load requests under the provisional load process.

SPP filed its proposed revision in June, saying that because it was seeing increased requests for new loads from data centers and industrial facilities, many transmission customers have been “unable to demonstrate sufficient existing” resources to serve their 10-year forecasts. It said Attachment AX will mimic Attachment AQ, the grid operator’s standard study process, except that it will consider a customer’s planned generation and its existing designated resources.

The RTO said the provisional load process captures the expected reliability effects of planned generation on the grid and will help the transmission customer plan for serving its future load.

Upgrade costs to interconnect new load will be assigned to the customer until planned generation is included in the transmission service agreement. Remaining upgrade costs will be rolled into regional rates.

The grid operator told FERC it has received just over 26 GW of interconnection requests larger than 100 MW since 2020. Data centers account for about 9 GW of those loads, the RTO said.

SPP stakeholders approved the provisional load process in April. It was later approved by the RTO’s state regulators and its board. (See “‘Chicken & Egg’ Issue,” New ERAS for SPP: Stakeholders Approve RA Studies.)

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Battery Developers Seek Relief on IESO Ramp Limits

Storage developers in Ontario are pushing back on IESO’s 100-MW/minute ramp limit for batteries, saying it will reduce their revenues.

IESO said the limit is needed to allow it to meet NERC standards requiring balancing authorities to keep system frequency at 60 Hz.

“IESO has experienced negative impacts to system frequency resulting from the fast-moving capabilities of BESS [battery energy storage systems],” the grid operator said in a presentation Oct. 16 on its Storage and Co-located Hybrid Integration Project, which will introduce a single bidirectional resource model for BESS.

The initiative, part of the ISO’s Enabling Resources Program (ERP), initially will focus on electricity storage and hybrid generation-storage resources. It will replace the current two-resource model — which separates the withdrawal portion of the resource as load and the injection portion as a generator — with a single continuous offer curve. The current model creates operational challenges and reduces market efficiency, according to the ISO.

IESO plans to continue using its current 100-MW/minute up and down limit per facility under the new model.

3,000 MW of Storage Expected by 2028

The ISO noted that it expects 25 BESS facilities to join the grid in the near term, with about 3,000 MW of contracted storage expected in service by 2028.

IESO relies on regulation services to compensate fast output changes from batteries, said Ihor Lopuch, a project adviser. “In some cases, ISO control room operators have had to take additional out-of-market control actions, such as constraining some resources or sending one-time dispatches to help rebalance the system,” he said.

Storage operators first raised objections to the static ramp rates following an engagement session July 24. (See IESO Seeks Feedback on Revised Storage Model.)

In the most recent session, Travis Lusney, director of power systems for Power Advisory, representing the Energy Storage Resources Consortium, led the opposition. The consortium’s 12 members include Capital Power, EDP Renewables, Brookfield Renewables and Northland Power.

Power Advisory’s Travis Lusney represents the Energy Storage Resources Consortium. | Power Advisory LLC

Lusney asked the ISO to determine the impact of increasing the ramp limit from 100 MW and whether there is an optimal limit that could maintain area control error while offsetting higher costs of regulation capacity. “Can it be 150, 200 [MW]?” he asked.

Lusney also asked for data on how often IESO will dispatch storage resources for operating reserves (OR) versus energy.

“The answer that I’ve gotten consistently is OR resources are … scheduled on the sideline to be there, but their dispatch instructions are only energy, and that there is no OR dispatch instruction,” Lusney said. “Part of that may have had to do with the previous market design, and that might be changed, but it’s not clear that there’s any historical information to understand how often an energy storage resource may receive an energy dispatch and be limited in that 100-MW/minute step up versus an OR dispatch that would allow them to ramp to their full capability.”

Lusney said battery operators face lost revenue because the limits negate the competitive advantage of their ramp speeds. “In a market design that encourages more price fidelity … this is quite restrictive on the competitive advantage of storage,” he said.

‘In Alignment’

IESO officials said the 100-MW limit is “in alignment” with other ISOs, including CAISO and SPP.

Tyler Chuddy, project superviser, said the ISO has limited analysis of batteries’ ramp impacts because it expects numerous BESS facilities to come online at the same time. “One hundred megawatts per minute means like a 500-MW shift in your production over one interval, which is pretty substantial,” Chuddy said.

Tyler Chuddy, supervisor of IESO’s Storage and Co-located Hybrid Integration Project | Tyler Chuddy

He asked Lusney to provide details on how the ramp restrictions would result in lost revenue for battery operators. Lusney agreed to provide some examples from the consortium.

The current phase of the project, which may run as long as through 2028, will seek to establish the single resource model and set rules on state-of-charge management. Phase 2 will consider ways to allow batteries to also offer frequency regulation, which the ISO uses to correct supply-demand imbalances.

Lusney urged the ISO to consider batteries as a potential solution to the ramping challenges.

“If it’s a regulation capacity challenge driven by the fast response of the energy storage, can energy storage provide some of that regulation capacity in its dispatch instruction?” he asked. “[I recognize that] it’s not part of the current engagement process, but it seems like they are interconnected.”

Next Steps

IESO is seeking written feedback to its proposed rules by Oct. 30 deadline at Engagement@ieso.ca. The next engagement session for the project is expected in the first quarter of 2026.

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NERC Standards Committee Passes Revised Proposals

In a busy meeting Oct. 15, members of NERC’s Standards Committee agreed to move forward with multiple high-priority standards development projects despite disagreements over details of the proposals from ERO staff.

First on the agenda was a standard authorization request (SAR) stemming from FERC Order 909, which in July approved new reliability standards establishing frequency and voltage ride-through requirements for inverter-based resources. (See FERC Approves IBR Ride-through Standards.)

PRC-029-1 (Frequency and voltage ride-through requirements for IBRs) permits owners of legacy IBRs — resources already in operation when the standard goes into effect — 12 months after the effective date of the standard to request an exemption to its ride-through requirements. FERC directed NERC to clarify within 12 months of Order 909:

    • acceptable evidence to demonstrate hardware limitations for legacy IBRs that would prevent them meeting the ride-through requirements; and
    • whether any additional exemptions should be made for HVDC-connected IBRs with choppers — used in offshore wind projects to protect converters during grid faults — and other IBRs with long lead times “between adopting IBR specifications and placing the IBR in service.”

A group of industry stakeholders developed the SAR and submitted it to FERC, NERC Director of Standards Development Jamie Calderon told attendees. Because the project originated from a FERC directive, the ERO has classified it as high priority. NERC asked the committee to authorize posting the SAR for a 30-day formal comment period and soliciting members of the drafting team for the project, which NERC has named Project 2025-05.

Asked by Claudine Fritz of Exelon whether NERC would reconstitute the drafting team for Project 2020-02 (Modifications to PRC-024 — generator ride-through), which developed PRC-029-1, to address Order 909, Calderon said while that team is no longer active, NERC has reached out to its former members to ask if any are interested in being involved.

Jamie Johnson of CAISO then asked if the comment period could be delayed until after a workshop on Order 909 that NERC is planning for Nov. 5. Johnson suggested this pause could “provide more insight for potential revision to the SAR.”

Calderon expressed concern that delaying the start of the project might leave the development team pressed for time. However, in light of the fact that the comment period is expected to start Oct. 29, she suggested extending its length to 45 days. She said this move would allow commenters to consider the issues discussed at the workshop before giving their feedback. Johnson moved to update the proposal with this extension, and committee members approved it unanimously.

Supply Chain, IBR Proposals Pass

Another FERC directive was next on the plate, as the SC took up a SAR addressing the commission’s order Sept. 18 that NERC develop standards addressing supply chain risk management (SCRM) plans by May 21, 2027. (See “Supply Chain Standards Due in 18 Months,” FERC Tackles Cybersecurity in Multiple Orders.)

The new standards must address the sufficiency of entities’ SCRM plans as they relate to identifying and responding to supply chain risks, as well as whether they apply to protected cyber assets (PCAs), defined as “one or more cyber assets connected using a routable protocol within or on an electronic security perimeter [ESP] that is not part of the highest-impact [grid] cyber system within the same” ESP.

NERC asked that attendees approve the SAR’s posting for a 30-day informal comment period and authorize soliciting drafting team members for 15 days. Members voted unanimously to accept a motion to do so.

Also approved without objection was a proposal to appoint the slate of members recommended by NERC for Project 2025-03 (Order 901 operational studies). This project addresses the fourth and final milestone of FERC Order 901 by establishing requirements for registered entities to perform “operational studies for registered IBRs, unregistered IBRs and [distributed IBRs] in the aggregate.”

However, a proposal to approve members for a project addressing Order 901’s requirement for planning studies met with concerns from committee members about the fact that it contained two candidates from the same company. Paul MacDonald, of the New Brunswick Energy and Utilities Board, said that while he was “typically very supportive” of NERC’s recommendations for drafting team composition, he would prefer to see one of the candidates — who were not identified by name during the meeting — removed from the list.

Conferring privately, NERC staff agreed to drop one of the candidates, after which MacDonald moved to approve the updated list. This motion passed unanimously.

The committee’s last standards action was to authorize drafting new or modified standards to allow PCAs, electronic access control or monitoring systems (EACMS) and physical access control systems (PACS) together in a single standard, a move intended to bring clarity to NERC’s enforcement process. SC members previously agreed to post the SAR for this project for a 30-day formal comment period; NERC Manager of Standards Development Alison Oswald said the SAR has been revised in accordance with the comments received through that process.

Finally, SC members voted to endorse NERC’s 2026-2028 Reliability Standards Development Plan (RSDP), which sets out “time frames and anticipated resources for each project under development or anticipated to begin” within the next three years. The RSDP will be presented to NERC’s Board of Trustees in December, and then to FERC for final approval.

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CEC Eyes Major Cuts to Light EV Charger Funding

The California Energy Commission projected significant funding cuts to a key electric vehicle charging program, despite the state setting a record for the number of EVs sold in a quarter.

CEC staff on Oct. 9 published a draft report of the investment plan for the CEC’s clean transportation program, in which forecast funding for EV charging infrastructure for light-duty vehicles dropped from $98.5 million in 2025/26 to $34.2 million in 2026/27. In 2027/28, the projected funding amount decreased slightly to $33.2 million.

But EV sales are going in the opposite direction: In Q3 of 2025, California sold about 125,000 EVs — the most recorded in a quarter in the state and about 29% of total vehicle sales in the quarter, Gov. Gavin Newsom (D) said in an Oct. 13 news release. The previous record occurred in Q3 2023 when about 27% of vehicles sales were EVs.

In February 2025, California had more than 178,500 public and shared-private Level 2 and DC fast-charging ports for light-duty vehicles.

The CEC told NetZero Insider that the decrease in light-duty EV charging funding is due to projected increased investment from the private sector, along with reduced future state budget allocations. If either of these scenarios changes, next year’s investment plan update could allocate funds differently, the CEC said.

As for medium- and heavy-duty charging infrastructure, CEC staff predicted an increase in funding from $15 million in 2025/26 to $44 million in 2026/27. About 5,800 medium- and heavy duty-vehicles were registered in the state at the end of 2024. Most of these vehicles were buses.

In total, California plans to have 1.5 million zero-emissions vehicles by 2025 and 5 million by 2030. As of June 2025, more than 61 percent of clean transportation program and supplemental funds have gone to projects in disadvantaged or low-income communities or both, the CEC said.

EV Data Collection Approved

Separately, at an Oct. 8 business meeting, the CEC approved new EV charging data-collection regulations, which require public EV charging port owners in California to submit data about charger usage semiannually. Required data includes a charger’s location, availability and pricing. The data may be shared with third parties.

California will become the first state to adopt EV charging reliability and reporting regulations, CEC Commissioner Nancy Skinner said at the Oct. 8 voting meeting.

“We are laying the foundation for EV charging station reliability across the nation,” Skinner said. “[EV charging] is so important for our consumers and so important to our meeting the goals of EV adoption, because if there is a sense of unreliability, then it’s going to be harder for people who haven’t yet gone to an EV to go there.”

Publicly available Level 2 chargers have a 96% reliability of working as designed, while DC fast chargers have a 91% reliability, Skinner said.

The data collection will give the CEC, for the first time, the ability to have a comprehensive inventory of the installed chargers in this state, Skinner said. The data includes all chargers not in a residence.

“Those of us who are EV drivers, we know that we commonly use different apps or websites to find a charger,” Skinner added. “Now, if the information is not widely shared, then that charger’s not going to show up, and we won’t know that it exists.”

The regulations, Skinner said, are “going to empower us to have that inventory and to get that more publicly accessible information. So, it’s just going to improve the overall EV driver experience in California.”

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VPPs Suffer Setbacks in Calif. Legislative Session

The 2025 California legislative session ended in disappointment for virtual power plant proponents, as Gov. Gavin Newsom vetoed several VPP-related bills and lawmakers didn’t approve new funding for an existing program.

Assembly Bill 740, AB 44 and Senate Bill 541 were vetoed before the governor’s Oct. 13 bill-signing deadline. Bills sent to Newsom that aren’t signed or vetoed become law without the governor’s signature.

Edson Perez, California lead at Advanced Energy United, called the vetoes of the VPP bills “missed opportunities to save billions in energy costs by leveraging technologies all around us in our homes, garages and on our roofs.”

“This policy whiplash undermines confidence across the sector, discourages the deployment of cost-saving technologies and drives away investments,” Perez said in a statement.

Virtual power plants are collections of distributed energy resources, such as solar panels, batteries, electric vehicles or smart devices, that can be called upon to boost the grid when needed.

AB 740 would have directed the California Energy Commission to work with CAISO and the California Public Utilities Commission to explore how virtual power plants could help meet statewide load shift goals and what opportunities are available for VPPs to qualify for resource adequacy. Perez said the bill aimed to make VPPs a core part of California’s energy portfolio rather than solely an emergency resource.

In vetoing the bill, Newsom cited budget constraints.

“While I support efforts to realize the potential of these energy resources and others, this bill results in costs to the CEC’s primary operating fund, which is currently facing an ongoing structural deficit, thereby exacerbating the fund’s structural imbalance,” Newsom said in his veto message.

Newsom also vetoed SB 541, which would have required the CEC to work with CAISO and the CPUC to analyze the cost effectiveness of certain load-shifting strategies, estimate each retail electricity supplier’s load-shifting potential, and report the amount of load shifting that each retail supplier achieved in the previous year.

Newsom called SB 541 “largely redundant and, in some cases, disruptive of existing and planned efforts” by the agencies to maximize the potential of load-management strategies.

AB 44, which the governor vetoed, would have directed the CEC to devise methodologies that load-serving entities could use to modify their demand forecasts in response to measures such as VPPs.

The governor said the bill does not align with the CPUC’s resource adequacy framework.

“As a result, the requirements of this bill would not improve electric grid reliability planning and could create uncertainty around energy resource planning and procurement processes,” Newsom said in his veto message.

Another disappointment for VPP advocates was lawmakers’ decision to not provide additional funding for the CEC’s demand side grid support (DSGS) program. As part of the program, battery owners agree to make their stored energy available to the grid during energy emergency alerts or when day-ahead prices go over $200/MWh. They then are compensated based on the power they shared with the grid. (See Budget Cuts Threaten Calif. VPP Program.)

In an Oct. 1 statement, the CEC said DSGS had about $64 million remaining. CEC expects to have enough money to pay out incentives from the 2025 program season and will look for ways to continue the program in 2026.

Advanced Energy United hopes the state will “course correct” on VPPs as soon as possible, Perez said, starting with more funding for DSGS in early 2026 to keep the program going.

Offshore Wind Funding

In contrast to the setbacks for VPP bills, lawmakers made progress on other energy-related issues.

As previously reported, the legislature passed and Newsom signed AB 825, known as the Pathways bill. The bill will allow CAISO to transition the governance of its markets to an independent “regional organization.” (See Newsom Signs Calif. Pathways Bill into Law.)

Newsom also signed SB 254, a law that will create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects. The legislation also establishes an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. (See Calif. Lawmakers Pass Bill to Accelerate Transmission Development.)

Offshore wind advocates were pleased that lawmakers passed and Newsom signed SB 105, a budget bill that includes $228.2 million for offshore wind. The funding is the first installment out of $475 million earmarked for offshore wind in Proposition 4, the $10 billion climate bond measure that California voters approved in 2024.

Of the $228.2 million in SB 105, the CEC has already distributed $42 million in grants to improve port facilities for floating offshore wind projects. (See CEC Approves 5 Offshore Wind Projects at California Ports.)

Offshore Wind California, an industry coalition, called the funding “another important proof point of California’s progress and commitment to move forward on offshore wind.”

“California is demonstrating its continued determination to be a clean energy leader, despite the federal headwinds we’re facing this year,” the group said in a statement.

Other legislation that Newsom signed includes a data center-related bill. SB 57 requires the CPUC to send a report to the legislature on the extent to which utility costs associated with new loads from data centers are shifted to other customers.

And SB 80, which Newsom signed, creates the Fusion Research and Development Innovation Initiative to distribute $5 million for fusion energy research and development. The goal is to deliver a fusion energy pilot project in the state by the 2040s.

Surplus Interconnection Bill Vetoed

Newsom vetoed other bills, including AB 1408, which would have required CAISO to consider surplus interconnection service in its long-term transmission planning. It also would have required utilities to evaluate and consider surplus interconnection options in their integrated resource plans. Proponents said unused interconnection capacity creates an opportunity to add renewable energy resources or battery storage at or near fossil plants.

In his veto message, Newsom pointed to the “highly technical structure of processes” used by the CEC, CPUC and CAISO for grid planning.

“This bill risks constraining energy resource procurement and interconnection options, likely increasing customer electric costs and undermining electric grid reliability,” he wrote.

A bill aimed at requiring more accountability from the CPUC didn’t even make it to Newsom’s desk. AB 13 also would have asked the governor and Senate to consider geographic diversity when selecting CPUC members to address a lack of Southern California representation. (See Calif. Lawmakers Seek More Accountability from CPUC.)

The bill died in committee.

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SPP Moving Forward with JTIQ Transmission Projects

LITTLE ROCK, Ark. — SPP says it plans to continue working the Joint Targeted Interconnection Queue’s portfolio of five 345-kV projects on its seam with MISO, despite the U.S. Department of Energy’s threat to pull $464 million in previously granted funds.

General Counsel Paul Suskie told stakeholders Oct. 14 that staff’s initial internal assessment has determined “nothing stops these projects from going forward.”

“They can proceed,” he said during a Markets and Operations Policy Committee meeting. “We are having communications with MISO to see if they’re in agreement with that. Staff’s current indication is these projects will still go forward if DOE funds are pulled for the grants.”

Suskie told MOPC that he called Minnesota Public Utilities Commissioner John Tuma, who confirmed that as of Oct. 13, DOE has not yet provided confirmation of the funding’s termination.

The funds were awarded in 2023 to the Minnesota Department of Commerce, the lead applicant in the JTIQ initiative that also involves the Great Plains Institute and the two RTOs. However, the department in early October included the $464 million grant under its Grid Resilience and Innovation Partnerships (GRIP) program on a list of projects that it intended to terminate. (See DOE Terminates $7.56B in Energy Grants for Projects in Blue States.)

POLITICO has reported that DOE has “clashed” with the White House over the administration’s desire to spare most grants so they can be used as bargaining chips with Congress and the states, explaining the lack of confirmation from the department.

“At this point, we don’t know [the grant’s status],” Suskie said. “We know the rumors, the press reports. That’s all we know at this point in time. Really, it’s a wait-and-see game.”

MISO has said it is monitoring the situation and that like SPP and Minnesota, it has yet to receive word of the grant’s termination. (See MISO Says JTIQ Tx Portfolio Stands — for Now.)

The GRIP funds would offset about 25% of the predicted $1.6 billion in capital costs for the JTIQ portfolio’s five projects.

FERC approved the RTOs’ request to allocate the portfolio’s costs 100% to interconnecting generation assessed on a per-megawatt basis. In doing so, it cited the GRIP funding as one of the “unique set of facts and circumstances of the proposed JTIQ framework.” (See FERC Upholds MISO and SPP’s JTIQ Cost Allocation over Criticism.)

“This potentially has not just impacts on the practicality of these lines,” the Advanced Power Alliance’s Steve Gaw said during the MOPC discussion. “I’m not seeing anything that others don’t see, but there are also potential legal implications from this equity impact.”

The portfolio’s projects are centered on the RTOs’ northern seam and have been framed as enabling 28 GW of primarily renewable generation. Each grid operator would have two projects in its footprint and share the fifth.

The SPP projects will be evaluated for system impacts first through its one-time expedited resource adequacy study process and then through the 2024 Integrated Transmission Planning cluster. Staff have targeted March 2026 to execute ERAS generator interconnection agreements.

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NYISO Again Identifies Reliability Need for NYC

New York City could be short as much as 650 MW in capacity in the summer of 2026, according to NYISO’s Short Term Assessment of Reliability (STAR) for the third quarter, issued Oct. 13.

The report, which assesses reliability over five years, also identified reliability needs in Long Island and the Lower Hudson Valley, though not until 2027 and 2030, respectively, and both are much less than the city’s.

The findings trigger a formal process by which the ISO will seek solutions including transmission, generation, energy efficiency or a combination of each. “NYISO will begin the process immediately by working with the local utilities and the marketplace to identify and evaluate possible solutions,” it said in a press release.

The shortfall is primarily driven by the impending retirements of the Gowanus and Narrows gas generators in the city, kept online by an ISO designation for reliability under New York state’s peaker rule. NYISO continues to say that several projects — including the Champlain Hudson Power Express HVDC transmission line and the Empire Wind offshore wind facility — would solve the city’s deficiency. But “until these system plans are completed and demonstrate their planned power capabilities to address the identified reliability needs, the previously identified … deficiencies would persist without Gowanus and Narrows,” according to the STAR.

NYISO used its press release to note the findings of its biennial Comprehensive Reliability Plan (CRP), even though it is still being finalized. (See NYISO Reliability Plan Calls for ‘New Dispatchable Generation’.)

“Taken together, these two reports show the grid is at a significant inflection point,” said Zach Smith, senior vice president of system and resource planning for NYISO. “Depending on future demand growth and generator requirements, the system may need several thousand megawatts of new dispatchable generation within the next 10 years.”

Gavin Donohue, president of the Independent Power Producers of New York, said residents should be alarmed by the findings.

“Electricity demand is continuing to drastically rise, and the state needs to look at all possible resources to safeguard strict reliability standards that millions of New Yorkers depend on,” Donohue said in a statement.

The STAR considers planned retirements, upgrades, forecast peak power demand and changes to the generation mix. Thirty-six gas turbines submitted retirement notices, including the 672-MW Gowanus and Narrows generators.

When the planned transmission and generation projects enter service and assuming all existing generators remain available, reserve margins would improve substantially, but the STAR notes that they would “gradually erode as forecasted demand for electricity grows.” As soon as 2029, the city would be once again deficient in the summer, by 68 MW for five hours.

“Even with the Champlain Hudson Power Express transmission project online, reliability margins will be breached in the near future due to lack of resources with the same capabilities coming onto the system to replace the planned peaker retirements,” Donohue said. “Increasing dispatchable generation must be prioritized so the state does not go dark.”

The ISO may extend the operation of Gowanus and Narrows until May 2029 under the peaker rule. They cannot continue operating beyond that date unless they meet state Department of Environmental Conservation emissions requirements.

Long Island could become deficient in summer 2027 by 39 to 116 MW because of the deactivations of the Pinelawn and Far Rockaway generators. Once Sunrise Wind is delivering power, the margins would improve in summer 2028 and again once the Propel NY Energy transmission project comes online in 2030.

NYISO said the Lower Hudson Valley reliability need is an exacerbation of the city’s and that solving the latter would solve the former.

But “the risk of deficiencies beyond the needs identified in this STAR is even greater when considering a range of plausible futures with combined risks, such as the statistical likelihood of further generator retirements or failures,” the ISO warned. “New York’s generation fleet is among the oldest in the country, and as these generators age, they are experiencing more frequent and longer outages.”

NYISO’s pronouncements echo those of its Reliability Needs Assessment just over a year ago. The ISO narrowly avoided issuing a formal reliability need then, but it made similar warnings of generator aging and retirements, and it also warned that the city’s reliability would depend on the Champlain Hudson project. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.)

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IESO Removes Credit Requirement for Transmission Registry

IESO has removed a credit rating requirement for prospective bidders to enroll in its Transmitter Selection Framework Registry (TSF-R), a prequalification mechanism for the ISO’s competitive procurement that is expected to begin in 2026.

Removing the requirement will ensure that all applicants are “assessed using consistent financial criteria,” IESO officials said in an engagement session Oct. 15.

“This allows us to evaluate organizations consistently through these early phases, but it’s expected that credit rating requirements will be expected and introduced as a requirement at the time of” the request for proposals, said Denise Zhong, IESO senior manager for resource adequacy and sector evolution.

IESO officials said the change was made in response to feedback after its stakeholder engagement in June. (See IESO Moving Forward with Competitive Tx Plans.) The TSF-R opened July 31.

“Concerns were raised around the current credit rating criteria within the TSF Registry that [they] may be too restrictive at this stage of the process, and it seemed that it was required for some but not all,” Zhong said.

Throughout their presentations, Zhong and her colleagues emphasized the importance of Indigenous participation and support for projects. They said since the June engagement, the ISO has continued talks with Building Ontario Fund (BOF) and Canada Infrastructure Bank (CIB) to develop ways to encourage Indigenous participation and provide loans to developers of TSF projects.

The BOF is administering the Indigenous Opportunities Financing Program (IOFP) — formerly the Aboriginal Loan Guarantee Program — which provides credit support to help Indigenous corporations attract lenders.

“The IOFP is not a loan or a grant program,” said Andrew Lee, IESO senior adviser for resource acquisition. “The IOFP is a form of credit support intended to enhance Indigenous corporations’ credit worthiness and attract lenders willing to provide a loan.”

Three loan guarantees totaling $327 million have been provided by the fund through September, Lee said, including most recently one for the Chatham-Lakeshore transmission line, a 49-km, double-circuit 230-kV line in southwestern Ontario.

IESO says initiating competition — a directive from the Minister of Energy and Mines’ Integrated Energy Plan (IEP) — will lower costs and produce innovation. The ISO is working with the ministry to identify the first transmission project to be opened to competition, with a focus on the South and Central Bulk Study, with recommendations scheduled for late 2025, and the North of Sudbury and Eastern Ontario bulk studies, both expected in early 2026.

But most of the 1,500 km of new transmission lines planned or under development will be awarded to incumbent transmitters.

‘Partial Contracting’ Model

The ISO announced in June that it had decided on a “COD+10” partial contracting model, in which the winning bidder will receive a contract covering all costs of financing, designing, building, operating and maintaining the line for the first 10 years of commercial operation.

Bidders will be asked to submit 10 annual revenue requirements (ARRs) for the initial 10 years of operation. In year 11, the contract will transition to traditional rate regulation under the Ontario Energy Board (OEB), which will review the prudency of ARRs going forward.

The model will include binding commitments for cost management, scheduling and Indigenous participation, officials said.

IESO also has been consulting with the OEB to develop the regulatory framework for the program, including exempting TSF-contracted transmission projects from “leave-to-construct” requirements.

IESO’s timeline for its TSF procurement | IESO

“One of the key recommendations coming out of the TSF is to remove the leave-to-construct requirement during project development phase for TSF projects,” Zhong said. “This change is intended to reduce timelines in the development phase, recognizing that, again, a procurement process overall will require additional time and careful execution.”

The ISO also has been meeting with transmitters, financiers, and engineering, procurement and construction firms to inform the design of the program.

Routing, Cost Containment

IESO said it will specify terminal connection points for projects but will not prescribe routes.

“In some cases, a corridor may have been identified and/or protected by the Ministry of Energy and Mines,” the ISO said. “Such a corridor will not preclude other route alignments as determined through field studies and/or community engagement.”

IESO said it is considering cost-containment provisions and ways to manage cost adjustments to balance “cost certainty and flexibility for legitimate changes.”

It asked stakeholders for feedback on whether it should set cost caps or allow developers to propose them.

To protect ratepayers, IESO said it will monitor developers’ performance and may reduce their payments if they fail to meet contractual benchmarks regarding availability (based on outages) and transfer capability.

“Unlike the rate regulated cost of service model where reasonable operational and maintenance costs are reimbursed to the transmitter, the IESO foresees a potential risk of underinvestment in maintenance and operation from transmitters as an approach to improving transmitter profit margins,” it said.

Feedback

Sonny McGinnis complained about difficulty communicating with the ISO. McGinnis, who was representing the Anishnaabeg of Naongashiing in northwestern Ontario, said he “tried calling after our sessions months ago. I could never line up with anyone. Nobody knew what the heck I was talking about. … It can’t be just lip service we’re getting.”

Stakeholders should provide written feedback on the TSF plan to engagement@ieso.ca by Nov. 5. IESO plans to share solicitation documents and contract term sheets in an engagement session in January.

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Sharper Load Growth in Utility Integrated Resource Plans

U.S. utilities continue to ratchet up load growth forecasts in their integrated resource plans.

As of September 2025, the IRPs are projecting demand will be 24% higher in 2035 than in 2023, RMI reported Oct. 15. This compares with 12% in December 2023 and 6% in January 2021.

The third-quarter “State of Utility Planning” report is the latest in a series by RMI and combines data from 130 IRPs. As RMI notes in its preface, IRPs are not a clear picture of the future, but they do provide a snapshot of trends, goals and strategies to meet those goals.

The third-quarter report is the first that reflects the impact of the One Big Beautiful Bill Act, with its phaseout of tax credits for wind and solar generation, which recently have been the largest source of new U.S. generation by nameplate capacity.

Other factors gaining prominence in the third quarter included delayed fossil retirements, uncertainty in planning, inability to bring new resources online quickly and difficulties in buying electricity from neighboring utilities.

Trends continuing from previous quarterly reports include changes in resource adequacy rules, particularly in MISO, as well as the expectation that new large loads will present demands that cannot easily be met.

These factors are set against a background of considerable uncertainty over factors such as resource costs, market rules, EPA regulations, other federal policies, frequency of extreme weather events, state policies and the load-growth forecasts themselves. The forecasts are demonstrably imprecise, and some observers maintain that top-end projections are unrealistically large.

Every IRP reviewed for RMI’s third-quarter report increased the load forecast over previous projections but also showed a wide range of uncertainty about the size of that increase. Both the quantity and hourly profiles of these new loads differ from historical trends.

The difficulty of resource planning amid all this is a common point of discussion for utilities, RMI said, along with the need to devise new ways to meet future needs.

RMI noted that since it began tracking IRPs, load projections have increased in all nine quarters and cumulative emissions projections have increased for seven consecutive quarters.

It also pointed out that emissions reductions are lagging in utility projections: The companies examined have targets of 63% emissions reductions by 2035 from a 2005 baseline, but their IRPs would lead to only a 53% reduction.

The IRPs include 259 GW of wind and solar additions through 2035, 103 GW of natural gas additions and 74 GW of coal retirements. This is 2.4% more wind and solar than was planned as of the end of 2023 but 106% more natural gas.

RMI acknowledged the challenges facing electric utilities as they try to balance regulations, costs for customers, profits for investors and climate impact.

But the clean energy advocacy nonprofit also said delayed fossil retirements and new gas generation are the default choice in most IRPs, which instead should incorporate alternatives such as energy efficiency, virtual power plants, grid enhancing technologies and clean repowering.

These alternatives — along with policy and regulatory support — would help utilities hold down costs as they transition to a zero-carbon future, RMI concludes.

The report combines historical data from RMI’s Utility Transition Hub with IRP data manually collected by EQ Research. The 130 IRPs reviewed would cover approximately 48% of U.S. electricity deliveries.

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LBNL Study Examines Drivers Behind Higher Power Prices in Some States

The Lawrence Berkeley National Laboratory released a paper recently examining why some states have seen retail power prices rise faster than inflation. The listed reasons include distribution investments, extreme weather and wildfire, natural gas prices and state renewable targets.

“Factors influencing recent trends in retail electricity prices in the United States” includes an article in The Electricity Journal. It found that states in the Northeast and on the West Coast saw some of the biggest price increases from 2019 to 2024 but noted the national averages were in line with inflation.

In nominal terms, prices rose 23% between 2019 and 2024. Controlling for inflation, they were flat outside of a bump in 2022 related to the Ukraine-Russia war’s effect on natural gas prices. The national average masks a big difference in state average prices that range from 8 cents/kWh in North Dakota to more than 27 cents/kWh in California.

“Examining recent trends in inflation-adjusted prices, 31 states saw real price declines from 2019 to 2024, while 17 states experienced increases,” the article said. “States on the West Coast and in the Northeast were most affected by rising prices — especially California, where average retail prices increased by 6.2 cents/kWh in real 2024 dollars.”

States with the greatest price decreases typically exhibited increasing customer loads over that period, which misses the recent run-up in PJM capacity prices in the 2025/2026 auctions that are affecting customer bills now, according to a presentation accompanying the study.

PJM’s Independent Market Monitor found that new data center load contributed to the largest chunk of the capacity price increase (alongside some market design parameters), and most PJM states saw retail prices jump from 10 to 15% when the new delivery year started.

Rising demand from data centers, manufacturing and other sources has been cited as creating a risk of higher prices due to their purported impact on wholesale markets, higher retail prices or cost allocation policies that might favor large commercial and industrial customers in the name of economic development. But the study found that load growth from 2019 to 2024 tended to reduce retail prices.

“In the 2019-2024 time frame, the regression suggests that a 10% increase in load was associated with a 0.6 (±0.1) cent/kWh reduction in prices, on average,” the article said.

That aligns with the understanding that a primary driver for utility spending has been refurbishing existing transmission and distribution infrastructure in recent years. Spreading those costs over a larger base cuts average prices, but the study noted that negative load-price relationship was seen in average prices and lost when focused on residential prices.

“Load growth over this historical period was led by commercial customers, and cost allocation practices have tended to benefit those large, non-residential customers,” the article said.

The study focuses on average prices across customer classes, but it noted that residential prices generally are higher than commercial and industrial prices and have risen more than those classes in recent years.

Investor-owned utilities have seen prices rise faster than public power, but the article noted that in California it is largely due to differences in wildfire risk and related costs.

“States with the greatest price increases typically exhibited shrinking customer loads — partially linked to growth in net metered behind-the-meter solar — and had renewables portfolio standards (RPS) in concert with relatively costly incremental renewable energy supplies,” the article said.

Net energy metering offers participants bill savings, but utilities must invest more in their distribution systems and recover fewer fixed costs from customers on NEM programs. The study found a 5% increase in net-metered, behind-the-meter solar led to an average price increase of 1.1 cents/kWh.

Utility-scale wind and solar development that happened outside of RPS might have led to lower retail prices in recent years, though the impact was not statistically significant, the article said. It added that RPS targets are likely to increase prices if they lead to renewables the market would not have delivered. Three-quarters of utility-scale wind and solar growth from 2019 to 2024 happened outside of RPS mandates.

Another major driver of higher prices is extreme weather, which impacts two of the states that have seen prices rise the most in recent years – Maine and California. Central Maine Power’s storm recovery cost rider rose from 0.1 cents/kWh in late 2020 to 1.8 cents/kWh in 2024.

“Between 2019 and 2023, California’s three large IOUs were authorized to include $27 billion in wildfire-related costs in retail prices,” the article said. “By June 2024, wildfire-related costs constituted an average of 17 % of total IOU revenue requirements, up from 1.7 % in 2019 and, if directly translated into one-year cost impacts, equivalent to a 4 cent/kWh increase.”

On average, the states with the highest wildfire risks have seen power prices rise by 1.1 cents/kWh, the article said.