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December 7, 2025

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OEB Chief: Independent Adjudication, Aligned on Policy

TORONTO — The Ontario Energy Board will retain its independence in adjudications even as it embraces the province’s directive for it to consider economic development in policymaking, the board’s new chief executive said during a speech at the Ontario Energy Conference on Sept. 29.

The OEB “is independent from, but aligned with, government,” said Carolyn Calwell, who was appointed CEO of the board Sept. 8. “Our adjudicated decision-making is, and will remain, independent, but our policy development isn’t necessarily so and, I would suggest, was never meant to be.”

The OEB operates under the Ministry of Energy and Mines’ annual letter of direction, which the ministry supplemented in June with its first-ever Integrated Energy Plan (IEP). The IEP contained multiple directives to the OEB and IESO. (See Ontario Energy Plan Gives IESO Long ‘To Do’ List.)

“The new model encourages people from across the OEB to work more closely together, breaking silos. It connects policy and adjudication,” Calwell said. “It enables a better understanding of how different initiatives work together to achieve larger outcomes.”

In his own speech, A.J. Goulding, president of London Economics International, said he trusts OEB and IESO to apply the economic growth criteria “thoughtfully.” (See related story, Goulding Hasn’t Drunk the ‘Energy Dominance’ Kool-Aid.)

“Directives should be used only as a last resort,” he said.

Bill 40

The IEP prompted Bill 40, pending before the legislature, which would enshrine economic development as a central goal of the OEB and IESO. It also would give the board’s CEO new authority to issue policies on procedures for hearings and determinations.

“Let me be clear: The OEB has always worked to support Ontario’s economy and its people,” Calwell said. “But the passage of Bill 40 would make economic growth part of the balance in our regulation of electricity. [It] is a critical priority, and a necessity for a secure Ontario, considering geopolitics today.”

She cited the government’s November 2023 directive to support new housing development. “Our team worked diligently last year to develop recommendations … related to getting houses built faster. It represented the OEB’s best, independent and evidence-based advice. The government accepted our advice and moved to implementation. And as of a week ago, the capacity allocation model [for assigning infrastructure costs among developers, ratepayers and distribution companies] is in full force and effect.”

Keeping the Planes in the Air

Calwell praised her staff for “keeping the planes in the air even as we change their major components.”

“Coordination with the IESO is already at an all-time high … thanks to [IESO CEO] Lesley Gallinger and her team,” Calwell said. “And given our joint work on enabling the Integrated Energy Plan, this integration, I think, will only increase over the fall.”

In March 2023, the OEB said it would consider a “margin on payments” for distributed energy resources owned by customers or third parties, but the program “was too open ended” and infrequently used, Calwell said. After considering further consultation or a generic hearing to consider alternatives, she decided to exercise her authority under the Ontario Energy Board Act to amend or create codes.

“So as CEO, I’m working toward amending the Distribution System Code to establish a margin on payment incentive,” she said.

“Amending the code is faster than another working group or a generic hearing, and it provides certainty for utilities. And by using a streamlined notice and comment process, we’re moving quickly to address this well defined opportunity. We’re creating a fair and predictable regulatory framework while we’re being flexible and ensuring prudence. And it’s a move that allows us to advance [at] the speed the energy sector needs,” she added. “More efficiency, less red tape — this is one element of the OEB Integrated Energy Plan implementation directive. There are 18 others.”

4 Workstreams

Calwell said the OEB is responding to the ministry’s directives through four “workstreams”:

    • Expanding DERs through new business models: The OEB launched a benefit-cost analysis framework and non-wires alternative guidelines last year to provide regulatory toolkits for distributors who want to adopt DERs. By the end of the year, the board plans to issue an Ontario-wide capacity map, issue new code amendments to promote DER connections and submit its distribution system operator roadmap to the minister.
    • Planning: The OEB is reviewing regional planning processes, the role of DERs in planning, scenario modeling and facilitating information sharing between the electricity and natural gas sectors. “Our goal is to build a common set of assumptions that help utilities effectively plan for an integrated energy future,” Calwell said. The OEB and IESO will soon be issuing a discussion paper to prepare for an integrated planning forum next year.
    • Utility remuneration: The OEB is benchmarking utility costs as a follow-up to its “Distribution Sector Resilience and Responsiveness” report to the ministry. “It’s a foundation for advancing performance-based regulation, including incentives,” she said. “The goal is to ensure the right data to support the next generation investment and ratemaking in Ontario.”
    • Streamlining procedures for connecting to gas and electric lines: “This work is critical to driving Ontario’s growing economy,” she said. “We’ll allow homes to be built and occupied sooner, [and] businesses to ramp up more quickly so they can create jobs and economic opportunities.”
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‘Above-normal’ Chance of Large Wildfire in Southern California This Fall

Southern California faces an above-normal chance of a significant wildfire in the coming months, less than one year after a set of deadly fires burned thousands of acres and structures in the Los Angeles region. 

“Southern California is now under moderate to severe drought, with just one little area of extreme drought over the lower desert,” Jeff Fuentes, assistant chief of the California Department of Forestry and Fire Protection (Cal Fire), said in an Oct. 2 winter readiness workshop hosted by CAISO’s RC West. “Santa Ana wind events will warm atmospheric conditions and drive above normal fire potential during October through December.” 

The South Coast region of Southern California shows the highest fire potential in the state because precipitation likely will be well below normal there from now through January, Fuentes said. 

About 10 months ago, a group of massive wildfires ignited in Southern California, including the Eaton Fire, which burned about 14,000 acres, resulting in 19 deaths and 22 missing people, and destroyed more than 9,000 structures. 

Rainstorms are expected in the region in late December or early January 2026. After these storms, “we get back to normal fire potential statewide,” Fuentes said. 

“[But] this doesn’t mean the wildfire season is over. All it takes is some dry events, some dry conditions and offshore winds … to kind of create those dangerous fire conditions,” Fuentes added. 

So far this year, more than 7,000 fires in the state have burned about 500,000 acres — a slight increase in fires compared with 2024. About 1,000 more fires this year have ignited compared with the five-year average. 

Water Outlook

As for precipitation, California ended the 2024/25 water year at about 91% of the normal precipitation level, said Jessica Stewart, CAISO senior energy meteorologist. California’s water year runs from Oct. 1 to Sept. 30. 

For the new water year, there is about a 71% chance of La Niña through fall and about a 54% chance through February. The stronger the La Niña signal, the lower the chance California has to see above-average snowfall, Stewart said.  

La Niña events historically have resulted in “more dry than wet years, but research also suggests that even as the climate grows hotter and drier overall, the precipitation that California does receive will arrive in stronger storms, increasing the risk from flooding,” the California Department of Water Resources (CDWR) said in a Sept. 30 press release. 

“There is no such thing as a normal water year in California,” CDWR Director Karla Nemeth said in the release. “Just in the past two winters, deceptively average rain and snowfall totals statewide masked the extremely dry conditions in Southern California that contributed to devastating fires as well as flood events across the state from powerful atmospheric river events.” 

In the coming months, the precipitation forecast is below average from the San Francisco Bay Area to the southern border of California, Stewart said. However, the ongoing drought in California and the West worsened between 2024 and 2025. Extreme flooding is a critical concern this year due to a warmer atmosphere, which causes an increased amount of moisture and more powerful storms, DWR said in the release. 

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Court Dismisses Claims of NextEra Antitrust Violations to Block NECEC

A U.S. district court judge in Massachusetts has granted NextEra Energy’s motion to dismiss claims the company violated federal and state antitrust laws in its efforts to block the New England Clean Energy Connect (NECEC) transmission project.  

In a September ruling on an Avangrid lawsuit alleging that NextEra undertook an “anticompetitive scheme” to block the NECEC line, District Judge Mark Mastroianni found that Avangrid failed to prove NextEra exercised monopoly power.

NECEC is an under-construction 1,200-MW transmission line connecting Québec and New England. The project, which was selected in a 2018 procurement by Massachusetts, is intended to facilitate large-scale baseload imports of power into ISO-NE. 

Avangrid’s lawsuit, issued in November 2024, alleges NextEra “has reaped hundreds of millions” from its efforts to stop or delay the NECEC line. Avangrid wrote that it has suffered at least $350 million in damages. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.) 

NextEra, which owns more than 2,700 MW of generation capacity in New England — including the Seabrook Station nuclear plant in New Hampshire — opposed NECEC in regulatory proceedings in Maine and Massachusetts, funded a pair of ballot initiatives in Maine to block the project, and clashed with Avangrid over the upgrade of a near-capacity breaker at Seabrook that was required to interconnect NECEC.   

The company’s opposition to NECEC appears to have successfully delayed its development for multiple years. While the referenda on the line ultimately were struck down in court and NextEra-funded political groups were fined for multiple campaign finance violations, the second referendum caused a two-year pause in construction on the line. 

Avangrid initially expected to complete the project in late 2022; it remains in the late stages of construction. 

NextEra filed a motion to dismiss Avangrid’s lawsuit in January, arguing that “all of the federal and state antitrust claims should be dismissed for the failure to properly plead monopoly power in a relevant market.” 

In his Sept. 22 ruling, Mastroianni found that Avangrid failed to demonstrate that NextEra had monopoly power in New England.  

“Avangrid has not identified NextEra’s percentage of market share in the relevant markets or even alleged, more generally, that NextEra possessed a predominant share” of ISO-NE’s markets, Mastroianni wrote.  

“While Avangrid has alleged interconnection of NECEC was likely to lower NextEra’s revenue in the relevant markets, there are no facts from which the court could plausibly conclude NextEra was able to set above-market prices in marketplaces operated by ISO-NE,” he added.  

Regarding Avangrid’s claim that NextEra resisted replacing the breaker at Seabrook to prevent new participants from entering the market, Mastroianni wrote that “a bottleneck that limits entry into the relevant market, on its own, is insufficient evidence of monopoly power.” (See D.C. Circuit Affirms FERC Ruling on Seabrook Circuit Breaker Dispute.) 

“There must also be a basis for finding the defendant can ‘profitably set prices well above its costs’ or would gain such power through the challenged conduct,” he added. 

“In the absence of sufficient allegations to support a finding that NextEra was able to charge supracompetitive prices within the relevant markets, or was likely to become able to do so if it could delay or prevent NECEC from entering those markets, the court cannot find NextEra’s multipronged campaign to delay or derail NECEC violated Section 2 of the Sherman Act,” Mastroianni concluded.  

He wrote that the court intends to issue a separate order on other claims made by Avangrid alleging unjust enrichment, intentional interference with a contract and unfair business practices. 

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IESO Seeking to Stay ‘Two Steps Ahead’ of Need

TORONTO — IESO is adopting more “proactive” planning processes as it embarks on its largest transmission expansion in two decades, ISO officials told attendees of the Ontario Energy Conference on Sept. 29.

Planners are working “to make sure that the transmission system stays two steps ahead of growth” with six bulk transmission plans and participation in 13 regional plans, said Beverly Nollert, director of transmission planning.

The ISO’s Pathways to Decarbonization study in 2022 identified a need for up to $50 billion of new transmission. On Sept. 25, the ISO announced a third transmission line into Toronto. (See Planners Pick $1.5B Underwater HVDC Line for Toronto’s ‘Third Supply’.)

“This is more transmission planning that I’ve observed in my just over 20 years here in the sector,” Nollert said.

“We’re looking at: How do we make sure that we can supply demand from Windsor to Hamilton and into the [Greater Toronto Area] from the west, from the north and from the east? How are we addressing bottlenecks for electricity flow into Ottawa and other areas in Eastern Ontario, such as Belleville? How are we addressing bottlenecks in Northern Ontario? [We’re also looking at,] how do we facilitate the connection of supply resources?”

During the low load growth years of the past, the province did not consider many large-scale transmission projects, Nollert said. “That was the reflection of the time, and it also [was] really in line with our mandate to ensure cost-effective reliability.”

Now, she said, “we’ve started to shift our mindset to a more proactive planning approach. And what we’ve been starting to do is to look for future-ready investments that are required under several different pathways and scenarios.

Beverly Nollert, IESO | © RTO Insider LLC

“When we’re comparing options, it’s no longer just looking at … what do we need under a reference growth scenario, but also what might we need under a higher-growth scenario? And then with both of those insights, looking at … what’s the right thing to do to future-proof the system? Because if we don’t do that, it might be a lot more expensive to go back to accommodate the next tranche of growth.”

As an example, Nollert cited the ISO’s Northern Ontario Connection Study, which considered how to serve First Nations communities still supplied by diesel, as well as connect generating resources and support mining extraction in the Ring of Fire region.

Although the reference demand scenario found that immediate needs could be served by a single-circuit 230-kV line, “we have identified that it’s actually more cost effective now to develop a double-circuit 230-kV transmission line to be able to future-proof the system and enable many different scenarios in the region,” she said.

Chuck Farmer, IESO’s executive vice president for power system development, said the ISO previously used planning scenarios “in a somewhat ad hoc way” in response to specific questions. Now it is using scenarios to “maintain optionality,” he said.

Chuck Farmer, IESO | © RTO Insider LLC

“We don’t commit [to investments] until we know [demand is real] so that we don’t lock in costs going into the 2040s and 2050s that — if the signals are not there — will be difficult for ratepayers to manage.”

The other half of “the planner’s dilemma,” Farmer said, is building too little infrastructure and becoming a limit on economic growth. “The sweet spot is a small, modest surplus. [That] is where you try to be. But the reality is, demand is uncertain; it will never play out quite the way you want.”

Robert Reinmuller, Hydro One’s vice president of transmission system planning and large accounts, said he welcomed the ISO’s new philosophy.

“There was a time back in … 2022-2023 when my interaction with IESO drove me nuts,” he said.

“We were saying, ‘Well, the need is not quite there. We need another 15 MW. We got to wait.’ And it happened to me couple of times [where] we sat on the bubble, and then the need materialized. And then the question I got from [IESO was]: ‘Can you do this in three years?’ No, I can’t. I’ve been trying … for five years to get this done, but now I need to do it in two, three years, because the need suddenly tilted over that that bubble.”

Injecting Competition

In July, the IESO released its transmitter registry of developers eligible for future competitive transmission procurements. The first solicitation is expected next year. (See IESO Moving Forward with Competitive Tx Plans.)

Evan Yager, of NextEra Energy Resources, said stakeholders “should give Bev and her team a bit of grace” over the time it has taken to implement competition.

“It’s taken time, but we are asking an awful lot of her and the ISO to get this process up and running,” he said.

He also said the ISO should learn from other grid operators, such as PJM, which has implemented a 120-day window on competitive transmission solicitations. Developers “have a 60-day window to pull together proposals and get those submitted. And on the flip side, PJM has a 60-day window to make decisions.”

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Abbott Names Leader for Texas Nuclear Office

AUSTIN, Texas — Texas nuclear industry experts are lauding Gov. Greg Abbott’s recent appointment of Jarred Shaffer to lead the Texas Advanced Nuclear Office (TANO), which is responsible for funding mechanisms and regulatory support to accelerate nuclear energy deployment in the state.

The office was created by House Bill 14, signed into law by Abbott in June. It establishes the $350 million Texas Advanced Nuclear Development Fund, the nation’s largest state fund for advanced nuclear energy, according to Texas officials. The fund will provide grants and funding for advanced nuclear reactor projects in Texas.

The bill also creates a nuclear permitting coordinator position that supports the development and deployment of advanced nuclear and innovative energy technologies.

“Jarred is a good choice who will be dedicated to an efficient and expedited process to get the state money out the door,” former utility regulator Jimmy Glotfelty, who chaired the working group tasked with studying and planning the use of advanced nuclear in Texas, told RTO Insider.

Glotfelty’s working group produced a report in 2024 that recommended setting up a state agency as the “tip of the spear” to provide a voice for the nuclear industry. (See Texas Now Wants to be No. 1 in Nuclear Power.)

“I think it’s great that we’re moving this forward very quickly, because until we get the pieces in place, we can’t actually start giving away the money,” said Casey Kelley, vice president of state government affairs in the South for Constellation. The company operates the largest fleet of nuclear plants in the U.S. and is a part owner of the 2.65-GW South Texas Project (STP) Electric Generating Station near Houston.

Vistra’s 2.5-GW Comanche Peak Nuclear Power Plant is the only other nuclear facility in Texas. Comanche Peak and STP both have room for two more reactors.

Reed Clay, president of the Texas Nuclear Alliance, said Shaffer’s appointment as TANO’s inaugural director “marks another historic step in Texas’s leadership on nuclear energy.” He said the office will expand the state’s clean energy portfolio, spur significant manufacturing investment, simplify the permitting process and ensure the U.S., not China, is exporting nuclear power technology to the developing world.

“Quickly executing on the mandate of House Bill 14 is necessary for the rapid deployment of new nuclear in the state,” he said in an emailed statement to RTO Insider.

Clay called Shaffer’s appointment further proof Texas is “leading a nuclear renaissance” in the United States. “With strong leadership in place, it’s time to build,” Clay said, referring to Shaffer as a “seasoned energy policy expert.”

Formerly a budget and policy adviser in the governor’s office, Shaffer served as committee director for the Texas House Committee on State Affairs, a legislative liaison for the Texas Department of Transportation, and with the Texas Commission on Environmental Quality. He holds several bachelor’s degrees from The University of Texas at Austin.

Abbott said Shaffer’s expertise on energy issues “makes him the best fit to streamline the nuclear regulatory environment” and direct investments to spur the state’s nuclear power industry.

“TANO and the Texas Advanced Nuclear Development Fund will increase Texas’ investment in an all-of-the-above energy approach to solidify Texas as the world’s energy hub,” Abbott said.

“We do everything big in Texas,” Glotfelty said during CERAWeek 2025 in March. “Success is steel in the ground, concrete in the ground, people working and building a plant. That is the end goal.” (See “Nuclear Hub in Texas?” Overheard at CERAWeek 2025.)

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Goulding Hasn’t Drunk the ‘Energy Dominance’ Kool-Aid

TORONTO — The Ontario government’s ambitious energy plan could prove costly to ratepayers if load growth stalls or new nuclear plants produce cost overruns, A.J. Goulding, president of London Economics International, said at the Ontario Energy Conference in a keynote speech Sept. 29.

“I worry a bit when words like ‘superpower’ or ‘energy dominance’ are used,” said Goulding, referring to the goals laid out in the Ministry of Energy and Mines’ Integrated Energy Plan (IEP) in June. “They suggest a shift of focus from cost/benefit, risk and reward.”

The IEP calls for expanding natural gas and nuclear generation, including four small modular nuclear reactors totaling 1,200 MW and a new 4,800-MW nuclear plant at the Bruce Nuclear Generating Station. The plan is based on a projected 75% increase in electric demand by 2050. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)

Despite its name, Goulding said, the ministry’s IEP is a “political document” rather than the investment blueprint that utilities file with regulators. “This is not a criticism. The IEP is a helpful statement of the government’s intent and informs the deliberation of Ontario’s quasi-independent agencies,” said Goulding, whose speech was titled “Skating fast enough or over our skis?”

Goulding praised the IEP’s “all-of-the-above” approach to generation as a way to balance affordability and environmental impact and said the province’s proposed expansion of nuclear power “makes sense from a reliability and emissions perspective, not to mention jobs and land use.”

Load Growth Projections

But he questioned the ministry’s projection that load growth will increase by three-quarters — 3% per year — over the next 25 years.

“Looking at successive 25-year periods since 1960, we find the most recent that averaged 3% load growth ended in 1995,” he said. “Only two individual years since 1997 have exceeded 3% lower growth.

“Per capita electricity consumption in Ontario peaked in 1988 and has fallen 36% since,” he continued. “We keep finding new ways to not use electricity, and it’s not clear that electrification will fully reverse these trends.”

A recession, or the impact of the U.S. government’s tariffs, also could dampen load growth. If growth falls short of projections, customers could face steep rate hikes to pay for infrastructure additions, he said.

New Nuclear Plants

Goulding raised concern over Ontario’s plan to build the first SMRs in the Group of Seven. The province hopes they will be a boon for economic development as other jurisdictions seek to tap its experience.

“While Ontario’s bet on first-mover advantages on small modular nuclear reactors … may pay off, it also carries with it first-of-a-kind” risk, he said, citing research showing nuclear projects have averaged cost overruns of over 120%.

Although he acknowledged that “recent experience in Ontario has been more positive with refurbishment of legacy designs,” he said it will take more than three SMRs to reach “N-of-a-kind” cost reductions.

“Ontario is not large enough to absorb sufficient reactors to reach that point on its own. Arguably, all of Canada may not be [large enough], making global partnerships critical,” he said.

The magnitude of Ontario’s planned spending on energy infrastructure leaves it vulnerable to “continuity risk” — the possibility that a large capital project is suspended following a change in government.

“Around the world, governments appear increasingly inclined to pivot from their predecessors’ policies, regardless of underlying merit,” he said. “This increases costs for projects that ultimately proceed and decreases investor confidence. Continuity risk is difficult to hedge. … and increases with project size. Large-scale nuclear investments could be particularly vulnerable to this risk.”

Granular Additions

Goulding said scenario analysis and maintaining optionality are central to addressing forecast risk.

“New-build plans need to be tested against multiple outcomes. The optimal plan should perform well across several resources that can be added in more granular increments,” he said. “An [Ontario Energy Board] process in which regulated entities detail IEP rate impacts and the extent of engagement with First Nations would provide both transparency and discipline as the province considers next steps.”

He also called for increased use of demand response to reduce the need for peaking plants. “Now, the challenge with demand response,” he joked, “is that it doesn’t make for a nice ribbon cutting.”

CCUS Utility

Goulding noted that the government’s continued commitment to natural gas generation is tied to development of carbon capture, utilization and storage (CCUS). “If we believe carbon capture and storage requires scale, perhaps we need a carbon capture utility to catalyze CCUS investment,” he said. “CCUS helps to legitimize the all-of-the-above strategy. It is also an area worthy of federal government support.”

Conclusion

“We can best manage the risks in the IEP through appropriate time-limited consultation, thoughtful scenario analysis, diversification of ownership and resource type, expanding the role of demand response and creating a foundation for CCUS, while maintaining a focus on affordability,” he concluded. “Policymakers need to take willingness to pay into account first as plans are being formulated, rather than after the fact, while also acknowledging that some rate increases are unavoidable.”

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MISO IMM Recommends Changes to Handling of Midwest-South Tx Constraint

MISO’s Independent Market Monitor has called for the RTO to change how it manages its Midwest-South transfer limit in ways he contends will open line capacity and reduce costs for Midwest market participants.

IMM David Patton asked MISO to create more steps on the limit’s transmission constraint demand curves to use more megawatt space on the transmission path and create headroom for deviations.

At a Sept. 30 MISO Market Subcommittee meeting, Patton said the Midwest-South limit has been binding more frequently since 2022 and contributed to $41 million in congestion over summer 2025, a 121% increase over 2024.

He said the regional transfer constraint has been used more in recent years due to solar additions in the South, a prolonged drought in Manitoba that has the Midwest exporting more power than usual and a drop in natural gas prices that has made MISO South’s plentiful gas generation more attractive.

Patton said reformulated demand curves on the transfer limit would allow greater energy transfer capability, increased use of MISO South generation and reduced costs to loads in MISO Midwest. He said adjusted curves could allow the RTO to tap into more than 200 MW on average in the South and increase flows by 50-60 MW.

Patton contended that adopting his demand curve recommendations would have reduced Midwest average energy prices by $3.48/MWh and driven down the region’s market costs by $515 million just over summer 2025.

Patton said that he’s long advocated MISO renegotiating its contracts with SPP and other neighbors to stipulate how MISO is allowed to use the transfer limit. He said because the transfer limit is a “contractual constraint that does not reflect any physical limits,” MISO should work to get more out of it.

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ISO-NE Publishes Draft 2026 Work Plan

Capacity auction alterations, a new asset condition reviewer role, parallel transmission planning efforts, new reserve products, Pay-for-Performance changes and interconnection modifications are likely to be on the docket for ISO-NE in 2026.

The RTO’s draft 2026 annual work plan, published in advance of the NEPOOL Participants Committee’s meeting Oct. 9, includes continued work on several major ongoing projects and outlines potential new initiatives related to dynamic operating reserves, PFP adjustments and surplus interconnection service.

The Capacity Auction Reform (CAR) project will continue to be the RTO’s main market development focus. The second phase of CAR, which is scheduled to run throughout 2026, will focus on overhauling the RTO’s capacity accreditation methodology and splitting annual capacity commitment periods into distinct summer and winter seasons. (See ISO-NE Kicks off Talks on Accreditation, Seasonal Capacity Changes.)

ISO-NE plans to seek technical committee votes in November on the first phase of the project, centered around the transition to a prompt market, followed by a PC vote in December. (See Stakeholders Mixed on ISO-NE Prompt Capacity Market Proposal.)

Other projects for 2026 include ISO-NE’s effort to stand up a new “asset condition reviewer” role. The role is intended to provide increased transparency around pooled costs associated with upgrades to aging and degrading transmission infrastructure, which have ballooned in recent years. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.)

As ISO-NE works to develop its in-house review capabilities over the next year, “the ISO plans to use a consultant to begin reviewing some [asset condition] proposals in an interim phase and facilitate stakeholder review and discussion of the consultant’s feedback,” the RTO wrote in its work plan.

Transmission Planning

Also in 2026, ISO-NE plans to evaluate and select a preferred transmission solution for the first Longer-Term Transmission Planning (LTTP) solicitation, which is intended to increase transmission capacity in Maine and help interconnect new onshore wind generation in the state. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

According to ISO-NE spokesperson Randy Burlingame, the RTO received six qualified responses prior to the Sept. 30 deadline. Burlingame declined to comment which companies submitted proposals, but said ISO-NE will publish summaries of the proposals within 60 days.

ISO-NE wrote in the work plan that it plans to select a preferred solution “as early as September 2026.”

“Upon completing, reviewing and adjusting for any lessons learned from the 2025 cycle, the LTTP process could then proceed with a subsequent cycle, which would seek stakeholder input,” the RTO added.

In the third quarter of 2026, ISO-NE plans to begin work to comply with FERC Order 1920, which establishes long-term planning requirements for grid operators. In February, FERC accepted ISO-NE’s request to push back the compliance deadline for the order by two years, extending it to June 2027. The RTO has said the delay will enable it to “implement and gain experience from conducting the first LTTP” request for proposals.

“While New England’s new LTTP framework accepted by FERC in July 2024 went far in complying with [Order 1920], notable differences must be addressed,” ISO-NE noted.

The RTO said Order 1920 compliance discussions likely will include a focus on “further including [grid-enhancing technologies] into transmission planning assessments,” along with the development of a process for right-sizing asset condition upgrades “as a way to address long-term needs.”

Dynamic Operating Reserves

To prepare the system for increasing variability in generation and demand, ISO-NE “is assessing and commencing development of dynamic, operating reserve demand curves for incremental quantities of existing real-time reserve products (10- and 30-minute reserves), in amounts that vary during the operating day based on the system’s near-term potential ramping needs,” it wrote.

The RTO is considering adding a 60- or 90-minute reserve product, which could include “dynamically determined demand quantities,” to prepare the system for “unanticipated supply and demand changes.”

In a memo published in March, ISO-NE wrote that, to address increasing uncertainty and ramping requirements, it plans to develop “a dynamic, real-time probabilistic forecast of the system’s energy ramping needs,” which could inform these new reserve products. (See “Flexible Response Services,” ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The RTO plans to begin stakeholder discussions on these potential changes in the fourth quarter of 2026.

Pay-for-Performance

ISO-NE also wrote that changes may be needed to its PFP rules following a recent New England Power Generators Association (NEPGA) complaint to FERC about “serious flaws” in the construct’s design.

In response to the complaint, ISO-NE has said it is open to capping the PFP balancing ratio but opposed NEPGA’s proposed changes to the stop-loss mechanism. (See ISO-NE Open to PFP Changes Following NEPGA Complaint.)

“The ISO may assess and discuss with stakeholders possible cost-allocation related revisions to the stop-loss mechanism and balancing ratio, depending on FERC action on NEPGA’s filing,” ISO-NE wrote in its work plan.

Surplus Interconnection Service

Prior to the publication of the work plan, some stakeholders pushed ISO-NE to pursue updates to surplus interconnection service rules, arguing that the RTO should allow increased flexibility for interconnecting resources that are willing to accept limitations based on the existing capacity resources at an interconnection point. (See Stakeholder Forum: Surplus Interconnection Can Maximize Capacity in ISO-NE.)

ISO-NE wrote that it plans to initiate discussions with stakeholders in the first quarter of 2026 “to identify the objectives, issues and scenarios driving stakeholders’ inquiries around existing and future access and use of assigned interconnection service rules.”

Following initial discussions, the RTO plans to “conduct a gap analysis of the use cases against the existing interconnection rules to determine the scope of potential solutions,” which would inform additional stakeholder discussions on potential rule changes.

ISO-NE is scheduled to complete its first cluster interconnection study under transitional Order 2023 rules in August 2026. The next cluster study will begin in October 2026.

Other Initiatives

The work plan includes initiatives intended to improve ISO-NE’s modeling of inverter-based resources, boost cybersecurity and deploy a new market clearing platform. The RTO also plans to publish a report on the performance of its new day-ahead ancillary services market that will include “any potential recommendations for enhancements.” The ISO will discuss the draft work plan with NEPOOL members at the PC meeting in West Hartford, Conn., on Oct. 9.

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N.Y. Build-ready Renewables Program to be Redirected

New York is planning a step back and a change of focus for a renewables program that never gained traction in the five years after it was launched.

The New York State Energy Research and Development Authority on Oct. 1 proposed to the Department of Public Service (15-E-0302) that the Build-Ready Program be terminated as a ratepayer-funded program and changed to an economic development model funded through other means.

Build-Ready was launched in October 2020 to develop a roster of turn-key plans that would place renewable generation on sites such as landfills, abandoned industrial areas and dormant generation facilities that could be sold to developers. Proceed from the sales would fund the next developments, and the program would become self-sustaining.

NYSERDA did an initial review of 16,400 parcels, narrowed that down to 3,400 sites and then identified 480 potential locations. But for a variety of reasons, all 480 were unworkable.

After nearly five years of effort at a cost of $15.6 million, Build-Ready’s one tangible result was a 12-MW solar project on the tailings pile of a defunct mine, sold to a developer in early 2025. (See Results Elusive in N.Y. Build-Ready Renewables Program.)

But in its five-year report to the DPS, NYSERDA identified some other results of Build-Ready: an interactive geographic information system and standardized database of all the sites it reviewed; a team that has developed expertise in photovoltaic solar project origination and development; and a template for partnership with other agencies, governments and organizations.

NYSERDA said the institutional knowledge gained through Build-Ready on interconnection, economics, leasing schemes and permitting is proving useful to other programs it and other agencies are pursuing. The agency proposes to meet Build-Ready’s statutory requirements by encouraging siting and development of renewable energy and storage on challenging sites.

Asked for clarification, a NYSERDA spokesperson said the program would continue to accept and evaluate site suggestions but focus on economic development opportunities, a shift it anticipates will give projects a better chance of coming to fruition.

This will include work with outside economic agencies: A memorandum of understanding is in place with the state’s economic development arm, Empire State Development, for Build-Ready to support its POWER UP and FAST NY programs.

The role now proposed for Build-Ready is to support economic development by optimizing siting and development of new loads; expanding existing loads; and helping investigate incorporation of clean energy technologies into economic development projects, the spokesperson said.

In a 2020 order, the Public Service Commission gave Build-Ready a $71.8 million budget, most of it from the ratepayer-financed Clean Energy Fund. NYSERDA spent only $15.6 million through Aug. 31, 2025, and in its Oct. 1 proposal, it said it would repay the CEF money through other funding streams and move forward without ratepayer money.

Build-Ready’s problems sprang from its central mission: design an inherently challenging and expensive project in a financially sustainable manner, then get it fully permitted and sell it.

“Build-Ready has determined that very few sites in New York state both meet the program’s numerous requirements (e.g. previously developed site, no agricultural land, no competition with the private sector) and also support economically viable large-scale renewable energy projects,” NYSERDA wrote.

Along the way, state leaders created in-house competition in 2023 by directing the New York Power Authority to take on a role as a renewable energy developer. And federal leaders in 2025 have made renewables much more expensive by adding tariffs and eliminating tax credits.

“Given this new policy paradigm in which Build-Ready must operate,” NYSERDA wrote, “developing economically viable Build-Ready solar PV projects going forward will be even more difficult.”

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FERC Ends Show-cause over SPP FTR Changes

FERC has terminated a show-cause proceeding against SPP and accepted the RTO’s proposal to revise its mark-to-auction (MTA) collateral requirement for financial transmission rights by including an additional re-marking mechanism for seasonal products.

The commission said in its Sept. 30 order that SPP’s tariff “now fully addresses” its concerns in the proceeding, saying the mark-to-auction mechanism “sufficiently requires collateral to address the risk that a [transmission congestion rights] portfolio may decline in value over time” (ER25-2261, EL22-65).

“SPP’s approach ‘take[s] auction-clearing prices [ACPs] into consideration and thus incorporate[s] market expectations of the future values of the TCRs,’” FERC said, referring to a March order accepting the grid operator’s MTA proposal. That order stopped short of terminating the show-cause proceeding that dated back to 2022. (See FERC Accepts SPP Revisions to TCR Market, Maintains Show Cause.)

“Specifically, SPP’s proposal will apply ACPs from monthly auctions within the relevant season to re-mark the collateral requirements of seasonal TCRs, thereby ensuring that all TCR products are subject to a forward-looking pricing mechanism that reflects current market conditions,” the commission said.

FERC said SPP’s proposal to update collateral based on the most recent auction price for seasonal and monthly TCRs “provides sufficient protection when considered alongside other features of SPP’s TCR collateral requirements and market design.”

The commission disagreed with DC Energy’s arguments that the show-cause proceeding should remain open to consider broader reforms to SPP’s TCR market design. It found further reforms are unnecessary to address its concerns regarding the increased risk of default that results from a TCR portfolio that declines in value.

It also rejected the SPP Market Monitoring Unit’s call to strengthen tariff language regarding ad hoc collateral adjustments. FERC agreed with SPP that under its tariff, the RTO already possesses “sufficient authority” through its existing credit policy to conduct ongoing credit assessments, revise customer credit limits and issue collateral calls in response to material changes in credit risk.

The commission granted SPP’s request for waiver of the commission’s 120-day prior notice requirement for good cause and accepted the proposal effective May 1, 2026, to allow the RTO to prepare for the TCR annual auction in 2026.

FERC Penalizes NorthWestern

FERC approved a consent agreement between its Office of Enforcement and Regulatory Accounting and NorthWestern Energy, completing an investigation into whether the utility violated SPP’s tariff over a wind farm’s operation (IN25-14).

The Enforcement investigation found that NorthWestern failed to meet a deadline to convert its Beethoven wind farm project from a non-dispatchable variable energy resource (NDVER) to a dispatchable variable energy resource (DVER). NorthWestern acquired the 80-MW facility in South Dakota from BayWa Wind in July 2015, several months after it began commercial operation.

The utility, Beethoven’s market participant, told SPP several times over a seven-month period before the acquisition that Beethoven was a qualifying facility (QF) and registered it as an NDVER. Beethoven was merged into NorthWestern, and in September 2015, BayWa Wind relinquished the facility’s QF status.

As a wind-powered VER, the wind farm should have been registered as a DVER in 2015, according to SPP’s tariff. However, it wasn’t until February 2025 that NorthWestern completed the registration and conversion of Beethoven to DVER status.

NorthWestern neither admitted or denied the violation but agreed to: 1) pay a civil penalty of $40,000 to the U.S. Treasury; 2) disgorge $32,000, inclusive of interest, to SPP; and 3) provide compliance monitoring reports to Enforcement.

Enforcement opened the investigation after receiving a referral from SPP’s MMU.