More than 400 stakeholders attended a set of workshops where CAISO staff described new processes for scheduling intertie resources and resource adequacy imports in the ISO’s Extended Day-Ahead Market, which will begin operation in May 2026.
ISO staff used the Nov. 5 and 6 workshops to review a white paper on the subjects.
“I haven’t seen [this many participants] on a CAISO call since you were dealing with the 2020 blackouts,” said Dan Williams, principal adviser at The Energy Authority.
One of the new EDAM processes involves intertie resource bidding and scheduling. Intertie resources in CAISO are currently modeled at specific scheduling points, but under EDAM, those resources will be modeled at a generation aggregation point (GAP).
A GAP is the collection of supply resources in a balancing authority area or group of BAAs.
EDAM will have three types of GAPs: default, custom and generic. A GAP can be resource specific or not, and its location will be in a Western Energy Imbalance Market (EIM) or non-WEIM BAA where the energy is produced or consumed, CAISO staff wrote in the white paper.
The GAP approach will significantly improve power flow and market accuracy, improve alignment with actual power flows by reducing phantom congestion and reduce operator conformance of transmission limits in real time, staff wrote.
CAISO Executive Principal George Angelidis described five intertie resource types: system resources, intertie transaction resources, intertie generating resources, transfer system resources and mirror system resources.
Some participants said they were unclear about these terms.
“I am already a little lost between the difference between a system resource and an intertie generating resource,” said Carrie Bentley, CEO of Gridwell Consulting. “The words seem almost exactly the same. I’m wondering if it would be helpful to ground us all in what all these different terms are for and maybe … dumb it down for us.”
“Both the system resource and intertie generating resource are registered in the master file,” Angelidis said. “The system resources in implementation are non-resource specific intertie resources.”
Williams added: “We are seven months out from this [process] being a live part of CAISO’s market, and as far as I am aware today, there are sort of two sources of power that trade in the forward market: a CAISO source and a non-CAISO source.”
“Western markets are not set up to be trading with any amount of liquidity on a resource-specific basis in the pre-day-ahead market space,” Williams said.
The paper introduced indirect intertie scheduling in EDAM. CAISO currently offers direct scheduling at interties but will now include indirect scheduling in EDAM to allow non-EDAM BAA resources to wheel power through a WEIM BAA that requires explicit wheel-through schedules, the paper says. Indirect scheduling is more complicated than direct scheduling and requires coordinating schedules of multiple resources, the paper says.
The paper also described generic RA import requirements.
CAISO tried to simplify monthly RA showings in EDAM. Monthly generic RA showings will not be resource specific, and scheduling coordinators who have generic RA import obligations will show these obligations in the ISO’s customer interface for resource adequacy (CIRA) system.
The paper also described requirements for imports of flexible RA. Monthly flexible RA will be resource specific, and CIRA will confirm that a scheduling coordinator has obtained the maximum import capacity at the intertie. If the source of the flexible RA obligation is in a non-WEIM BAA, the custom GAP must be the location of a physical resource in that non-WEIM BAA, the paper says.
The Regulatory Assistance Project (RAP) has assembled nine former state utility regulators to try to make electricity more affordable for ratepayers.
RAP announced the initiative Nov. 6 and said the former commissioners will try to influence regulatory initiatives to “secure access to clean, affordable and reliable energy for all.”
The bipartisan council includes:
Jay Griffin, former chair and commissioner of the Hawaii Public Utilities Commission and executive chair of RAP’s U.S. program;
Kent Chandler, former chair and vice chair of the Kentucky Public Service Commission;
Megan Decker, former chair and commissioner of the Oregon Public Utility Commission;
Sarah Freeman, former commissioner on the Indiana Utility Regulatory Commission;
Carl Linvill, former commissioner on the Nevada Public Utilities Commission;
Michael T. Richard, former commissioner on the Maryland Public Service Commission;
Ted Thomas, former chair of the Arkansas Public Service Commission;
James Van Nostrand, former chair of the Massachusetts Department of Public Utilities; and
Carrie Zalewski, former chair of the Illinois Commerce Commission.
RAP said the council is necessary as the grid becomes strained by growing demand. It said the group can “speak candidly and with authority” to current commissioners “on what’s holding back progress in U.S. energy systems.”
Griffin said the council will offer advice to utility regulators on how to achieve the most meaningful changes through commission action.
“This group understands the pressures on regulators and will serve as trusted peers to commissions throughout the U.S.,” Griffin said in a press release.
“At a time when energy issues are becoming increasingly politicized, this council’s experience will help today’s decision-makers cut through the noise, focus on the most urgent challenges and set the course toward the affordable, safe and secure energy all Americans deserve,” RAP CEO Katherine Dixon said in a press release.
Griffin told RTO Insider that RAP doesn’t plan for the council to weigh in on individual proceedings like rate cases, but it would release statements on topics it deems important.
RAP staff and senior advisers, including some council members, will continue to release reports on regulatory topics and engage directly with commissions, other government entities, utilities and stakeholders, he said. RAP assembled the council “to support today’s leaders in state commissions across the U.S.”
RAP will hold its first full meeting with the council in December and plans to hold a second meeting in February, Griffin said. It plans to maintain the council for the foreseeable future and is working out the details of council members’ terms. He said some “natural turnover” could occur, and he anticipates more former commissioners serving as senior advisers to RAP.
Nationwide, electricity prices have jumped approximately 40% since February 2020, according to the U.S. Bureau of Labor Statistics. The increase is attributed to grid modernization, rising data center demand and higher natural gas prices.
Household debt in the U.S. reached a record $18.59 trillion in the third quarter of 2025, up $197 billion from the previous quarter, according to data from the Federal Reserve Bank of New York.
Financial outlets increasingly refer to a bifurcated, “K-shaped economy,” where the upper arm of the “K” represents upper-class Americans’ income and spending growth since the COVID-19 pandemic, while the lower arm depicts lower- and middle-class Americans struggling with inflation, debt and increasingly expensive necessities like housing and health insurance.
RAP is a think tank that describes itself as “an independent, global non-governmental organization with a mission of advancing policy innovation and thought leadership within the energy community.”
The Michigan Public Service Commission has approved tailored rate provisions between Consumers Energy and energy-intensive load customers.
Clean energy groups commended the commission’s efforts to protect consumers but were critical of the Nov. 6 ruling’s lack of directives that large loads meet Michigan’s clean energy standard of 80% by 2035 and 100% by 2040.
The new provisions apply to customers with loads of at least 100 MW. Contracts would contain a five-year ramp-up period to full service and a 15-year term thereafter. The contract’s minimum billing demand requirement would have customers paying for on-peak demand, transmission demand and maximum demand charges based on 80% of their contracted capacity, regardless of actual usage. If customers want to exit the contract early, they must pay a fee equal to their minimum billing demand multiplied by the number of remaining months in the contract (U-21859).
The PSC said its decision attempts to simultaneously take advantage of economic opportunities while making sure large load customers cover the costs required to serve them. It said it believed its order would ensure “adequate guardrails” to avoid socializing data center costs and would prevent other customers from picking up the tab on stranded costs if anticipated loads fail to materialize.
Contracts would extend automatically in five-year increments and require four years’ notice to terminate.
The order requires prospective customers to pay an administrative fee to Consumers for worker hours spent studying and drawing up plans to serve the customer.
“These requirements are meant to ensure large load customers remain in service long enough that they will contribute significantly to new and embedded costs while also giving Consumers time to plan for unprecedented changes to its overall load,” the PSC said in a press release accompanying the order.
The new terms allow a large load customer to seek a one-time capacity reduction of no more than 10%, with a four-year written notice. Requests for reductions larger than 10% will have to go through commission approval. Consumers can suspend service to the customer if its usage begins to exceed contracted capacity by 1 MW or more.
However, the commission did not prescribe a specific rate design, leaving that for future rate cases Consumers brings forward. Instead, the PSC directed Consumers to propose six different cost-of-service study and rate design proposals “meant to analyze large load customers’ impact on rates and their contribution to interconnection costs, which will be used to set the rate for these customers going forward,” the PSC said.
The commissioners said large load customers can expect to be categorized under a separate rate class using a different cost allocation. They told Consumers to file ex parte cases for each large load customer to show that costs wrought by them aren’t bankrolled by other customers.
Consumers is further obliged to make annual reports to the commission containing data on large loads, their demand and energy use, changes in their capacity requirements and possible exit fees.
Finally, the commission held off on ordering further stipulations to mitigate large load customers’ effect on integrated resource planning and the state’s renewable and clean energy standards. The PSC said those matters were best handled in separate, ongoing proceedings before it.
Prior to the PSC’s order, Consumers had only its general primary demand (GPD) rate as its default terms of service, with the largest customer under the GPD at 28 MW. The original GPD uses a minimum on-peak billing demand of 60% based on previous summer use with a one-year minimum contract.
Consumers currently serves just one customer larger than 100 MW through a special rate established by the state legislature.
In testimony, Jim Dauphinais, counsel for the Association of Businesses Advocating Tariff Equity, said Consumers has received inquiries for new data center projects totaling 15 GW, with a half dozen of the inquiries for 900 MW or more for an individual customer. Dauphinais said discovery in the commission’s proceeding showed that Consumers contacted a local transmission owner over a 2.65-GW addition and was told the needed transmission investment to accommodate the extra demand would range from $730 million to $780 million.
Dauphinais testified that Consumers risked entangling its existing customers in subsidizing large loads unless it was held to strict consumer protections and annual reporting.
Consumers’ peak total demand is 7 GW. It announced in late July that it had reached an agreement to supply power to a data center of up to 1 GW for an unnamed developer.
Environmental advocates said that while the commission addressed the threat of higher bills, it didn’t shut down the possibility that data centers would undercut Michigan’s clean energy goals.
“This ruling is an important first step towards protecting Michiganders from the energy costs of data centers and the speculative rush that’s threatening to drive up our already high costs of electricity and deplete our water supply. We cannot afford to continue building high-cost gas or running expensive, dirty and old coal plants just to feed the data center rush. We expect regulators and our utilities to prioritize the use of cleaner, cheaper renewable energy to benefit all Michiganders,” Elayne Coleman, director of the Sierra Club’s Michigan chapter, said in a statement following the ruling.
The Michigan Environmental Council, Natural Resources Defense Council, Sierra Club and Citizens Utility Board of Michigan intervened in the case, arguing for 90% capacity payments instead of 80% under the new service terms. The group was represented by Earthjustice and Troposphere Legal.
“When data centers arrive, they typically bring the threat of higher utility bills and too often the undermining of clean energy goals. Today’s ruling is an important step towards reducing the risk of the former but, unfortunately, fails to address the latter,” said Shannon Fisk, director of state power sector advocacy at Earthjustice.
Fisk said she was encouraged the commission protected consumers against stranded asset costs and vowed to continue fighting to ensure data centers are supplied by clean energy “rather than dirty fossil fuels.”
Derrell Slaughter, a Michigan-based policy director at the NRDC, said that while the PSC’s order “makes strides on customer protection,” it fell short of compliance with Michigan’s clean energy standards.
“Without guardrails from the Public Service Commission order, it creates uncertainty about whether these large new customers will be powered by clean energy and ultimately help Michigan meet its clean energy goals,” Slaughter said.
A drone shot follows wind blowing through tinder-dry grass to transmission lines that clank ominously in the Sierra Nevada foothills. The opening scene of Apple TV+’s The Lost Bus is not subtle: The electric utility is painted as the villain behind the fire the down-on-his-luck school bus driver hero has to overcome.
Dej Knuckey
The movie was based on the real-life tragedy that unfolded when a 97-year-old suspension hook (C-hook) broke, causing a transmission line to fall and spark a fire that took lives, destroyed 18,000 structures and nearly wiped Paradise, Calif., off the map. The 2018 Camp Fire forever harmed the public’s trust. In a rare criminal case against a corporation, Pacific Gas and Electric pleaded guilty to 84 counts of involuntary manslaughter.
Since then, there have been many other massive wildfires throughout the United States, most notably in Hawaii and California. Some have been blamed directly on utilities, such as the Maui fire that destroyed Lahaina. The Palisades and Eaton fires in early 2025 in California caused an estimated $28 billion to $35 billion of insured property losses, the highest wildfire loss estimate yet in the U.S.
Grid operators and utilities no longer can afford to view climate-change-fueled wildfire risk as merely an environmental or safety issue. It’s a systemic reliability, financial and governance challenge. And it has implications for operations, investment strategy and long-term planning.
This is the third in a series of how extreme climate events affect the grid, following previous features on extreme heat and extreme precipitation.
The Climate-wildfire-electricity Nexus
While fires always have been a risk, multiple studies conclude climate change has “led to an increase in wildfire season length, wildfire frequency and burned area,” according to EPA.
The science is straightforward: Higher temperatures and longer dry seasons pull moisture out of vegetation, making it easier to burn. Precipitation that may end a drought also can create excessive growth in grasses and undergrowth, adding fuel for future fires.
Climate change also causes an increase in lightning strikes, the main natural cause of wildfires, responsible for 15% of wildfires and 60% of acres burned. That risk will continue to grow: Each 1-degree Celsius increase in global temperature increases lightning strikes by about 12%.
Grid operators and utilities have double exposure to the increasingly fire-prone environment: Grid assets can cause fires and be damaged by them.
There’s also a feedback loop when it comes to liability, particularly for investor-owned utilities, according to a report from Stanford University’s Climate and Energy Policy Program (CEPP).
“Because the economic damages from a single catastrophic wildfire can reach into the billions of dollars, the possibility that a utility could be found liable for a fire as a result of its infrastructure causing an initial ignition creates serious financial challenges for utilities,” the report said. “This makes IOUs riskier investments, which, in turn, makes it more difficult and expensive for them to access the capital needed to build infrastructure.”
Three Lines of Defense for Wildfire Risk Management
One approach to wildfire risk is to think about preventive measures, proactive response when fires happen and post-fire recovery. An IEEE paper defined these three lines of defense: “The first line of defense focuses on strategies to prevent wildfires from occurring in the first place.” It includes prediction, detection and vegetation management.
IEEE’s Three Lines of Defense for Wildfire Risk Management in Electric Power Grids | IEEE
“The second line of defense is focused on mitigation strategies and proactive response to minimize hazardous impacts of wildfires on the power system and its surrounding natural and built environment, should a wildfire spark.” This includes modeling active fires to predict their path and de-energizing lines ahead of the fire’s spread.
“Finally, if a wildfire sparks and spreads, we need a third line of defense that is focused on resilience-building measures and recovery preparedness so the system can bounce back to its pre-wildfire condition as quickly as possible without suffering devastating losses.”
This includes not only immediate temporary support, but also investing in resilient rebuilding, such as how PG&E is installing distribution lines underground as it rebuilds Paradise, Calif.
Playing Defense in an Offensive Environment
Utilities, particularly those in the West and Southwest, are taking action, particularly on the first line of defense. For example, PG&E conducts aerial line inspections using LiDAR to identify trees that need trimming. Utilities are hardening lines, replacing aged components and undergrounding selective circuits, an expensive process. In 2023, PG&E lowered the cost of its undergrounding program from $4 million per mile to less than $3 million per mile.
Mapping transmission lines against historic wildfire locations may help utilities plan. | Felt and National Interagency Fire Center data
On dry, windy days with high fire risk, utilities can preemptively power down lines. Public safety power shutoffs (PSPS) may lower risk but create public backlash when they stretch into days. It’s an example of how utilities must juggle tradeoffs between safety and reliability, as well as liability and service continuity.
Technology is helping to both monitor and manage the grid’s wildfire risk, with solutions ranging from pole-based monitoring, such as Gridware, to overhead line sensors, like those from Sentient Energy, as well as hardened components from hardware suppliers like ABB and Eaton.
Fires also complicate forecasting load and, where there are lots of solar assets, generation. “Wildfire smoke causes wiggling in the PV power output, which has the potential to impact the frequency stability of the grid,” a research paper found.
Some utilities have tried to get ahead of the financial risks, too. For example, the three largest California IOUs have started a California Wildfire Fund, with a $3 charge each month for account holders; however, the massive 2025 fires will drain funds earlier than expected. A group of policy experts proposed a national wildfire fund to spread risk across states.
While these approaches are needed, many are reactive and localized, focused on risk reduction, not system transformation.
Operating in the Heat of the Moment
When a wildfire starts, utilities must decide whether and where to power down the transmission and distribution lines. In the 2025 Altadena fires in the Los Angeles area, Southern California Edison (SCE) was criticized for powering down only four of the 12 circuits in the community.
Technology can give utilities and emergency services real-time fire monitoring and precise modeling of where and how fast the fire is likely to spread, based on satellite monitoring feeding into models that account for topography, wind, vegetation cover and more. OroraTech’s map of the spread of part of the Eaton fire shows how sophisticated this modeling has become.
Communication between grid operators and emergency services is critical, but often challenging, during a fire. The Associated Press reported that during the 2023 Lahaina wildfires on Maui, dispatchers, the local fire department and the utility, Hawaiian Electric Co., had significant difficulty coordinating. The culprits? Failing cellular networks, downed towers and separate radio channels.
Toward Climate-adjusted Grid Architecture
Utilities in areas with wildfire risk must treat that risk as a fundamental design parameter, in the same way they plan for load growth or changing generation mix.
There are questions for asset siting: Should critical lines or substations even be in fire zones? And for resilience planning: How should fire exposure be reflected in reliability metrics such as SAIDI and SAIFI? And for investment frameworks: How should regulators support preemptive resilience spending, not just post-event recovery?
The goal should be a climate-adjusted grid architecture with distributed, flexible and modular systems that can operate safely in fire-prone regions. Software, sensors and hardware solutions need to be designed to make a grid that can fail safely or self-isolate.
As remote communities consider their future resilience, the “grid edge” shifts. The main hospital in Paradise, for example, was rebuilt with an islandable 1-MWh energy storage and 425-kW solar microgrid to protect against PSPS and outages. Grid-attached microgrids and stand-alone systems should be explored for remote communities, a strategy that has worked in fire-prone remote areas in Australia, where removing the connection to the grid reduces fire risk for grid and off-grid customers.
The changing insurance and finance landscape will constrain the buildout of climate-adjusted grid architecture: Utilities are facing harder capital environments due to fire risk exposure.
From Centralized Risk to Distributed Resilience
To achieve a grid that is less likely to cause fires and more able to react to and rebuild resiliently after, there are policy levers at federal and state levels that can help.
While the federal government has reduced incentives for many types of renewables, utilities should lobby to reinstate incentives that support distributed resilience investments.
At the state level, regulators need to assess nontraditional infrastructure investments with an eye on their lifetime value, especially given that the value may be measured in not only homes but also lives saved. The gnarliest issue for regulators is how to balance cost recovery for proactive adaptation while keeping utility bills reasonable.
The Fire Next Time
Wildfire risk is reshaping the grid faster than most planning cycles can adapt. Yet for utilities and grid operators, rebuilding better after fires and getting ahead of future fires is not optional, it’s essential. Without moving from reactive defense to proactive resilience, the grid’s assets and their owners’ financial health will be at risk.
To mitigate wildfire risk and minimize future liability, utilities need to integrate climate risk — from fires, floods and storms — into every capital and operational decision. As the industry adapts to these risks, there are opportunities to develop innovative business models centered on resilience as a service. There also is a need to build cross-sector partnerships to facilitate smooth coordination with first responder groups on the ground when fires happen.
Wildfire is a risk no one wants, but it’s a reality that no longer is a seasonal hazard. Industry leaders who shift their organization’s mindsets from “compliance operators” to “resilience stewards” will be best positioned to survive in this new era.
Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience.
FERC can make large load flexibility a reality through the implementation of the Department of Energy’s Advance Notice of Proposed Rulemaking on large load interconnections, according to a recent policy paper published by Duke University’s Nicholas Institute for Energy, Environment & Sustainability (RM26-4).
The paper — “How DOE’s Proposed Large Load Interconnection Process Could Unlock the Benefits of Load Flexibility” — was authored by a group of lawyers from Roselle, a firm “focused on the energy transition,” and former FERC Commissioner Allison Clements, now with 804 Advisory.
The Nicholas Institute produced a paper on data centers and load flexibility earlier in 2025 that found just 0.5% flexibility could unlock nearly 100 GW of headroom for new data centers. (See US Grid Has Flexible ‘Headroom’ for Data Center Demand Growth.)
The ANOPR mentions flexibility as one way to increase speed to market. The paper is meant to flesh out the details of what FERC can do in the rulemaking to make its use widespread, Roselle partner and co-author Sam Walsh said in an interview Nov. 7.
“There are huge benefits potentially from these kinds of flexibility commitments, [and there are] benefits in terms of speed to power, because if you commit to a flexible operation, there may be fewer needs for upgrades [and] less capacity that needs to be procured,” Walsh said. “It’s kind of easier for the interconnecting transmission owner to bring you onto the grid, and so the whole thing should be able to be achievable on a faster timeline.”
Flexibility from large loads means other ratepayers will not be on the hook for as many upgrades as would be required by data centers and others requiring firm service at peak demand times, he added.
“What we tried to do in the paper is start to kind of roll up our sleeves. … DOE is opening the door to, No. 1, creating a new rule that asserts jurisdiction over large loads interconnecting to the transmission system,” Walsh said. “And No. 2, it is urging that load flexibility, curtailability, to be part of that. Then what are they going to actually need to do in this rulemaking to make it happen?”
The paper noted the ANOPR will set up a jurisdictional battle over interconnection of customers, which historically has been left to the states. The National Association of Regulatory Utility Commissioners is debating a resolution at its Annual Meeting on that jurisdiction issue. The meeting, which began Nov. 9 in Seattle, will conclude just over a week before the first round of comments are due Nov. 21. (See Energy Secretary Asks FERC to Assert Jurisdiction over Large Load Interconnections.)
Data centers can offer flexibility in several ways, such as by cutting energy use at the sites themselves, sending compute to another site or using on-site resources. Those can include backup diesel, which comes with issues around air permits, and co-located generation and or batteries.
“Energy supply resources may also be located adjacent to (but not behind the meter of) load, integrating with load to provide joint value (reducing net capacity market impacts for the combined load-supply pair and, largely, the transmission impact), but otherwise operating independently,” the paper says. “Data center developers have indicated that these types of arrangements are often more commercially workable than the fully integrated energy park model.”
Commitments to flexibility can be temporary on behalf of large loads so they can connect to the grid before the five years on average it takes to build a new generator or the transmission grid and distribution system are fully upgraded. Or it could be a permanent commitment.
“Both can provide value to customers: Bridge flexibility can accelerate site energization, defer major upgrades and help ensure affordability and reliability in the near term, while permanent flexibility supports enduring grid optimization,” the paper says.
FERC needs to work through several issues to make large load flexibility a reality, including rules around how often data centers would be expected to curtail and what notice they get, Walsh said.
“Similarly, if you’re going to enable flexibility to reduce upgrades, you need to have a study process that incorporates that,” he added.
Interconnection studies now take a customer’s largest load and assume it will fall on the hours that the grid is most stressed, but that will not be the case with flexible loads, Walsh said. “They would need to build in these flexibility commitments into the modeling in order to see … what upgrades might be needed and might not be needed if they operate flexibly.”
In regions with capacity markets, large loads should be eligible for at least some kind of discount, allowing them to be non-capacity-backed loads, as PJM originally proposed, Walsh said. (See PJM Drops Non-capacity Backed Load, Shifts Focus to Resource Queue, PRD.) The loads themselves will need to face requirements so that they actually curtail when that is needed, he added.
The paper argues that “FERC could consider requiring transmission providers to offer non-firm network transmission service. Such an offering would allow a greater array of hybrid facility and adjacent load-supply arrangements to facilitate additional speed-to-power benefits, perhaps using technical approaches and business models we cannot currently foresee. As more load connects to the system and load interconnection studies more frequently identify network upgrades, such service arrangements could be valuable tools in providing speed to power.”
It points to ERCOT’s “connect and manage” approach to interconnecting generators as a possible model, as it has helped the Texas market achieve faster interconnections than others.
Flexibility can help hybrid resources work, Walsh said. The ANOPR discusses such arrangements and indicates pairing supply and demand could be one way to offer hyperscale customers speed to market.
“What we’re talking about really is kind of vital to the success of hybrid resources,” Walsh said. “If you get into the paper, we talk a fair bit about making sure that flexible loads and hybrid resources have access to non-firm, injection and withdrawal rights. We think that’s really critical. There are very few data center operators that don’t also want grid access. Even if they have a co-located generator, they want grid access to ensure their uptime.”
MISO is adding Bonneville Power Administration’s former chief operating officer to its Board of Directors and welcoming back two term-limited directors in 2026 after collecting membership votes.
MISO members approved three-year terms for board incumbents Todd Raba and Barbara Krumsiek alongside Joel Cook, BPA’s former COO and senior vice president of transmission services. (See MISO Board Set to Add Bonneville Power Exec, Keep 2 Existing Members.) New terms begin Jan. 1, 2026.
Joel Cook | Bonneville Power Administration
Cook departed Bonneville in February when he took up the federal Office of Personnel Management’s buyout offer.
Incumbents Raba and Krumsiek are relying on a special waiver of MISO’s rules that allows them to serve a fourth, three-year term. Ordinarily, MISO board members are limited to three terms. This year, MISO’s Nominating Committee — comprised of three board members not up for re-election and two MISO stakeholders — recommended the use of waivers to prevent a potential 33% turnover on the board. MISO’s board is comprised of nine independent directors and MISO CEO John Bear.
Longtime board member H.B. “Trip” Doggett is vacating the seat Cook will take over. Doggett’s final official duties will be during MISO Board Week in December.
MISO membership voted electronically throughout October on the trio of candidates. MISO’s board elections require preselected candidates to receive a majority of votes in support among membership. MISO members can vote for, against or abstain from selecting any of the candidates.
Twenty-five percent of MISO membership (39 members in 2025) must vote in order to establish a quorum. MISO will release more details concerning the vote at its annual meeting Dec. 11, part of Board Week in Indianapolis.
“As MISO faces growing complexities and dynamic changes, the continuity of directors Raba and Krumsiek provides a source of strategic leadership and momentum that is critically important,” MISO CEO John Bear said in a press release. “We also welcome the new insights and perspectives from Director-elect Cook. His experience in the electric power industry will be beneficial to MISO and its members.”
Board Chair Raba thanked Doggett for his service. “His deep experience, insights and professionalism have been immeasurable during a period of extensive transformation,” Raba said.
ISO-NE’s probabilistic modeling indicates there is minimal risk of shortfall in the upcoming winter, COO Vamsi Chadalavada told the NEPOOL Participants Committee on Nov. 6.
The risk levels identified by ISO-NE’s Probabilistic Energy Adequacy Tool are well below the duration and magnitude metrics recently established by the RTO in its Regional Energy Shortfall Threshold (REST). (See ISO-NE Proceeding with Shortfall Threshold After Positive Feedback.)
The REST shortfall metrics are calculated based on the 0.25%, 21-day model cases with the greatest shortfall risk. These extreme model cases averaged a 0.1% shortfall magnitude and a 0.7-hour shortfall duration for the upcoming winter, well shy of the 3% magnitude and 18-hours criteria that would need to be exceeded to violate the REST.
Chadalavada said ISO-NE is confident it can maintain grid reliability even in the worst-case scenarios.
“The worst-case 21-day energy shortfall quantities result from a low probability combination of several uncertainties,” including low LNG and fuel oil inventories, low import levels and high levels of unexpected outages, Chadalavada said.
“In the worst cases, energy shortfall begins on Day 14 or later, thus allowing time for additional actions,” he said. “ISO expects that in the event of a forecasted energy shortfall, market-based incentives will encourage relief in the form of market response, including additional fuel replenishment.”
If ISO-NE’s 21-day forecast indicates a shortfall is likely, the RTO would have access to other emergency measures, including limiting exports, scheduling imports, seeking waivers to air permit limits and conservation appeals, he said.
Seasonal weather forecasting shows a 33 to 40% probability of above-average temperatures for southern New England, and equal changes for above average and below average temperatures in northern New England, Chadalavada said.
He said ISO-NE anticipates the tanks at the Saint John LNG terminal being full, and he added that generators with large fuel oil storage capabilities have indicated “that pre-winter replenishment is underway and supply chains are expected to be strong with adequate supply available.”
Operations Report
Energy market value totaled $429 million in October, up significantly from $350 million in October 2024, ISO-NE reported. Ancillary market value totaled nearly $17 million, more than double the $8 million total in the prior October.
ISO-NE recorded its first monthly net export in 13 years in October, Chadalavada noted.
The low import levels appear to be driven by continued drought conditions and low reservoir levels in Québec and also may be affected by Hydro-Québec’s looming baseload export commitments associated with the New England Clean Energy Connect and Champlain Hudson Power Express transmission projects.
ALBANY — The state of New York has reversed course and issued a critical water-quality permit for a proposed natural gas pipeline off the coast of New York City.
The New York Department of Environmental Conservation’s approval Nov. 7 reverses the state’s three previous denials. Hours later, New Jersey’s Department of Environmental Protection issued water quality and other environmental certifications for the same project.
The permit approvals come after public fights over offshore wind, gas pipelines and congestion pricing between Gov. Kathy Hochul (D) and President Donald Trump.
“Today’s decision is a complete reversal from their previous determinations to reject the exact same pipeline over threats to New York’s water quality,” said Mark Izeman, senior attorney for the Natural Resources Defense Council. “The proposal is the same. The law is the same. The only thing that’s changed is the politics.”
In an emailed statement, Hochul said she stood by the DEC’s decision.
“While I have expressed an openness to natural gas, I have also been crystal clear that all proposed projects must be reviewed impartially by the required agencies to determine compliance with state and federal laws,” Hochul wrote. “I am comfortable that in approving the permits, including a water quality certification, for the NESE application, the DEC did just that.”
The Northeast Supply Enhancement (NESE) project would carry natural gas 24 miles from New Jersey into New York City and Long Island across Raritan Bay. It is an expansion of Williams Cos.’ massive, nationwide gas pipeline system operated by the Transcontinental Gas Pipeline Co.
In the permit approval announcement, DEC said another project, the 124-mile Constitution Pipeline, would not move ahead. The department said Constitution Pipeline Co. withdrew its application for permits. The Constitution Pipeline was planned to cross New York into New England and was controversial with locals and many New York elected officials.
Chad Zamarin, CEO of Williams, told Politico the company was “proud” NESE was moving forward and that the company planned continue working on the Constitution project. The company revived both pipelines after receiving public support from the Trump administration.
“As governor, a top priority is making sure the lights and heat stay on for all New Yorkers as we face potential energy shortages downstate as soon as next summer,” Hochul said in an emailed statement. “We need to govern in reality.”
Trump took to Truth Social days earlier to support NESE and Constitution.
“Gov. Kathy Hochul of New York state is killing the entire region with energy prices that are out of control and expected to triple because she can’t get an upstate and separately Long Island pipeline built,” Trump wrote before condemning New York City’s congestion pricing tolls.
Earlier in 2025, the president publicly feuded with the governor over the denial of pipeline permits and offshore wind. The president moved to stop construction on Empire Wind 1 but reversed course after claiming to reach a deal with Hochul in May. (See BOEM Lifts Stop-work Order on Empire Wind.) The White House claims Hochul “caved” on natural gas while the governor’s office denies any deal was reached.
Anshul Gupta, policy and research director for New Yorkers for Clean Power, said in an emailed statement that shortly after Trump and Hochul reached an agreement, the New York State Public Service Commission found a reliability need for the NESE.
“The reasons that the PSC gave in its rushed determination of NESE’s reliability need are transparently concocted to justify the project,” Gupta wrote. “It’s a remarkable coincidence that this so-called reliability need happens to exactly meet the 400,000 Dt/day capacity of a project that was proposed more than five years ago.”
The Independent Power Producers of New York praised the decision, saying it affirmed that natural gas is a crucial resource in maintaining the reliability and safety of the New York grid. IPPNY noted that 90% of electricity generated in the city is from natural gas and oil.
“I commend the DEC for recognizing that natural gas will continue to play a key role in the state’s energy future,” IPPNY CEO Gavin Donohue said in an emailed statement. “Until zero-emissions dispatchable resources … have been identified and developed, natural gas will remain a necessary transitional component of New York’s fuel mix.”
Izeman said he’s preparing to fight the permit in court. The NRDC, Earthjustice and other groups had challenged FERC’s greenlighting of the pipeline in federal appeals court at the end of October. In an emailed statement, Earthjustice called the approval “shameful.”
LITTLE ROCK, Ark. — It took almost two months of stakeholder meetings, outreach and education, working group discussions, staff modeling and everyone’s consternation over affordability before SPP’s Board of Directors approved a 2025 Integrated Transmission Plan (ITP) designed to keep pace with accelerating load growth and ensure grid reliability.
The ITP’s portfolio includes four 765-kV projects that total 949 miles and are part of a planned 765-kV backbone, along with 46 other proposals approved for construction permits. It also comes with an $8.6 billion price tag, eclipsing the record 2024 ITP that had SPP’s first 765-kV project and a $7.65 billion cost. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.)
SPP says the 10-year ITP assessment shows the portfolio is necessary to ensure the grid is ready for future demand, citing industrial electrification, manufacturing onshoring and economic development forecasts that show the grid at its limits. The grid operator is projecting a 25% increase in demand by 2030 for its 14-state footprint and a near doubling of its peak load (56 GW) in 10 years.
The portfolio has regional benefit-to-cost ratios between 12:1 and 18:1, the highest in the RTO’s planning history.
Still, with memories fresh over a recent cost-estimate increase for SPP’s first 765-kV project, members expressed concerns over the portfolio’s expense. The board in September approved a revised cost estimate of $3.62 billion, up from an original projection of $1.69 billion in February, for Southwestern Public Service’s 765-kV project in the 2024 ITP. (See SPP Board Approves 765-kV Project’s Increased Cost.)
“It’s really hard for us at a local level to talk about affordability when the metrics in the report are region-wide. The only thing our customers see in their [bills] is their rates going up,” Evergy’s Denise Buffington said during the Nov. 4 discussion.
“We have the job over the next 12 months, probably 10 months, to go to our legislature and our governor and our customers and explain to them why 765 is important,” she added, asking for “a little grace” and time to advocate about why the 2025 ITP is the right long-term solution. “We have to get the metrics down to a local level.”
Buffington’s message and those of other members were received by the board.
“As a board, we recognize that we’re making decisions that will significantly impact every homeowner and business in SPP,” board Chair Ray Hepper said as the meeting ground on through the lunch hour. “Reliability and affordability are a really delicate balance, and we strive to do our best in making that balance, thinking like every dollar we are approving is our own dollar. We also recognize that economic development for this region and attracting new loads that can serve our national interests is a key driver for a cost-effective system that will support growth in this critical time.”
SPP Mitigation Measures
To help ease concerns, SPP staff filed a memo with the board and the Members Committee outlining their measures to mitigate risks related to the viability and cost of 765-kV projects in the 2025 ITP. The measures will apply to 765-kV projects that receive a conditional construction permit or a request for proposals. They include SPP’s commitment to analyze the proposed 765-kV overlay analysis within the 2026 ITP assessment.
Hepper then added his own requirements for SPP so the board can fulfill its oversight responsibility and help “assure that only appropriate costs for new transmission are incurred.”
“Our goal is a reliable, cost-effective transmission system that will serve the region for years to come,” he said.
Hepper directed staff to file quarterly reports with the board should there be any changes that could affect approved projects in the 2025 ITP or any future assessments. He earned a commitment from COO Antoine Lucas to work through the stakeholder process and complete the 765-kV overlay analysis as part of the 2026 ITP and determine whether further mitigation actions or changes are needed.
Finally, he ordered staff to bring to the February board meeting a plan to expedite and improve the competitive project process, including a plan to improve the evaluation of RFPs.
“You’ve created a set of off-ramps and on-ramps for projects, which makes a lot of sense because things change relative to forecasts,” director Steve Wright said.
The Members Committee’s advisory vote passed 17-3, with three abstentions. Electric Cooperatives of Arkansas, Nebraska Public Power District and Omaha Public Power District voted against the measure.
The portfolio the board approved began as an $18.1 billion package of projects that staff identified to meet 10-year reliability and economic needs. It was whittled down by deferring about $7 billion in projects without near-term needs or that could be “further optimized” within the 2026 ITP, and again by deferring two economic 765-kV projects and their $2.6 billion costs, reducing the package to its final total.
The 2025 ITP does not include another $1 billion in zonal planning criteria projects submitted for study by members.
Most deferred projects will be further evaluated in the 2026 ITP as SPP continues to study a 765-kV backbone. It says a single 765-kV line can carry four times the power of a 345-kV line, using less land and losing less energy over long distances. That makes 765-kV a more efficient, cost-effective and forward-looking solution for a growing grid, staff said.
“We’re building today for the demands of tomorrow,” Casey Cathey, the RTO’s engineering vice president, said.
Stacey Burbure, American Electric Power’s lead for transmission business development and joint ventures, applauded SPP’s decision to move forward with its 765-kV overlay. She noted AEP’s service territory includes some of the poorest parts of Appalachia, where the company has some of its more than 2,000 miles of 765-kV infrastructure.
“It’s our baby. This was the most efficient and effective way for us to serve our customers, and it remains a very effective tool in the bucket for every RTO,” Burbure said. “This is a tool that folks are turning to to solve the issues that confront us, regardless of which RTO you’re in. Is this the right outcome for SPP as a region? I think the answer is obvious. It’s yes.”
Matt Pawlowski, vice president of development for NextEra Energy Transmission, pointed out that the portfolio includes two 765-kV legs on either side of the footprint, but no road connecting the two highways. While NextEra supports the $8.6 billion ITP, it would have preferred the $11.1 billion package, he said.
“Without a connector, the systems on either side of those lines are going to be overloaded,” Pawlowksi said. “We are going to have reliability issues. If we don’t address it with the two economic projects, I think we’re really missing out.”
He said if the two economic projects are again deferred, SPP will face the danger of getting behind an “entire queue of projects in the supply chain.”
“If you defer these projects, you are totally kidding yourself. You are not going to build these projects by 2030 plus, 2035 probably at best,” Pawlowski said. “So what is preventing us from looking at those two projects and improving them as a region when staff has already said that they’re needed?”
The discussion will continue in February when the board gathers again in Little Rock for its first quarterly meeting of 2026. Hepper, who prefers to have people around the table debating issues, has canceled the original virtual scheduled meeting to further discuss in person 765-kV lines and the competitive project process.
“We are going to have some very significant decisions to talk over,” he said.
SPP Introduces CARE Team
SPP has introduced another acronym to its lexicon with the creation of the Cost Control and Allocation Review and Evaluation (CARE) Team. The cross-functional body will review, evaluate, assess and recommend refinements or alternatives to current transmission cost controls and cost-allocation methodology.
Wright and Kayla Hahn, the Missouri Public Service Commission’s chair, will co-chair the 15-person team and have already met once to discuss CARE’s scope. It has been asked to deliver a final report in August 2026.
Other members will include independent director Stuart Solomon, commissioners Chuck Hutchinson (Nebraska), Justin Tate (Arkansas) and Kathleen Jackson (Texas), and state regulatory staffers Jon Thurber (South Dakota), Jason Chaplin (Oklahoma) and Justin Grady (Kansas). Members from the Members Committee and the Strategic Planning Committee will be added later.
“The idea was, ‘Let’s get this conversation happening. Let’s have a conversation between the groups within SPP that have the organizational responsibility for allocation and cost control,’” said New Mexico Commissioner Pat O’Connell, the Regional State Committee’s president.
“So, to me, just getting all those folks together to have this conversation by itself is valuable,” he said. “I am also confident that SPP works to deliver good results, so that the recommendations will be also valuable and impactful.”
FERC has approved the 2026 business plans and budgets for NERC, the regional entities and the Western Interconnection Regional Advisory Body, along with allowing the Midwest Reliability Organization, Northeast Power Coordinating Council and SERC Reliability to tap their reserves to reduce next year’s assessments.
Commissioners accepted the budgets in an Oct. 30 filing (RR25-5). Chair Laura Swett and Commissioner David LaCerte, sworn in Oct. 20 and Oct. 27, respectively, did not participate in the decision.
NERC’s budget for 2026 is $129 million, up $5.6 million from its 2025 budget. This includes planned spending in both the U.S. and Canada, as well as $45 million for the Electricity Information Sharing and Analysis Center, up $1.4 million from the prior year. The E-ISAC budget increase reflects rising contractor and consultant costs and the addition of three positions in the areas of stakeholder engagement, security operations and intelligence functions.
Most funding for NERC’s activities comes from its assessment, which load-serving entities pay to support the ERO’s work. NERC’s 2026 assessment is to rise by $5.3 million to $114 million; this figure comprises $103 million from U.S. entities and $11 million from Canada.
The difference between the budget and the assessment will be made up with funding from other sources, including third-party funding for the E-ISAC’s Cyber Risk Information Sharing Program, the System Operator Certification and Credential Maintenance program and the E-ISAC’s partnership with the Downstream Natural Gas ISAC.
NERC CEO Jim Robb said in May that the organization is approaching 2026 as a “bridge year” between the previous three-year plan, which will conclude at the end of 2025, and a new three-year plan, to begin in 2027. (See 2026 to be ‘Bridge Year’ for NERC Budget.) Robb said the uncertainty introduced since the beginning of President Donald Trump’s second term, along with ongoing efforts such as the ERO’s work on modernizing its standards development process, made long-term planning “a fool’s errand at this point in time.”
RE Budgets, Assessments to Rise
The total planned ERO budget, including NERC, the REs and WIRAB, comes to $321 million, up from $304 million in 2025. Assessments for all entities are $290 million, up from $271 million the year before; $260 million of the total assessments for 2026 is allocated to U.S. entities.
NERC asked for, and FERC approved, an exception to Section 1107.2 of the ERO’s Rules of Procedure. The section states that funds received by NERC or REs from penalties assessed in the U.S. must be used to offset the collecting entity’s budget for the subsequent fiscal year if received by July 1, or for the second subsequent fiscal year if received on or after July 1.
The exception granted by FERC allows MRO, NPCC and SERC to deposit penalty monies received before July 1, 2025, into their assessment stabilization reserves, rather than apply them to the REs’ 2026 budgets. FERC will also permit the organizations to use penalties collected before July 1, 2024, and still held in their ASRs to reduce the 2026 assessments.
As a result of FERC’s decision, NPCC will deposit $210,000 collected in penalties between July 1, 2024, and June 30, 2025, into its ASR and withdraw $500,000 from the reserve. SERC will deposit $1.5 million in penalties into its ASR and release $2.5 million from the ASR. MRO will deposit $24,000 in penalties and release $1.6 million.
