President Donald Trump pulled the federal government out of a deal the previous administration had signed that eventually could have led to breaching several dams on the Snake River in the Pacific Northwest operated by the Bonneville Power Administration.
Trump issued a memo June 12 withdrawing from the deal that was entered into after lengthy litigation about four tribes’ rights to fish in the river. The deal was opposed by other interests in the region including senior Republicans in Congress. (See Parties Split on Biden Administration Deal on Snake River Dams.)
The Biden administration was considering breaching four dams that produce more than 3,000 MW, but it had not made a final decision.
“The negative impacts from these reckless acts, if completed, would be devastating for the region, and there would be no viable approach to replace the low-cost, baseload energy supplied; the critical shipping channels lost; the vital water supply for local farmers reduced; or the recreational opportunities that would no longer be possible as a result of these acts,” Trump’s memo said.
The memo directs cabinet secretaries to work to withdraw from the deal and to rescind a supplemental environmental impact statement on the four dams that was published in December 2024.
The Department of Energy said the Biden-era memo of understanding (MOU) required the government to spend $1 billion to comply with commitments aimed at replacing the dams in the Lower Snake River, including possibly breaching them.
“The Snake River Dams have been tremendous assets to the Pacific Northwest for decades, providing high-value electricity to millions of American families and businesses,” DOE Secretary Chris Wright said. “American taxpayer dollars will not be spent dismantling critical infrastructure [or] reducing our energy-generating capacity.”
The Biden administration signed the deal with the Yakama, Umatilla, Warm Springs and Nez Perce tribes along with the states of Oregon and Washington. The deal supported federal investments in a comprehensive plan for salmon restoration, energy development and transportation infrastructure in the Columbia Basin, said a press release from the Confederated Tribes and Bands of the Yakama Nation.
The MOU from Biden also led to the stay of ongoing litigation under the Endangered Species Act over federal hydropower operations the federal government had consistently lost in, said the Yakama.
“The administration’s abrupt termination of the Resilient Columbia Basin Agreement jeopardizes not only tribal treaty-reserved resources but also the stability of energy, transportation and water resources essential to the region’s businesses, farms, and families,” Yakama Tribal Council Chairman Gerald Lewis said in a statement. “This agreement was designed to foster collaborative and informed resource management and energy development in the Pacific Northwest, including significant tribal energy initiatives. The administration’s decision to terminate these commitments echoes the federal government’s historic pattern of broken promises to tribes and is contrary to President Trump’s stated commitment to domestic energy development.”
The Yakama Nation is disappointed Trump withdrew from the deal, especially without prior consultation. The way the government has managed the river historically will lead to salmon extinction, Lewis said.
Sen. Ron Wyden (D-Ore.) also blasted the decision to withdraw from a deal two states and four tribes worked hard on only “to have it upended so casually from 3,000 miles away.”
“Donald Trump proves yet again his irrational preference for litigation and mindless destruction of actual achievements like this settlement agreement,” said Wyden, a senior member of the Senate Energy and Natural Resources Committee. “His approach will make life more difficult for businesses and families by upending meaningful progress to meet regional energy production, water resources and transportation needs while recovering a river and its salmon key to our part of the country.”
The National Rural Electric Cooperative Association welcomed the move by Trump, which seeks to ensure the dams are not breached.
“Hydroelectric power is the reason the lights stay on in the region,” NRECA CEO Jim Matheson said in a statement. “And as demand for electricity surges across the nation, preserving access to always-available energy resources like hydropower is absolutely crucial.”
CAISO is proposing a new method for verifying how much energy thermal resources can provide during peak conditions on California’s grid for resource adequacy purposes.
CAISO presented the proposal at a June 11 meeting as part of its resource adequacy (RA) working group, which reviews RA rules, requirements and processes for grid reliability and operations.
Under current rules, a resource’s seasonal ambient derate data is not consistently reflected in that resource’s net qualifying capacity (NQC) value. This inconsistency creates challenges in reliably operating the grid, CAISO said in its proposal. For example, a 50,000-MW peak load contains about a 4% ambient derate, compared to a 20,000-MW peak load on the system, which has about a 2% ambient derate, CAISO said.
In California, RA programs began in 2004 under the California Public Utilities Commission to ensure the state’s grid always had enough power to meet demand. CAISO’s RA initiatives are intended to complement the CPUC’s RA programs.
In the proposal, CAISO would verify an RA resource’s qualifying capacity (QC) value based on that resource’s historic outage data. The proposed method “ensures RA resources’ operational capabilities during peak load conditions are reflected in NQC values,” CAISO said in the proposal.
More specifically, CAISO would produce monthly “capability values” as part of its NQC process. These capability values represent a resource’s availability during peak load conditions, which often happen during times of high ambient temperatures.
To calculate a capability value, CAISO would review a resource’s ambient derates due to temperature during peak demand in recent years with existing outage management system data, CAISO said in the proposal. Each year, CAISO publishes RA NQC data to its reliability requirements webpage.
However, the proposed method has a “notable drawback,” CAISO said. Forced outages are “not consistently reported by resource SCs when a resource is experiencing multiple overlapping outages,” CAISO said.
To address this potential issue, scheduling coordinators (SC) could adjust proposed QC values based on site-specific generator performance information under typical peak system conditions, thereby establishing monthly capability values for thermal resources. If weather data is not available at a generator’s site, SCs could pull data from nearby weather stations. SCs then could verify that a generator’s maximum output is feasible. This maximum value could reveal the generator’s likely performance under typical peak system conditions, CAISO said.
The proposed method would apply only to thermal resources — i.e., gas, oil, coal, nuclear, biomass, geothermal and biogas fuel types — and represents resource availability during median peak load conditions, not extreme conditions.
American Clean Power-California, in comments to CAISO, said it is concerned about double counting under the proposed method. The group encouraged CAISO to avoid including historic ambient derates into NQC processes if those historical derates already are accounted for in other processes.
CAISO also considered using performance test data from each thermal generator, rather than historical data, to verify an RA resource’s QC value. However, stakeholders viewed the potential benefits of such a testing program as “providing limited value compared to the administrative costs of such a program,” CAISO said.
“Given the challenges and administrative burden of developing an NQC testing program in accordance with CAISO [tariffs], CAISO is not moving forward with a testing-based proposal,” CAISO said in the proposal.
Stakeholder comments on the proposal are due by June 25.
NERC continues to work on streamlining its slate of standards development projects to ease the burden on industry, members of the ERO’s Standards Committee heard at their quarterly in-person meeting, held at CAISO’s headquarters in Folsom, Calif.
Reviewing the standards prioritization initiative that NERC staff have been pursuing since 2023, Manager of Standards Development Alison Oswald noted that the ERO has six projects under development that are classified as “high priority.” This category comprises projects that address “significant” risks, identified by the following criteria:
subject of a NERC or FERC directive with a set due date;
identified as a priority in NERC’s work plan; or
recommended to address a specific risk by compliance feedback, stakeholder feedback or a study.
NERC’s medium-priority projects, which account for five of the remaining current standards projects, must “steadily progress but … do not include a firm timeline,” Oswald said. These efforts may be in tandem with high-priority projects, address emerging risks, seek to clarify an existing standard, satisfy regulatory directives without a set deadline or originate from compliance or stakeholder feedback or a study.
Low-priority projects “will be advanced as time and resources permit,” though Oswald emphasized that these still address real issues and their ranking is more a function of “resource management and NERC’s agile framework than an evaluation of the risk that’s being addressed.” These address standard requirements that are known candidates for retirement, corrections to existing standards or stakeholder feedback regarding a specific risk, and comprise the remaining eight active projects.
Asked by Maggy Powell of Amazon Web Services about the expectations for progress by medium-priority standards development teams, Oswald confirmed that these projects have the same level of legal, engineering and compliance support from NERC as high-priority projects. The main differences are that these efforts do not have a set timeline and may have to wait to post their standards for ballot and comment periods if high-priority projects also are up for posting.
Vicki O’Leary of Eversource Energy asked how NERC manages to keep the members of the low- and medium-priority project drafting teams engaged. In response, Director of Standards Development Jamie Calderon acknowledged that this topic is “a real concern” for the ERO, noting that “over a period of time, people need to come and go, and the longer that period of time is extended, the more people that might apply to.”
Project Votes
Calderon observed that O’Leary’s question provided a “great segue” to the first standards action on the committee’s agenda. This item asked members to approve the solicitation of nominations to supplement the SDT for Project 2017-01 (Modifications to BAL-003 — Phase II), a low-priority project to revise BAL-003-2 (Frequency response and frequency bias setting).
Calderon explained that the project had to pause along with other low- and medium-priority projects in 2023 because of the high volume of high-priority projects. During the hiatus, three team members departed the project. NERC proposed the solicitation of new members to fill these vacancies, with a focus on expertise in synchronous and asynchronous generation operations, along with representation from the Texas Interconnection and areas with high levels of inverter-based resources. The proposal passed with no objections.
Members next tackled a similar proposal to supplement the SDT for Project 2023-07 (Transmission system planning performance requirements for extreme weather). The project is in its second phase, developing a standard to provide long-term planning requirements for normal and extreme natural events, gas-electric interdependencies and events involving distributed energy resources.
Manager of Standards Development Sandhya Madan explained that of the SDT’s 12 original members, only seven could return for the second phase because of “competing work requirements.” NERC wishes to solicit replacements for the five who could not participate. This proposal also passed unanimously.
The final standards item called on the SC to reject a standard authorization request that was assigned to Project 2021-03 (CIP-002 Phase Two). This SAR was intended to address a threat to grid cybersecurity posed by communications protocol converters, but the project’s SDT determined, based on industry comments, that the SAR did not clearly define the reliability risks involved and that the request did not match the scope of the project in any case. The team recommended that the SC reject the SAR with written feedback to its creator.
This proposal also passed unanimously, though Marty Hostler of the Northern California Power Agency noted that the SAR was assigned to the team in 2023 and asked why it took so long for the team to recommend its rejection. Calderon replied that at the time, the team was also working on a high-priority SAR and did not have time to review comments on the new SAR until that work was completed.
NERC on June 12 released its State of Reliability report, which found the bulk power system remains highly reliable and underlying performance metrics such as frequency response and misoperation rates are improving or remain stable.
“Severe weather remained responsible for the most severe outages in 2024, with two significant winter storms and five major hurricanes that made landfall,” the report says. “NERC saw an improvement in performance during the winter events, with no operator-initiated load shed, in part due to industry’s efforts to improve generator performance during extreme cold weather following NERC and Federal Energy Regulatory Commission recommendations and regulatory updates.”
Hurricane Helene caused a record 431 transmission outages, but more than 95% of the outages caused by the storm were resolved within eight days, which is well below the average of 15 days seen for Category 4 hurricanes, NERC’s Jack Norris said on a press call.
An issue that continues to dominate the industry’s attention this year is the growth in data centers.
“Data centers can be developed faster than the generation and transmission infrastructure needed in the area to support them, resulting in lower system stability,” the report says. “Additionally, the voltage sensitivity and rapidly changing, often unpredictable, power usage of these facilities creates new operating challenges. As such, more accurate models of the operational characteristics of these impactful loads are essential to reliability to prevent instability caused by these large changes in electricity demand.”
Developers are not going to plan a major data center for a site that lacks enough capacity on the system to meet its needs, NERC Director of Reliability Assessments John Moura said.
“The issue is that this confidence often rests on assumptions of capacity that may not fully materialize, especially during system stress events,” Moura said. “So, the scenario we’re really warning about involves rapid demand growth outpacing the timing of new generation and transmission infrastructure. Even with a good plan, there are things that can challenge getting the infrastructure in place.”
Needed generation could get caught up in an interconnection queue or run into supply chain issues, while transmission projects could be delayed.
“Fortunately, due to the location of this 2024 event, there was no major negative impact to reliability, but as more of these types of load interconnect, the need to address this risk will continue to grow,” Norris said. Northern Virginia is home to the largest concentration of data centers in the world, so 1,500 MW of load dropping off did not impact frequency on the grid as much as it could have if the facilities were in a more isolated location on the grid, he said.
The growth in data centers caught the industry by surprise, with a sudden focus on meeting rising demand after decades of stagnant growth in most markets. FERC recently held a two-day conference on resource adequacy where that was a key issue, and the Department of Energy has been ordering power plants to keep running based on NERC’s reports of narrow reserve margins. (See Wright Addresses Recent Orders Keeping Power Plants Open at Hearing.)
Another part of the issue is that markets have incentivized narrower reserve margins as part of their design to ensure reliability at the cheapest possible price, which means avoiding the overbuilding that preceded them, Moura said. But with the new demand growth and rising prices, power plants have seen retirements pushed back.
Some retirements that were planned have been deferred, but the changing market dynamics have also improved the economics for generators that were on the edge. Now higher prices are keeping them open to help meet the rising demand, Moura said.
California regulators approved Intersect Power’s Darden Clean Energy Project, which is expected to be the largest battery energy storage system in the world when completed.
The California Energy Commission voted June 11 to approve the project, which includes a 1.15-GW solar facility and 1.15 GW of four-hour battery storage. The solar facility will consist of about 3.1 million panels.
The decision marks the commission’s first project approval under its streamlined “opt-in” permitting process.
“The transition to 100% clean electricity by 2045 requires bold, utility-scale projects like Darden,” CEC Chair David Hochschild said in a statement. “This project is significant not only for its size but its cutting-edge design and safety measures.”
The CEC reported in April that California had 15,763 MW of battery storage: 13,248 MW of utility-scale storage, 1,829 MW of residential storage and 686 MW of commercial storage. The total puts the state at about 30% of its storage target of 52,000 MW by 2045.
“The key to a cleaner, more reliable power grid is batteries – and no other jurisdiction on the planet, save China, comes even close to our rapid deployment,” Gov. Gavin Newsom said in a statement in May.
Community Benefits
Intersect Power subsidiary IP Darden I will build the Darden project on 9,500 acres of retired agricultural land in Fresno County. It will interconnect to one of Pacific Gas and Electric’s existing 500-kV transmission lines, Los Banos-Midway No. 2.
Under the CEC’s opt-in requirements, projects must deliver community and economic benefits. The Darden project will invest $2 million into the community over the next decade, starting with $320,000 to Centro La Familia Advocacy Services, a nonprofit that supports crime victims, family wellness and civic engagement in rural communities.
In addition, the project will produce more than 2,000 prevailing-wage construction jobs and an estimated $169 million in economic benefits over its 35-year lifetime.
The CEC’s opt-in certification is a voluntary process intended to streamline permitting of renewable energy projects.
Under the opt-in procedure, the CEC becomes the lead agency for permitting and state environmental review, consolidating the permitting process. The environmental review for a project must be completed within 270 days of the project application being deemed complete, unless the proposal changes significantly.
Intersect Power has another solar-plus-storage proposal moving through the opt-in certification process. The Perkins Renewable Energy Project, proposed by subsidiary IP Perkins, would be a 1.15-GW solar facility in Imperial County. It also would include up to 1.15 GW of four-hour battery storage, or up to 4,600 MWh of storage.
Another opt-in project, the Compass Energy Storage Project, was the subject of a public meeting earlier in June. The proposed 250-MW project in Southern California has drawn a slew of comments, many voicing concerns about the safety of the facility. (See CEC Considers Opposition to Compass Battery Project in Southern California.)
In a release about the approval of the Darden project, the CEC said the safety of battery storage facilities “remains a top priority.”
In 2024, the governor launched a state-level collaborative to continue to strengthen safety standards for battery storage systems. The efforts include updating the California fire code to include specific fire safety requirements for stationary lithium-ion battery storage systems.
The California Public Utilities Commission also approved new safety standards and enhanced oversight of emergency plans for grid-scale battery energy storage systems.
New York has authorized its first tranche of projects under a 2024 order that sought to address urgent existing and anticipated electric infrastructure needs as the state pushes to decarbonize transportation and buildings.
The 29 projects chosen are intended to expand capacity by 642 MW at an anticipated cost of $636 million, or about $1 million per megawatt. They were winnowed down from 65 proposals rated at 1,290 MW that would have cost $1.88 billion, or $1.5 million per megawatt of new capacity.
The Public Service Commission voted unanimously to approve the work at its June 12 meeting (Case 24-E-0364).
Most of the projects are in upstate New York, but much of the spending and much of the new capacity will come through five Con Edison upgrades in a few square miles of New York City facing immediate constraints.
Con Edison said extensive transportation electrification in an area of the South Bronx requires urgent near-term distribution system, sub-transmission and area station investments.
The area is dotted with fleet depots and service centers that serve an estimated 15,000 commercial vehicles, some of which are expected to electrify and some that already have.
There also is the largest-of-its kind Hunts Point Food Distribution Center, target of multiple electrification initiatives including a freight-focused charging facility and development of dozens of DCFC and L2 plugs.
Con Edison’s five projects would increase capacity by 380 MW at an estimated cost of $440 million.
Con Edison, National Grid, NYSEG and RG&E submitted the 65 proposals; Central Hudson and O&R indicated they had nothing “urgent.”
Department of Public Service staff rejected more than half the proposals for not meeting one or more of the evaluation criteria:
The work is needed to meet anticipated load growth from building electrification and/or transportation electrification.
Construction-related activity could start by July 1, 2026.
There is a high degree of certainty about location, magnitude and timing of load
There is demonstrated consideration of risks and benefits of the size and timing of the proposed action, and of delaying that action or not taking it at all.
The 36 proposals that did not meet all four conditions may be able to advance later on a path other than this urgent/proactive process.
“We are approving these projects today because significant grid capacity is needed to support electrification across vehicle duty classes and buildings,” PSC Chair Rory M. Christian said in a news release. “Grid constraints have already begun to limit electrification in some parts of the state. The urgent grid upgrade projects would expand grid capacity in many areas of the state, relieving urgent constraints on an accelerated basis while a broader, unified planning framework is developed.”
One project each was authorized for NYSEG and RG&E.
NYSEG’s Kent Falls project would add 30 MW of capacity at a cost of $37.1 million to support a large and expanding manufacturing facility.
RG&E’s Station 124 project in Penfield would add 47 MW of capacity at a cost of $33.2 million to address electric vehicle charging needs and growth of existing loads in the Rochester area.
PSC approved 22 National Grid proposals with a combined capacity of 185 MW and estimated cost of $126 million — most of them small, but with a few station rebuilds and other larger projects included.
Among them is an “innovative” bridge-to-wires project that involves 4.4 MW of mobile battery energy storage systems. It would address immediate constraints, support transmission electrification and provide flexibility while a substation solution is developed for the longer term. At $21.6 million, its estimated cost per megawatt is nearly five times the average of the projects authorized June 12.
The most expensive project by capacity on the list would support a load request by a depot serving a school bus fleet that is being electrified to meet a state mandate. At 2.2 MW and $15 million, it would cost $6.8 million per megawatt.
MINNEAPOLIS — MISO conceded to its Board of Directors that it should have done more to convey the danger it perceived ahead of the late spring load-shedding event in Greater New Orleans.
MISO Executive Director of Market Operations JT Smith said the April and May events were remarkably similar: The load shedding that was required in both cases avoided the potential for voltage collapse, and both events were brought on in part by tornado-ravaged transmission lines and scheduled maintenance being performed on generation in import-constrained areas.
“The spring was incredibly active. It was not one of the easiest springs I’ve seen overall,” Smith told the board’s Markets Committee on June 10. “These were not actions that were taken lightly.” He added that he understood the ensuing frustrations.
Smith said MISO has had time to reflect since the New Orleans outages and has concluded its channels of communication are lacking.
“It surprised everyone, and it should not have. We should have been more out with our membership … and let them know we were in this tight condition,” Smith said. MISO could have warned membership of its grid weakness and told members to ready long-lead load-modifying resources or notified utilities and regulators that public appeals would become necessary, he said.
“That was a failure on our part for not having that communication out there,” he said. “This is one where we probably had more insight than we shared externally, and we need to be better on that.”
However, Smith also said MISO only had a few moments before it became clear shedding load was necessary.
Speaking to the board June 12, MISO CEO John Bear said the RTO had a “challenging” spring. He said the 13 generation outages, six derates and a key 500-kV line outage on May 25 had everyone tense.
Bear said MISO is thinking through declarations and posting of transmission contingencies. He said that while it is good at communicating meager energy, it’s “not so good” at conveying transmission challenges.
A post-mortem analysis is ongoing, and MISO will discuss the event again and strategies to prevent it at the September board meeting in Detroit, Bear said.
Independent Market Monitor Carrie Milton said the load-shed event was “set in motion” much earlier in the spring when Entergy’s 500-kV line in the area was knocked out and the day prior when a conventional steam generator and large generator unexpectedly went offline. She agreed that the whole of spring was “very challenging” for MISO South.
Milton noted that the April 2 event was the result of severe weather that “parked” over the seam, compounded by planned, major transmission outages in SPP that dogged MISO operations in southwest Arkansas.
On May 25, MISO increased transmission demand curves on six different lines in an effort to entice more distant electricity supply to the area to no avail, she said.
The situation was made worse by online resources in the area that did not perform to their stated emergency ranges, she added. Milton also said MISO had no time to pinpoint which LMRs would have helped and said their lead times were prohibitively high anyway.
Milton said MISO should instate penalties for traditional resources that don’t operate according to their stated emergency output values during an emergency, similar to the penalties it assigns to LMRs. “Currently, none exist.”
MISO should also improve its locational awareness of LMRs so it knows which can help local system strain, she said.
Finally, Milton said MISO should set short-term reserve requirements for load pockets and develop a process to decommit resources that have a day-ahead schedule. Those two recommendations were included in the IMM’s previous State of the Market reports.
Transmission Planning Questions Crop up Again
Director Robert F. Lurie asked if the May 25 blackout might spur “investigations on the physical system” in southeastern Louisiana. He asked if MISO would consider expediting some planned transmission projects in the future or use a “blank sheet of paper” method to bring all ideas to the table to ease the constrained, load pocket situation.
Smith said the load pocket contained significant generation outages in addition to an inaccessible 500-kV line.
“It was a combination of so many things that got us to this point,” he said. Nevertheless, he said MISO’s planning team would run the probabilities of a similar situation occurring in the future and adjust accordingly.
In a later public comment period, the Union of Concerned Scientists’ Sam Gomberg seconded the need for probabilistic planning. He said the shifting energy mix and more erratic weather courtesy of climate change demands more probability-based plans.
Former FERC Commissioner John Norris said MISO’s tentative, 2026 start date on MISO South long-range transmission planning means the RTO would be planning regional transmission a full 15 years after Entergy joined. He reminded MISO that its core duty is planning transmission.
Now of counsel with Iowa-based Horizon Group, Norris said that in 2011, commissioners “were being gamed by Entergy,” and since then he has seen “effort after effort to stall transmission” by Entergy. He said there’s an “anticompetitive sentiment” in MISO South states and urged the RTO to recognize and “call out” Entergy’s stalling tactics, which he said include bickering over cost allocation.
Norris said given what he knows now, he would not have cast a vote for Entergy to join MISO. He said at the time, “none of us could have conceived” that it would take 30 years to get new transmission to assist the Midwest-to-South constraint.
The Alliance for Affordable Energy’s Yvonne Cappel-Vickery called on MISO to apply the same amount of transmission planning scrutiny to MISO South as it does to Midwest. She asked the RTO to ensure that “fair-weather load-shed events don’t happen in area that already has enough weather challenges.”
Cappel-Vickery reminded board members that even if MISO gets started on long-term transmission planning in MISO South within a few years, the first transmission lines won’t be energized until about 2040.
Andy Kowalczyk, transmission director at the Southern Renewable Energy Association; said the load shed delivered “a stark reminder” that MISO South needs more than a “reactive posture” to its system reliability risks. He said recent transmission projects proposed by transmission owners there seem to be reactions to risks as they crop up and not “part of a long-term vision.”
However, Bill Booth, a consultant to the Mississippi Public Service Commission, said MISO South utilities have recently invested billions in transmission projects.
The Holiday Weekend ‘Curse’
Director Nancy Lange said she appreciated MISO’s “candor” over its communication missteps. She asked if the RTO is contemplating how the region’s collection of resources could better serve the area.
Smith said that if MISO had its proposed load-modifying accreditation in place, it may have helped. MISO is seeking to sort its LMRs into fast- or slow-start designations and call up slower resources before emergencies occur. (See Stakeholders Ask FERC to Soften MISO’s Proposed DR Accreditation.)
However, Smith said he’s not sure that LMRs would have made a noticeable enough difference for MISO to avoid tapping out generation stores in the area.
“We were fighting congestion and import limitations on the southeast Louisiana system,” he said.
Director Barbara Krumsiek asked if MISO was reconsidering its usual spring outage season.
“We might be moving into a situation where planned outages in late May might have to be rethought,” Smith said. However, he said planned outages weren’t the main problem in this case. He said the unplanned generation outages coupled with the downed transmission were most burdensome.
Krumsiek asked if it was ironic that MISO’s latest emergency again occurred on a holiday weekend. MISO has a long-running joke among its ranks that sticky situations arise on long weekends: Winter Storm Elliott near Christmas 2022, Winter Storm Uri on Presidents Day weekend in 2021 and the Gulf Coast blizzard that began Jan. 20 on Martin Luther King Jr. Day.
Director Theresa Wise joked that MISO is “cursed” on holiday weekends.
At the MISO Advisory Committee’s meeting June 11, Arkansas Public Service Commission Administrative Law Judge Bridgette Frazier said that while the RTO isn’t public-facing, Louisiana regulators are; it could have sent word to them to make public service announcements.
Pelican Power’s Tia Elliott suggested MISO begin circulating one-pagers immediately following blackouts that explain in general terms the triggers and how they unfolded.
Cappel-Vickery said “it feels like a slap in the face” for MISO and Entergy to call the event rare when ratepayers in New Orleans regularly experience power outages.
“The typical consumer is not going to make the distinction that this is a transmission constraint versus this is a distribution-level event caused by, say, a squirrel,” Cappel-Vickery explained.
She asked Entergy, MISO and Cleco Power to make a plan on how to prevent reliability issues going forward.
“We need better answers than ‘we’ll improve communications,’” Cappel-Vickery said.
Beyond Memorial Day weekend, MISO said heavy storms and tornado activity beleaguered its members throughout spring. Load, however, peaked at 95 GW on May 15, the most subdued it has been in years.
MISO’s South and Central regions were under severe weather alerts for the first week of April, with MISO warning of freezing rain, cell formations, tornado outbreaks, high winds and hail. At the end of the month, all of MISO Midwest was under a severe weather alert because of thunderstorms, tornados and hail. Arkansas, southeastern Missouri and southern Indiana bore the brunt of large, long-lived storms.
MISO reported 61 GW of daily average generation outages over spring, the highest they’ve been in at least six years.
Entergy Arkansas reported a peak of 71,300 customer outages April 5 after the service area sustained five rounds of severe weather in a little more than a week. The utility reported widespread damage to substations, transmission towers, poles and wires.
Former Seattle City Light CEO Debra Smith has been nominated to join the Western Energy Markets (WEM) Governing Body, with a three-year term to begin July 1.
Established in 2016, the WEM Governing Body is the oversight board for CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the latter of which is scheduled to launch in 2026 with PacifiCorp and Portland General Electric as its first members.
The Governing Body in 2024 was authorized to begin assuming greater authority over decisions related to the two markets as part of the “Step 1” proposal by the West-Wide Governance Pathways Initiative, a multistate effort to bring more independent governance to the ISO’s markets in the face of competition from SPP’s Markets+ offering. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Tariff Amendments.)
“Ms. Smith has demonstrated wide-ranging expertise and experience that will help guide the ISO as it navigates issues relating to market rules of the Western Energy Imbalance Market and Extended Day-Ahead Market, and an increasingly changing energy and electricity market landscape,” Northern California Power Agency General Manager Randy Howard, chair of the WEM Nominating Committee, wrote in a June 11 memo to Governing Body members, who will vote on Smith’s nomination at their June 18 general session in Reno, Nev.
Smith was City Light’s CEO for five years before retiring in 2023, “leading the utility through a significant modernization program,” according to the memo. Former Seattle Mayor Jenny Durkan appointed Smith to lead the utility after it became mired in a host of organizational problems, including widespread claims of sexual harassment and cost overruns for a new billing system.
Smith began her career in the utility sector in 1996 with the Eugene Water and Electric Board in Oregon, where she rose to the position of assistant general manager. She then was chosen to head up Central Lincoln Public Utility District in Newport, Ore.
“Ms. Smith is a respected voice in both regional and national energy affairs,” Howard wrote in the memo. “She is well networked throughout the West with a deep understanding of energy markets in the region along with well established relationships and the willingness to engage proactively with current and potential WEM market participants.”
Smith would assume the seat being vacated by John Prescott, the last remaining member of the original Governing Body appointed in 2016. Prescott is stepping down after reaching the body’s limit of serving three full terms.
Campbell up for Reappointment
The WEM Nominating Committee also has recommended the reappointment of Member Andrew Campbell to another three-year term.
Campbell first was appointed to the Governing Body in 2022 and served as its chair from July 1, 2023, to June 30, 2024.
“Member Campbell works diligently to prepare for decisions and to understand ISO staff analysis and stakeholder perspectives on complex market issues that come before the Governing Body,” the memo said. “He has worked to maintain existing relationships and to build new relationships with stakeholders across the market footprint.”
Campbell is executive director of the University of California, Berkeley’s Energy Institute at Haas.
The Internal Market Monitor weighed in on ISO-NE’s proposed capacity market overhaul at the NEPOOL Markets Committee meeting June 11, expressing support for increased flexibility around resource retirement notifications and recommending the elimination of the pivotal supplier test.
The RTO is in a multiyear effort to drastically cut the time between capacity auctions and commitment periods, improve its capacity accreditation methodology and split each capacity commitment period into winter and summer seasons. It’s working with stakeholders on the detailed design of the “prompt” auction, which includes significant changes relating to resource retirements and market power mitigation.
Historically, ISO-NE has processed resource retirements through the forward capacity market, requiring retirement notifications about four years prior to the capacity commitment period (CCP). In the transition to a prompt auction, ISO-NE plans to decouple the retirement process from the capacity auction. (See ISO-NE Introduces Proposed Resource Retirement Changes.)
ISO-NE has proposed to require retirement notices two years prior to the applicable CCP. It has said this timeline would balance the need to give participants up-to-date market information with the need to provide ISO-NE enough time to pursue solutions to potential reliability issues created by retirements.
The proposal has evolved in recent months, as ISO-NE initially proposed, and then walked back, a market power penalty intended to deter participants from retiring economic resources in an attempt to increase revenues for their remaining resources. (See ISO-NE Discusses Details of New Prompt Capacity Market.)
At the MC meeting, David Naughton, executive director of market monitoring at ISO-NE, expressed support for the two-year notification timeline, saying it “reasonably balances reliability and efficient market goals.”
Differing from ISO-NE’s current proposal, and echoing requests from multiple stakeholders at the prior MC meeting, Naughton recommended allowing resources to rescind deactivation notices “should the economic outlook for the resource materially improve.”
ISO-NE has expressed concern that allowing revocable retirement notifications could allow participants to “fish” for out-of-market retentions and could undermine the market signal sent by retirements.
“Low barriers to exit and re-entry in market design are particularly important in the context of uncertainty in demand growth, new entry timing and barriers to entry,” Naughton said. The IMM detailed this recommendation in its 2024 annual markets report, which encouraged “flexibility around the exit and potential re-entry of existing resources.”
The report, released in May, noted that capacity prices in the region are “much lower” than the net cost of new entry, with low prices threatening to increase retirements of aging resources in the near-term.
“Depending on the pace and cost of new resource development, it may prove more cost-effective for the market to procure existing resources that can be reactivated, rather than relying solely on new entry,” the IMM wrote in the report.
Naughton advocated for a defined “revocation window” for retirement submissions and a clear process for determining whether changes in market conditions warrant rescinding the retirement request. He also recommended that ISO-NE eliminate the capital investment threshold for resource repowering, which would make it easier for retired resources to reenter the market.
Market Power Mitigation
Regarding the mitigation of market power in resource retirements, Naughton said the IMM evaluated three potential approaches: implementing a market power charge, continuing the current framework of proxy supply offers and relying on referral to the FERC Office of Enforcement.
He said the IMM prefers the market power charge approach, but said extending the status quo to the prompt auction format would be “adequate to safeguard consumers.”
The market power charge approach, Naughton said, provides the “strongest deterrent to exercising market power” and would be more likely to deliver “efficient price formation for current and future auctions.”
Continuing the practice of using proxy supply offers for resources that fail IMM conduct and benefits tests would protect customers from high prices in the year following an uneconomic exit but may not prevent impacts beyond that year, Naughton said.
At the May MC meeting, ISO-NE said it remains interested in a market power charge in the long term but said it does not plan to pursue the mechanism in the first phase of its capacity auction reform project, citing concerns about unintended effects expressed by multiple sectors.
To prevent market participants from exercising seller-side market power, the IMM has recommended that ISO-NE replace the existing pivotal supplier test with a “conduct and impact test framework.”
Under the current rules, if a participant fails a pivotal supplier test and a conduct test, it is held to a binding price set by the IMM. The IMM wrote in its annual report that a conduct and impact framework would more accurately evaluate and more consistently mitigate market power.
“While the market is currently long on capacity and the ability to unilaterally exercise market power is low, adopting an impact test is robust under all supply/demand conditions,” the IMM wrote, adding that as the balance of supply and demand tightens, reliance on a pivotal supplier test “could result in the over mitigation of resources.”
Winter Markets Report
Also at the MC meeting, the IMM reported that wholesale market costs more than doubled in the past winter compared to the prior winter, increasing by about $2.4 billion. A mild winter in 2023/24, followed by the coldest average temperatures in decade in 2024/25, was the root cause of this dramatic price swing, said Dónal O’Sullivan of the IMM.
Consistently cold weather caused high gas demand, which drove up energy market costs and increased reliance on oil generation and imports compared to the previous winter, O’Sullivan said. The markets performed well throughout the season and the region did not experience any scarcity conditions, in part due to the lack of extended stretches of extreme cold weather, he added.
O’Sullivan noted that ISO-NE’s inventoried energy program (IEP), which compensated generators for maintaining stored firm fuel on-site over the past two winters, did not have a measurable effect on the region’s fuel storage levels. The program expired this year, and ISO-NE appears unlikely to revive it in the upcoming years. The program cost about $78 million for the past winter, similar to the cost in the previous winter.
“The equivalent of 4,900 MW per hour of natural-gas-backed generation participated, although it is unclear whether these resources procured additional fuel as a result of their participation,” O’Sullivan said. “Oil replenishment was 50% lower than the year prior to IEP implementation, despite similar oil generation.”
ERCOT stakeholders wasted little time in discussing and unanimously approving a revision request (NPRR1238) during a June 12 webinar that it had tabled in May.
Technical Advisory Committee members spent more than two hours debating the measure during the May meeting. During the June 12 call, they spent a little more than 15 minutes considering additional comments and approving the NPRR.
“My over-under was actually more in the 30-minute range, so this is really exceeding my expectations,” TAC Vice Chair Martha Henson said in facilitating the webinar.
The revision request and its related change to the Nodal Operating Guide (NOGRR265) would register loads that can curtail under certain system conditions so they can be accounted for differently in load-shed tables. The NPRR was tabled until the Texas legislative session ended June 2 in case further revisions had to be made to the measure.
The Texas Industrial Energy Consumers advocacy group filed comments June 5, noting that a utility does not have a “unilateral right” to require a customer to commit to being controllable to be interconnected. It said without making the curtailable load voluntary, the NPRR would need to be revised to define what qualifies as “curtailable.”
“It can’t be mandatory,” said attorney John Russ Hubbard, representing TIEC. “It’s voluntary to register once you are part of a voluntary, early curtailable load. It is mandatory to comply with ERCOT instructions. We think this squares nicely with [state law], and it also squares with Senate Bill 6.”
ERCOT staff and Golden Spread Electric Cooperative, the NPRR’s sponsor, also filed comments. They agreed with Hubbard, leading to the 29-0 approval of the measure.
