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.
In a gubernatorial race seen by some analysts as a bellwether to the first months of the Trump presidency, voters in New Jersey’s gubernatorial primary backed a Republican vigorously pushing gas and nuclear generation to face a Democrat who favors solar to meet growing electricity needs.
Republican Jack Ciattarelli handily beat four other candidates in the June 11 primary, taking two-thirds of the vote to win by more than 45 points. He will face Democrat Rep. Mikie Sherrill, who took 34% of the vote in a six-way primary that she won by 14 points.
The matchup will determine who heads a usually Democratic state that, under incumbent Democratic Gov. Phil Murphy, emerged as one of the most aggressively progressive clean energy states and now is struggling with a predicted dramatic shortfall in electricity generation.
Jack Ciattarelli | Ciattarelli for Governor
Ciattarelli, a former state assemblyman and small-business owner and a Trump-endorsed Republican, opposes many of the clean energy policies Murphy pursued in his two terms. In his acceptance speech, Ciattarelli called Sherrill “Phil Murphy 2.0,” adding that putting her in the governor’s office would mean “four more years of offshore wind farms and rising electricity bills.”
But Sherrill, a three-term congresswoman who is a former federal prosecutor and Navy helicopter pilot, has yet to embrace Murphy’s full-on, clean energy policies, which some analysts see as contributing to Murphy’s decline in popularity. In the last gubernatorial race, in 2021, Murphy beat Ciattarelli by just three points, down from his seven-point margin four years earlier.
When he took office in 2018, Murphy launched a major offshore wind initiative, pledging to develop 11 GW of wind projects off the Jersey Shore in the next two decades, which now largely has stalled. He created a community solar program, developed incentive programs for electric vehicles and chargers, and pushed for the state to electrify buildings. He also backed the adoption in New Jersey of California’s advanced clean trucks and cars rules.
Offshore Wind Ban
How that helps or hinders Sherrill is unclear, as polls show voters are less interested in clean energy than in the past. A nationwide Pew Research Center survey released June 5 found Americans less supportive of wind and solar, mainly due to declining Republican interest.
Ciattarelli, on his website, says he will ”ban offshore wind farms from being built off our coast and along our Jersey Shore.” He has pledged to withdraw New Jersey from the Regional Greenhouse Gas Initiative (RGGI). And he would “repeal unrealistic and unaffordable state mandates and timelines regarding electric vehicle sales, household appliances, home renovation and home construction.”
He also said he will create a new Energy Master Plan that “promotes an all-of-the-above energy policy,” in contrast to the heavy promotion of electrification in Murphy’s 2019 Master Plan and again in a new draft master plan unveiled this year. (See NJ Releases Electrification-focused Energy Master Plan.)
Ciattarelli said in an op-ed that he would invest “in safe, clean natural gas and nuclear until emerging renewable energies are more practical and affordable.”
Ciattarelli, a certified public accountant, served three-and-a-half terms as a state assemblyman, after periods on the town council and as a county commissioner. He ran two medical publishing companies, one of which he founded and the other he co-founded, and has four children.
In November, Ciattarelli sent a letter to the Democratic candidates demanding they “publicly pledge that you will not seek to continue Gov. Murphy’s energy policies if elected, and you will end state support for EV mandates and offshore wind.”
Permitting Issues
In the primary campaign, Sherrill, who called Ciattarelli a “Trump lackey” in her acceptance speech, was muted in talking about her energy platform, offering few specifics. Yet she was endorsed by two of the state’s largest environmental groups, the Sierra Club and the New Jersey League of Conservation Voters, which called her the “strongest candidate” to take on Ciattarelli and said it expects her to help “achieve a 100% clean energy future by 2035.”
Sherrill, who also has four children, spent 10 years on active duty in the U.S. Navy after graduating from the U.S. Naval Academy. She was a prosecutor in the New Jersey U.S. Attorney’s office and was elected to Congress in 2018.
Sherrill has said the state “needs a comprehensive strategy to address climate change,” and pledged to take “bold action at the state level to invest in clean energy like solar, which is one of the cheapest energy sources to develop.”
When the federal government announced in January 2022 that it would auction the offshore wind areas in the New York Bight, Sherrill called it a “crucial step” in the state meeting its potential.
“Between the steps New Jersey has already taken,” and the federal government’s support for offshore wind, “New Jerseyans are sure to see the economic, ecological and energy-saving benefits of wind power,” she said in a release at the time.
She has cast the state’s inability to advance its wind projects as a “failure of permitting and regulation in our state.” The state’s first approved projects, Ocean Wind 1 and 2, fell apart in October 2023 when developer Ørsted withdraw, citing financial and supply chain obstacles.
The developer of the state’s next-most advanced project, Atlantic Shores Offshore Wind, petitioned the New Jersey Board of Public Utilities (BPU) earlier in June to terminate the Offshore Renewable Energy Certificates, saying Trump’s Day 1 action targeting offshore wind development had forced it to cancel contracts and lay off staff. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)
“Virginia has been able to move forward with an offshore wind farm that is so far along the federal government cannot pull it back,” Sherrill has said. “We, because of many regulatory and permitting problems, took way too long. That cost us.”
The state has “to get more clean power to the grid if we’re gonna drive down utility costs,” she says, but her most frequently mentioned plan is to push for increased investment in the state’s solar capacity.
Energy Shortage Forecast
The race is unfolding as New Jersey, like other states, faces what New Jersey officials and PJM predict will be a dramatic shortfall in electricity generation, in large part — according to PJM — due to the closure of fossil-fuel generators at a faster pace than clean energy sources come online. Another driving factor is rising demand growth from the shift to EVs, building electrification and the expected needs of data centers. (See N.J.’s Power Future Clouded by Data Center Uncertainty.)
That shortfall has manifested itself in a 20% hike in the average New Jersey electricity bill, which took effect June 1, and has angered legislators and squeezed ratepayers.
Assessing the race, Micah Rasmussen, director of the Rebovich Institute for New Jersey Politics, said: “I think we can expect a robust discussion about where New Jersey goes from here in terms of bolstering our supply and where we get it.”
“Jack Ciattarelli will surely be pointing the finger at Gov. Murphy,” he said. He expects Sherrill to “point out that New Jersey is far from alone in experiencing these price increases. In fact, Ohio ratepayers are facing electric hikes of the same magnitude, even though their permitting policy is decidedly an obstacle to wind development.”
Sherrill, in a recent campaign interview, blamed PJM for being slow to connect new energy sources.
“As a governor, I would hold PJM accountable, much like you see Josh Shapiro doing,” she said referring to the Pennsylvania governor, who filed suit against PJM over price hikes. The effort resulted in an agreement that PJM would cap capacity prices. (See PJM, Shapiro Reach Agreement on Capacity Price Cap and Floor.)
Sherrill has said the rate hikes are “unacceptable” to households and businesses.
“You’re going to start to see businesses move away if they have such high utility costs,” she said in an interview before the election. She pledged to be a governor who gets “power into the grid, having the amount of power we need, while at the same time driving down costs for consumers.” That would include working to “pressure regional grid operators, controlled by big oil and gas CEOs, to plug in clean energy projects to the grid,” her platform states.
Ciattarelli released an ad saying the hike is the result of “Murphy’s radical agenda.” In an interview at the time, he said he would seek to begin his term as governor by “cleaning house” at the BPU, which regulates the state’s energy sector.
Rate Mitigation
Rasmussen said Murphy — by releasing a plan to mitigate the increase for taxpayers — may have taken some of the wind out of Republican efforts to use ratepayer anger over the issue in the election. Murphy’s $430 million plan will give $100 to all ratepayers and an additional credit of $150 to low- and moderate-income taxpayers.
“Republicans had hoped customers would be feeling the pain of the recent rate increases from PJM’s annual commodity pricing,” he said.
Ray Cantor, deputy chief government affairs officer for the New Jersey Business and Industry Association, one of the state’s largest business groups, said the organization has not taken a position on Murphy’s hike mitigation strategy but is looking for the next governor to address the long-term energy capacity problem.
“Generation is the key,” he told NetZero Insider in an email. “We need to reform permit and approval systems so we can put generation online expeditiously. We have put in place policies that discourage generation, both nuclear and natural gas. That needs to change.
“We want the candidates to take realistic positions on energy. While goals are helpful to focus efforts, mandates often distort the market, increase costs and have unintended consequences. We want an all-of-the-above energy policy that encourages nuclear power and natural gas, at least until there are technologically sound and cost-effective lower carbon replacements.”
At the quarterly meeting of NERC’s Reliability and Security Technical Committee on June 10, NERC Chief Engineer Mark Lauby reminded members that the industry is facing “a busy time” dealing with the growing number of risks to grid reliability.
“Every meeting I come to, I always say this is the most important meeting we’ve had in a long time,” Lauby joked in his introductory remarks at CAISO’s headquarters in Folsom, Calif. “Of course, the RSTC is … the centerpiece of risk identification and risk mitigation, and clearly the work we have before us today is extremely important.”
The challenges “coming at [the ERO] like a head of steam” include the rapid growth of large loads like data centers and their impact on the grid, along with the reliability risks posed by inverter-based resources, which Lauby reminded attendees was the subject of several ongoing standards projects to meet FERC Order 901.
NERC Trustee Kristine Schmidt acknowledged the meeting — which kicked off three days of joint meetings among the RSTC, Reliability Issues Steering Committee and Standards Committee — represented a “heavy lift” for members and their companies. Echoing Lauby’s comments, she told attendees it was “critically important that we have your participation, leading the charge and creating such an important role for everything we do.”
The risks identified by Lauby and Schmidt ranked high on the meeting’s agenda, with Jack Gibfried of NERC’s Large Loads Task Force (LLTF) submitting for RSTC comment a white paper assessing the ability of existing engineering practices, requirements and reliability standards to address the reliability impacts of emerging large loads. Committee members will have 30 days to submit comments, starting June 13.
Gibfried said the white paper will feed into the LLTF’s next work plan item, a reliability guideline proposing best practices to address the gaps identified in the paper. He added that the task force hoped to submit the final edit of the white paper, addressing members’ comments, at the RSTC’s September meeting, hence the shortened comment period from the usual 45 days.
The LLTF white paper was the first of three accepted for comment by committee members. The next came from the Electric Vehicle Task Force (EVTF), with the goal to “identify, validate and prioritize the potential [grid] reliability risks related to motor vehicle electrification.”
EVTF members also requested a shortened comment period of 30 days for this white paper, in hopes of finishing their revisions by the September RSTC meeting. However, at the urging of Southern Company’s Todd Lucas, committee members approved a standard 45-day comment period for the paper.
NERC’s System Planning Impacts from DERs Working Group (SPIDERWG) asked for comment on a white paper analyzing the impact of DER aggregators on SPIDERWG’s model framework. The committee again approved extending the proposed 30-day comment period to 45 days.
Two more white papers, both from NERC’s EMT Modeling Working Group (EMTWG), were submitted for the committee’s approval, having completed their own comment periods and been revised according to the feedback received.
The first will help industry “enhance the understanding and utilization of EMT modeling in addressing the emerging challenges and opportunities associated with high penetration of [inverter-based resources] and changing resource mix,” according to the EMTWG. The second is meant to “highlight the typical life cycle for an IBR project and its model, use cases and challenges in the operations planning study space, typical practices and lessons learned.”
Members agreed to endorse three standard authorization requests (SARs) at the meeting as well, the first submitted by SPIDERWG. This SAR was prompted by observations of the impact on grid frequency of DER tripping from underfrequency load shedding programs.
Specifically, the SAR is aimed at establishing “consistent modeling practices as other stability depictions for the UFLS database” by clarifying terms and equations used in NERC’s standards. SPIDERWG said the clarity enhancements in the SAR are needed because “UFLS is a last measure before widespread frequency collapse.”
The other two SARs were developed to help NERC meet its obligations under Order 901, the fourth and final milestone of which — involving planning and operational studies requirements for all IBRs — is approaching next year. (See NERC Submits IBR Work Plan to FERC.) One of the SARs represents operating studies and the other planning studies.
EPA proposed repealing greenhouse gas emissions standards for power plants under Section 111 of the Clean Air Act and the 2024 amendments to the Mercury and Air Toxics Standards.
The move was widely expected, as the agency’s attempts to regulate emissions in the power sector have gone through several 180-degree reversals over the past decade depending on the party occupying the White House.
“Affordable, reliable electricity is key to the American dream and a natural byproduct of national energy dominance,” EPA Administrator Lee Zeldin said in a statement announcing the move June 11. “According to many, the primary purpose of these Biden-Harris administration regulations was to destroy industries that didn’t align with their narrow-minded climate change zealotry. Together, these rules have been criticized as being designed to regulate coal, oil and gas out of existence.”
The proposal would repeal the 2015 emissions standards for new fossil fuel-fired power plants issued under President Barack Obama and the 2024 rule for new and existing fossil fuel-fired power plants under President Joe Biden. The 2024 rule was needed because the Supreme Court struck down the first Clean Power Plan in 2022 in West Virginia v. EPA, which introduced the “major questions doctrine” as a legal argument limiting regulatory power.
Unlike other air pollutants that have a regional or local impact, the emissions targeted in the rules are global in nature. EPA is proposing that the Clean Air Act require the agency to make a finding that the targeted emissions from fossil fuel-fired power plants are significant in a global context.
“The share of GHG emissions from the U.S. power sector, including CO2, to global concentrations of GHGs in the atmosphere is relatively minor and has been declining over time,” the proposed rule says. “In 2005, U.S. electric power sector GHG emissions comprised 5.5% of total global GHG emissions. This percentage has fallen steadily since then to 4.6% in 2010, to 3.7% in 2015, and comprising 3% of total global emissions by 2022.”
Part of that decline is from the rise in GHGs in other countries, with the proposed rule saying that while domestic coal use has declined since its peak in 2007, more coal was burned globally than ever before in 2024.
A major reason that EPA tried to regulate CO2 in the first place was the Supreme Court’s 2007 decision in Massachusetts v. EPA, which held it could if it made an endangerment finding on GHGs. EPA is not trying to overturn that endangerment finding, Zeldin said in a press conference unveiling the two proposed rules.
“I don’t have anything to announce today as it relates to any proposed rulemaking that may be to come on that topic, and we will update the public as soon as we do have an announcement,” Zeldin said.
2024 MATS Amendments
EPA also proposed eliminating the 2024 updates to the MATS for coal and oil-fired power plants, reverting back to 2012 standards that drove a sharp reduction in the covered pollutants.
By 2021 mercury emissions from coal plants were already 90% below pre-MATS levels; acid gas hazardous air pollutant emissions have been cut by over 96%; and emissions of non-mercury metals like nickel, arsenic and lead are down 81%.
EPA said repealing the rule would save $1.2 billion in regulatory costs over a decade, or about $120 million a year.
Reactions to the EPA’s proposed repeals were mixed, with Democrats and environmentalists opposing them and Republicans and some industry supporting it.
Electric Power Supply Association CEO Todd Snitchler said repealing the rule will help the power industry meet growing electricity demand, which requires policies that encourage the continued operation of existing power plants and attracting new investment.
“EPA’s rulemaking requiring the use of carbon capture and sequestration technology for existing coal and new natural gas power plants nationwide was unrealistic, unachievable and poorly timed,” he said. “The United States is on the cusp of an increased level of demand for electricity, driven in part by the development of artificial intelligence, a resurgence of domestic manufacturing and electrification policies.”
The National Rural Electric Cooperative Association said the carbon rule exceeded EPA’s authority and disregarded prior Supreme Court decisions, while the MATS updates were costly with minimal benefits that would prematurely retire coal plants.
“Today’s announcements are a welcome course correction that will help electric co-ops reliably meet skyrocketing energy needs and keep the lights on at a cost local families and businesses can afford,” NRECA CEO Jim Matheson said. “These rules force power plants into premature retirement and handcuff how often new natural gas plants can run. Both of them are textbook examples of a bad energy policy that compounds today’s reliability challenges.”
Natural Resources Defense Council CEO Manish Bapna said in a statement that EPA is waving the white flag to combating pollution that harms the climate.
“Power plants are the largest industrial source of carbon emissions, spewing more than 1.5 billion tons of greenhouse gases annually,” Bapna said. “EPA claims this pollution is insignificant — but try telling that to the people who will experience more storms, heat waves, hospitalizations and asthma attacks because of this repeal. What’s more, … EPA is trying to repeal toxic air pollution standards for the nation’s dirtiest coal plants, allowing the worst actors to keep poisoning the air.”
