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December 17, 2025

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WECC Report Highlights Larger Loads, Longer Emergencies

Peak demand in the Western Interconnection hit a record high of 168.2 GW in 2024, reflecting “early effects” of the growth in large loads such as data centers, according to a new WECC report.

Peak demand in the interconnection has grown 8.5% since 2015, when it was 155 GW. The 2024 peak demand, reached on July 10, was the fifth time in the past 10 years that a new record has been set.

Annual demand also set a new record in 2024 of 926,000 GWh.

“Demand growth is higher today than at any other time in the last 20 years,” WECC said in its 2025 State of the Interconnection report, released May 22.

Large-load challenges have been the topic of WECC webinars in recent months, and the organization commissioned a report from Elevate Consulting on large load risks in the Western Interconnection. (See IBR Lessons Can Guide Data Center Challenges, WECC Report Finds.)

WECC’s State of the Interconnection report highlights the large load experience of Arizona Public Service (APS), which expects its annual energy needs to grow by almost 24 GWh between 2023 and 2038. The utility attributes nearly 80% of that growth to data centers and large industrial and manufacturing facilities, especially semiconductor chip factories.

From 2023 to 2031, APS expects nearly 40% growth in its annual peak demand.

Forecasting Issues

The unprecedented growth in demand is creating forecasting challenges, WECC said.

At the interconnection-wide level, annual demand forecasts have been close to actual demand for the past five years, WECC said. But some balancing authorities seem to be better at forecasting than others, according to the report, which pointed to an unnamed BA that had forecasts averaging 32% over its actual demand in all forecast years. And forecasts from other BAs sometimes turn out to be less than actual demand.

“It could be a concerning indicator that demand forecasting practices vary widely,” the report said.

To meet the growing demand, resources are being built at a faster rate. More than 24 GW of new resources were added in 2024, far more than the 10-year annual average of 7.4 GW. The 24 GW represented 80% of the new resources planned to be built last year.

“The West will have to build at the 2024 rate at least to meet forecast demand,” the WECC report said.

Of the new generation added last year, 5.5 GW was natural gas. About three-quarters of the new additions were inverter-based resources: 8 GW of solar, 3 GW of wind and 7 GW of battery storage. That brought the interconnection totals for solar, wind and battery storage to 44 GW, 39.3 GW and 16.7 GW, respectively.

The WECC report also tallied system events across the Western Interconnection.

The number of energy emergency alerts (EEAs) rose sharply, from 21 in 2023 to 30 in 2024. Last year’s total included 18 Level 3 EEAs, the most serious of the three levels in which rolling blackouts may be deployed. Nearly half of those events took place in January 2024 during winter storms Heather and Gerri.

EEAs also lasted longer in 2024. EEA-1 events, in which energy conservation is called for, averaged 4.47 hours last year compared to 1.94 hours in 2023.

The average duration for all EEAs was 4.28 hours in 2024 compared to 2.47 hours the previous year.

“Extreme weather (variability and extreme temperatures) continues to be the biggest driver of EEAs across the interconnection as it leads to surging demand and the potential to impact generation,” WECC said in the report.

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SERC Outlines Gas-electric Issues for State Regulators

Speakers at a SERC Reliability-hosted webinar urged state lawmakers, policymakers and regulators to do their part to promote coordination between the natural gas and electric industries to reduce the risk of serious grid incidents like those that occurred in the winter storms of 2021 and 2022. 

SERC held the webinar to provide state-level stakeholders with an overview of the increasingly interdependent gas and electric systems — a topic that has sparked concern in the ERO Enterprise — and suggest ways they can help with the stress during times of increased demand, especially extreme cold periods when gas is needed for electricity generation and home heating. 

Marty Sas, SERC’s manager for reliability assessment, shared some of the regional entity’s concerns in its most recent Regional Risk Report. Sas warned that the ongoing replacement of coal-fired generation by intermittent resources like solar and wind generation has led to “an increased dependency on natural gas” for dispatchable energy. 

“That increases some vulnerability to supply disruptions. Limiting fuel flexibility can threaten generation availability,” Sas said. “Diversifying our fuel mix and enhancing infrastructure resilience are key actions that need to be taken as we move forward around these ever-changing resources and the dependency on natural gas.” 

Heather Polzin, SERC’s senior reliability adviser, added that the gas system also relies on electricity. She cited a 2023 study by Carnegie Mellon University noting that about 10% of pipeline compressor stations in the U.S. are electric-powered “and thus vulnerable to electric power outages.” The study suggested that an outage at one such station “can significantly reduce gas available to downstream generating stations,” leading to outages “as large as or larger than the most severe single-cause failure currently considered in electric reliability planning.” 

Polzin said the topic of gas-electric coordination is particularly prominent for SERC, which “is roughly 50% reliant on natural gas-fueled generation.” In some areas, this dependence is even greater: 75% of the generation in Florida is gas-fired, Polzin said, and nearly 68% of generation in MISO South is gas-fired. The presence of oil and gas refineries in the region presents another challenge. 

“We certainly think of [this] a lot as a winter problem, because of that competing demand with home heat, and you don’t have that in the summer,” Polzin said. “But one of the big risks that we have in the summertime is that over 50% of the [U.S. natural gas] refining capacity is on the Gulf Coast. … Even if a hurricane is not going to be a direct hit, [refineries] often will close down pre-emptively to protect the refining capacity. So that’s one big issue.” 

The speakers reviewed some of the recommendations from FERC and NERC’s joint reports on the 2021 and 2022 winter storms, which included requiring natural gas infrastructure operators to maintain cold weather preparedness plans and creating regional natural gas reliability coordinators similar to the ERO Enterprise. They suggested that regulators and policymakers improve their awareness of their states’ electric and gas systems. 

“Is your state one of the five states that provides about 70% of all the total [U.S.] dry natural gas production?” Polzin said, referring to Texas, Louisiana, Oklahoma, Pennsylvania and West Virginia. “Do you know the percentage of the generation resources in your state that rely on natural gas? [SERC] can help you with this information. And do you know which natural gas pipelines your state relies on to produce electric energy, whether they’re interstate or intrastate pipelines, [and] what difference does it make? We can also help with this.” 

Sas emphasized that gas is likely to remain a major part of the generation mix because of its usefulness for providing reliability services. However, he urged listeners to pursue policies that promote diversity of resources while encouraging “cross-sector coordination between gas and electric utilities” and maintaining an awareness of regional risks as outlined in the ERO’s annual risk reports. 

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WestTEC Tx Study on Track Despite Delays

The Western Transmission Expansion Coalition (WestTEC) is on track to publish the first phase of its transmission planning study this summer despite some delays in finalizing the models that will underpin the study, coalition members said during a May 27 webinar.

The goal of the study is to produce transmission portfolios for 10- and 20-year planning horizons. Models related to both planning horizons have been delayed by a few months, Keegan Moyer, a partner at Energy Strategies and consultant for WestTEC, said during the presentation.

Moyer said the delays are not to be “totally unexpected” given the study’s “scope and ambition.”

“We were going to have results around now from the preliminary analysis,” Moyer said. “The models are still being finalized, so we are expecting to have a better understanding of what we’re seeing in the 10-year time frame in the next two to three months. We still think we’re going to be roughly on time for the report focused on that 10-year horizon, which will be issued in the late summer, kind of early fall, time frame.”

The 20-year horizon is similarly delayed but “overall on track for the project as a whole,” he added.

The 10-year plan originally was scheduled to be published in August 2025 and the 20-year horizon study in September 2027.

The WestTEC study, jointly facilitated by the Western Power Pool and WECC, will address long-term interregional transmission needs across the Western Interconnection. The WestTEC Steering Committee unanimously approved the project’s study plan in September 2024. (See WestTEC Committee OKs Plan for ‘Actionable’ Tx Study.)

The study will include a reference case based on anticipated trends in load growth, technology and policy in transmission planning. The reference case assumes a 2.2% annual load growth between 2024 and 2045.

The scenario planning subcommittee also is developing two separate cases, labeled “flux” and “core,” to be included in the 20-year horizon, according to the study plan.

The flux case represents a high-growth scenario that reflects rapid changes in power demand and technology innovation in areas like artificial intelligence, wind, solar and energy storage. The annual load growth under the flux case is 3%.

The core case, meanwhile, includes a moderate-growth scenario with select technology breakthroughs and a 2% annual load growth, according to the May 27 presentation.

The technologies in the core case “are sort of advanced geothermal, nuclear, [small modular reactors], carbon capture, these types of technologies with a lower level of load growth and an assumption that there’s some statutory delays,” Moyer said.

“The goal with these two scenarios and the reference case is to create divergent futures,” Moyer said. He added that “there are a wide range of futures that should definitely produce some interesting modeling results.”

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FERC Approves PJM 2024 RTEP Cost Assignment

FERC has approved PJM’s proposed cost allocation for $6.7 billion in transmission upgrades included in the first window of the 2024 Regional Transmission Expansion Plan (RTEP). (See PJM Board Approves $6B in Grid Upgrades.) 

The allocation was opposed by the Maryland Office of People’s Counsel (OPC), which argued the need for more transmission is driven predominantly by data center growth in northern Virginia and that saddling Maryland ratepayers with $789 million, or 16.4% of the total cost allocation, runs against cost-causation principles. It stated that the Dominion locational deliverability area (LDA) is forecast to grow by 44% by the 2029/30 delivery year, whereas the Baltimore Gas and Electric (BGE) and PEPCO zones are expected to remain flat or see minor growth. 

“The vast majority of the [Window 1] facilities will not be in Maryland, nor are they required to serve Maryland loads. Yet the Maryland LDAs will receive a disproportionate ‘spill over’ of cost responsibility because of how the (solution-based distribution factor) cost component operates under the PJM tariff’s method for determining cost responsibility for regional transmission projects,” the filing said. 

“The costs are driven by the unprecedented context of huge, forecasted data center load growth in northern Virginia and how that growth impacts the PJM tariff’s method for allocation of cost responsibility,” the filing said. “Moreover, these unjust and unreasonable impacts on Maryland customers will continue in future RTEPs, as PJM pursues future procurements of transmission facilities through the RTEP process in response to continued forecasts of huge load increases in the Dominion LDA in future years.” 

While the OPC objected to the figures PJM calculated, the office nonetheless acknowledged the RTO had followed its tariff in the filing. PJM responded to the OPC comments stating that its arguments are out of scope. 

“[OPC] is mindful that this is not the proper proceeding in which to challenge PJM’s cost allocation under its approved tariff. [OPC] reserves its rights with respect to possible additional remedial measures required to address these infirmities in the PJM tariff as it is being applied.” 

The commission’s May 27 order found PJM had properly followed its tariff and said the OPC arguments are beyond the scope of the proceeding. 

“Challenges to the PJM tariff cost allocation provisions are appropriately raised through separately filed complaints and not through protests to the reports of cost responsibility assignments,” the commission wrote. 

The most significant components of the work would expand the 765-kV network from the John Amos substation running east to a new facility, Rocky Point, located near the Doubs substation in Frederick County, Maryland. Another 795-kV to the south would run from Joshua Falls to a new Yeat substation, with a 500-kV loop branching off from North Anna, through a new Kraken substation and into Yeat. 

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MISO Going for 2nd Attempt to Fast Track Power Plants in Queue

MISO confirmed it will make a second bid to FERC to establish a temporary fast lane in its interconnection queue, this time limiting the process to a total of 50 generation projects.

The new, 50-project limit would stand to reduce the number of quarterly cycles MISO ultimately accepts in the expedited process. MISO also would limit the number of projects it studies per quarter to no more than 10.

FERC in mid-May turned down MISO’s proposed express lane, saying MISO failed to establish standards on which projects may enter based on resource adequacy needs and failed to control how many projects could line up for expedited treatment. (See FERC Rejects MISO’s Interconnection Queue Fast Lane.)

Previously, MISO planned to open up to 14 quarterly submission windows to an unlimited number of projects through the end of 2028.

“FERC gave us good guidance on what is necessary to refile,” Director of Resource Utilization Andy Witmeier said at a May 28 Planning Advisory Committee meeting when announcing the intention to refile.

MISO plans to submit a fresh proposal to FERC by June 6, which would request an Aug. 5 effective date. The RTO is forgoing a usual stakeholder comment period on edits to the refile.

Witmeier said the 50-project limit is based on PJM’s Reliability Resource Initiative and said FERC appeared to be “comfortable” with that figure. He also said MISO has been coordinating with the Organization of MISO States (OMS) and individual state regulators to put finishing touches on the filing.

MISO now would require that projects and their correlated resource adequacy needs be within the same local resource zone. Developers must submit the specific load addition or capacity shortage their project would address, with MISO publicly posting those associations.

The RTO also is stipulating that the interconnection service of the projects should not exceed 150% of an identified megawatt need.

Regulators now must “verify instead of notify” MISO as to how projects will meet a resource adequacy need, Witmeier said.

He said the new project maximum and regulator verification will eliminate the open-ended number of projects and better describe how projects will meet anticipated generating shortfalls.

“There are no real changes to the process. These are just guardrails and gaming requirements,” Witmeier told stakeholders.

Witmeier said the expedited process should wrap up sooner than it would have under MISO’s first proposal.

“It’s possible that we’re done by 2027 or late 2026. … I suspect we’ll have our 50 projects by the time 2027 comes into play,” Witmeier said. “We’re proving that this is not a new queue and will address immediate needs.”

Because of FERC’s initial rejection, MISO would accept project applications under a second try through Aug. 11 and kick off its expedited studies for the first cycle Sept. 1 instead of the originally planned late May.

Wisconsin Public Service Commissioner Marcus Hawkins contradicted MISO’s characterization that OMS is working in close collaboration with it on the revised filing. Hawkins said aside from previewing a MISO draft of the regulator verification of projects, “most of the proposal we’re seeing for the first time.”

“OMS really can’t work in a 14-day time period. That’s just not how we work. … It’s not possible to have OMS coordination on this new filing.” Hawkins said. He explained that decision-making in OMS involves multiple check-ins and bringing several parties up to speed on issues.

Witmeier said he understood the OMS board setup and agreed that scheduling obstacles would preclude the organization from full participation before the refiling target date.

Stakeholders said they worried that disparities among states’ methods for substantiating resource adequacy needs would result in expedited projects spread unevenly throughout the footprint.

Witmeier said it was possible a state would never justify a project for the fast lane while other states would recommend multiple facilities. He repeated several times in his presentation that MISO is not a resource planner.

Clean Grid Alliance’s David Sapper said he’s concerned about the 150% threshold beyond stated needs. He said such a large margin would be anti-competitive and discriminatory and could introduce network problems.

“It’s that margin that’s not balanced that could change import and export limits in ways that are not good for reliability,” Sapper said. He also said MISO’s in-zone requirement would unfairly elbow out suppliers from other zones.

“That’s a biggie. We need to think about this need determination,” Sapper said.

Sustainable FERC Project’s Natalie McIntire questioned why MISO would use interconnection service instead of a megawatt value to set the 150% threshold.

Other stakeholders said they didn’t see how the proposal wouldn’t again exclude Illinois’ and Michigan’s retail choice areas, where competitive markets, not vertically integrated utilities, ensure resource adequacy. MISO would open the fast lane to interconnection customers with power purchase or other agreements in addition to load-serving entities with self-supply acknowledgments and projects in the existing queue wishing to transfer to the express lane.

Finally, stakeholders asked if MISO would consider exceptions beyond the 50 projects.

“We certainly believe that this will meet our current needs and meet FERC’s requirements. Beyond that, we don’t see a need for extension,” Witmeier said.

It’s unclear if MISO’s project cutoff and documented resource adequacy requirements will be enough to quell clean energy groups’ discrimination complaints about the first proposal. The Natural Resources Defense Council, Sierra Club, Sustainable FERC Project and Union of Concerned Scientists were among the groups challenging the design the first time around.

Following FERC’s rejection, the Sierra Club said MISO’s “discriminatory plan” would have favored gas plants at the expense of the approximately 200 GW of wind and solar generation and battery storage currently in the MISO interconnection queue.

“It’s good to see FERC taking a deep look at extreme proposals like MISO’s here. Interconnection fast-track proposals … are fundamentally discriminatory, and the commission made clear that discriminatory tools should only be used to address the most severe emergencies. MISO failed to demonstrate such an emergency here, and its policy was not well tailored to meet one,” Sierra Club Senior Attorney Greg Wannier said in a statement.

Wannier said Sierra Club planned to engage in MISO’s stakeholder process to “address the serious concerns raised by commissioners and stakeholders and come back with a targeted solution.”

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NERC Compliance Director Clarifies New Abeyance Rule

A recently introduced policy allowing more flexibility in the ERO’s compliance monitoring and enforcement process should provide registered entities needed flexibility in some circumstances, NERC Director of Compliance Assurance and Certification Lonnie Ratliff said at ReliabilityFirst’s monthly Technical Talk with RF webinar May 27.

However, he warned, utilities should expect the new abeyance measure to be applied sparingly and not see it as “a free pass” on compliance.

NERC first proposed allowing abeyance periods for select standards in a supplement to its five-year performance assessment submitted to FERC in 2024. Described as a way to “streamline the standards development process” by addressing “stakeholders’ considerations of compliance risk,” the policy would allow the ERO to set a length of time following the adoption of a new reliability standard in which some types of noncompliance may be processed in ways other than compliance violations, including “standards development feedback or implementation [of] lessons learned.”

Ratliff urged attendees of the RF webinar to keep in mind the limits of the new policy. He emphasized that for standard drafting teams, “abeyance and abeyance language isn’t a reason to write a subpar standard.” NERC’s proposal states that SDTs do not have input into whether a standard includes an abeyance period; instead, NERC staff and the regional entities will decide on a case-by-case basis whether the standard is a candidate for such action and how much time is appropriate. This language will be inserted in the “Compliance” section of each standard.

For utilities, abeyance is “not a free pass [or] an extension of the implementation plan,” Ratliff said. Abeyance also will not apply to all standards projects, only to those dealing with high-priority projects creating a new standard or extensively modifying an existing standard, and where the project involves:

    • new technology required to implement the standard;
    • emerging reliability issues for which best practices have not yet been identified; or
    • high levels of technical complexity.

“If a standard is effective and enforceable, we will continue to monitor as every other standard,” Ratliff said.

The ERO put the abeyance proposal into practice with EOP-012-3 (Extreme cold weather preparedness and operations), submitted for FERC approval in April with a planned effective date of Oct. 1. (See NERC Board Approves Cold Weather Standard.) In its petition for approval of the standard, NERC proposed a two-year abeyance period beginning on the standard’s effective date.

During this period, the ERO will not pursue enforcement actions against entities for failure to comply with requirement R1, section 1.1 of the standard, which mandates that generator owners calculate the extreme cold weather temperature for each of their applicable generating units.

NERC explained that some stakeholders had expressed “concerns about how to perform this calculation when their available datasets may have missing or invalid hourly values,” and it wanted GOs to rest assured they would not be penalized for an incorrect calculation when they were “acting in good faith to comply with the standard.”

“This compliance abeyance period [will] encourage entities to share observations and experiences through implementation of new standards without fear of potential noncompliance … to mitigate reliability risks,” NERC said. “This feedback loop [will] collectively be used to inform the standards development process … to revise the standards prior to full enforcement.”

Ratliff encouraged attendees to take the EOP-012-3 abeyance period, and those in any future standard, not as a signal of easy enforcement, but as an indication the issues identified need significant attention. He advised entities to work with their peers and the REs to share their concerns and ideas about how to approach compliance so they will be prepared when enforcement starts.

Addressing a question about abeyance periods that he said he gets often, Ratliff said the new policy applies only to new standards going forward. NERC will not examine existing standards with confusion about their requirements to see if abeyance periods should be added.

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D.C. Circuit Affirms Rejection of N.Y. Transmission Owners’ Request for Self-funding

The D.C. Circuit Court of Appeals on May 27 denied a petition by New York Transmission Owners seeking to overturn a FERC decision rejecting their request to be able to self-fund network upgrades (21-1256). 

A three-judge panel of the court found that FERC “adequately” and “reasonably” explained its rationale for rejecting the TOs’ complaints in 2021 and affirming that decision in 2022 (EL21-66, ER21-1647). (See FERC Upholds Denial of NYTOs’ Cost Allocation Complaint.) 

The TOs had filed two complaints simultaneously under Federal Power Act sections 205 and 206 seeking to change the NYISO tariff to allow them to fund network upgrades on their lines. They argued that the ISO’s current rules, which give generators the right to fund the upgrades needed to interconnect to the grid, impose risks on them for which they are uncompensated. 

Key to FERC’s rejection of the TOs’ arguments in its Section 205 complaint was that risks themselves are not costs, for which they could be entitled to recover under the FPA and the NYISO-TO Agreement. The TOs already recover the costs associated with maintaining and operating the upgrades; the costs of managing and mitigating risks are not “reasonably incurred costs” as defined by the agreement, FERC ruled. 

The court reiterated much of FERC’s reasoning in its order. 

The TOs “did not aim to recover ‘reasonably incurred costs,’” it wrote. “They do not identify any expense they have actually incurred that is uncompensated. Instead, the owners argue that the rules governing upgrade funding should be changed to compensate them for ‘risks’ associated with owning and operating the upgrades. That framing illuminates the owners’ true goal: They hope not to recoup costs already ‘incurred,’ but to anticipatorily recover potential costs that have not yet materialized.” 

The court also rejected the TOs’ “rebrand” of their risks in their judicial appeal as the cost of capital, which they argued should be treated as recoverable. But “the cost of capital is not an expense that the owners shoulder by virtue of operating the transmission grid,” it wrote. “Neither ‘risks,’ nor the ‘cost of capital’ that reflects those risks, are relevant to identifying a utility’s incurred costs.” 

In examining the TOs’ Section 206 complaint, the court found they were “no more successful in challenging FERC’s dismissal.” It said they had not demonstrated that the NYISO tariff was unjust and unreasonable, and that “the commission fully and reasonably addressed” their arguments. 

“FERC consistently explained that its ratemaking approach includes an ‘enterprise-wide’ risk calculation that compensates the owners for any such risks they face,” it wrote. 

The commission is currently examining TO self-funding in other RTOs. It issued an Order to Show Cause in 2024 to MISO, PJM, SPP and ISO-NE, telling them explain how the practice is just and reasonable, as it potentially favors TOs over interconnection customers (EL24-80). (See FERC Issues Show-cause Order on TO Self-funding in 4 RTOs.) 

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Imperial Irrigation District Inks Agreement to Join CAISO Markets

The Imperial Irrigation District (IID) has agreed to join CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), the ISO announced May 27.

CAISO said the publicly owned utility, based in Southern California’s Imperial County, has signed implementation agreements and will begin participating in the markets in 2028.

In a separate announcement on May 20, IID said its board of directors approved a $24 million budget amendment “to advance preparations for joining” WEIM and the soon-to-be-launched EDAM. The money will fund upgrades to the utility’s control infrastructure, telecommunications, metering and energy management systems, according to the announcement.

“As a large public power provider in California, IID is pleased to join both the Western Energy Imbalance Market and the Extended Day-Ahead Market,” Jamie Asbury, general manager at IID, said in a statement. “This is a significant step toward modernizing how we purchase and manage power, which will translate into savings for our ratepayers annually by giving us the ability to react much faster to energy market conditions. This also aligns IID more closely with emerging regional energy practices yet allows us to retain our independence as an energy balancing authority.”

IID serves about 165,000 customers in service territory covering 6,611 square miles that includes California’s Imperial Valley and parts of San Diego and Riverside counties. The utility controls about 1,100 MW of generation, including contracted resources, and operates more than 1,800 miles of transmission and 5,000 miles of distribution lines.

CAISO noted that when IID begins participating in the markets, “it will mark the first time all California balancing authorities are participating in ISO-operated electricity markets.”

The agreement between IID and CAISO comes shortly after California publicly owned utility Turlock Irrigation District announced it would join EDAM in 2027. PacifiCorp and Portland General Electric have agreed to begin participating in EDAM in 2026, with the Los Angeles Department of Water and Power and the Balancing Authority of Northern California set to join in 2027. (See LADWP Gets Board’s OK to Join CAISO’s EDAM and Turlock Irrigation District to Join EDAM in 2027.)

PowerWatch (formerly BHE Montana), PNM, NV Energy, Idaho Power and Arizona G&T Cooperatives have indicated they’re leaning toward EDAM as their preferred day-ahead market choice.

Changed Perspective

IID’s decision also is significant because of the district’s at-times contentious relationship with CAISO — and its past opposition to “regionalizing” the ISO.

In July 2015, IID filed an antitrust suit in the U.S. District Court of Southern California contending CAISO had gained monopoly power over the state’s transmission services and operations markets.

The suit alleged that — through a series of memos and public statements made between 2011 and 2014 — CAISO had “induced” IID to make $30 million in upgrades to Path 42, one of two transmission lines linking the utility district with the ISO.

CAISO had estimated the improvements would increase IID’s maximum import capability (MIC) into the ISO from 462 MW to 1,400 MW, but later downgraded the MIC to the previous level, citing closure of the San Onofre nuclear generating station as the reason for its decision, which IID contested. (See Federal Judge Upholds Imperial Irrigation District Suit Against CAISO.)

The two parties reached a settlement in the suit in 2018 after the ISO approved line upgrades that would allow more renewable energy to flow into the ISO from the utility’s service territory.

IID also opposed CAISO’s previous efforts to expand into an RTO, initiating a separate lawsuit in 2016 seeking to force the grid operator to publicly disclose protected information related to ISO-commissioned studies supporting regionalization.

Speaking at a joint California agency workshop in July 2016, IID’s then-General Manager Kevin Kelley said the utility opposed regionalization because it would require the state to relinquish oversight of an entity that suffered costly market manipulation during the 2000/01 Western Energy Crisis.

Kelley at the time said he suspected the “driver” of regionalization was a “for-profit corporation” — namely, PacifiCorp, which was the first utility to commit to joining both the WEIM and EDAM. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)

But times have changed and IID’s energy consumption and customer base grow each year, with demand increasing, Robert Schettler, a spokesperson for IID, told RTO Insider.

“We’re out there making agreements ahead of time as best we can,” Schettler said. “But then sometimes the energy that we’re expecting isn’t available, and we have to go on the market and get it and pay market prices, and then we have to shift those prices to our customers, which has not been popular.”

IID hopes participation in the markets will broaden the utility’s reach and bring stability to fluctuating adjustment costs in customers’ bills. Additionally, IID has been around for 114 years, and entry into the markets comes as the utility has launched a 15-year plan to upgrade its infrastructure, Schettler noted.

WEIM launched in 2014, and EDAM is slated to go online next spring. IID said in the news release that a “conservative estimate” shows the utility could save $12 million annually once both markets are in use.

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Uranium Mine Expansion Approved in Just 11 Days

Federal regulators are off to a running start on their expedited review of energy projects, greenlighting a uranium mine expansion in just 11 days. 

The Velvet-Wood site in southeastern Utah produced about 4 million pounds of uranium and 5 million pounds of vanadium from 1979 to 1984. Significant additional deposits are believed to remain in the ground, and owner Anfield Resources Holding has sought a modification of the existing plan of operation for the site that would result in 3 acres of surface disturbance. 

The Department of the Interior on April 23 implemented emergency permitting procedures for uranium, oil, gas, coal, critical minerals and other materials judged relevant to addressing Trump’s Jan. 20 declaration of a national energy emergency. 

Analysis of these proposals would take 14 or 28 days depending on their complexity, Interior declared, rather than the typical one or two years. 

On May 12, Interior announced it would start, conduct and complete the environmental review of the Velvet-Wood project within 14 days. 

On May 23, Interior announced it had found there would be no significant impact from the proposal, and that Interior has given Anfield all needed clearance to move ahead. It was the first expedited review of its kind, and possibly the first of many. 

“This approval marks a turning point in how we secure America’s mineral future,” Interior Secretary Doug Burgum said in the official announcement. “By streamlining the review process for critical mineral projects like Velvet-Wood, we’re reducing dependence on foreign adversaries and ensuring our military, medical and energy sectors have the resources they need to thrive. This is mineral security in action.” 

The accelerated permitting protocol was met with dismay by environmental advocates worried about the impact of rushed reviews. Uranium mining is a particularly sensitive issue for tribal nations in the U.S. Southwest that historically have suffered the effects of such operations. 

The May 23 announcement about Velvet-Wood came on the same day Trump issued executive orders easing the regulatory burden on nuclear developers and attempting to expand the supply chain in hopes of bringing new nuclear generation online, and quickly. (See Trump Orders Nuclear Regulatory Acceleration, Streamlining.) 

Reactor fuel is an important part of this vision, as almost all the uranium used for commercial purposes in the United States today is imported. Vanadium has strategic value as well, given its importance in steel alloys. 

Atlas Minerals extracted 400,000 tons of ore from the Velvet Deposit between 1979 and 1984. At grades of 0.46% and 0.64%, that yielded 4 million pounds of uranium and 5 million pounds of vanadium. 

Anfield bought the mines and the Shootaring Canyon uranium mill from Uranium Ore in 2015. It estimates the Velvet and Wood mines can yield enough ore to produce 4 million and 552,000 pounds of uranium, respectively, at grades of 0.29% and 0.32%. Roughly 1.4 times as much vanadium would be expected. 

Anfield CEO Corey Dias welcomed Interior’s decision in a May 27 news release: “This confirms our view that Velvet-Wood was well-suited for an accelerated review, given that it is a past-producing uranium and vanadium mine with a small environmental footprint. The company will now pivot to advancing the project through construction and, ultimately, to production.” 

The Shootaring Canyon Mill operated only briefly in 1982 due to depressed uranium prices. It is one of only three licensed, permitted and constructed uranium mills in the United States, Anfield said. 

Its radioactive source materials license is on standby, which would have to change to allow mill operations to resume, Anfield said, but the facility stands in what historically was one of the most productive U.S. uranium mining regions. 

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MISO Requires Load Shed in New Orleans to Avoid Grid Instability

MISO initiated an hourslong load shedding event in greater New Orleans over Memorial Day weekend with nuclear power outages appearing to play a role.

The RTO said on X that it ordered Entergy and Cleco to drop about 600 MW on the evening of May 25 to “maintain the reliability of the bulk electric system.”

“High temperatures in Louisiana led to higher-than-expected demand, and with planned and unplanned transmission and generation outages, MISO needed to take this action as a very last resort. MISO is coordinating closely with Entergy and Cleco to restore power as quickly as possible,” MISO wrote at the time.

Entergy New Orleans and Entergy Louisiana reported they initiated the rolling blackouts on MISO’s orders around 5 p.m. CT. Entergy said the “last resort” actions were to “prevent a more extensive, prolonged power outage that could severely affect the reliability of the power grid.”

“MISO is directing actions to be taken to restore the system to normal operations as quickly as possible and will direct Entergy to stop these outages as soon as the power shortfall no longer threatens the integrity of the rest of the electrical power system,” Entergy said in a press release at the time. Later that day, the utility issued a second release announcing MISO canceled further periodic load shed. Entergy said it would work with MISO to understand the sudden load shed directive.

Local news outlets reported that more than 100,000 customers around New Orleans were impacted by the controlled outages. Entergy said it restored power around 8 p.m. CT. Entergy and Cleco’s territories in Orleans, Jefferson, St. Tammany, St. Bernard and Plaquemines parishes reportedly were affected.

Cleco also confirmed it instituted rolling outages on MISO’s instructions.

“If the power supply cannot meet the demand, periodic power outages could be needed to protect the stability of the power grid and prevent widespread lengthy outages,” said Jennifer Cahill, director of corporate communications. “This was the case yesterday when we took the unprecedented step, as directed by MISO, to force outages to some customers in St. Tammany Parish.”

In a statement to RTO Insider, MISO again emphasized the temporary, periodic outages were its only remaining option to maintain reliability in MISO South. The grid operator did not disclose additional information on the incident.

“We will conduct a thorough assessment of the event and provide additional information once complete,” MISO spokesperson Brandon Morris said.

MISO’s real-time market notifications don’t list any emergency steps that might have preceded the event.

The outage could be the result of hot weather and nuclear power unexpectedly going offline. Entergy declined to comment on whether the nuclear outages contributed to demand exceeding supply.

MISO pricing the evening of May 25 | MISO

But Louisiana Public Service Commissioner Davante Lewis said Entergy’s 974-MW River Bend Nuclear Station in St. Francisville, La., tripped offline May 25 as Entergy attempted to restore it to service. The unexpected outage reportedly occurred at the same time Entergy’s Waterford nuclear plant in Killona, La., was on a scheduled outage. The Nuclear Regulatory Commission listed both reactors as offline before the holiday weekend.

Meanwhile, temperatures around New Orleans registered at about 90 degrees Fahrenheit.

Lewis told local station WWL-TV that the simultaneous scheduled and unscheduled outages should not have risen to a load shedding event. “That means there’s more to the story — either bad forecasting, bad modeling or higher demand than was projected,” he said.

Fellow Commissioner Eric Skrmetta said the load-shed orders arrived less than three minutes before action was required so utilities didn’t have the option to cut interruptible industrial customers first in an attempt to reduce demand. He said the notification time was “unacceptable” and said upcoming commission meetings would focus on appropriate notification times from RTOs before delivering load shed instructions.

Until now, MISO had directed load shedding just once in the past 17 years, ordering about 700 MW offline in MISO South during Winter Storm Uri in early 2021.