Search
December 21, 2025

Posted on

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.”

Posted on

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. 

Posted on

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.”

Posted on

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.

Posted on

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.) 

Posted on

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.

Posted on

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. 

Posted on

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.

Posted on

PJM MRC Briefs: May 21, 2025

Stakeholders Endorse Proposal to Add Transparency to ELCC

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed by acclamation a proposal intended to add transparency to the RTO’s effective load-carrying capability (ELCC) process and how the ratings it produces contribute to resources’ capacity accreditation. (See “PJM Presents Proposal to Add Transparency to ELCC,” PJM MRC/MC Briefs: April 23, 2025.)

Providing more information to generation owners about the amount of capacity their units can provide is one of several areas where stakeholders have sought to make changes through the ELCC Senior Task Force. The MRC endorsed a proposal in March to add two resource categories and limit the Capacity Performance deficiency penalty rate for units whose accreditation falls between a Base Residual Auction and Incremental Auction. (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

The transparency proposal would create an exception to PJM’s confidentiality requirements to allow market sellers to request data showing the historic performance of the resource through June 2012, even if that extends prior to the owner’s acquisition of the asset. Proponents argued those data are integral to understanding how PJM determines the inputs driving the unit’s ELCC rating.

Before rounds of ELCC analysis are initiated, pre-study stakeholder sessions would be held to review the assumptions and updates to data inputs PJM is considering. Additional sessions would be held once the analysis is complete to discuss the results. PJM also would publish an annual report outlining the assumptions, methodology and results of the ELCC analysis, including any sensitivities.

More sensitivities could be conducted after the analysis, such as developments in the load forecast, weather data or resource performance.

Independent Market Monitor Joe Bowring asked PJM to produce a legal opinion outlining its perspective that it can share confidential information from a prior resource owner to a new owner without permission from the former. PJM legal staff said their client is the RTO, not the Monitor, after which a member also requested more information on PJM’s legal reasoning.

Discussion of CETL Deferred

The MRC voted to delay consideration of an issue charge focused on a “disconnect” between PJM’s winter-skewed risk modeling and the use of summer peaks to calculate capacity emergency transfer limits for locational deliverability areas. (See “LS Power Seeks Issue Charge to Align CETL Calculation with Winter Risk,” PJM PC/TEAC Briefs: Oct. 8, 2024.)

LS Power Director of Project Development Tom Hoatson, who made the motion to defer, said he believes the issue is intertwined with the concept of a seasonal capacity market and suggested the two should be discussed together. He also said the stakeholders and PJM engineers who would lead the work are the same employees engaged with discussions on other areas of the ELCC paradigm, presenting workload challenges.

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the issue charge, which was sponsored by LS Power, was well developed and broached an issue of importance to consumer advocates. He said they could support a delay of a few months, but not longer.

The motion to defer until “stakeholders undertake work on a seasonal capacity construct” was endorsed with the support of all sectors except end-use customers.

Stakeholders Torn on Further SATA Education

Stakeholders held mixed perspectives on whether to recommence work on an issue charge seeking to establish rules for storage acting as a transmission asset (SATA), with some feeling more education is warranted and others arguing it’s time to move on to proposal development.

PJM Director of Stakeholder Affairs Dave Anders said that, after a series of presentations at the Operating Committee in recent months, he believes the education component of the work has run its course and said the issue charge is slated for an endorsement vote at the MRC’s June 18 meeting. He added that approving the issue charge does not mean further education and stakeholder discussion cannot happen.

The committee voted in October 2024 to delay acting on the issue charge until PJM had completed education sessions at the OC, both to allow stakeholders to focus on several capacity market proposals being considered at the time and to bring them up to speed on a SATA proposal last considered in 2021. The OC’s sessions focused on the 2021 proposal, how SATA could impact operations and FERC’s regulatory authority. The issue of developing rules for SATA was brought by PJM in September 2024, nearly four years after members voted to delay further activities on the subject until market rules for storage had been established. (See “Vote on Issue Charge to Establish SATA Rules Deferred,” PJM MRC Briefs: Oct. 30, 2024.)

Constellation Energy’s Juliet Anderson said there are unanswered questions around where SATA would fall into the federal and state jurisdictions over transmission and distribution networks. She noted that the October 2024 deferral delayed action on the issue charge until education at the OC had been completed.

Bowring asked whether PJM believes it’s appropriate to proceed without a more complete understanding of how SATA could impact market operations. Anders responded that market impacts fall under the issue charge’s key work activity 6.

Poulos said most issue charges have a significant educational component, so it’s surprising to him there’s opposition to continuing that work here. He said SATA is a priority for advocates who see it as a valuable tool for resolving reliability issues, and they’re frustrated that barriers are being put up to having the subject discussed further.

Exelon Director of RTO Relations and Strategy Alex Stern said there have been several discussions over the past five years to determine whether storage can act as transmission. In that time FERC has issued policy statements, and other RTOs have developed their own rules, while PJM has been blocked artificially from advancing the discussion by stakeholders using pre-education as a pretext for delay, he said. Whether or not stakeholders want to proceed with establishing a SATA framework, he said, their position should be made clear and communicated to the states, which have been pushing for increased storage deployment.

“I’d just as soon like to know whether this is something we can have in the toolkit or not,” he said.

PPL’s Robin Lafayette said SATA has been discussed at more than 30 meetings and is clearly a tool PJM believes it needs to have available.

“Other ISOs and RTOs have found ways forward on this issue, and I do acknowledge some of the issues raised by some of my colleagues on interactions with the markets,” he said. “PPL strongly supports trying to find a way forward on this issue; even if it is a targeted, limited tool, it could be a valuable one.”

1st Read on Uplift Formula Proposal

PJM Senior Director of Market Settlements Lisa Morelli presented a first read on a proposal to rework how balancing operating reserve (BOR) credits are calculated, including a new metric to determine whether a resource is following dispatch signals. (See “Stakeholders Narrowly Endorse Uplift Changes,” PJM MIC Briefs: April 2, 2025.)

The proposal would replace the three desired megawatt metrics used to determine deviation charges with a new tracking ramp-limited desired (TRLD) metric, which would compare actual output to how a resource should be operating if it had followed dispatch instructions. Morelli said the existing metrics are limited to how dispatch instructions and resource output change over five-minute intervals, which can mask when a resource is deviating from instructions by small amounts over a long period, particularly because there is a 10% margin before a resource is found to be deviating.

The BOR credit formula also would be revised to take the lesser of real-time output or the TRLD, adjusted for a unit’s ramping parameters. The period for which a resource is eligible for uplift also would be realigned to when its commitment began and continue through either the minimum run time parameter or the end of the commitment.

Depending on how a unit operates, the proposal either could lead to increased uplift payments or higher deviation charges, Morelli said, adding that PJM and the Monitor, which jointly sponsored the proposal at the Market Implementation Committee, aimed to take a balanced approach to how uplift would be affected by the proposal, rather than just reducing the amount of uplift paid.

If endorsed, a soft launch would be rolled out at the end of 2025 or early 2026, starting with calculating how the TRLD would affect settlements and communicating that to market sellers through their Market Settlements Reporting System reports. Changes to actual settlements would not come for another year once the full implementation begins.

Gregory Pakela, manager of regulatory affairs for DTE Energy Trading, said the proposal could have significant impacts during periods of high system stress and asked if PJM could conduct backcasts on how it would have changed settlements during the two winter storms in early 2025, when conservative operations were initiated.

Morelli said PJM has conducted limited backcasting, but there’s a balance between the number of staff hours that fully recalculating results would take versus the benefits. She said PJM is comfortable that the proposal is worth moving forward with.

Vistra’s Erik Heinle said the phased implementation process allows market participants to have more understanding of how their resources would fare under the proposed paradigm. Having the opportunity to spend a year understanding how TRLD would determine when a unit is following dispatch and the ability to update the unit’s parameters based on that information is crucial, he said.

Posted on

EBA Event Examines History of Electricity Demand Growth as Industry Tackles New Wave

WASHINGTON — The return of rapid load growth still is a relatively new phenomenon for the power industry, but demand has seen such cycles several times before, speakers said at the annual half-day meeting of the Energy Bar Association’s Electricity Steering Committee.

Electricity started off as a niche product, with fully distributed power generators serving mansions and some industrial customers in the late 19th and early 20th centuries, recalled Hannah Wiseman, professor of law at Penn State University.

Appleton, Wis., was home to the first grid in the country, with a hydropower dam serving multiple homes and the lights dimming as water flow slowed.

At first, industry preferred distributed power, and residential customers used electricity only for lights, but that expanded to new products like electric clocks. It was not until World War I that industrial use took off and the grid as we know it started to be patched together, Wiseman said.

“We start to see more centralization, and we start to see more federal involvement, which means we also start to see more public involvement in power,” Wiseman said. “So the War Department in World War I became directly involved in determining where the electricity needed to be generated most.”

The department helped to wring efficiency out of the grid by determining when coal power needed to be dispatched due to hydropower not producing enough to meet demand, she said.

Under the New Deal, electricity service started expanding to more rural areas, such as through the Tennessee Valley Authority. Then World War II and its demands on industry made the backbone transmission system developed in the 1930s a valuable investment. Demand surged during the war as industry built massive fleets of airplanes that needed aluminum, she said.

“Historians say that that previous buildout that was in the 1930s was viewed as an overbuild,” Wiseman said. “Private industry said: ‘Will the rural customers … use this much power? Do we need all this transmission?’ It turned out to be quite important.”

After the war came the golden age of the investor-owned utility, when demand grew by 416% between 1949 and 1969, with residential demand growing even faster at 540%, Harvard Law School’s Ari Peskoe said.

There was a massive housing boom after the war, and the electric industry tried to maximize their individual power demand.

“If you get what was called ‘a total electric home’ at the time, where it’s using electricity for heat, hot water for cooking; that’s a massive increase in the amount of electricity that house is going to consume,” Peskoe said.

From 1970 to 1990, demand grew by 100%. A survey by the Department of Energy in 1979 found homes that only had electricity used three times the amount of power as homes that had another fuel such as gas or oil, Peskoe said. The industry tried to maximize those total electric homes with direct financial incentives and via advertising in the early days of television.

“There’s some great commercials there,” Peskoe said. “You can see Ronald and Nancy Reagan promoting all sorts of electricity use in the home.”

The rapidly growing demand coupled with efficiencies from new, larger power plants meant that adding capacity to the grid lowered costs for everyone, Peskoe said. That led to similarly rapid growth in power demand, which had to be managed either by taking turns building new plants or working together on joint projects.

“Consistent with Section 202(a) of the Federal Power Act, the Federal Power Commission was focused on encouraging utility coordination at the bulk power system,” Peskoe said. “So, for instance, in 1964, it publishes a two-volume national power survey, and the theme of that is basically the benefits of coordinated growth. That is, utilities ought to be interconnecting more. They ought to be trading more. There ought to be more joint planning, even potentially joint dispatch.”

That all should sound familiar to anyone who knows the FPC by its newer name, FERC, and while the commission, states and industry are grappling with demand growth and the need to meet it now, the days of power too cheap to meter are over.

Former FERC Commissioner Philip Moeller, who recently left the Edison Electric Institute, started at the commission in 2006 when the economy was booming, but then the 2008 financial crisis hit. That contributed to low demand growth, but it also led central bankers to cut interest rates to zero in advanced economies.

“We had a period of extraordinary monetary policy where interest rates were basically zero for almost 10 years,” Moeller said. “I mean, that’s an exaggeration, but not too far off.”

In a capital-intensive industry where investments last for decades, the cost of borrowing money is important, Moeller said. Those zero interest rates are a thing of the past. But when it comes to the electric industry, the regulatory framework also is vitally important, said Moody’s Ratings Vice President Jairo Chung. About 50% of the credit risk in Moody’s analyses comes from the regulatory side of things.

“We look at the judicial underpinning of the regulatory framework where the authorities operate,” Chung said. “So, this could be state regulation, but also federal-level regulation, and we also look at the consistency and predictability of the law.”

Other ratings agencies assign utility credit scores to states, but Moody’s instead is more granularly focused on how specific utilities work within their state frameworks because that can vary across firms under the same jurisdiction, she said.

Maryland People’s Counsel David Lapp criticized agencies that rank states because he has found the rankings to be arbitrary, with different agencies scoring his state very differently.

“My primary concern as the customer advocate is regulators overusing or being oversensitive to how a rating agency may categorize the state as a whole,” Lapp said. State rankings can change, with no impact on a utility’s credit rating, which is more important to investors than ratepayers, he said.