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December 14, 2025

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FERC Declines MISO Queue Cap Rehearing Requests

FERC is resolute in its support of MISO’s annual megawatt cap in its generator interconnection queue.

The commission rejected rehearing requests that framed the queue cap as discriminatory, preferential and riding roughshod over state authority (ER25-507).

FERC in late January gave MISO the go-ahead to impose an annual megawatt cap on the generation applications it accepts in its interconnection queue. The cap limits megawatt values of queue cycles to 50% of MISO’s non-coincident peak among its five study regions. (See FERC Approves Annual Megawatt Cap for MISO Interconnection Queue.)

Two study regions — East and Central — already have exceeded their megawatt caps for the 2025 cycle. Across all regions, MISO has a 77.82-GW cap for the 2025 cycle. As of mid-May, it has fielded 50.13 GW across 176 submissions.

MISO South regulators in early March asked FERC to reconsider its approval of MISO’s queue cap. Led by the Mississippi Public Service Commission, regulators argued the cap needs an exemption for state-designated necessary resources. They asked FERC to backtrack and either reject MISO’s plan or condition it on MISO including an exemption for the states, saying the MISO plan tested the very limits of cooperative federalism.

In its May 27 order, FERC decided it didn’t transcend its statutory authority and infringe on state jurisdiction by allowing the queue cap, even though the cap will have “incidental effects” on state jurisdiction. It said the Supreme Court already decided those inadvertent encroachments are of no legal consequence. FERC also said that despite Southern regulators’ prerogatives, the commission is allowed to consider “resource adequacy concerns in exercising its jurisdiction.”

FERC also said it judged the queue cap plan as fair and reasonable without the state exception and would not order MISO to include one.

Clean energy groups also argued against FERC’s acceptance of the cap. They said FERC should reconsider because MISO didn’t have a strong rationale for the cap and said the cap itself will introduce undue discrimination and preference among developers vying for a spot on the MISO grid.

FERC disagreed with the groups, who said that in accepting the cap, the commission abandoned standardized generator interconnection processes established under FERC Order 2003. FERC said the clean energy groups should have raised the argument sooner in proceedings but said “in any event,” the queue cap followed Order 2003’s “recognition of independent entity variations for RTOs/ISOs.”

FERC also said it found nothing amiss with MISO’s first-come, first served aspect of the cap to determine cutoff points. The commission disagreed with the groups that argued prioritization could create an unfair environment by incentivizing projects to line up for exploratory or speculative positions. Instead, MISO ultimately would study submitted interconnection requests as part of a cluster. FERC said projects that entered too late to beat the cap simply would be subjected to a later cluster of projects.

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MISO: New Orleans Area Outages Owed to Scant Gen, Congestion, Heat

MISO has shed light on the reasons behind the Memorial Day weekend load-shed event in southeast Louisiana, describing a system taxed by early summer heat and rife with congestion and unavailable generation.

Executive Director of Market Operations JT Smith said there were “a number of” planned and unplanned generation outages coupled with higher-than-normal temperatures that paved the way for challenges headed into the weekend.

“We approached some pretty warm days for the season down there,” Smith said during a Reliability Subcommittee meeting May 29. He added that evening peaks with “early summer heat” can be a hazardous time.

MISO ordered an approximately three-hour, 600-MW load-shedding event in Greater New Orleans the evening of Sunday, May 25 to avoid bigger reliability issues. (See MISO Requires Load Shed in New Orleans to Avoid Grid Instability.)

During the first hour of the load-shed event, electricity prices were in the negative — as low as ‑$400/MWh around the Mississippi Delta — while prices in southern Louisiana soared past $2,000/MWh. Electricity appeared undeliverable into the greater New Orleans area because of a lack of transmission.

Smith said MISO operators began noticing congestion problems on Wednesday, May 21. By the weekend, operators were “battling congestion all over the place” in Louisiana, Smith said. He said MISO was keenly aware that it was “important for the transmission system to hold up” with reduced generation and warm weather.

Generation was available outside Louisiana, “but you could just not get it in” because of the congestion on May 25, Smith said. Smith said MISO’s pricing map showed “a lot of red” in southeast Louisiana and “a lot of blue and purple sitting out” north, indicating high prices butting up against negative-cost, trapped generation supply.

Smith said there were a lot of “infrastructure availability” issues May 25. He said operators contended with unusual flow patterns and “import limits not usually seen.”

Leading up to the event, MISO was identifying post-contingent positions on transmission lines. Smith said the RTO conducted several on-the-spot analyses to see if any potential congestion problems could rise from localized system operating limit issues to the more serious and widespread interconnection reliability operating limit (IROL) issues.

Smith said that “unfortunately on the 25th,” MISO identified a constraint north of Lake Pontchartrain that presented as 125% over its limit.

“It was identified to have cascading potential, putting at least 1,000 MW of load at risk,” said Smith, calling it a “very significant” issue that necessitated MISO’s call for Entergy and Cleco Power to shed load.

Members of the Louisiana Public Service Commission and the New Orleans City Council have expressed concern over the short notice on the power deficit and have vowed to get answers. Smith said that unfortunately when an IROL is identified, MISO has precious little time to correct it. Nevertheless, he said the RTO would review its communication protocols and see if it can improve notification time. It will have more information to share at its Board Week meetings in June, he said.

“We’ll be looking to improve that posture overall,” Smith said. “Since then, it has been a whirlwind of data collection. It’s an unfortunate situation, but one that can come up from time to time.”

Reliability Subcommittee Chair Ray McCausland, of Ameren, told stakeholders that information still is scarce because the meeting was a mere four days after the event and “there’s a lot to discover.” From his experience in control rooms, he said he was surprised that MISO wasn’t forced to “sacrifice” more megawatts given the situation.

Michigan Public Power Agency’s Tom Weeks asked if an earlier order of conservative operations may have helped the situation.

Smith said MISO had very few options in the moment, and a conservative operations declaration would not have returned enough equipment to service to make a difference.

Entergy: Nuclear Gen Offline Days Before Event

Meanwhile, Entergy has challenged Louisiana regulators’ narrative that its two offline nuclear plants played a major role in the blackouts.

In a statement to RTO Insider, Entergy said its own models did not indicate load-shed conditions, but “MISO uses a different model and has a broader view of system conditions, which MISO is able to see due to its status as the regional transmission coordinator.”

“Entergy had been monitoring load conditions due to warmer-than-typical weather, but as noted, its models did not show the need for load shed,” Entergy spokesperson Brandon Scardigli said in a statement.

Entergy also said the implication that the nearby, offline River Bend nuclear plant exacerbated circumstances might not stand up to scrutiny.

“While the River Bend generating unit was offline during the event, it had been out for several days before the event, and its outage was accounted for in the generation that Entergy Louisiana and Entergy New Orleans made available to MISO and in MISO’s own modeling,” Scardigli said.

River Bend reportedly shut down unexpectedly on May 21 because of a leak in its cooling system. The Union of Concerned Scientists released a May 27 report in which it singled out River Bend for being one of the most problematic nuclear plants in the U.S. in terms of regulatory violations.

Entergy added that its refueling outage at the nearby Waterford 3 plant was within the norm, as it routinely plans maintenance in the spring and fall. Entergy said the outage was scheduled months in advance.

“The timing of the planned outage was to ensure that this important unit is up and running during the summer months when customer usage is high,” Scardigli said.

Episode Spurs Calls for MISO South Tx Planning

The rolling blackouts have revived debate around MISO South’s lack of regional transmission projects and webwork of load pockets.

The Louisiana-based Alliance for Affordable Energy circulated a one-pager after the load-shed event that said the longer MISO South waits on transmission planning, “the longer consumers remain vulnerable to load-shed events.” It said the RTO needs expanded transmission capacity between its Midwest and South regions to alleviate the South’s load pockets.

“Corporations like Entergy have long fought efforts to do this because it could negatively affect their bottom line by forcing them to compete with other electricity producers, and the [Louisiana PSC] and New Orleans City Council have often had their backs in doing so. It’s time we put the people of Louisiana and New Orleans first — increasing transmission means we will be better protected from grid failures and will also help to bring down costs,” the group wrote.

However, Southern Renewable Energy Association Transmission Director Andy Kowalczyk cast doubt on the notion that more Midwest-South transmission could have helped the load pocket in this situation. He pointed out at the subcommittee meeting there was plenty of available generation below MISO Midwest that could not reach Louisiana.

The alliance also said earlier investments in locally available renewable energy and battery storage could have offset the need to shed load.

Finally, the organization said the Louisiana PSC and New Orleans City Council should demand information from Entergy and Cleco. It faulted the PSC for dismantling a statewide energy efficiency program weeks before that could have dampened demand. (See Louisiana PSC Scraps Statewide Energy Efficiency Program.) The PSC has reverted to utility-led programs for energy efficiency.

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Amended ‘Pathways’ Bill Boosts — and Complicates — Calif. Protections

The latest version of California’s “Pathways” bill strips out a previous amendment that would have given state regulators authority to order utilities to withdraw from the West-Wide Governance Pathways Initiative’s “regional organization” (RO) under certain circumstances.

But that doesn’t mean the bill has been slimmed down. Just the opposite, in fact.

Instead, a newer iteration of the bill replaced that provision with a lengthier one prescribing a more complicated process for undertaking the same action, while adding a slew of other conditions intended to protect California’s policies and ratepayers.

“In short, this new provision reflects the delicate negotiation between California and the rest of the West as they figure out how to marry their energy systems,” Lincoln Davies — professor of law and executive director of energy, resource and environment programs at the University of Utah’s S.J. Quinney College of Law — told RTO Insider in an email.

“This should be expected, and this bill is still a strong step in the right direction. It would ensure RO independence but give California assurance it can exercise its sovereign power to protect its citizens,” Davies said.

Senate Bill 540 emerged from the Senate’s Appropriations Committee on May 23 in a 4-1 vote recommending that the full house pass the legislation as amended, but the exact content of the amended bill remained a mystery until the Legislature printed and posted it May 28. (See California’s ‘Pathways’ Bill Heading to Senate Floor.)

The newest version removes language the Senate Judiciary Committee added in April to address the concerns of constituents and lawmakers who fear that CAISO’s membership in the proposed independent RO could provide a backdoor for the Trump administration to compromise California’s ambitious environmental and clean energy policies. (See California Lawmakers Seek to Trump-proof Pathways Initiative Bill.)

To prevent that outcome, the Judiciary Committee inserted an amendment stipulating that the California Public Utilities Commission could direct its jurisdictional utilities to withdraw from the RO if the new entity’s rules were to become “detrimental to California consumers.”

The amendment also mandated withdrawal if the state’s renewable portfolio standard is “held invalid by [a] reviewing court on claims of impermissible discrimination” or if the Trump administration — or future administrations — invoke emergency powers that require California to subsidize fossil fuel generation.

That amendment has been deleted, only to be replaced by a more complex one that outlines the creation of a new Regional Energy Market Oversight Council designed to ensure “that participation in a regional energy market serves the interests of the state.”

The council would consist of the CPUC president; the chair of the California Energy Commission; the chairs of the Senate Committee on Energy, Utilities and Communications and Assembly Committee on Utilities and Energy; and the state’s attorney general, with the AG serving as chair.

It would be charged with approving “initial participation” in the RO by California’s “electrical corporations” and load-serving entities and, “at any point” after that approval, determining whether those entities “should be required to withdraw from an energy market governed by the independent regional organization” after convening a public meeting on the matter.

In its capacity for making RO withdrawal decisions, the council also would be responsible for reviewing the RO tariff both before and after FERC approval, as well as for monitoring any “subsequent actions” related to the market that might:

    • weaken or invalidate California’s RPS;
    • require the state, CAISO or any LSE to procure or subsidize fossil fuel generation located outside California; or
    • result in “adverse impacts on California’s resource planning, procurement, environmental, reliability or other applicable public interest policies.”

The amendment also makes the council respsonsible for protecting ratepayers by authorizing the new body to order utilities to withdraw from the RO if the organization or the federal government take measures that cause the cost of California’s regional market participation to exceed benefits over a two-year period.

The council also could order withdrawal if the RO fails to fully compensate California ratepayers for CAISO’s costs to provide the RO with “any services, facilities, equipment and property, including intellectual property,” or if the RO doesn’t hold both ratepayers and the ISO “harmless” for legal claims arising from the operation of the regional market.

The new amendment further prohibits CAISO from modifying its own tariff in relation to the RO without the council’s approval.

Getting Hitched

Sources familiar with the California legislative process have told RTO Insider that the Appropriations Committee’s process of adding amendments to bills is something of a black box — and that appears to be the case for SB 540.

One source close to the SB 540 effort said it was unclear exactly which lawmakers added the amendments, or why. The office of the bill’s sponsor, Sen. Josh Becker, had not responded to questions as of press time.

But Davies said he thinks the new provision seeks to achieve three objectives.

“First, it creates a checkpoint for California electricity providers for entry or exit into these new markets. Under the prior version of the bill, this was left mostly to self-execution, with an express reservation of PUC authority to order withdrawal. Now, companies need to ask ‘mother, may I?’ to get in or out of the markets,” he said.

“Second, it spreads authority across multiple entities rather than concentrating it in the CPUC. The prior withdrawal provision left sole authority to the CPUC to act. Now, the council would have representatives from multiple agencies, both chambers of the Legislature and the attorney general.”

The third objective could be the most fundamental, according to Davies, because it aims to allow California to maintain control over its policies while still providing for independent governance of CAISO’s markets.

“This is understandable, particularly given how federal energy policy is developing right now, including the White House specifically naming California energy policy as a target for federal action in executive orders,” he said.

Davies noted that “any bill that erodes the independence of the new RO is certain to crater a broader Western market,” and that the widest possible market is in the interest of all participants, including California.

“At some point, of course, everyone will need to end the courtship and just decide to get hitched or not,” he said. “This bill should make that possible — to the benefit of California, the climate and the broader West. Anything that moves more control to California likely will not.”

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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.)