Search
December 16, 2025

Posted on

CAISO Battery Storage Initiative Focuses on Outage Management, Nonlinearity

CAISO is moving ahead with a key initiative to resolve how battery storage resources function on the grid as the battery boom continues in the Golden State.

The ISO is prioritizing battery outage management enhancements, battery nonlinearity guidance and state of charge (SOC) clarifications in its storage design and modeling initiative that began earlier this year.

CAISO held a stakeholder meeting May 28 to address technical challenges associated with the increase in battery storage capacity on its grid, which has grown from 500 MW in 2020 to more than 11,000 MW in 2025.

CAISO’s current outage management system has served conventional resources effectively but does not easily convey a battery’s SOC limitations, CAISO said in an issue paper. Storage resources face limitations and outage types not covered in the outage management system that are unique to storage resources, such as negative minimum energy outputs.

There is a lack of clarity around how battery resources can accurately represent their availability to CAISO using the existing outage management system, CalCCA said in comments to CAISO. Another stakeholder in the initiative, Vistra, asked CAISO to clarify reporting thresholds for a battery’s SOC, specifically recommending the ISO add reporting requirements for changes that exceed 10 MW or 40 MWh, or 5% of registered values lasting 15 minutes or longer and within 60 minutes of discovery.

CAISO agreed with stakeholders about the need to align its outage management system with storage-specific outage types and characteristics. To do so, the ISO is considering implementing an outage card that can adjust a battery’s availability, maximum load, maximum energy and minimum energy values on one card.

Nonlinearity Options

Another key concern addressed by the initiative is battery storage nonlinearity, meaning the concept that batteries charge and discharge energy at a nonlinear rate. Nonlinearity complicates the modeling and control of battery storage resources, which in turn reduces a battery’s responsiveness and dispatch capability, CAISO said in the issue paper. Nonlinearity is comparable to gas generators that may take time to ramp up to reach their maximum dispatch, CAISO said at the meeting.

As a battery approaches its SOC limits, its maximum and minimum energy output are “greatly affected, potentially hindering its ability to respond to grid demands,” CAISO said. For example, a 100-MW battery storage facility might be able to charge or discharge only 50 MW at the extremes of its SOC.

“Nonlinearity is the area we got the most diverse comments,” said Sergio Dueñas, CAISO storage sector manager, at the working group meeting. “Everyone is getting more and more comfortable with the idea of, ‘Let’s pursue a [solution] in the near term and then move to a more doable solution in the long term.’”

CAISO is considering four ideas to account for nonlinearity, one of which is to use outage cards that indicate the effects of nonlinearity on ramp rates and maximum energy outputs. Currently, some market participants might be communicating the impacts of nonlinearity through outage cards that do not include all of these characteristics, since nonlinearity is not explicitly called out in the outage management system, CAISO said.

As a near-term solution, CAISO favors participants including a comment noting that an outage is related to nonlinearity. This near-term guidance will allow for resources shown as resource adequacy (RA) resources to be evaluated in the context of the RA availability incentive mechanism (RAAIM), the ISO said. The RAAIM provides incentives or disincentives for resources to help ensure they’re available for CAISO to meet reliability needs. If a battery resource is shown as RA and evaluated as RAAIM, then the battery would be accounted for according to its actual dispatch availability under instances of nonlinearity, CAISO said.

CAISO plans to publish a revised issue paper and hold another stakeholder meeting June 30.

Posted on

FERC OKs MISO Generation Replacements Connecting at Different Points than Predecessors

FERC has approved MISO’s new generation replacement provision that allows replacements to reconnect at more preferred points on the grid over clean energy groups’ concern that it plays favorites.

The commission said replacement generation in MISO should be able to link up at different points of interconnection (ER25-1802). MISO proposed that it would allow the interconnection point substitutions when they’re “electrically equivalent to the original point of interconnection” and when they don’t cause material adverse impact to MISO’s transmission system.

Clean energy groups, including American Clean Power Association, the Solar Energy Industries Association, Advanced Energy United and Clean Grid Alliance, had argued MISO’s proposal should be rejected because it’s unfair to other planned generating facilities. The groups said the plan would discriminate between similarly situated projects.

However, a group of utilities, including Alliant, Lansing Board of Water and Light, Consumers Energy, DTE, ITC, Michigan Public Power Agency, MidAmerican Energy, Muscatine Power and Water, Wolverine Power Supply Cooperative and WPPI Energy, said the proposal would allow replacement generation to connect at more favorable interconnection points that have similar impacts on the grid.

FERC decided the plan would allow “more cost-effective and timely replacement of existing generating facilities, which will help address regional resource adequacy needs and allow interconnection customers to avoid investing in redundant infrastructure.” The commission further said the replacement facilities would dodge duplicative contracts, deeds and site control costs that might come with both a new site for a replacement facility and “a path to connect that site to the original point of interconnection.”

The commission said it agreed with the Organization of MISO States that MISO’s plan would remain in keeping with MISO’s current methods for discovering and minimizing adverse impacts on the transmission system. FERC said it would pair “offering increased flexibility to interconnect new generation resources in a more efficient manner” with “supporting state resource planning and ratepayer affordability.”

FERC said the new prerequisites MISO placed on moving an interconnection point in addition to its usual replacement study process — interconnecting at the same voltage level, not introducing new constraints and not forcing a distribution factor change of more than 5% — “will ensure that an alternate point of interconnection is electrically equivalent to the existing point of interconnection.”

The commission disagreed with arguments that by allowing replacement facilities to move their points of interconnection, MISO was creating a process that more closely resembled a new interconnection request with the added bonus of skipping the queue.

“We do not believe that providing this limited flexibility to replacement generating facilities to interconnect at a different, but electrically equivalent, point of interconnection results in an unduly discriminatory interconnection process,” FERC wrote in the May 27 order.

FERC said MISO’s commitment to preventing a replacement generator from adversely affecting the grid should take care of clean energy groups’ concern that permission to move a point of interconnection would drive up network upgrade costs by replacements claiming spots on the grid that other interconnection customers had “reasonably expected” to use.

MISO has said its generator replacement process has been instrumental in limiting the impacts of power plant retirements. Since it began the process in 2019, MISO said it has accepted about 5.9 GW in replacement requests and is studying 4.9 GW of replacement requests.

The RTO expects 25 GW of coal retirements through 2030, up 5% from its 2024 forecast. In the same time frame, MISO’s membership plans to add about 10 GW of solar generation and significantly more gas generation.

Posted on

More Green Projects Halted amid Policy Changes

Clean energy and transportation project cancellations continue as 2025 rolls on, with analysis of public announcements showing investments of $4.5 billion abandoned in April alone.

Business advocacy group E2 on May 29 blamed uncertainties about finances and policy under the new Republican leadership in Washington. It tallied the impact so far this year at $14 billion in investments and 10,000 potential new jobs.

The two manufacturing and two generation projects that E2 counted as canceled in April far eclipsed the seven newly announced manufacturing projects announced in April, which carried a combined investment of only about $500 million. But the disparity was not as wide as it seems: The largest announcement — by the electric vehicle startup Slate — did not carry a price tag.

E2 Communications Director Michael Timberlake said in the news release that pending policy changes may add to the reductions.

“Now is not the time to raise taxes on clean energy and compound the business uncertainty that is clearly taking a greater and greater toll on U.S. manufacturing and jobs,” he said. “If the tax plan passed by the House last week becomes law, expect to see construction and investments stopping in states across the country as more projects and jobs are canceled.”

E2 and the Clean Economy Tracker have been following public announcements of job-creating green projects since passage of the Inflation Reduction Act in August 2022. They have tallied 390 major proposals across 42 states and Puerto Rico that carry planned investment of $132 billion and the hiring of 123,000 permanent workers.

From January 2023 through April 2025, 45 projects have been canceled, closed or downsized, accounting for commitments of $16.7 billion in investments and nearly 20,000 jobs.

Twenty-seven of the 45 announcements came after the election in November 2024 of President Donald Trump, who had pledged a strong reversal of President Joe Biden’s support for clean energy and clean transportation. The Trump administration’s rapid-fire policy changes have complicated efforts, and the current version of the budget bill would provide further costs and hindrance.

E2 noted the irony contained within the geography for the proposed and canceled investments: More than 61% of all clean energy/transportation announcements have been in Republican congressional districts, and they account for 72% of planned job creation and 82% of planned spending. More than $12 billion of the $16.7 billion in canceled investments were to have been made in Republican districts.

Posted on

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.

Posted on

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.

Posted on

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.”

Posted on

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.

Posted on

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. 

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.