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November 19, 2024

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CAISO Backtracks on Proposal to Refine Battery BCR

CAISO is reconsidering its proposal to address unwarranted bid cost recovery (BCR) payments for storage resources following internal analysis that suggested the proposed solution wouldn’t sufficiently address the problem.  

The initial proposal would have redefined dispatch unavailable due to battery state of charge (SOC) constraints in the binding interval as “non-optimal energy,” which is ineligible for BCR. (See CAISO Adjusts Timeline for Storage Bid Cost Recovery Initiative.) But due to the use of multi-interval optimization (MIO), the ISO found the proposal may not significantly reduce BCR payments and would be challenging to implement.  

“The proposed solution is based on the assumption that dispatch in the binding interval is optimal,” Sergio Dueñas Melendez, CAISO storage sector manager, said at a Sept. 11 Storage Bid Cost Recovery and Default Energy Bids Enhancements workshop. “By optimal, we mean that it’s economic. This assumption, however, may not hold true, in general, because of how MIO operates, particularly with regards to energy storage.” 

Dueñas Melendez explained that it’s “possible for an economic dispatch to occur in the binding interval that would preserve or even increase the state of charge moving forward” in a way that could be repeated across several real-time dispatch runs, “resulting in a situation where the proposed solution would not be triggered and BCR would continue to be allowed to accumulate.”  

For the proposal to be effective, the ISO would need to modify the solution to consider both binding and advisory intervals. CAISO encountered a similar problem with the ancillary services SOC constraint, Dueñas Melendez said, and while the issue is familiar, it increases the complexity of the solution.  

Another concern with the proposed solution was identified regarding market power mitigation, where stakeholders noted that the BCR calculation should not exclude instances in which resources were mitigated in intervals prior to a buy- or sell-back of energy. 

“It is important to consider instances in which resources may have had an inadequate state of charge to meet awards of schedules because of mitigation in prior intervals,” Dueñas Melendez said.  

CAISO’s Market Surveillance Committee flagged the issue in prior meetings and recommended further analysis to understand its impact on BCR. According to MSC’s recommendation, if the analysis showed a material impact, the market could benefit from the ISO developing an exception for mitigation.  

Multi-interval Optimization

The ISO provided background on the relationship between MIO and storage BCR. For storage resources, the MIO charges or discharges a storage asset due to projected conditions in the future, “linking solutions over intervals to ensure the asset’s limited SOC is utilized when it is most valuable,” an ISO presentation said.  

MIO charges or discharges a resource to prepare for a future energy award, to avoid hitting a maximum SOC constraint, to adjust for future interval economic conditions stemming from supply, demand or net interchange forecasts, or to rebalance an exceptional dispatch.  

“As a result, MIO may dispatch a resource uneconomically in the binding interval due to actions taken by the scheduling coordinator, due to factors that inform the ISO’s market optimization, or due to the optimization process itself.”  

MIO could increase the complexity of developing a solution due to the proposal’s assumption that the ISO will be able to identify when a binding interval has an SOC constraint. The problem, Dueñas Melendez said, is that SOC constraints are often not binding in the binding interval, meaning the solution may not be triggered when needed.  

Mitigation has ‘Minimal Impact’

While stakeholders noted that instances in which resources were mitigated in intervals prior to a buy- or sell-back could merit specific BCR provisions, a presentation from CAISO’s Department of Market Monitoring (DMM) suggested otherwise.  

For the first half of 2024, real-time BCR for state-of-charge-induced buy- and sell-backs of day-ahead schedules were “primarily driven by negative revenues, not the bid costs,” DMM Senior Advisor Roger Avalos said.  

Avalos also identified that mitigation of batteries has had minimal impact on dispatch of batteries prior to peak net load hours, even if batteries bid high.  

“This indicates that more efficient bidding incentives created under ISO’s initial proposal would not have been undermined by local market power mitigation,” the presentation reads.  

Stakeholders requested additional data that shows not just the impact of mitigation on dispatch, but also its effect on a resource’s ability to charge.  

“That seems to be where the mitigation is really causing a chokepoint, because it’s moving your willingness to pay down lower,” said Cathleen Colbert, senior director of Western markets policy at Vistra.  

To better understand the complexity of the issue, other stakeholders echoed Colbert’s request.  

“It would be helpful to see a more distinct breakdown between reductions of discharge versus reductions of charging for purposes of mitigation, just to see if there’s any effective patterns that might be found there,” said Josh Arnold, senior market and operations analyst at Customized Energy Solutions. “Some additional clarity would be very welcome.” 

The draft final proposal is slated for Sept. 30.  

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ERCOT Cybersecurity Monitor Shares Best Practices

Speaking to ERCOT stakeholders, Chuck Bondurant, the Texas Public Utility Commission’s director of critical infrastructure security and risk management (CISRM), urged his listeners to treat the ISO’s grid as a special jewel. 

“You know, we brag that we’re our own grid,” he said Sept. 10 during a Talk with Texas RE webinar. “So, let’s protect it that way.” 

As the commission’s security lead, Bondurant helped set up ERCOT’s Cybersecurity Monitor Program, a voluntary outreach effort to involve the state’s utilities in sharing best cyber-defense practices. The program, focused on physical security issues, kicked off what he said was a “massive” recruitment effort in 2020; it now numbers 65 participants. 

The monitoring program was created by state legislation requiring the PUC and ERCOT to “foster a more collaborative, strategic approach identifying cybersecurity issues” and improve security measures in electric infrastructure. The cybersecurity monitor is responsible for managing the outreach, communicating emerging threats and best business practices, reviewing cybersecurity self-assessments, researching and developing best business practices for cybersecurity, and reporting “monitored utilities’” preparedness.  

The program is free for utilities in the ERCOT region but costs $4,322 for those in the MISO South, SPP and WECC portions of Texas. It is managed by Paragon Systems, a Houston-based security guard service. 

Quarterly meetings form the program’s backbone. Bondurant said the meetings are open to utilities that “may be on the fence” about joining the program to learn more about the program. 

“This is what we originally envisioned. … This is a chance for utilities to have a safe space where they could dialogue,” he said. “This is just another forum, another opportunity for utilities to kind of get together and discuss, ‘Hey, these are the things that that concern us.’” 

Stressing the cybersecurity monitor is not an auditor, Bondurant said, “We’re here to come alongside the utilities and get a better understanding of what we are and where we’re at, cyber security-wise across the state.” 

“Texas is a huge space, and it’s pretty hard to be able to touch every single one of the utilities within the state. This program kind of helps us get an overall, generalized view of what we look like across the board, whether it’s municipal utilities, co-ops or investor-owned utilities,” he added. 

Recent topics have included unmanned aerial systems, which include drones.  

“That is a huge, huge topic that’s not just being talked about here in Texas,” Bondurant said. “Some of the discussion is, ‘How do we help utilities?’ [Utilities] are kind of hamstrung by federal requirements on what you can and can’t do in defense of your systems in concern with unmanned aerial systems. We’re discussing this, seeing what can be done legislatively to give [utilities] additional tools [to] combat this.” 

The program will hold a Critical Infrastructure Cybersecurity Summit on Oct. 9-10 on the University of Texas at San Antonio campus. It will feature speakers from the U.S. Department of Energy, the federal Cybersecurity and Infrastructure Security Agency, NERC and other security professionals.  

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NERC RSTC Approves Charter Revisions

The chair of NERC’s Reliability and Security Technical Committee (RSTC) hailed this week’s quarterly meeting in Montreal as a “very productive” gathering that moved forward on several important issues.

“I want to thank everyone for their engagement, their questions, [and] their perspectives on those issues, because we’re going to draw on that heavily over the next year or so,” Chair Rich Hydzik of Avista Utilities said at the conclusion of the informational session that took up the meeting’s second day.

Among the topics that members worked on during the two-day meeting was a standard authorization request (SAR) proposed by NERC’s Inverter-Based Resource Performance Subcommittee (IRPS). The SAR (on page 318 of the agenda) is aimed at revising FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to “address the reliability risks presented to the [grid] due to … observed systemic deficiencies in IBR [inverter-based resource] performance and modeling.”

NERC Senior Engineer Alex Shattuck explained the SAR was inspired by recent grid events such as the Odessa disturbances of 2021 and 2022, when the Texas interconnection lost 1.3 GW and 2.6 GW of solar and synchronous generation respectively. (See NERC Repeats IBR Warnings After Second Odessa Event.) Shattuck said the IRPS worked to make sure the potential “enhancements” to both standards are “aligned with FERC Order 901,” which directed NERC to submit reliability standards over several years touching on multiple reliability issues with IBRs.

RSTC members voted to endorse the SAR, which will be submitted to NERC’s Standards Committee for approval. Endorsement by the RSTC is not required to begin the standards development process, but it indicates the proposal has support from the community.

Members also approved a set of revisions to the committee’s charter intended to improve the balance of industry representation at meetings. NERC’s Board of Trustees approved the charter in 2019 when the RSTC was created from the merger of the Planning, Operating and Critical Infrastructure Protection committees. (See NERC Board OKs Committees Merger.)

The committee’s current membership rules permit two voting representatives each from industry sectors 1-10 and 12, along with 10 voting at-large seats. If any sector receives no nominations during the election process, that sector’s seat can be converted into an at-large membership for the remainder of the term.

While the meeting agenda stated this structure was intended to ensure “a full RSTC membership ready to tackle reliability risks,” Candice Castaneda, NERC’s senior legal counsel, said that the number of at-large members had grown beyond NERC’s intentions, reaching 15 at the beginning of 2024.

“This, coupled with the RSTC rule that matters require a two-thirds vote to pass, began causing tension with the sector balance requirements,” Castaneda said. She explained that NERC’s bylaws, along with the Federal Power Act, state that committees “organized on a sector basis must ensure that no two sectors are able to control a vote on a matter, and that no single sector can defeat a matter.” The growth of at-large members created a risk that one or two sectors could reach a dominant position on the committee.

To address these issues, NERC staff proposed to:

    • Eliminate the at-large conversion process and allow a sector to seek a special election to fill an open seat.
    • Remove the numerical cap on the number of representatives from a sector that can serve as at-large members.
    • Explicitly direct the RSTC Nominating Subcommittee to prioritize balanced sector representation, including citation of relevant parts of NERC’s Rules of Procedure.

The committee voted to approve the charter revisions, which will be submitted to NERC’s board for approval.

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New MISO Day-ahead Market Engine to Emerge Soon After Delay

MISO’s new day-ahead market clearing engine should move into standalone production near the end of the month following a delay in testing, executives with the RTO have said.

The new engine is one piece of MISO’s yearslong work to replace its aging market platform. Earlier this year, MISO said it planned to begin running its day-ahead market on the new engine in May. (See MISO Sets Sights on 2025 Completion for New Market Platform.)

“I can see the light at the end of the tunnel. I know I’ve been here for four months, but this is years and years of work,” Nirav Shah, MISO’s new chief digital and information officer, said during a Sept. 11 teleconference of the Technology Committee of the RTO’s Board of Directors.

Shah later confirmed to board members that “there were absolutely delays from a testing perspective.”

CEO John Bear acknowledged in June that MISO encountered challenges bringing the day-ahead market into parallel operations with the existing platform. At the time, he said the RTO was working with vendor General Electric to iron out problems that are preventing MISO from cutting over to the new platform and retiring the legacy system.

“The problems and challenges we’re addressing here will help us move faster on the rest of the project,” Bear said.

Shah said the testing phase of the day-ahead market clearing engine is now proceeding smoothly and MISO is in daily communication with GE.

The delay will likely impact the testing of MISO’s new real-time market clearing engine, which was expected to begin parallel operations in the third quarter of this year, but Shah said that start time is looking tenuous.

However, Shah said MISO plans to finish most of the projects associated with its market platform replacement by the end of 2025.

The RTO said it remains on track to launch its new one-stop model manager and end parallel operations of its old, siloed modeling systems in 2025.

MISO said it has worked with vendor Siemens to standardize data fields across the RTO’s separate modeling structures to make a cohesive model manager. It expects to complete data migration sometime in the first quarter of next year.

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EDF Report Promotes Heat Pumps Over Hydrogen in NY

A report commissioned by the Environmental Defense Fund slams the concept of natural gas-hydrogen blends as a false path to New York’s building decarbonization goals. 

Such blends have been proposed by New York gas utilities, but they would be minimally effective at reducing greenhouse gas emissions from buildings, according to the report, which advocates instead for using electric heat pumps. 

“Blending Hydrogen & Natural Gas: A Road to Nowhere for New Yorkers” concludes that an 80-20 blend of natural gas and green hydrogen would cut greenhouse gas emissions from buildings by 7% and cut emissions from the building sector as a whole by only 3.9%. 

Meanwhile, it would take 48 TWh of electricity from renewable sources to generate that much green hydrogen for heating fuel, the reports states, nearly eight times more than heat pumps would need to heat the same buildings. 

“Injecting hydrogen into gas pipelines, homes and buildings is not an interim decarbonization solution, despite industry assertions,” Erin Murphy, EDF’s senior attorney for energy markets and utility regulation, said in a news release.  

Buildings generate approximately a third of New York’s greenhouse gas emissions, due primarily to combustion of carbon-based fuels for heat, and slashing that output is a central piece of the state’s climate protection strategy. 

The report was released Sept. 12 and authored by Switchbox, a New York City think tank. It is based on present-day hydrogen-generation and heat pump technology and on circa-2021 data on buildings and gas service in New York. 

Numerous efforts are underway to develop ways of generating hydrogen at lower cost and greater efficiency. 

But heat pumps are 7.8 times more efficient than hydrogen for heating, and that is a huge gap to close, said Max Shron, research director at Switchbox and an author of the report. 

“I don’t think there is a way to have hydrogen be economical for heating,” he told NetZero Insider. 

Also, even more-efficient heat pumps may be developed as hydrogen production is improved, he added.  

Beyond the cost of generating hydrogen, there is its energy density — less than one third that of natural gas, the report states, meaning that more must be burned to obtain the same amount of heat. And there is loss in storage and transmission of hydrogen. 

The report suggests that instead of heating fuel, hydrogen should be targeted for hard-to-decarbonize applications in the transportation and industrial sectors. 

“You can use hydrogen for other things that are not heating and have it be much more economical,” Shron said. 

Green hydrogen must be produced with renewable electricity to be considered “green.” Advocates go one step further, and insist the renewable electricity be generated from newly created generation, because generating hydrogen from existing renewable generation would push other users back onto fossil fuels.  

Construction of new renewables in New York is lagging the ambitious timetable the state has set for itself. 

Murphy told NetZero Insider that the report is intended to be educational if not preemptive. New York gas utilities, facing a future where their product is excluded from buildings, have begun proposing projects and long-term plans involving continued service with hydrogen or biogas blends presented as less impactful to the environment. 

“That is really concerning because all the leading analyses are clear that is not the solution,” Murphy said. 

The state Public Service Commission has not approved any of these requests, she said, but neither has it articulated a clear policy.

The report is an attempt to move that policy-making process along and inform consideration, Murphy said. 

She’s optimistic the political climate in New York will make hydrogen less likely to be accepted as a means of building decarbonization. 

“The state has a strong climate law and then the policy documents that have been developed have also been quite clear on this point,” she added. 

The report also examines the differences between heat pumps and a 100% piped hydrogen scenario. 

Neither Murphy nor Shron was immediately aware of such a proposal in New York, but they said it was included in the report because a 20% hydrogen blend is sometimes presented as a stepping stone to 100% hydrogen. 

A 100% green hydrogen replacement for natural gas also is not a viable heating solution, the authors write, as it would reduce building emissions by only 54%, require four times more renewable electricity, and require installation of thousands of miles of new gas mains, plus all-new appliances to burn it. 

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NYISO Proposes Increased Budget, Admin Rate for 2025

NYISO on Sept. 6 presented its $204 million draft budget for 2025 to the Budget and Priorities Working Group, with an administrative rate of $1.319/MWh based on a 154,700-GWh transmission throughput. 

The proposed budget is a 4.72% increase over 2024’s $194.8 million. The proposed Rate Schedule 1 surcharge — the ISO’s administrative fee to recover its operating costs from members — is nearly 3% higher than this year’s $1.281/MWh. The surcharge is billed to all users of transmission lines based on the calculations set forth in NYISO’s tariff. 

“The increase in the revenue requirement for 2025 relative to 2024 is $9.2 million, which is about 4.7%,” NYISO CFO Cheryl Hussey told stakeholders. “The projected 2025 megawatt-hour throughput is an increase of 2.6 million MWh, which is an increase of 1.7% compared to 2024.” 

Hussey reported that NYISO is projecting a 2024 budget surplus because of overcollections under RS1 and spending being under budget. The ISO is therefore proposing an RS1 carryover of $3 million into the 2025 budget. This would reduce the impact of 2025 cost increases by approximately 2 cents/MWh, Hussey said. She also explained that if the carryover were not used to decrease the cost of RS1, it would be used to pay down debt. 

“For example, in 2023, we used $5 million as a carryover, and then the balance we used to pay down debt,” Hussey said. “In recent years, we’ve used a surplus to pay down debt. 2023 was the first time in a number of years that we proposed a carryover.” 

Debt servicing was projected to increase in 2025 to $7 million, an increase of about $4.8 million. 

Mark Younger, of Hudson Energy Economics, requested that NYISO provide more information about the kinds of debt the ISO had currently so stakeholders could see whether paying off high-interest and variable-interest loans or a carryover would be a better use of funds. Hussey said NYISO might be able to present something to address that at future meetings. 

“Why are your debt services going up?” asked Amanda De Vito Trinsey of Couch White, representing New York City. 

Hussey explained that in 2024 and 2025, NYISO was borrowing more money to pay for its increased project portfolio and infrastructure capital needs. In 2024, the ISO had borrowed $37 million to pay for its projects. 

“Obviously, the more money we borrow, we need to pay that back, and that leads to increased debt service costs in future years,” Hussey said. “I’ll point out that we are proposing to borrow $37 million again in 2025 to cover the cost of the project portfolio.” 

Hussey ran through more drivers of the cost increase, including a cost-of-living adjustment for its Market Monitoring Unit. Salary and benefits are also increasing between 4 and 6%, with 19 new staff positions being added, primarily to work on FERC orders 2023 and 1920 compliance and the Coordinated Grid Planning Process. 

“We always have to keep in mind that we maintain our salaries as competitive as compared to the market and as best we can limit inequities between certain positions that we have here at the ISO that should be placed in similar levels,” Hussey said. 

One stakeholder asked whether the budget was based on full staffing or the expected vacancy rate for NYISO. Hussey said that the vacancy rate was expected to be around 6% and that the budget was based on that lower number. She explained that NYISO was balancing its staffing needs against normal churn and imperfect replacement of departing employees. 

The final big line item was computer services. NYISO projects it will spend $3.9 million on computer services, up $1.5 million from the previous year. This is primarily for upgrades, enterprise software subscription costs and increased Amazon Web Services costs. 

Forecasts Through 2029

Max Schuler, an economic analyst for NYISO, presented the RS1 forecast through 2029. 

The RS1 rate is based on net load, billable exports, wheel-throughs and incremental supply. NYISO anticipates increased load driven by large load interconnections, electric vehicles, heating electrification and general economic growth.  

“Another important factor is the weather, which is most significant during the winter months for the exports and general system conditions and balance with external control areas,” said Schuler, while also noting that climate change is expected to lead to increased net load because of warmer weather in the summer.  

Schuler said that by 2029, the total throughput is expected to reach 159,400 GWh. Balancing the expected increases in net load are increased behind-the-meter solar, energy efficiency and billable exports. BTM solar and EE are forecasted to cut RS1 by 0.6 and 1.3%/year, respectively.  

Net load is forecasted to dip slightly in 2025 to 147,850 GWh from this year’s estimate of 148,580 GWh. After next year, NYISO thinks that the net load will gradually increase to 152,320 GWh by 2029. 

Next Steps

The Board of Directors will review a “high-level” summary of the draft budget at its meeting Sept. 17, with the Management Committee reviewing it at its meeting Sept. 25. 

Following more Budget and Priorities Working Group meetings, the MC is expected to vote on the budget Oct. 31 and the board Nov. 19. 

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Consumer Response Saved Alberta Grid During Jan. 2024 Cold Snap

An emergency alert urging the public to conserve energy helped the Alberta Electric System Operator narrowly avert rolling blackouts during January’s extreme cold snap, an AESO representative said during a WECC webinar.

The Alberta Emergency Management Agency sent the alert to cell phones and televisions at 6:44 p.m. on Saturday, Jan. 13, asking residents to immediately limit their electricity use to essential needs only.

“Extreme cold resulting in high power demand has placed the Alberta grid at a high risk of rotating power outages this evening,” the message said.

Within three minutes, load dropped by 170 MW, followed by an additional 100 MW after 10 minutes, according to Lane Belsher, AESO’s director of grid and market operations. Load continued to fall as “people were shaming their neighbors into shutting their lights off,” he said.

“It amazed me,” Belsher said. “We did not end up shedding any firm load.”

Belsher discussed the January cold snap during a Sept. 10 WECC webinar focused on winter-weather readiness.

The Canadian province had been enjoying mild, fall-like weather in early January before temperatures dropped below minus 40 degrees Fahrenheit in some locations.

The system hit an all-time winter peak of 12,384 MW on Jan. 11. Strong winds — and accompanying wind generation — that accompanied the falling temperatures helped the system meet demand on that day, Belsher said.

But conditions grew more challenging as the wind died down. AESO issued an energy emergency alert 3 on four days in a row, from Jan. 12-15.

The situation was especially dire as AESO neared its peak demand Jan. 13. Solar power is mostly gone by the peak, Belsher said, and AESO is heavily dependent on gas generation during winter.

But right at the system peak, generation from a large thermal unit dropped from 450 MW to about 160 MW, he said. AESO decided to use 190 MW of battery storage that it had been keeping “in our back pocket,” Belsher said. But the extreme temperatures meant the batteries would work for only about an hour rather than the expected two hours.

Similarly, about 150 MW was available through Western Power Pool reserve sharing, but only for about an hour.

Belsher talked to Alberta government officials, who deemed the situation to be life-threatening. The emergency alert was sent to the public, and blackouts were avoided.

Alert Used During Calif. Heat Wave

A public alert is a tool that has also been used successfully to avoid rolling blackouts in California — albeit during a heat wave rather than a cold snap.

At 5:45 p.m. on Sept. 6, 2022, the Governor’s Office of Emergency Services sent a message to 27 million cell phones, accompanied by a series of shrieking tones.

The message, sent during a 10-day, record-breaking heat wave, said: “Conserve energy now to protect public health and safety. Extreme heat is straining the state energy grid. Power interruptions may occur unless you take action.”

CAISO saw demand drop by 2,385 MW, to 48 GW, within 20 minutes of the alert, enough to avoid blackouts. (See CAISO Reports on Summer Heat Wave Performance.)

At AESO, another issue during the January cold snap was the price cap for imports. Belsher said the Mid-C spot price in the Northwest the evening of Jan. 13 was about $1,300 CAD; AESO’s price cap is $1,000.

Belsher noted that the system completed its phaseout of coal this year. A gas generator was off temporarily during the cold snap due to a frozen gas valve.

Two additional combined-cycle gas units were commissioned this year but weren’t available in January.

“It would have been nice to have them, but I think we’re in better shape for this winter coming forward,” Belsher said.

Another speaker during the WECC webinar was David Lemmons, co-founder of Greybeard Compliance Services. He discussed a new NERC standard, EOP-012-2, which requires power plants to have a winter-readiness plan.

Lemmons said plant operators should consider whether their gas delivery path is protected from the weather, and if start-up will take longer when it’s cold outside.

Other advice included checking for broken or missing windows and making sure windows are closed before cold weather arrives.

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Clean Energy Buyers Push Passage of New Calif. Reliability Law

Large buyers of clean energy were the key backers of a California bill passed last month to strengthen the state’s reliability planning.

The state’s reliability planning has grown more challenging given the increased frequency of extreme weather events, higher temperatures and greater load variability — creating the need for better planning to offset uncertainty and keep the lights on.

Sponsored by the Clean Energy Buyers Association (CEBA), Assembly Bill 2368 seeks to address that need, requiring the California Public Utilities Commission to adopt a 1-in-10 loss of load expectation (LOLE) — or a similarly robust planning standard — when setting resource adequacy requirements.

The bill also directs the commission to develop a “mid-term reliability assessment” using probabilistic modeling that looks two to five years into the future to better anticipate potential procurement shortfalls and resulting reliability issues.

Additionally, it requires increased information-sharing between the CPUC and CAISO to enable the ISO to conduct its own reliability modeling and ensure it can meet its own regulatory obligations.

While the 1-in-10 metric is a widely used planning standard, the legislation marks the first time it has been written into California law.

According to Heidi Ratz, CEBA deputy director of market and policy innovation, FERC views RA as state jurisdictional, though most planning standards are set by regional balancing authorities. Other entities, such as the Western Resource Adequacy Program, have formalized a 1-in-10 LOLE target, and agencies such as the CPUC and the California Energy Commission support it for California.

‘Right Amount of Resources’

Proponents of the bill say that enshrining a stricter LOLE standard into law will modernize the state’s planning framework and improve the planning and procurement process.

“Grid planners in California have acknowledged the challenges to electricity resource adequacy and grid reliability within the state, and CEBA sponsored this legislation to tackle some fundamental energy planning issues,” Ratz said in a CEBA press release. “As our grid faces unprecedented pressures, including extreme weather and demand growth, California leaders must have a sense of urgency in implementing sound resource adequacy planning and procurement processes.”

Ratz further emphasized that the bill will help grid planners increase trust in their RA programs and decrease the need to rely on the state’s Strategic Reliability Reserve.

“As planning agencies move towards procuring the right amount of resources well in advance, we will see fewer outages, ‘near misses’ and emergency procurements, meaning reliability will hopefully be noticeably improved,” Ratz told RTO Insider in an email. “We’ll also see a decrease in scarcity which leads to lower transaction costs in the real-time energy market and more functional capacity markets that send better price signals to market participants. Ensuring the right resources show up in the energy market during times of grid stress is the primary way to improve reliability.”

CAISO stakeholders have been calling for improved LOLE modeling for some time. In June, Gridwell Consulting asked the ISO to take a bigger role in reliability planning and conduct probabilistic LOLE modeling to better understand the aggregate impact of the changing climate on grid conditions. (See Stakeholders Call on CAISO to Take Larger Role in Reliability Planning.)

Gridwell CEO Carrie Bentley emphasized the need for better planning by citing data showing that, between 2017 and 2023, load variability was significant enough to cause load forecasts to deviate from actual loads by several thousand more megawatts than historically normal.

Gridwell joined CEBA in support of the legislation, also emphasizing its potential to lower costs.

“This will improve reliability and in the long run lower costs compared to the system in place today that caused California’s reliability levels to vary widely over time,” Bentley said.

In 2014, the CPUC opened a proceeding to address mid-term reliability that resulted in recommendations that were never adopted. Had they been adopted, it is likely that much of 2020’s capacity shortfalls could have been avoided, Ratz said. The lack of a stricter planning and modeling framework created the conditions for the events in 2020 and continues to have impacts on cost and reliability.

“Since the outages of 2020, California has issued four last-minute, ad-hoc emergency procurement orders; each ordered the LSEs to sign contracts with new resources that can come online as quickly as possible,” Ratz said. “CPUC did conduct limited modeling (reliability analyses) before adopting these decisions that demonstrated the urgent need for additional generation capacity to come online in the mid-term. Combined with the strategic reserve, these were some of the most expensive procurements in California’s history, and these expensive electricity emergencies have material impact on customers’ operations in the state.”

CEBA is urging Gov. Gavin Newsom to expedite signing the bill, which has received support from other agencies such as the Environmental Defense Fund, Pacific Gas and Electric, International Brotherhood of Electrical Workers and more.

AB 2368 is the first reliability-focused bill sponsored by CEBA, signaling the importance of reliability to the group’s members.

“The planning improvements in the bill are critical to California’s ability to provide energy customers with low-cost, reliable, clean power,” Ratz said.

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FERC Refuses MISO, MDU Complaints Regarding Crypto-strained MISO-SPP Flowgate

FERC has dismissed separate complaints from MISO and Montana-Dakota Utilities Co. over a MISO-SPP flowgate chronically stressed by a North Dakota cryptocurrency mining operation.   

The commission issued a Sept. 10 order, refusing the pair of complaints; it said neither MISO nor Montana-Dakota Utilities (MDU) proved that the Charlie Creek flowgate in North Dakota failed to meet the criteria for market-to-market (M2M) coordination, nor was SPP in the wrong for continuing to insist on M2M coordination (EL24-61).  

MISO and MDU have been sparring with SPP over the flowgate since last year, when cryptomining facility Atlas Power Data Center opened and brought 200-MW load to SPP’s transmission-constrained Northwest North Dakota load pocket, which now has a peak load of about 1.5 GW but only approximately 1 GW of import capability. (See MISO Lodges 2nd Complaint Against SPP over Disputed Crypto Load on M2M Flowgate.)  

FERC said it disagreed with MISO and MDU that SPP violated sections of the MISO-SPP joint operating agreement, that MDU incurred duplicate congestion charges and that the rules MISO and SPP rely on for M2M termination are unreasonable.  

The commission found that “MDU and MISO have not demonstrated that SPP acted unreasonably in declining to grant consent to remove the Charlie Creek Flowgate from the market-to-market coordination process.”  

SPP has maintained that Charlie Creek remains eligible for M2M coordination based on the RTOs’ flowgate studies, which it argued determine hundreds of other MISO-SPP flowgate designations. 

MISO and MDU have argued that although the Charlie Creek Flowgate passes MISO and SPP’s flowgate studies, its M2M status should be revoked because the RTOs’ coordination is helping SPP manage a local issue caused by data center load growth, and not a regional issue. The two said the congesting spikes caused by the Atlas Power Data Center are squarely in SPP’s territory and said SPP’s insistence on M2M coordination is at the detriment of MISO market participants and customers.  

MISO last year initiated a formal dispute process with SPP over the flowgate. By March, it asked FERC to terminate M2M coordination on Charlie Creek and requested refunds on the M2M coordination charges it paid to SPP beginning in April 2023.  

MDU filed a complaint against MISO and SPP early this year, saying it was overcharged $18 million for congestion management because the two RTOs were conducting unwarranted M2M coordination. MDU, a MISO member, has 150 MW of load and two 115-kV lines in the load pocket and relies on network integration transmission service from SPP to serve load when its own transmission is insufficient. 

MISO claimed that improper M2M coordination cost its members $38 million in M2M charges to manage congestion. The grid operator also argued that SPP’s approval of a temporary remedial action scheme for the Charlie Creek flowgate shows that the M2M coordination is being used to address a local issue wrought by load growth.   

MISO’s Independent Market Monitor further argued that, during periods of market-to-market coordination, MISO could provide less than 1 MW of relief on the Charlie Creek flowgate, while curtailment of Atlas’ load in SPP could provide more than 90 MW of relief. 

However, FERC said MISO and MDU were misreading the definition of an M2M flowgate as laid out in the MISO-SPP joint operating agreement. FERC said while a section of the RTOs’ Interregional Coordination Process says M2M coordination should be reserved for issues that are regional and not local in nature, that’s not an explicit prerequisite for a flowgate to be eligible for an M2M flowgate designation. 

Because it determined the regional issue threshold wasn’t a requirement for M2M coordination, the commission declined to determine whether the added cryptomining load constitutes a local issue. 

FERC pointed out that SPP provided evidence that revoking Charlie Creek’s M2M flowgate status might risk SPP needing to resort to transmission loading relief or load shedding.  

FERC also refused to deem MISO and SPP’s Interregional Coordination Process unreasonable because it allows either MISO or SPP to refuse to lift M2M designation even when the other RTO can offer little congestion relief. MISO argued that the mutual agreement condition amounted to an “unconditional veto.”  

But the commission said the rules give MISO and SPP “reasonable discretion on an equal basis to mutually agree to add or remove market-to-market flowgates without any conditions or requirements.”  

FERC decided SPP acted reasonably by not agreeing to remove M2M coordination. It said SPP provided evidence that it can redispatch to alleviate the flowgate in “most” hours. FERC also said keeping up the M2M coordination “helps create an appropriate market signal for MISO to dispatch generating units within its footprint that have a significant generator shift factor on the flowgate,” making for a more efficient market solution versus terminating M2M procedures.  

Because it denied the complaints, FERC likewise denied a related waiver request from MISO that would have allowed the RTO to adjust SPP’s Integrated Marketplace settlements beyond the current 365-day limit (ER24-1586).  

Nearby Basin Electric Power Cooperative announced plans in May to build a 1.4-GW gas-fired power plant to address growing demand from North Dakota’s data center industry.  

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ISO-NE Responds to Feedback on Capacity Auction Reforms Scope

ISO-NE’s Capacity Auction Reforms (CAR) project will include an evaluation of additional resource accreditation modeling enhancements, the RTO told the NEPOOL Markets Committee on Sept. 10. 

The RTO also plans to estimate seasonal tie benefits in its resource adequacy assessment model, it said. The remarks came in response to feedback it solicited on the “straw scope” of the project, which aims to move the Forward Capacity Market to a prompt and seasonal market. (See ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms.) 

Some stakeholders argued  ISO-NE’s resource accreditation modeling does not accurately reflect the region’s risk profile, including the duration of events. (See ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns.) 

“As part of CAR, the ISO plans to assess whether it can make further enhancements to the modeling and accreditation proposal to better align accreditation values with contributions to resource adequacy,” said Chris Geissler, ISO-NE director of economic analysis. The RTO also plans to consider how it models intermittent and limited-energy resources, along with improvements to the load model, he said. 

Other stakeholders expressed concerns  the new accreditation methodology would not consider the marginal reliability impact (MRI) of tie benefits, potentially causing the RTO to overestimate the reliability benefits of interties. 

In comments submitted prior to the meeting, Calpine argued that “any supply source, including imports, used to meet capacity requirements should be counted similarly and subject to similar performance requirements” and that ISO-NE “should apply this standard to the CAR work.” 

Geissler said the RTO will work with its neighbors to evaluate seasonal tie benefits, which “represent the expected contribution from other regions during emergency conditions.” 

However, ISO-NE does not plan to calculate MRI values for tie benefits, or to subject tie benefits to Pay-for-Performance (PFP) rules, Geissler said. He noted that tie benefits will be modeled in resource adequacy assessments, which are used to determine the RTO’s installed capacity requirement. He added that “tie benefits are not directly competing” with capacity resources to meet this requirement. 

Geissler also told the MC that ISO-NE is not planning to include an evaluation of how the capacity market treats resource retentions. He added that, in a future phase of work, the RTO may consider broader changes to its rules for reliability-must-run contracts if it determines that retentions for energy security reasons are needed. 

The RTO also is not planning to model resource start times because of the constraints of GE MARS, its resource adequacy modeling software, despite interest from some stakeholder groups, Geissler said. 

“Assessing changes to the resource adequacy platform would be a significant, multiyear effort that would take resources away from other parts of the CAR effort and jeopardize the ISO’s ability to complete CAR in time for [capacity commitment period] 19,” Geissler said. 

In a memo published prior to the meeting, environmental advocacy groups pushed the RTO to model startup times, arguing it is a necessary step to fairly compensate resources for their ability to support the power system on short notice. 

“Units with lengthy startup times simply do not offer the same resource adequacy value as more flexible ones,” the organizations wrote. “We understand that this will involve substantial resources, but given that ISO has already committed to spending several years on overhauling its capacity market reform, now is the best time to address this important consideration.” 

The groups also urged the RTO to model “correlated outages and ambient temperature adjustments” as part of the CAR project. 

Gas and diesel resources are “susceptible to both cold and hot temperature-dependent forced outages,” the organizations said while calling on ISO-NE to “model these reliability impacts as accurately as possible.” 

Geissler said ISO-NE still is considering whether to include temperature adjustments and correlated outages in the project scope, noting that the topic “raises technical modeling questions that must be more fully assessed before a decision can be made.” 

He added that ISO-NE is planning to model correlated outages of gas resources related to the region’s gas constraints in the winter. 

IMM Quarterly Markets Report

Wholesale market energy costs were down by 23% this spring relative to that of 2023 because of lower natural gas prices and capacity clearing costs, according to the ISO-NE Internal Market Monitor’s quarterly markets report. 

The real-time hub LMP averaged $24.64/MWh, ranging from 9 to 13% lower than in spring 2023. The average load (11,869 MW) was up by about 180 MW per hour in part from higher temperatures in May compared to the prior year. 

Nuclear generation rebounded after several down seasons because of lower rates and accounted for about 28% of the average output. Natural gas remained the largest generation source at 45% of the average output. Imports decreased because of a drought in Canada that affected hydro reservoir levels.