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November 17, 2024

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FERC Workshop Examines How to Speed up Interconnection Queues

FERC still is working to implement the changes to its generator interconnection rules from Order 2023, but it also is considering further changes, as it held a two-day workshop Sept. 10-11 to gather more input. 

Order 2023 made improvements, FERC Chair Willie Phillips said at the start of the event, but it was not meant to be a silver bullet to queues that are seeing massive interest from new resources and overlapping with widespread demand growth. 

“Our country has a severe interconnection queue backlog. We have over 2,000 GW of generation that’s waiting in the wings to be connected,” Phillips said. “We know right now that the average wait time is over five years for projects to get through the queue. That means that projects that are pretty much ready to go right now have to wait until at least 2029 before there’s a single shovel in the ground. I believe, I’m sure you agree, that’s unacceptable.” 

All five of the commissioners participated in or observed the staff-run workshop at different points over the two days. 

Commissioner Mark Christie argued that more changes are needed, as many power plants are shutting down while demand is rising. 

“Reliability is the overriding goal of interconnection,” Christie said. “That means prioritizing those generation resources that can be built quickly and efficiently and that give us the most generation capacity as quickly as possible, at the least cost burden to customers.” 

The glacial pace of the queues, along with the retirements and rising demand, is contributing to a looming reliability crisis, Christie said. Speeding up new supply can help. One idea that stood out to Christie was from Colorado Public Utilities Commission Chair Eric Blank, who proposed letting state regulators designate which resources would help ensure reliability and giving them preference. 

In his written testimony, Blank argued that the current process in Colorado is working well, but a law in the state requires it to join an RTO before 2030, and that could lead to delays. Resources that clear Colorado’s competitive resource solicitation are prioritized now, and Blank wants that to continue in an organized market. 

“It may be fundamental to Colorado’s ability to maintain resource adequacy and cost-effectively comply with our statutory emission-reduction goals by enabling us to select the type of resources we need, where and when we need them,” Blank said. “As our transmission utilities seek to join RTOs, we would implore FERC to allow us to continue to prioritize the winning bidders from our competitive resource solicitation process, at least for some transitionary period.” 

CAISO has taken queue reform further than most transmission providers, but its most recent cluster of new projects, Cluster 15, had 541 projects representing 354 GW of new supply, which is so much it just does not make any sense to study it all, said Danielle Osborn Mills, the ISO’s principal for infrastructure policy development. 

“We now have over three times the amount of capacity that we expect to need to achieve our 2045 objectives,” she said. 

The issue is not a lack of staffing, or the length of time it would take to study all that excess generation, but rather that developers have proposed so many projects that never will lead to steel in the ground, Mills said. 

“The ISO’s focus has been really on trying to find ways to increase competition earlier in the process, and to find the best and most ready projects that align best with system need and transmission availability early in the process, so that we’re using our study resources to really focus on the projects with the highest likelihood of success,” she added. 

PJM is working through a major backlog of resources and not accepting any new requests until 2026. The RTO is considering a parallel queue to get shovel-ready projects that can help it maintain reliability as its reserve margins are narrowing, said Adrien Ford, director of wholesale market development for Constellation Energy Generation. 

“Demand is increasing at an ever-growing rate, and the pace appears to only be getting faster,” Ford said. “I believe that RTOs have an obligation to facilitate the reliable and ready resources.” 

Constellation is the largest nuclear plant owner in the country, most of them in PJM, and they could expand available capacity quickly through uprates. The company has plans to expand two units by 135 MW, but PJM will not be able to even consider its applications for expanded interconnections until 2026, and that delay could be compounded by the units’ refueling cycle, which is when such work has to take place. 

“If resource adequacy and/or reliability aren’t anticipated to be maintained, then the rate cannot be just and reasonable,” Ford said. “So, I think it’s imperative that action is taken. The expedited reliability process could run in parallel to the existing queue.” 

FERC has maintained a commitment to open access and ensuring a level, competitive playing field for all resources, said Jason Burwen, vice president of policy and strategy for GridStor. Key precedents such as orders 888 and 2003 are focused on keeping barriers to entry low to allow for more competition to benefit consumers. 

“The energy storage industry, of which my company is a member, owes its historic growth to low barriers to market entry that this commission has upheld to date, and open access has been key to enabling capital formation and new market entrants, like my company,” Burwen said. “So, when we think about rationing interconnections, this is, first of all, something I just want to call out. This is a second-best, maybe a third-best, solution to the problem at hand. And we should also consider that it is a Band-Aid; that it is probably a temporary fix.” 

Proactive Planning’s Role

SPP is trying out a new approach to queue management, which Burwen and others called the “entry fee approach,” and solutions like that could mitigate the underlying issues without sacrificing open access, he added. 

The Consolidated Planning Process would mix transmission planning and generator interconnection, co-optimizing the processes and allowing SPP to plan lines that can be paid by both load and new generators, said Natasha Henderson, the RTO’s senior director of grid asset utilization. 

The CPP involves proactive planning for both new load and supply and then aligning the analysis for both processes, which will enable planners to co-optimize the future grid around both inputs. Then SPP needs to tackle cost allocation so the beneficiaries of those co-optimized lines pay their fair share, Henderson said. 

“The concept of the ‘entry fee’ SPP has in mind is to look for a 20-year transmission plan, determine what that transmission would look like, devise an entry fee based upon that and that entry fee would be known to generation interconnection customers before they would enter the queue,” Henderson said. 

Developers were in favor of the idea because getting one fee upfront eliminates a key problem they have with the current system: uncertainty. Several developers complained over the two days about frequent restudies upsetting their earlier expectations, and that even when they made it through a balancing authority’s queue, they sometimes could be hit with a major bill for upgrades in a neighboring “affected system.” 

“We need to provide certainty to generators sooner in the process, to allow decisions to be made earlier in the process,” said David Mindham, EDP Renewables’ director of regulatory and market affairs.  

SPP’s proposed CPP process would do that, he added. The idea of combining proactive transmission planning with interconnection was supported by many speakers at the conference, with R Street Institute Senior Fellow Beth Garza arguing it would make sense for consumers. 

“In too many areas, the interconnection process is being used, instead of comprehensive regional planning, to effectuate network upgrades, and this leads to inefficient outcomes,” Garza said. “These inefficient outcomes mean consumers are harmed because, make no mistake, consumers pay, either directly or indirectly, the cost of all transmission. Whether the transmission results from an interconnection process or regional planning process, costs and risks assigned to generators will find their way to consumers, either through higher prices or potentially an inability to procure or purchase the power from their desired sources.” 

The concept was the subject of a paper that Advanced Energy United and the Solar and Storage Industries Institute commissioned from Brattle Group and Grid Strategies ahead of FERC’s workshop. (See AEU Webinar Highlights Potential Queue Improvements.) 

“The transmission system is not built for new generation resources and load growth,” report co-author and Brattle Group Principal John Michael Hagerty said. “That results in a perpetually constrained system that requires complex studies to identify upgrades that are higher costs than they need to be, that does not consider other system needs and is built just in time for new resources.” 

Connect and Manage

ERCOT avoids the need to study generators’ impacts with its “connect and manage” approach to interconnection, in which any impacts new resources cause, like increased congestion, are dealt with in the transmission planning process, said Warren Lasher, president of Lasher Energy Consulting. 

“The benefit for the generator is it can move through it at its own pace, and you can see generation that comes online in two and a half, three years,” said Lasher, previously ERCOT’s senior director of system planning. “The downside is, as you have mentioned, the risk of curtailment. Now, importantly, the risk of curtailment is only shared by renewables at this time, because there are Planning Guide provisions that state that thermal dispatchable generation has to meet a certain amount of dispatchability for resources, specifically for resource adequacy concerns.” 

ERCOT has not been doing much proactive transmission planning lately, though Lasher said it is working on changes to its economic planning criteria that could lead to improvements. 

The Competitive Renewable Energy Zone lines were a pioneering effort in proactive planning and helped Texas shift huge wind resources from points west to its major cities in the eastern part of the state, Lasher said. Now the state’s Public Utility Commission is considering transmission development that would shift power the other way as large loads in the form of oil and gas drilling and data centers have located there, in part to take advantage of cheap renewable power that is caught behind constraints. 

The FERC equivalent of connect-and-manage is energy resource interconnection service (ERIS), in which generators sign up to be able to sell on the grid with a higher risk of curtailment. There also is network resource integration service (NRIS), which ensures enough deliverability to qualify for capacity auctions in markets that use them. But the difference between ERIS and NRIS can be narrow in some markets. 

“ERCOT is not the only transmission provider in the United States treating energy-only service in a significantly less restrictive way,” said Tyler Norris, a doctoral student at Duke University’s Nicholas School of the Environment, whose research focuses on electric power systems. “At least two other ISOs take a similar approach. Currently, in New York and California, both of those markets have concluded that all, or most thermal power flow constraints for transmission-scale generators can be managed in real time via redispatch, so generally, they are not assigning thermal upgrade costs to ERIS generators.” 

Interconnection Queue Automation

Another option FERC considered during the workshop was automation through software. 

“I believe automation can yield benefits in three principal areas,” said Clayton Barrows, senior researcher at the National Renewable Energy Laboratory: “first, identification of solutions that might not have been apparent to the engineers that traditionally conduct the interconnection studies; second, evaluation of significantly more conditions to improve the robustness of results; and then third, improving the transparency and quality of solutions and the mitigation options that might arise from them.” 

Pearl Street Technologies is one software firm offering a way to automate the system impact studies in the interconnection process in ways that can speed it up greatly, said its CEO, David Bromberg. 

“Even within the studies, there’s a whole lot of sub-steps involved, ranging from taking in the data, to building up the power flow models, running the power flow study, identifying the constraints, proposing network upgrades, estimating the costs, running the cost allocation, and then putting all of this in a report that’s digestible by interconnection customers,” Bromberg said. “So that’s a pretty long list. But even that is a simplification, it is a very complex process.” 

Some of those sub-steps have benefited from automation for years, but Pearl Street offers developers and grid planners ways to automate the entire process, he added. Developers use it to try to pick the best sites for new power plants, while Pearl Street is working with SPP and MISO to automate elements of their interconnection studies. 

“SPP has applied automation to our current backlog studies, and we’re making our way through those clusters,” said Jennifer Swierczek, the RTO’s manager of generator interconnection. “By next summer, every request will have a phase 1 and a phase 2 answer, and many more requests will have reached [generator interconnection agreement]. A lot of that is due to the automation that we put in place.” 

Artificial intelligence has been a hot topic in the electric industry for its projected impact on demand because of the required new data centers, but FERC asked whether the technology could help speed up the queue. 

The kind of large language models that consumers are familiar with are not the kind of AI that is capable of speeding up the queue, Bromberg said. Pearl Street’s optimization engine can help, but it is just modern computational software, he added. 

“We can’t tell AI to do even steady-state analysis, let alone transit stability, or if you have a weak grid area, like an electromagnetic transient study, something really complex,” said Cody Doll, NextEra Energy senior manager of transmission business management. “AI does, however, seem to do very good job at pattern identification for large datasets, and we’ve explored potential uses such as parameter verification.” 

Sifting through large datasets for patterns can be of some use, but it will require new AI technology to transform the interconnection process, he added. 

Automation in general has its limits for the complex and nuanced studies required by the interconnection process, said Donnie Bielak, PJM director of interconnection planning. 

“You need to have the oversight and the engineering judgment that goes into the scrutiny, and that does take time,” he added. 

PJM is automating and streamlining where it is possible, but going too far down that road could lead to “poor solution quality” in the interconnection process. 

“I like to think of PJM planning as kind of the bouncers at the door,” Bielak said. 

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Building Foundations for More than Wind Turbines

COEYMANS, N.Y. — Major components of New York’s next offshore wind farm are taking shape on a hillside far from the ocean, and along with them the makings of a domestic supply chain.

On Sept. 12, Ørsted gathered industry, labor and environmental officials in upstate New York to mark some milestones in preparation for construction of Sunrise Wind.

The offshore wind developer said it has completed 50% of the advanced foundation components, 50% of the onshore substation and 30% of the duct bank work for the onshore power line.

Horizontal directional drilling will begin for the near-shore cable this autumn, and foundations for the 84 turbines will start to be installed in the spring.

The growing pains early U.S. offshore wind projects have suffered are due in part to the limitations of the domestic supply chain, and the industry’s future will benefit from the experience being gained in places like Coeymans.

Johnta Terry, an ironworker with Local 12, confers with a supervisor during finishing work on one of dozens of external platforms for the Sunrise Wind project. | © RTO Insider LLC

“I was here in October of 2021, and we walked around and what we saw was a blank, ungraded piece of land along the river, and we weren’t sure what could become of this site,” David Hardy, CEO of Ørsted Americas, said at the event.

Three years later, contractor Riggs Distler has more than 100 people working on the site and thousands of tons of their handiwork is lined up, ready for shipment.

Chris Johnston, vice president of offshore wind at Riggs Distler, said institutional knowledge is being built as the first wind farms are being built.

“They’re difficult projects. They haven’t been done in the U.S. before. And you know, we’re all learning as we go on some of these projects.”

Even things as simple as the tent placed over concrete as it cures have been improved, construction manager Chuck Carter said. During work in Rhode Island on Ørsted’s South Fork and Revolution projects, the company had to move the tent with a crane. Here in New York, it built the tent on rollers.

“It’s done really well from our challenges in Rhode Island,” he said.

Dozens of 130-ton external working platforms are lined up, two hoists on top of each. One hoist is for materials, and one is for technicians.

Lucas Boehlke, an ironworker with Local 12, installs a railing on an external platform that will be part of the Sunrise Wind project. | © RTO Insider LLC

The latter is called the GUS crane.

That’s not the manufacturer’s name. It’s a descriptive acronym: Get. Up. Safely.

No more hopping and scrambling to get into the tower.

“Guys or gals would have to jump across to the ladder and climb up, and then get to the platform, and then go inside and go to the top to do the work,” Hardy explained.

With GUS, they can get hoisted right off the deck of the crew transfer vessel.

The Supply Chain

So why do this work in Coeymans?

It is 135 miles of sailing to get to the closest part of the Atlantic Ocean, then 150 more to get to the lease area where Ørsted will build Sunrise.

Answer: Land is plentiful and affordable in Coeymans, and anything from a barge to an oceangoing ship can pull right up to the quay.

In a nice bit of turnaround, the Port of Coeymans sits on the former site of the last working brickyard out of the scores that once lined the Hudson River. So one of the places that manufactured pieces of New York’s urban landscape in the 1800s and 1900s is now building pieces of its energy portfolio in the 2000s.

“Folks, I’m here to say this is what building offshore wind looks like,” said Doreen Harris, president of the New York State Energy Research and Development Authority. “This is what we knew could be possible, and now we see it before us, literally, here today.”

Hardy said Ørsted’s planned investment in U.S. renewable energy is in the $20 billion range, and said the work done in Coeymans will cost $86 million.

New York’s interest in offshore wind is many-faceted, but economic stimulation is near the top of the list.

Union ironworkers applaud a progress report on Sunrise Wind component fabrication. | © RTO Insider LLC

Harris said: “Of course, we see the major components, the blades, the towers and nacelles, but within that are literally thousands of subcomponents that come with, in this case, hundreds of jobs. It’s a huge value proposition.”

New York had obtained tentative commitments for blade, tower and nacelle factories to be built along the Hudson River in or near Coeymans, but those were contingent on awards in its third offshore wind solicitation, which had to be canceled for lack of specified turbines.

The state still has $500 million available to incentivize supply chain developments, Harris said, and new proposals may be in the offing.

“This is an industry, if we have learned anything, it requires determination, fortitude and commitment, and that is very much what you see here from the state of New York and from the Hochul administration,” she said.

The state has been trying to steer offshore wind job creation toward organized labor — many of the workers building pieces of Sunrise Wind in Coeymans are unionized.

Michael Lyons, president of the Greater Capital Region Building and Construction Trades Council, is happy about this. Beyond the metrics with which offshore wind is measured — billions of dollars spent, gigawatt hours of electricity generated, millions of tons of carbon dioxide not emitted — it can be evaluated for its impact on working people.

Riggs Distler Construction Manager Chuck Carter speaks about the fabrication work his company is doing for Sunrise Wind. | © RTO Insider LLC

“When we talk about hundreds of union jobs Sunrise Wind is creating, that’s not just a number, that’s hundreds of New Yorkers who are excited to be a part of this historic project,” Lyons said. “And that’s why we’re all here today, not just to celebrate the incredible tradesmen and women building our clean energy future, but also to reiterate our commitment to growing this important local industry.”

South Fork Wind, the nation’s first utility-scale offshore wind project, was completed earlier this year and is feeding into the New York grid.

Sunrise Wind is back under contract and under construction after concluding in 2023 that it could not go forward under the financial terms of an earlier contract.

Empire Wind is also back under contract and laying groundwork for construction. It is presently building an $861 million offshore wind hub in Brooklyn, 130 miles closer to the ocean than Coeymans.

At least three projects have been bid into New York’s latest solicitation; the state hopes to award contracts in early 2025.

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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.