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November 18, 2024

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NERC’s Gugel Says Action Ahead for Renewable Integration

ATLANTA — At the first day of the North American Generator Forum’s Annual Compliance Conference, held at NERC’s headquarters, NERC Vice President of Engineering and Standards Howard Gugel jokingly complained that because he worked for the ERO, most attendees probably automatically thought of him as “the standards guy.”

“Unfortunately, [for] a lot of people, when you mention the name NERC, your mind immediately goes to standards and compliance. And of course, that’s what we do,” Gugel said. “But we do things other than standards, right? We do reliability assessments. … We also monitor the bulk electric system. … And so when things occur on the system, when reliability coordinators alert us to things, we’re able to go in and look to see how things are evolving in the system and keep folks appraised of how things are evolving.”

Gugel was at the conference to discuss NERC’s response to what he called “the brave new world of resilience,” which is being brought about by the interconnected trends of “decarbonization, decentralization and digitization.”

The first of these refers to the growth of carbon-free generation sources like wind and solar, whose energy output is dependent on the weather and must be managed in a completely different way than traditional generators. Decentralization, which refers to the spread of behind-the-meter resources, is linked to the growth of rooftop solar panels, as well as battery energy storage systems. Meanwhile, digitization — the reliance on the internet to facilitate the management of these new technologies — underpins each of these developments.

Howard Gugel 2022-10-11 (RTO Insider LLC) FI.jpgHoward Gugel, NERC | © RTO Insider LLC

A major challenge in the management of these new resources, Gugel said, is that because they do not belong to the BES, they do not actually fall under NERC’s reliability standards, even though they make up a significant fraction of the asynchronous generation on the bulk power system: 16.2% as of 2021. By comparison, only 3% of synchronous generation connected to the BES did not fall under NERC’s standards last year.

Even renewable resources that are connected to the BES pose major challenges for grid operations because of their very different behavior patterns. Gugel said that unlike inertial generators, whose output declines gradually in the event of a problem, giving operators a bit of time to respond, solar facilities in particular behave more like a “step function” with output falling right away.

“You can see 1,000 [to] 2,000 MW come off immediately, and then five minutes later when that momentary cessation is done, it all comes back at the same time. That causes the operators to really be concerned about how they control that system,” Gugel said.

The theme of digitization creates challenges related to the cutting-edge nature of many new generation resources, which means they need constant internet connectivity to monitor, troubleshoot and deliver software updates that in some cases come from their manufacturers overseas. This makes these facilities an attractive target for hackers, especially because a relatively small amount of companies are responsible for a large proportion of grid-connected hardware. If an intruder can break into one manufacturer’s systems, they could be in a position to conduct a major operation against the North American power grid.

Returning to the topic of standards, Gugel assured the audience that NERC is taking the challenge posed by the grid’s evolution seriously. The organization’s efforts range from standard development projects aimed at revising the facility interconnection requirements, to potential moves to re-evaluate the definition of the BES itself so that NERC’s standards can apply to behind-the-meter resources that they currently don’t cover.

“It’s obvious that we can’t just stay where we’re at; the status quo is just going to make us farther and farther behind [on] this reliability issue,” Gugel said. “The time to act is now, so you’ll hear more about [the] evaluation of the definition of BES and possible changes to registration criteria as we go forward.”

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MISO Insists it can Handle Record-setting Interconnection Queue

MISO on Monday assured stakeholders that it has the means to study the 170 GW of new generation requests that were added to its interconnection queue in September.

However, stakeholders seemed unsure whether the grid operator is up to the task, bolstered, perhaps, by Berkeley Lab’s analysis showing it’s more expensive than ever for generation to connect to the footprint’s grid.

MISO said last month it must sort through a record 171 GW of proposed generation projects across 956 interconnect requests for the 2022 cycle. The requests could bring the queue to the brink of 300 GW, triple what was there just two years ago. (See MISO: Record 1,000 Interconnection Requests in 2022.)

Phil Van Schaack, manager of resource utilization, said the 2022 cycle almost doubled the requests received in 2021.

“MISO saw nearly 100% growth year over year,” Schaack said during Mondays’ Interconnection Process Working Group (IPWG) teleconference. He said the megawatt value of this year’s queue entrants is “greater than all the installed capacity in the MISO commercial model.”

Five years ago, the RTO’s planners said processing what was then a 60 GW queue was a tough proposition. (See MISO Works to Address Unprecedented Queue Volume.)

Van Schaack said solar generation is dominating the queue and a record number of requests came from first-time developers in MISO. If all the interconnection requests are realized, the queue would be composed of more than 95% renewable and storage resources.

“Not all of these projects will make it to the end, but still, record setting-numbers,” he said. “We appreciate everyone working with us as we work through these requests.”

Staff is reviewing the projects to validate whether they have secured site control, Van Shaack said.

Invenergy’s Arash Ghodsian asked whether there’s a plan to handle the technical challenges in studying the huge volume of requests. “Will MISO be able to solve the models with the magnitude of generation in the queue?” he asked.

WEC Energy Group’s Chris Plante suggested the RTO might need to change its study strategies, given the generation additions.

Van Shaack said staff is prepared to solve models with the best available information and bring on additional people to help, if necessary.

“We’re going to do our best to meet the timeline,” he said. “The need to scale and augment the internal process is ongoing … We do anticipate being able to handle this.”

NextEra Energy’s Aaron Bloom asked whether MISO plans to revisit its three 20-year futures used for transmission planning in light of the generation plans. Staff responded they will internally discuss refreshing the futures’ assumptions.

Stakeholders also requested MISO lead workshops for updates on the queue.

Stakeholders Ask About Odds of IC Agreements

As MISO normally sees about 80% of interconnection requests withdrawn from the queue, stakeholders asked whether staff expects a similar result with the 2022 round.

“We don’t know what the dropout rate is going to be. Historically, the number has been a 20% success rate. But two big things happened that drove the numbers we saw,” Andy Witmeier, director of resource utilization said, pointing to the Inflation Reduction Act’s renewable energy tax credits and the 18 new 345-kV lines from MISO’s long-range transmission plan (LRTP).

The grid operator’s board of directors approved a $10 billion LRTP portfolio of projects in MISO Midwest this summer, partly to integrate more renewable energy. It also intends to stand up $1 billion in projects on its western seam through its Joint Targeted Interconnection Queue study with SPP.

“Those could affect the dropout … But this is still a historic amount of generation,” Witmeier said. “You could see a lot of upgrades coming out of these. First off, there’s just not enough people to buy this capacity.”

Van Schaack said staff could still find prohibitively expensive network upgrade assignments among the latest generation hopefuls.

“That economic trend has definitely continued into 2022,” he said, referencing projects from earlier queue cycles that were unviable because they were paired with pricey upgrades.

Berkeley Lab Focuses on Snowballing Upgrade Costs

Lawrence Berkeley National Laboratory observed last week that MISO’s interconnection environment has led to “rapidly growing” interconnection costs over the past four years.

The national laboratory said in an Oct. 7 study that RTO’s average network upgrade cost of $102/kW for recently completed projects is nearly double that of historical costs from 2000 through 2018. The lab also said that projects still actively moving through the queue faced estimated interconnection costs that have tripled in just four years to about $156/kW.

The cost analysis was funded in part through the U.S. Department of Energy’s Interconnection Innovation e-Xchange.

“The capacity associated with [new] requests is more than twice as large as MISO’s peak load in recent years — about 120 GW — and, if substantial amounts are built, will likely exert competitive pressure on existing generation,” Berkeley said. “However, most projects have historically withdrawn their applications, often in response to high interconnection costs: only 24% of all projects requesting interconnection between 2000 and 2016 have ultimately achieved commercial operation at the end of 2021.”

The lab said 366 GW of projects have left the queue, while just 62 GW have been interconnected. It said the most recently withdrawn interconnection requests confronted the highest average upgrade costs of about $452/kW.

Berkeley also said that the potential interconnection costs on recent submittals for storage, wind and solar generation are more expensive than for natural gas-fired generation. It found that wind generation has $399/kW in network upgrade costs, storage $248/kW and solar $209/kW; natural gas is expected to pay a more modest $108/kW.

MISO Adamant on Narrower DFAX Cutoff 

MISO still plans to reduce congestion by instituting a lower system-impact threshold on interconnecting generation that will likely prompt more network upgrades.

The RTO’s proposal might dim the prospects for some of the new interconnection requests.

The RTO suggested this summer to halve new generation’s allotted distribution factor (DFAX) impact on transmission from 20% to 10% for its basic and unguaranteed level of interconnection service, called energy resource interconnection service (ERIS). (See MISO Recommends Lower Distribution Factor to Address Congestion.)

At the behest of some MISO South members, the grid operator studied a DFAX limit down to 5% but decided that the threshold would be too drastic. Staff said 10% provides a good balance without being too aggressive.

Generation developers maintain that a tighter DFAX threshold would be punitive and place even more responsibility for system planning on interconnection customers, who are trying to get sorely needed generation on the system.

Sustainable FERC Project’s Lauren Azar said during the IPWG’s Monday meeting that lowering the threshold will “exacerbate and result in more transfer of costs to generators.”

Some stakeholders argued that MISO was conflating transmission reliability with real-time congestion costs.

“Interconnection is about reliability and not addressing congestion. What’s resulting is congestion in real-time, which is an economic issue. ERIS generators are energy-only and should expect to be curtailed,” Clean Grid Alliance’s Natalie McIntire argued.

Staff contended that the binding constraints interconnections cause are a reliability issue. They said potential constraints are currently being ignored in the interconnection process, only to crop up later on the system.

Stakeholders said that it’s premature to lower the DFAX threshold across the board when MISO hasn’t yet put together an LRTP portfolio for its southern region. The current and upcoming LRTP portfolios are marketed as being able to support more generation interconnections on the grid.

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Texas PUC Lauds Jones for Stepping in at ERCOT

The Texas Public Commission honored interim ERCOT CEO Brad Jones’ tenure last week, showering him with praise, political recognition, the Lone Star Flag that flew over the State Capitol in his honor and his second standing ovation of the week.

“I cannot, on behalf of all the people of this agency, ERCOT and the state of Texas, thank you enough for being willing to step up and take what has to be one of the toughest jobs in the state in a time of true crisis,” PUC Chair Peter Lake said during the commission’s Oct. 6 open meeting.

Jones was pulled out of retirement to lead ERCOT on an interim basis two months after the February 2021 winter storm that brought the Texas grid within minutes of a total collapse. The PUC first asked him to serve in a consulting role before he was asked to replace Bill Magness, who was fired in the storm’s wake. (See ERCOT Board Chooses Jones as Interim CEO.)

What Jones hoped would only take a few months lasted more than a year before ERCOT’s Board of Directors found a permanent CEO in Pablo Vegas. In the meantime, Jones focused on improving the grid operator’s credibility. He guided ERCOT through two summers dotted with conservation measures — setting a new record demand peak of 79.8 GW last July — and ensured staff implemented winterization measures to reduce the chances of another disaster.

“It was a very tough, tough spot to be in. You handled it confidently with poise and composure,” Lake said. “A lot of tough decisions, a lot of first-time moves, unprecedented actions and then getting through this record-breaking summer. So, thank you again for not only being willing to do the job, but doing it so well under such extraordinarily tough circumstances. You got a big retirement smile on your face, and you’ve earned it”

Commissioner Will McAdams recalled that Jones only requested $1 for his salary when he was asked to take over at ERCOT.

“I think you were willing to do it for free, but we wouldn’t let you, and there was nobody else around that would step up to take such a very extraordinary difficult position,” said Commissioner Lori Cobos, who sat on the board at the time.

“In my mind, there was only one person that was capable of coming in and helping,” Commissioner Jimmy Glotfelty told Jones, who spent more than 30 years in the sector, including a stint as ERCOT’s COO. “I’m sure everybody who’s been around this town for a long time, who’s been in the power sector and coming to the PUC, said, ‘Brad Jones has to step up and do this.’ It was a daunting task, but it comes pretty naturally to you. You know this system frontwards and backwards, and I think all Texans have benefited from your knowledge.”

Brad Jones 2022-10-06 (Admin Monitor) FI.jpgBrad Jones recognizes ERCOT, PUC staffs before the commission. | Admin Monitor

Jones thanked the commissioners for their comments, saying the PUC was “extraordinary” during the last year and a half, providing leadership and support to he and ERCOT.

“I wanted to make sure that you all knew what each of you meant to us, the collaborative nature, the conversations that we’ve had about numerous topics. It’s been helpful to us in setting our targets, but it’s also been helpful in having your support and driving some of this change in the last year and a half,” Jones said.

“And when I say the commission, I don’t want to leave out the staff,” he said. “I’ve watched the staff work extraordinarily hard over the last year and a half to make very quick changes on pathways that we’d never used before to get reliability in place quickly and to do that in a way that had not been done ever before. The staff has been fantastic with us and working closely with us.”

Jones also thanked the State Legislature for the laws passed after the winter storm and Gov. Greg Abbott for his support. In turn, Jones was presented with resolutions from both houses of the legislature and a statement of recognition from Abbott.

Finally, McAdams pushed Jones on his immediate plans after he winds up a transition period with Vegas on Oct. 31.

“He is going on a vacation, and he needs to say that publicly,” McAdams said.

“Yeah, now that I’m finished at ERCOT, I’m going to Disney World. …

“All I can say is, ‘Wow, what a time to be coming back into Texas,’ with what’s going on in the market and what’s going on in the economy. I can’t remember a more exciting time to be in this industry,” he said.

Sierra Club Efficiency Petition Rejected

In business matters, the PUC rejected the Sierra Club’s petition for a rulemaking related to energy efficiency (53971).

The commission said Sierra’s proposal would significantly change peak demand reduction and energy efficiency goals, increase cost caps for consumers and utility investment in low-income programs, adjust performance bonuses, and remove barriers to program disclosure.

However, it also said there is no room on its current rulemaking calendar to accommodate the environmental organization’s proposal.

Lake has tasked Commissioner Kathleen Jackson with directing the PUC’s energy-efficiency efforts. A workshop has been scheduled for Oct. 18 to discuss an implementation plan.

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NYISO 10-kW Min for DER Aggregation Participation Riles Stakeholders

NYISO stakeholders on Friday responded negatively to the ISO’s proposal for a 10-kW minimum capability requirement for individual distributed energy resources to qualify for participation in an aggregation.

Although most proposals discussed at the Installed Capacity Working Group (ICAPWG) meeting did not elicit reactions from stakeholders, NYISO’s 10-kW DER minimum requirement proposal generated significant pushback.

The ISO argued that the proposal would help DER market implementation, save staff time reviewing aggregations for interconnection and enable it to fully integrate new software and internal procedures to comply with FERC Order 2222. (See NYISO Proposes 10-kW Min. Capability Req for DERs in Aggregations)

Stakeholders, however, took exception to the ISO’s language that they would “explore” lowering the minimum capability requirements later after getting experience and a better understanding of DER penetration versus directly promising to lower the minimum capability later.

Chris Hall, of the New York State Energy Research and Development. Authority, summarized the main concern, arguing that, with average size of residential storage resources at 7 kW, the “provision essentially eliminates all of these residential assets from participating.” Though NYSERDA is “sympathetic to the ISO’s limitations,” it is “deeply troubled by this proposal,” he said.

Adam Evans of the New York Department of State agreed with Hall’s assessment, stating that “folks at the DPS who are close to these types of resources have been hearing that this proposal would pretty much eliminate residential participation.” NYISO’s intention should be to “get more resources to participate” and that putting “a barrier right from the get-go” was inadvisable, he said.

David Skillman of Sunnova Energy echoed these complaints, saying how his company’s fleet consists of resources between 6 and 8 kW, meaning they would not be able to participate in aggregation. That, he said, “flies in the face of FERC 2222,” which was established to “give the small guys a chance to play on the same field as the big guys.”

Aaron Breidenbaugh of CPower shared how recent conversations he had at the Advanced Energy Management Alliance indicated that there was “pretty significant concern about the potential disenfranchisement of an entire customer class” and suggested that NYISO change the language of “explore.”

Other tariff revisions or modifications were collectively proposed to clarify existing rules and processes.

These included making no aggregation types eligible for the NYISO Station Power program, accommodating retail charging rates for aggregations and clarifying several rules in the ISO’s Market Administration and Control Area Services tariff.

The ISO intends to return to an upcoming ICAPWG meeting to further review the draft language and then expects to seek approval from Business Issues Committee and Management Committee later this year. It would then file the proposals with FERC for an anticipated implementation in 2023.

Comments or questions should be sent to DER_Feedback@nyiso.com.

Study Results on Ramp Rates

Also during Friday’s ICAPWG meeting, NYISO Principal Economist Nicole Bouchez presented the results of a study examining the differences in expected ramp-up and ramp-down rates as the grid undergoes rapid transition, the impact of seasonality impacts and the rate of growth as more intermittent resources are added.

The study is part of Phase 2 of the ISO’s larger Grid in Transition Study, which is based solely on the 20-year forecasting System & Resource Outlook. (See NYISO 20-Year Forecast Highlights Generation, Tx Hurdles to Climate Goals.)

The ISO examined two policy cases listed in the outlook for the years 2030 and 2040, calculating their ramp rates, average number of ramp hours per event and hourly percentiles to better show distribution of the rates.

Bouchez pointed out that initial findings “qualified as having no real observable trend” in the number of hours ramped over time, and that if anything, one could “posit that ramp-down events are a little bit longer, but even that is difficult to say.”

However, when NYISO examined how many megawatts there are in those ramp periods, it found that the ramp rates were “amplified” in magnitude over time as “more and more installed capacity of renewable resources” were added.

More important, Bouchez said, the ISO found that although ramp events are normally distributed over time, the average ramp megawatt is impacted across the seasons.

For Case 1 there were less ramp up and down needs in the shoulder seasons. Case 2 had more ramp needs in the winter, while both the summer and shoulders were similar.

Bouchez stated that the findings will be included in a white paper that the ISO expects to present in draft form either in late October or early November, after which there will be a stakeholder comment period of three to four weeks. She also said that any related market changes or additions will be studied in next year’s Balancing Intermittency Project, which will use the data presented at Friday’s meeting for structure.

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Transmission Owners, RTOs Defend Planning, Cost Control Practices

Transmission owners found themselves on the defensive throughout Thursday’s FERC technical conference on transmission planning and cost management, as panelists decried the rising spending on end-of-life and other local projects that do not face any prudency reviews.  

Kamran Ali, vice president of transmission planning and analysis at American Electric Power (NYSE:AEP), pushed back against the criticism, saying PJM’s Attachment M-3 process, which governs planning of supplemental projects —  those not needed for system reliability or public policy compliance — is “the gold standard” for transparency.

Lisa McAlister (FERC) Content.jpgLisa McAlister, American Municipal Power | FERC

“I can say that because I manage the transmission planning for AEP in four different RTOs,” Ali said. “I think it would be beneficial if people were to bring actual factual examples to the table: ‘In the M-3 process, here are the regional projects that would have displaced local projects, or here are the local investments that were not prudent, that were not rationalized that somehow made it through.’ If we have some of those real examples, I think we can enhance the M-3 process. Without examples I think it’s very difficult to make any improvements.”

PJM evaluates supplemental projects only to make sure they do not harm reliability. Municipal stakeholders have long complained about the lack of transparency surrounding their costs. (See PJM TOs Sign off on Supplemental Project Deal.)

Lisa McAlister, general counsel for regulatory affairs for American Municipal Power, responded that the reason that there are no examples is “because we simply don’t have enough information to identify” any. She said AEP does “a better job” than other PJM TOs in providing information, but “what we don’t have is how those replacements are prioritized; we don’t know [how] replacement versus maintenance decisions [are made]; how assets rank compared to other assets on the system.”

‘Appearance of Transparency’

“AEP has done a very good job in the M-3 process of responding to a limited number of suggestions,” agreed Kentucky Public Service Commission Chair Kent Chandler. “I have a certain number of questions, and [there] are now stock answers that they’re ready to provide people. … The reality is that although I understand what their criteria is … I have no idea what weight they’re giving” to them.

Kent Chandler (FERC) Content.jpgKentucky Public Service Commission Chair Kent Chandler | FERC

“The M-3 process gives us far more insight into local planning than the non-RTO utilities that we have, and even the MISO utility that we have,” Chandler added. “We understand through the M-3 process what their assumptions are and the criteria maybe, but there’s no way that we’re provided enough information to be able to replicate the decisions that are made by the utilities. So we understand that they may be looking at asset conditions, [but] we have no idea what kind of weight they’re giving them; whether they’re prioritizing certain conditions over others. It’s the appearance of transparency, and it’s enough to maybe placate some folks … but it is not enough to have an appreciation for how they’re actually doing local planning.”

But that’s still far more than what the PSC gets from its non-RTO utilities, he said. “We don’t find out what their planning outputs are until they show up to the commission for a certificate of public convenience and necessity, or it’s a fairly small transmission project and we don’t see until they file a rate case and it shows up in their forecasted test period. … We have no insight into their local planning.”

McAlister said RTOs should do more rigorous analyses of local planning criteria and proposed projects. But “to really have a meaningful opportunity to have a back-and-forth, you need more than the ability to submit comments,” she said. “There has to be some kind of actual requirement that the transmission owners respond.”

Greg Poulos (FERC) Content.jpgGreg Poulos, Consumer Advocates of PJM States (CAPS) | FERC

She said PJM created a website for members to submit questions, but the RTO usually just says, “we’re working with the transmission owners; we’ll get back to you.” She said mirroring the M-3 process in other regions, “just having an arbitrary set of meetings and days to comment, we don’t think is something that gets us there.”

Greg Poulos, executive director of the Consumer Advocates of PJM States (CAPS), said in-house experts can only do so much.

“We have the money to hire an expert. I just don’t know what our expert would do with only 10 days to review projects, no ability to ask the questions and no expectation that they’re going to respond to us,” he said.

“Those are things you would hear from … an independent transmission monitor: ‘Those are flaws in this process. There’s a significant gap here [and] PJM, you need to do something about that.’ It’s different from me saying that, because I’m not getting response to that.”

PJM Cites Difficulty Identifying Regional Projects

Kenneth Seiler, PJM’s vice president of planning, said the RTO has not pursued more regional projects because the RTO is not seeing high load growth except in some areas such as Northern Virginia, which has experienced an explosion of data center load.  (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)

Kenneth Seiler (FERC) Content.jpgKenneth Seiler, PJM | FERC

“We look for opportunities for regional transmission, but in many cases, it’s not the most cost-effective solution,” Seiler said. “We have had occasions in the past, though, where we had identified regional solutions [and] we could not get the line sited. The one example I can think of off the top of my head was about a $100 million regional transmission facility … The [state] commission wouldn’t site it within that particular state. And we ended up spending over double — over $200 million for sub-transmission upgrades.”

Erik Heinle, of the D.C. Office of the People’s Counsel, said PJM’s expertise in engineering and power flow analysis is “world class.”

“But we see far too many instances where PJM is not acting as the regional planner and bringing regional projects to the region,” he said.

Existing Cost Containment Practices

FERC Commissioner Willie Phillips expressed interest in MISO’s variance analysis, in which the RTO reevaluates projects facing lengthy schedule overruns or a 25% cost increase. MISO can either let projects continue, cancel them or assign them to different developers. Jeanna Furnish, MISO’s director of expansion planning, said the variance analysis could be applied in other regions to scrutinize projects.

Willie Phillips (FERC) Content.jpgFERC Commissioner Willie Phillips | FERC

SPP Executive Vice President of Regulatory Policy Paul Suskie said that, more than a decade ago, SPP’s first regionally funded 345-kV line turned out to be significantly more expensive than its original estimate, causing the RTO’s Regional State Committee to call for a review and develop methods to contain costs. Since then, Suskie said, SPP has been tracking project costs in an evolving process. He said projects that exceed 20% of their original costs are subject to restudy, suspension and even cancellation.

FERC Chair Richard Glick asked transmission owners how they currently reduce cost exposure for customers on large, regional transmission projects.

Carolyn Cowan Barbash, vice president of transmission development and policy for NV Energy, said her company tries to write projects’ technical specifications as clearly as possible and makes sure it attracts multiple bidders on solicitations.

Ameren Transmission Company (NYSE:AEE) President Shawn Schukar said his utility considers how large projects will impact future projects and vets contractors for past performance in addition to their cost estimates. He also said Ameren considers the quality of transmission components and how often they might need maintenance and replacement. He said he “took exception” to the perception that transmission owners aren’t currently motivated to keep costs in check.

‘Cooking the Books’

Attorney Lauren Azar, a former Wisconsin regulator, said FERC should create a process for challenging local planning criteria (LPC), saying “a few bad apples” in MISO have overly restrictive criteria for the generation interconnection process.

“Even before any new generation is added into the models, upgrades are already required, because of the LPCs. So in other words, the TOs are cooking the books so that those generators are required to pay for those upgrades, even before their proposed generation is added,” she said. “That’s not OK.”

Grid-enhancing Technologies

Panelists also weighed in on the role of grid-enhancing technologies as a way to cut costs.

PJM’s Seiler said the industry could benefit from a guide identifying where grid-enhancing technologies “would have the biggest bang for the buck.”

Erik Heinle (FERC) Content.jpgErik Heinle, D.C. Office of the People’s Counsel | FERC

“There’s a lot of reluctance on behalf of our asset-owning utilities to apply grid-enhancing technologies, frankly, because of things like the reliability of the internet, security of [the technologies and creating an] additional avenue by which we could be attacked from a cybersecurity view.

“And these things have to be reliable. From a pure planning viewpoint, in my mind, there’s very few grid-enhancing technologies that can be relied upon on a day-in, day-out basis where I know I can count on having that extra transmission capability.

“Things like dynamic line ratings can be applied on the physical transmission line to squeeze out a few more megawatts from a pure system operations view. From a planning view, I can’t count on” them, he said.

Heinle disagreed, saying GETs should be part of regional planning. Distributed energy resources “served as a valuable planning tool in California a few weeks ago. And when you hear comments like, ‘Well, we can’t always count on this or that’ — those were similar comments that we heard about solar [and] wind, not too long ago. We found ways to incorporate them into the grid, and to use them in our planning for resource adequacy.”

Glick asked consumer advocates if grid planners give sufficient consideration to alternatives when local transmission projects are proposed.

CAPS’ Poulos said there is not: “The transmission owners in the [PJM] region say, ‘We have control of whether we’re going to do grid-enhancing technology. You have no input on this.’”

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PJM Market Implementation Committee Briefs: Oct. 6

Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR

VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a PJM effort to prohibit critical gas infrastructure from participating in demand response programs that could jeopardize the reliability of gas-fired generators. The endorsed language revises sections of manuals 11 and 18 to add language excluding “critical gas infrastructure” from being eligible as price responsive demand programs.

The changes are being considered as NERC and FERC work on their own efforts to address concerns raised by the impact of February 2021’s winter storm — that a spike in load could lead to gas infrastructure being curtailed and causing a cascading failure as downstream gas generators have their fuel interrupted. The PJM language would stand until the federal regulatory bodies finalize their own standards. (See “Critical Gas Infrastructure Approved,” PJM MIC Briefs: March 9, 2022.)

Much of the lengthy discussion on the topic focused on how PJM is considering defining critical gas infrastructure in its tariff: “as electric loads, which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation.” The tariff language is not part of the package endorsed Thursday and is still being fine-tuned by PJM staff with input from Thursday’s meeting.

At issue was the definition of “significant impact.” Calpine’s David “Scarp” Scarpignato questioned how PJM would classify a curtailment causing a drop in pipeline pressure causing a downstream gas plant to run at less than full capacity, or a curtailment that doesn’t cause a direct drop in a plant’s ability to generate but has that effect when combined with other contingencies.

“A significant impact is a difficult measure. That’s going to be difficult to implement those rules. … I wonder if we can substitute ‘direct’ for ‘significant,’” he said.

Joe Bowring, PJM’s independent market monitor, said he believes the language is “fuzzy” and therefore not enforceable. He also questioned whether there’s a risk of gas infrastructure being enrolled in DR programs this winter (2022/23) as PJM considers the revisions, which will not be applied until the winter of 2023/24. Bowring also questioned why PJM has not done its own assessment of the facilities rather than relying on the sellers of demand response for the information. 

PJM’s Peter Langbein said curtailment service providers have told staff that there are not currently any gas infrastructure facilities enrolled in their programs that would meet the general definition under consideration.

Paul Sotkiewicz, of E-Cubed Policy Associates representing J Power USA, said he’d prefer to see an explicit prohibition against electric-driven gas compression stations participating in DR in any form. 

“We’re setting ourselves up for a cascading failure without addressing compression,” he said.

Elimination of ‘CT Rule’ Receives Endorsement

Stakeholders also endorsed manual revisions being sought by PJM to eliminate the “CT Rule,” which grants combustion turbines an exception from rules requiring that generators follow dispatch signals. Currently CTs can recover the costs of their full generation regardless of their load signal, while other generators receive the lesser of their actual generator or their dispatch.

PJM’s Lisa Morelli, director of market settlements initiatives, said the rule is a holdover from when CTs put out a fairly constant rate of power. Now that they have a wider dispatchable range, it makes sense to require them to conform to dispatch, she said. The elimination of the exception can be made by removing a single line in Manual 28.

“CTs will now be treated as all other resources in balancing of operating reserve credits,” she said.

During the Sept. 21 Markets and Reliability Committee meeting, Morelli said simulations show that uplift payments to CTs were about $1.3 million lower when recalculated without the exception over the eight highest CT uplift days in summer 2021, a 10% drop. (See: “PJM Staff Seek Removal of CT Exception on Load Signaling,” PJM MRC/MC Briefs: Sept. 21, 2022.)

Impact of State and Local Regulations on Net CONE Discussed

PJM staff provided a first read on an issue charge and problem statement exploring how local considerations, such as state and local regulations, might affect the development of the net cost of new entry (CONE). The topic will return to the MIC for possible endorsement at its next meeting.

James Wilson, a consultant to state consumer advocates, recommended broadening the issue charge and potential solutions to include other possible changes beyond net CONE, such as to the shape of the variable resource requirement curve.

Gary Helm of PJM said the RTO’s intent was to stick with addressing CONE and net CONE, as opposed to weighing the outcomes.

Four-year Review of Default CONE and ACR Underway

PJM’s Skyler Marzewski and consultants from The Brattle Group presented an overview of the first four-year review of the default CONE and avoidable cost rates and the timeline for drafting the new values.

PJM’s tariff requires the RTO to update default gross CONE and default gross ACR values for minimum offer price rule purposes every four delivery years beginning with 2022/23.

The methodology would use public national sources for the installed capital costs and fixed operating and maintenance costs, as well as using the same financial assumptions as in the quadrennial review.

“It will be a very similar process to what we did last time,” Marzewski said.

Stakeholders questioned if there’s sufficient geographic variability to justify using data specific to the PJM region, instead of national data. Marzewski said this was explored; however, it was found that there’s limited local data available. The largest variations in the cost of development tend to be the size and configuration of generators, according to Brattle’s presentation.

Default values for offshore wind were not explored in the analysis thus far as the focus was on existing generation. Instead, unit-specific analysis would be undertaken for OSW, as well as other generators with highly variable costs.

PJM Reviews Proposed VOM Language

PJM staff reviewed a set of proposed manual revisions that would codify a PJM package creating standardized variable operating and maintenance costs. The RTO’s package was the preferred solution coming out of the MIC’s Sept. 7 meeting, receiving more than 70% support over a competing package from Constellation Energy, which received 54%. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)

Constellation’s Jason Barker questioned PJM’s classification of nuclear major maintenance costs as variable costs that are directly related to electric production based on starts and run hours and thus must be reflected in a unit cost-based offer, rather than in a capacity market offer. Barker said there is an apparent contradiction in PJM’s proposed Operating Agreement and manual provisions that define nuclear refueling and other major maintenance projects as “variable” while also excluding time-based or preventative maintenance from classification as a variable cost. Barker said that Constellation and other nuclear operators consider costs incurred during planned nuclear outages as “fixed” costs. He also highlighted that all nuclear planned outages are scheduled years in advances, suggesting that projects undertaken during those outages are time-based. The company’s package would exclude nuclear planned outage costs from PJM’s definition of major maintenance.

The manual changes will go to the MRC on Oct. 24 for a first read with a vote anticipated on Nov. 16.

Other MIC Topics

  • A first read was presented on a proposal to merge the DER & Inverter-Based Resources Subcommittee and Demand Response Subcommittee into a new subcommittee, given the similarity of the subjects they cover and the composition of their stakeholder participation. PJM staff said doing so would simplify scheduling internally and for stakeholders, although there were some concerns that doing so could conflate their charges and the issues they aim to address.
  • PJM’s Andrew Levitt gave a first read of a proposal to expand the RTO’s current hybrid resource provisions to include installations with multiple types of generation paired with storage. The current hybrid definition allows for only one type of generation, for example solar paired with storage, while the Hybrid Resources Phase II solution would allow for “any number of different types of [generation].” The proposal would also create a detailed energy market model for inverter-based resources paired with storage, such as wind and solar combinations. 
  • PJM provided an explanation on the impact of negative day-ahead and real-time LMPs in the calculation of the balancing operating reserve credits. Negative DA or RT LMPs can result in unnecessary BOR credits caused by the treatment of day-ahead or balancing revenues, the RTO says. PJM plans to present potential solutions during future special sessions.
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FERC Tech Conference Highlights Regulatory Gaps on Transmission Oversight

FERC Commissioner Mark Christie said Thursday that the commission should consider limiting formula rate authority to transmission owners whose projects are subject to “robust” state regulatory reviews to help close the “regulatory gaps” between state, federal and RTO oversight.

Meanwhile, state officials and consumer advocates told FERC’s technical conference on transmission planning and cost controls (AD22-8) that the commission should also provide more scrutiny of formula rates, under which expenses are presumed to be just and reasonable.

Christie was incredulous when Indiana regulator Sarah Freeman, president of the Organization of MISO States, said that her state has no process for reviewing transmission projects.

“There is a gap in what scrutiny is taking place at the state level, and yet that is where all these projects should be scrutinized,” Christie, a former Virginia regulator, said at the close of the hearing. He said the testimony showed state oversight on the cost and prudence of projects “varies greatly.”

FERC has “authority over [just and reasonable] rates at the wholesale level and transmission. We don’t have authority to tell a state how to structure your CPCN [certificate of public convenience and necessity] process, but we do have authority to say who gets formula rate treatment when you come here,” Christie said. He invited stakeholders to submit comments on whether FERC should limit such rate treatment to TOs from states with a “robust state permitting process.”

“At a minimum, a robust state permitting process would be looking at, not just [the] prudence of cost, but also looking at need,” Christie said. “If you look at the three sections we’ve talked about today — the RTO planning part; the state CPCN part; and then the formula rate part [at FERC] when it comes to how to pay the bill — each one of those really connect.”

FERC Chair Richard Glick said he was taken aback by Iowa Consumer Advocate Jennifer Easler’s written testimony, which described the state’s lack of authority over the cost of local transmission projects.

“When they come in for the franchise application, we do conduct discovery on it, and we ask, ‘What alternatives did you consider?’” Easler said. “And we will get responses along the lines of, ‘We object. The costs of these projects are not regulated by the Iowa Utilities Board.’”

Glick said the conference exposed both a regulatory gap and “an informational gap,” as evidenced by regulators and consumer advocates who said they lack the access to information on local transmission plans or the expertise to evaluate them. “Those are two items I think we need to address going forward,” he said in his remarks concluding the conference. “We have, in my opinion, more work to do on transmission and hopefully more [Notices of Proposed Rulemakings] to come at some point.”

States Seek Help

FERC heard from officials of eight states and D.C. during the daylong conference.

Cameron Dyer, senior assistant general counsel for the Public Utilities Commission of Nevada, said there is only one vertically integrated investor-owned utility in his state — NV Energy — that “handles just about all the transmission in the state, which means that any time new transmission is being proposed — in the intrastate context, at least — there is a lot of robust interview, review and analysis of that new transmission.”

Most state officials were less sanguine.

The topic of the first of the five panels at the conference was the development and use of criteria for local transmission planning, where state regulators and municipal utilities told the commissioners they often don’t have any idea what those criteria are.

Under FERC Order 890, “we get the baseline reliability criteria from the transmission providers and [their] specific engineering criteria for their projects, and that’s all,” said Dan O’Hagan, manager of regulatory compliance for Florida Municipal Power Agency. “We don’t get other criteria that go into that decision-making process, like end-of-life for facilities, or cost considerations, or public policy considerations … that might come into play behind the scenes where they select one project over another.”

Simon Hurd, program and project supervisor with the California Public Utilities Commission, said the PUC appreciates its working relationship with Southern California Edison and Pacific Gas and Electric, but the discussions are mostly past-tense because 63% of utility projects are self-approved. These projects are not put into the transmission planning process and they do not get CAISO review, he said.

“We need to be more upstream. … We want review; we want input in the process at the assumptions, the needs, the solution stage. We’re doing our best to be having that conversation with the utilities, but it’s after the solutions have already been identified,” Hurd said.

Too Late

James McLawhorn, director of the North Carolina Utilities Commission’s Energy Division, said the NCUC enters the process too late.

“We have attempted to question some of the projects that have been proposed as to whether there are other options. … By the time it comes to us, we’re being told, ‘Well, no, this is the only solution that was available and now we’re out of time and we need to move forward with it,’” he said. “Maybe it was the only solution that was available, but we simply don’t have the information to evaluate that.”

McLawhorn, who advocates for consumers as part of his job, was among speakers who favored an independent transmission monitor to increase oversight of the transmission planning process.

“The commission looks for us to do the evaluation, to come to them and make recommendations, but we do not have particular transmission expertise on staff, and we desperately need something like an independent transmission monitor to assist us,” McLawhorn said. (See related story, States Urge More Transparency on Tx Planning, Independent Monitors.)

The North Carolina commission recently engaged a transmission consultant to provide that help, McLawhorn said, but the process was a struggle. There was one response to the request for proposals, he said, and it came in on the last day of the submission period.

Phil Bartlett, chair of the Maine Public Service Commission, said that by the time his agency gets to review a transmission project, it “is pretty far along.”

“So even a very robust process, in my view, is not a substitute for really engaging early on the planning process. It’s also not a substitute for following through afterwards.”

In contrast with FERC’s lack of scrutiny for prudency, Bartlett said, “we are always looking at the prudency of investments that have been made. And that includes the management of those projects in development. We routinely disallow costs if we think there are unreasonable overruns or other issues. So, both in terms of not being present at the planning stage, and not being present after the CPCN process on the cost-management side, I think it’s a real shortcoming of even the most robust CPCN process.”

Formula Rates

Bartlett and others said the use of formula rates has shifted the burden of proof. In state rate cases, TOs must demonstrate just and reasonable rates; under formula rates, states and consumer advocates must rebut the proposed rate.

Ron Gerwatowski, chair of the Rhode Island Public Utilities Commission, said his commission recently discovered that Narragansett Electric (now Rhode Island Energy) was collecting $10 million a year in excess profits on its transmission line connecting the Block Island offshore wind farm to the mainland.

“It is telling to consider that the windfall profit being generated from the formulaic cost-recovery mechanism used in this case was only discovered because someone in the accounting department of the utility misallocated revenue and expenses to the wrong business unit in a report on distribution earnings,” he said in his written testimony. “But for that human error, neither the Rhode Island PUC nor FERC’s processes would have picked up the continuing windfall profits flowing from ratepayers to shareholders.”

Gerwatowski said that more than $2.5 billion in “asset condition” projects have been placed in service in New England and $3.1 billion more are listed in ISO-NE’s Regional System Plan (RSP) as proposed, planned or under construction. By comparison, as of the June 2022 RSP update, reliability projects in the pipeline resulting from the ISO-NE planning process total less than $1.3 billion.

Attorney Robert Weishaar, who represents industrial consumers, said FERC’s Office of Administrative Litigation (OAL) could play a larger role in the transmission formula rate review process.

He said OAL staff are “extremely helpful” in the initial establishment of formula rates but become uninvolved when it comes time for annual updates. Weishaar suggested that FERC expand OAL’s authority and resources so staff can engage in the annual update process and “review the actual flow-through of the costs.”

Larry Gasteiger, executive director of WIRES, saw it differently. He said formula rate protocols involve “extensive” stakeholder sessions with utilities and opportunities to challenge the rate inputs.

In addition, he said, FERC has “a fairly robust” program for auditing utilities with formula rates. “The audits, I know from personal experience, are extensive,” said Gasteiger, who served at FERC for almost two decades, including almost six years as a top official in the Office of Enforcement. “And they are effective, because they do a very thorough examination of how adherence to the rate protocols and the formulas is all working.

“If you believe the rhetoric around it, FERC has all but abandoned any regulation of transmission rates in this context,” he continued. “I think it’s important to debunk that notion. Maybe it plays well in the Twitter-space, but it doesn’t reflect the reality of what is going on here.”

But FERC Commissioner Allison Clements noted that the commission only conducts about a dozen audits a year. Although the Office of Energy Market Regulation has “improved stakeholders’ ability to engage on formula rates,” the “structural problem” with formula rates may require appointing independent transmission monitors, she said.

“The cost is peanuts on the dollar of deferring just one transmission investment,” she said. “But if that’s not the way you think we get at these problems, we certainly are open to other ideas. … I think I hear a real need to take action.”

In addition to increasing its scrutiny of formula rates, Bartlett said FERC should revisit the return on equity allowed for formula rate investments. “Given the lack of oversight and difficulty in challenging prudence, there is little risk in undertaking these investments and the ROE should reflect that,” he said.

Iowa Consumer Advocate Easler was also critical.

“Transmission providers that use forward-looking formula rates with incentive ROE adders and obtain automatic cost recovery of transmission costs from retail customers via state-authorized transmission cost trackers simply do not have a strong incentive to engage in least-cost transmission planning for lower-voltage local transmission facilities,” she said in her written testimony. “The absence of customer-initiated challenges to local transmission upgrades in formula rate reviews is not an indication that all is well. Rather, in the face of relentless transmission rate increase, it is an indication that this regulatory process is inadequate to protect customers from unjust and unreasonable charges resulting from inefficient siloed transmission planning processes.”

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PJM Operating Committee Briefs: Oct. 7, 2022

OC Endorses Renewable Dispatch Effort

The Operating Committee endorsed a revised package of changes addressing renewable dispatch after the proposal had been sent back to the subcommittee level for additional fine tuning last month. The joint Independent Market Monitor/PJM proposal would require intermittent resources with capacity commitments to offer economic maximum megawatts equal to or greater than their hourly forecast.

Stakeholders speaking at the Sept. 8 OC meeting worried that the original language could result in renewable output being held back by use of an under-forecasted value and opted to send the proposal back to the DER and Inverter-Based Resources Subcommittee rather than vote on it. (See “Renewable Dispatch Proposal Vote Delayed,” PJM Operating Committee Briefs: Sept. 8, 2022.)

Some stakeholders were concerned about the proposal’s elimination of the curtailment flag, which PJM uses to notify generation operators that their units have been curtailed and that they should adjust their output accordingly. Friday’s presentation said the intent is to have generators following economic base points, rather than curtailments, which can be inadvertently prompted because of bid-in parameters or offers.

“I think we were able to work through those concerns,” PJM’s Michael Zhang said.

Cold Weather Preparations Begin

PJM is beginning to implement annual cold weather preparations, with data reporting for generating unit reactive capability verification underway from Oct. 1-31 and reporting for the seasonal fuel inventory and emissions data request beginning Oct. 17 and remaining open through Nov. 21. The cold weather preparation guideline and checklist will also be open Nov. 1 through Dec. 15.

The RTO is no longer facilitating a formal cold weather exercise and is asking generators to self-schedule their own testing in December on a day when temperatures are forecast to be below 35 degrees F.

Fuel Inventories Remain Low, Expected to Increase Going into Winter

Fuel production rates are up across most resource types, but inventory stocks remain low as volatility and prices remain high, according to the fuel supply overview presented to the OC. (See NERC Warns of Fuel Shortages Going into Winter.)

Oil inventories (PJM) Content.jpgOil inventories remain below their 5-year average as economic concerns continue to outweigh high production. | PJM

 

Distillate and residual fuel inventories remain about 9% below their five-year averages on the East Coast, PJM Principal Fuel Supply Strategist Brian Fitzpatrick said, while recession fears and a strong dollar continue to keep prices high.

Progress on contract negotiations for rail workers has alleviated concerns about a strike; however, not all unions have signed onto the agreement, and it’s believed that the process could continue through the Nov. 20 ratification deadline.

Production of both oil and coal fuels remain above average, and Fitzpatrick said inventories are expected to rise over the coming months as generators stock up for the winter season.

“So far, based on the response we’ve seen, no significant concerns have arisen,” Fitzpatrick said. “There have been signs of improvement recently with inventory build.”

Revisions to Fuel Requirements for Black Start Resources Presented

PJM’s Thomas Hauske went over the clarifications and revisions made to the proposed solution addressing fuel requirements for black start resources, which was endorsed by the Operating and Market Implementation committees last month. The Markets and Reliability Committee is scheduled to vote on the revised proposal during its Oct. 24 meeting. (See PJM, Monitor Debate Black Start Fuel Requirements Proposals.)

A provision allowing intermittent generators to contribute black start capacity as long as they are capable of providing 16 hours of full load operation with 90% confidence was clarified to ensure that it is only applicable for renewables. PJM also clarified that if a unit has its installed capacity increased because of a capital recovery upgrade, its black start revenues will be reduced commensurate with the increased capacity revenues received from the upgrade — preventing the generator from being paid twice for that added capacity.

Generators that store fuel onsite and are connected to two or more interstate pipelines will not be penalized if their fuel inventory falls below the 16-hour supply requirement if they can instead operate on fuel from the pipelines in the event of a black start.

Other OC Discussions

  • The OC reviewed the recommended winter weekly reserve target from the 2022 reserve requirement, with a vote expected at the next meeting. This year’s recommendations are largely lower than last year’s study results, with 21% for December, 27% for January and 23% for February.
  • The implementation of PPL’s dynamic line rating initiative is now live, after being delayed from the anticipated go-live date on Sept. 28. The program is now active following an Oct. 6 launch. PPL had already delayed an expected July launch until September because of additional work needed for changes to its energy management system by its vendor. (See “PPL Delays DLR Implementation to September,” PJM Operating Committee Briefs: July 14, 2022.)
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States Face Challenge Tying Storage Incentives to Emissions Reduction

ATLANTIC CITY, N.J. — Spurred by the rapid rise in renewable energy project planning and declining battery costs, storage development is growing nationwide, but states need to ensure that they fund, shape and incentivize projects that contribute to their emission-reduction goals, a speaker told New Jersey’s Clean Energy Conference on Oct. 4.

States such as New Jersey, which is in the process of planning its first large-scale electricity storage incentive program, need to focus not only on stimulating storage capacity development but on making sure that the resulting projects help cut the use of fossil fuel generating plans, Todd Olinsky-Paul, of the Clean Energy States Alliance, said on a panel at the conference, organized by the New Jersey Board of Public Utilities (BPU).

The goal is “not just to get the storage there; it’s to get it there and link it to whatever policy targets or aspirations the state has,” Olinsky-Paul said. Projects need to charge up their batteries with cheaper, off-peak power and be ready and available to discharge when demand is greatest, to help negate the need for utilities to fire up fossil-fueled peaker plants, he said.

His comments came amid what he said is a dramatic increase in storage development in almost all states. Ten years ago, he said, he could have summed up national storage development activity by citing a handful of programs. “But things have exploded so much in policy in the last few years that I can no longer do that,” he said.

The rapid advance of the sector prompted another panelist, Brian Kauffman of Enel North America, to advise states looking to jumpstart or boost their storage capacity that they no longer need to think of developing a pilot program first.

“There’s a lot of examples of how to structure them and what results in customer uptake. There’s a very mature ecosystem of competitive purchase market participants,” Kauffman said.

“A lot of times, these pilot programs are set up where you don’t really know what the cost of doing the project is going to be [or] who’s going to participate in the project; you just want to learn,” he said. But now, “you have thousands of customers who are participating in programs across a dozen states or so.”

Finding the Right Incentive Level

Storage is widely seen as a paramount element needed to manage electricity supply as intermittent renewables become increasingly dominant.

The conference came just after New Jersey, admitting that it had lagged state ambitions in developing storage capacity, released a straw proposal on Sept. 27 that outlined a plan to stimulate the development of standalone storage capacity by offering incentives for grid-scale and consumer-level projects. (See NJ Offers Plan to Boost Lagging Storage Capacity.)

The BPU’s plan, known as the Storage Incentive Program (SIP), would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.

Jim Ferris, deputy director division of clean energy at the BPU, told the conference that the fixed incentives would be awarded using a “declining block structure” that has worked in other states. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower rate.

“In that way we are providing certainty to the market, but also finding the right incentive level,” Ferris said. “Obviously, if a particular block does not fill at that incentive level, we will have the opportunity to either extend that particular block and incentive or even go back and increase the incentive.”

The agency also has sought to ensure that it does not provide financial support for a project that “just sits unused,” he said. To receive the incentive, “the device will need to be available for 95% of hours,” he said.

The pay-for-performance incentive, which is based on PJM marginal carbon intensity data, is designed to tie the BPU’s incentive to demonstrable emissions reductions, Ferris said.

“So we would be incentivizing when storage is charged when emissions are low, and discharged when emissions are high. And that delta will yield an incentive,” he said. The performance incentive for distributed projects is based when the project injects energy into the system or is used to reduce the use of energy at the request of electric distribution companies, a strategy used in programs in Connecticut and Massachusetts, he said.

Monetizing Storage

States have taken different approaches in seeking to stimulate storage development, CESA’s Olinsky-Paul said. They include mandating a certain amount of storage by a particular date, or just setting a target capacity procurement, he said. Nine states have set a target. Among them are California, shooting for 1,825 MW by 2020; Massachusetts, with 1,000 MWh by 2025; New York, with 3,000 MW by 2030; and Oregon, 5 MWh by 2020.

He displayed a slide that showed more than two dozen states have taken three or more types of action to plan for storage development, including studies and investigations, new policies and regulations, and financial incentives and rates. And all but three states have taken at least one step toward storage development.

One difficulty in stimulating storage development, according to the BPU and panelists at the conference, is that storage devices are difficult to “monetize,” which in turn puts the onus on state support. For that reason, the BPU proposal encourages investors in storage projects to pursue “value stacking,” or looking for several revenue streams to support the project.

While storage projects can provide benefits such as reduced electricity costs and emissions, “the current revenue streams, as in a lot of places in the U.S., including New Jersey, really aren’t sufficient now for storage to scale,” Enel’s Kauffman said.

Olinsky-Paul said one of the “best practices” that states should follow is identifying the attributes of a project that are “priced” or monetizable. He cited the example of a service station owner who installs a storage project on the property.

“So when the grid goes down, I’m able to fuel customers’ cars, first responder vehicles; that’s providing value to the community,” he said. “Did I get paid for it? No. Because there is no market for resilience. I can’t bid that service into a market or sell that service to utility as a backup power service.”

So the state needs to look at the balance of monetizable and non-monetizable benefits and work out “how are we going to provide that gap funding somehow to encourage that market to develop,” he said.

For the operator, the monetary benefits depends on the business model that the storage operators develops, Olinsky-Paul said. For example, the operator may use an arbitrage model of charging up the storage at night when the power price is low and selling the energy at peak hours when the price is higher, he said.

The operator of a solar farm may find storage provides “capacity value,” which in turn provides a financial revenue, he said.

“Solar by itself doesn’t have a lot of capacity value, because it doesn’t have an on-off switch; you can’t rely on it,” he said. “So you’ve now firmed the solar power that was previously variable. Well, there’s a value to that. If you’re bidding that power into a wholesale market, and they want firm power, they’re going to pay more for it if they know that you can turn it on and off than if you are just at the mercy of the clouds.”

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NYISO Transmission Planning Advisory Subcommittee Briefs: Oct. 3, 2022

Interconnection Base Case Rule Changes

Rensselaer, N.Y. — NYISO is proposing to broaden its rules for including projects in the base cases of transmission studies because of an increasing risk that projects studied in one process may affect those studied in others, the ISO’s Thinh Nguyen told the Transmission Planning Advisory Subcommittee Oct. 3.

Because of timing issues, projects being studied in the ISO’s transmission interconnection procedures (TIP) do not always meet the base case inclusion rules of the class year study, or vice versa. As a result, Nguyen said, there may be interactions among these projects that need to be studied.

Nguyen also said the chance of this issue between studies being conducted in parallel has increased with the rise in requests entering the NYISO interconnection queue as well as the increasing number of distribution-level projects.

One proposed enhancement to the ISO’s rules would revise the ISO’s base case inclusion rules to specifically refer to projects being studied outside of the ISO’s procedures that a transmission owner identifies as having advanced sufficiently to be considered “firm” in the TO’s planning its local system.

Another change would add tariff provisions on the use of sensitivities and true-up studies in the TIP facilities studies to account for interactions with class year projects that could require the same or similar upgrade facilities. Following the completion of a class year study, the ISO will conduct a true-up to reflect class year projects accepting or rejecting their cost allocations and posting security to continue development.

Although the current tariff allows the ISO “flexibility” to account for these timing issues, the ISO said explicit tariff provisions detailing the use of sensitivities would improve coordination between the study processes.

The ISO plans to present proposed tariff revisions later this month or early in November.

RNA Draft Report Findings

The ISO presented findings from its fourth draft of the 2022 Reliability Needs Assessment (RNA), which did not identify any reliability needs for the 10-year study period but found that resource adequacy and transmission security margins are tightening over time.

The RNA report identified the risk that extreme weather events, such as heat waves and severe storms, could result in significant reliability deficiencies reducing the ability to serve demand, particularly in New York City.

The RNA also evaluated the impact on the system if 6,300 MW of gas-fueled generation became at risk due to fuel shortages during winter peak conditions. The RNA found that if these generators are unavailable during a peak winter in 2032, reliability would be diminished but still within the loss-of-load-expectation criterion. However, reliability would not meet statewide system margin under expected winter weather conditions by winter 2031-32, presenting a significant future risk.

The ISO told the committee it made small changes in response to stakeholder comments and questions since the second draft of the RNA was presented at the Sept. 1 TPAS meeting. (See “RNA Draft Report Finds No Immediate Needs,” NYISO Proposes Fixes for Interconnection Backlog)

The ISO plans to bring the RNA to votes at the Operating Committee Oct. 13 and the Management Committee Oct. 26 before submitting it to the NYISO Board of Directors for final approval in November.