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November 2, 2024

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Large Consumers Miffed at NYISO Proposal to Shorten SCR Notice Period

NYISO last week proposed shortening the activation notice period for special-case resources from 21 hours to four, which caused consternation among program participants at the Installed Capacity Working Group’s meeting.

SCRs are large consumers that act as demand response resources at the direction of NYISO itself. As part of its Engaging the Demand Side initiative, the ISO has proposed to increase the required duration of SCRs’ load curtailment from four hours to six. That proposal has received broad support from stakeholders, with some caveats. (See NYISO Proposes Changes to Special-case Resource Program.)

Among those discussed at the Aug. 29 meeting was NYISO’s proposal to not give SCRs the option of curtailing load for only four hours. Michael Ferrari, a market design specialist with NYISO, said to have both the four-hour and six-hour options would require an annual elections process in which resources would have to declare ahead of the capability year what class they were in.

Zach Smith, senior project manager for NYISO, said adding the additional options would delay implementation and it did not want to delay a reliability program with broad stakeholder support.

Aaron Breidenbaugh, senior director of regulatory and government affairs for CPower, said this was the first time he heard NYISO say it was not doing something for a reason other than operational difficulty.

“Previously we’ve heard that operations can’t handle multiple durations in real time, and I suspect they’ll have a harder time if they only have four hours,” Breidenbaugh said.

NYISO staff acknowledged this was the primary issue with having multiple durations.

Notice Period

The ISO wants to reduce the current notice period to help maximize the grid operator’s flexibility and reduce the likelihood of false notifications, Ferrari said.

But this proposal left some stakeholders surprised and frustrated.

One stakeholder who represents Multiple Intervenors — a group of large industrial, commercial and institutional consumers — said the proposal was a “dramatic change” to spring on the demand side.

NYISO said in July it was considering shortening the notification period, though it did not say by how much.

“This whole project is supposed to be about NYISO engaging the demand-side participants in these programs,” the stakeholder said. “While participants could perform with less than 21 hours’ notice, they strongly desired some advanced-day notification, preferably prior to the end of the prior work day.”

To adjust load or activate generation, work schedules needed to be shifted in the event of a call, they said. The manufacturers who participate in the program go to great lengths to reduce their load when called on.

“They will see this proposed change as the straw that breaks the camel’s back and causes them to leave the program,” they said. “If that’s not a concern for NYISO, that’s fine. But I think NYISO should be aware that this could have a dramatic impact on participation.”

The stakeholder said Multiple Intervenors would be happy to have more meetings with NYISO, but they would not perform survey work for the ISO to assess their members’ sentiments.

“We’re not going to do a survey and do the NYISO’s work for it,” they said. “If you want that information, hold a meeting. We’ll participate.”

Jay Goodman, another representative of Multiple Intervenors, asked whether NYISO could provide any historical data on events in which it has called on SCR program participants and did not get corresponding activations. A NYISO staff member said they don’t believe such information is published.

“I do want to note,” Goodman said, “it’s frustrating in the context of a project that is supposed to be engaging with the demand side, where requests for information not only from the demand side but the MMU, is met with the response of ‘No, we can’t provide that information. We won’t provide that information.’”

Goodman went on to ask why NYISO hadn’t brought up the four-hour notice period with the demand side directly, during earlier meetings with Multiple Intervenors. Ferrari said the four-hour notice period had not been decided on by NYISO internally yet.

“The city is shocked as well to this significant change to the program,” said Couch White attorney Amanda De Vito Trinsey, speaking on behalf of New York City.

“This causes a lot of industrial issues, but even for non-industrial customers, this is still a very significant impact on their operations and their ability to respond in a four-hour period,” she said. “I encourage NYISO to come back right away with something to review.”

A representative of the New York State Energy Research and Development Authority said they were disappointed that NYISO wasn’t presenting a more flexible program and didn’t have more information available for reasonable stakeholder follow-up questions.

Another stakeholder compared the various revisions to the SCR programs to multiple ruptured bulkheads on the Titanic. No one issue was going to kill the program, but all of them together would drive participants out.

“The first hole was having revenue reduced by one-third because of capacity accreditation; wham bam, now we’re up to four bulkheads,” they said. “Like, how much more do you think you can do in the guise of catering to operational needs and desires and still have a viable program? I’d say you’re past that point.”

They went on to say this felt like evidence NYISO wanted to get rid of the SCR program entirely. If NYISO wants to save the program, it needs to tone down some of the changes, they said.

“Thank you for your comments,” said Ferrari. “If you’ll allow me to take liberties with your analogy, there are a lot more icebergs in the water. … The grid is changing; it’s a much more dynamic system; and you know we haven’t made changes to this program in a quarter-century.”

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Mass. DPU Approves 1st Round of Utility Grid Modernization Plans

The Massachusetts Department of Public Utilities has approved grid modernization plans from electric distribution companies that outline longer-term strategies for handling increased electrification and the deployment of distributed resources.

The electric sector modernization plans (ESMPs) include five- and 10-year load forecasts, investments to meet forecasted demand and boost resilience, and cost-benefit analyses for the proposed investments. Overall, the plans predict major new costs for ratepayers. (See Mass. Utilities Submit Grid Modernization Drafts.)

The plans were mandated by 2022 legislation requiring utilities to submit new ESMPs every five years, along with two reports per year providing updates on investments and forecasts.

“The department expects the ESMPs to be each utility’s roadmap outlining how the discrete investments proposed will achieve the statutory objectives,” the DPU wrote in its Aug. 29 ruling.

The DPU largely accepted the utilities’ proposals, despite concerns raised by the Massachusetts Attorney General’s Office, Department of Energy Resources, and several environmental and consumer advocacy groups.

While the Grid Modernization Advisory Council, a stakeholder group set up to provide recommendations on the plans, advised that the ESMPs “should be the central distribution system planning document” for “whole-of-business” electric utility planning, the DPU rejected this suggestion.

“This approach would add requirements that the 2022 climate law does not envision,” the DPU ruled, writing that their review of the plans “is limited to the new, discrete and incremental investments proposed in the ESMP.”

The department did note the difficulties “regarding the need to monitor and attempt to influence multiple department proceedings that touch upon distribution system planning.” It wrote that it “sees value in the companies reporting high-level, informational-only data in the ESMP reports relating to non-ESMP investments.”

The investments proposed by the utilities are significant: Eversource Energy presented more than $600 million in additional spending over five years, while National Grid proposed more than $2 billion. The mounting costs are in part a reflection of projected growth in peak demand. Eversource anticipates a 21% increase in electricity demand over the next 10 years, while National Grid forecasts about a 29% increase.

The department’s approval of the plans is not a preapproval of the investments. The DPU wrote in a February 2024 interlocutory order that it will review the proposals “in the context of strategic planning documents only.”

However, the scale of the investment spurred concerns from advocacy groups and the AGO, which wrote that “the magnitude of the planned EDC investments is a sobering challenge to ratemaking and to affordability for ratepayers.”

Representatives of climate and environmental justice organizations expressed disappointment that the DPU did not take a broader approach to the ESMP proceeding.

“I wish they had gone further,” Kyle Murray of the Acadia Center told RTO Insider. There were “not a lot of significant changes from what the companies proposed,” and the DPU “didn’t take a lot of suggestions from the intervenors.”

However, Murray said the move toward long-term planning is a step in the right direction, and he applauded the DPU’s decision to lengthen the stakeholder process for the next round of ESMPs.

Larry Chretien of the Green Energy Consumers Alliance said the DPU’s decision not to use the ESMPs as central planning documents could make it difficult for the department and intervening organizations to evaluate and engage with proposals across separate dockets, filings and stakeholder advisory groups.

“The oversight is going to be tremendous, and it’s going to be every year,” Chretien said. “It’s just not practical to think that the public interest groups and the EJ groups will have the bandwidth to play this game over time.”

Demand Forecasting

The AGO and the DOER both expressed concern about deficiencies in the utilities’ load growth forecasts, writing that they lack consistent inputs and do not account for certain peak load reductions strategies.

“The forecasts offered by the companies fail to meet the standards established; are not transparent; are not comparable across the companies; do not provide a full accounting for underlying assumptions; and lack consideration of important tools like load management, which can reduce costs for ratepayers,” the DOER wrote.

The DOER argued that the EDCs appear to underestimate the potential of peak demand reduction strategies including managed electric vehicle charging, new rate designs, new building codes and energy storage.

The DPU ruled that ESMP load forecasting complied with the law, and that variance between the utilities’ approaches could help accommodate differences in the characteristics of their respective service areas.

“The department finds that each company’s forecasting method and assumptions are reasonable, appropriate and reliable,” the DPU found.

To evaluate the accuracy of future forecasts, the DPU directed the companies to include a comparison of forecasted and actual demand in their biannual filings, and to compare their ESMP five- and 10-year forecasts with their more recent figures. The DPU also required utilities to include separate modeling of demand reduction and energy efficiency programs in the next round of ESMPs.

Climate Resilience

The state’s 2022 climate law also required utilities to detail their plans to prepare the grid for the effects of climate change. The DPU determined the utilities’ proposals complied with the requirements of the law but found “the need for greater consistency in the climate vulnerability assessments prepared by the utilities.”

The DPU noted the utilities proposed different horizons for their climate projections and included limited detail on how they plan to mitigate the risks identified in climate vulnerability assessments. It directed utilities to identify resilience investments using “major event-inclusive performance data” to analyze cost-effectiveness and account for the location of critical facilities.

“In their biannual ESMP reports, the companies shall provide updates on their progress toward finalizing their frameworks for climate vulnerability risk assessments as well as on their targeted resiliency investment identification and prioritization method,” the DPU wrote.

Gas Planning

Environmental advocacy groups expressed concern that the plans do not include enough information on coordinated gas-electric planning and wrote that aspects of the plans citing the potential of hybrid heating systems and blending alternative fuels in the gas network are not compliant with a recent DPU order on the future of gas (20-80-B). (See Massachusetts Moves to Limit New Gas Infrastructure.)

The DPU wrote that it cannot rule on the viability of the gas companies’ decarbonization strategies in the ESMP proceeding, and that it will evaluate these proposals when the companies submit their Climate Compliance Plans in spring 2025.

The department did note that it expects the EDCs to be compliant with orders on gas decarbonization in ESMP filings and directed the companies to “account for any future department decisions on the propriety of these technologies in their future ESMPs.”

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Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+

A new study may dispel the notion that New Mexico utilities must follow the day-ahead market choice of their Arizona counterparts in order to realize benefits from market participation.

The Brattle Group performed the study for Public Service Company of New Mexico (PNM) and El Paso Electric (EPE). It compared the projected benefits from joining either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+. The study models a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power (TEP) — join Markets+.

Brattle Principal John Tsoukalis presented the study results Aug. 29 during a New Mexico Public Regulation Commission workshop.

PNM’s annual benefits would be $20.5 million in the EDAM case, the study found, compared with $8 million from participating in SPP’s Markets+. For EPE, projected benefits are $19.1 million a year for EDAM, versus $9.1 million for Markets+.

Compared to previous analyses, the new study modeled transmission connectivity in the two day-ahead market options in much more detail, including how third-party transmission rights could be used, according to Kelsey Martinez, PNM’s director of regional markets and transmission strategy.

“What we realized through this study is that we do have a choice,” Martinez told the commission.

That realization means that factors not included in the study may become more influential in PNM’s market choice, Martinez said. She noted the potential operational challenge of having large amounts of wind energy moving through the PNM system.

“One market would be dispatching our resources, and another market would be dispatching all the resources that are using and connected to our system,” she said.

Comparing Seams

Tsoukalis said the study was designed to look at the impact of two potential seams resulting from a day-ahead market choice.

“One of those key study questions was looking at which seam was worse,” he said: “that seam with Arizona, or the seam with all the wind in New Mexico that has off-takers in California?”

Brattle looked at the results of the New Mexico utilities joining EDAM or Markets+ as compared to a “current trends” case, which is “a representation of where we think the WECC could go,” Tsoukalis said.

In the current trends case, the Arizona utilities join Markets+ along with a cluster of Northwestern entities, including the Bonneville Power Administration, Powerex and Puget Sound Energy. Western Area Power Administration (WAPA) Upper Great Plains and WAPA Colorado Missouri go with SPP’s RTO West in the scenario.

Entities including CAISO, PacifiCorp, NV Energy, Portland General Electric and Idaho Power would participate in EDAM in the current trends case, while PNM and EPE would remain in CAISO’s real-time Western Energy Imbalance Market (WEIM) but would not join a day-ahead market.

Brattle chose 2032 as the study year.

The study found that for PNM, adjusted production costs fall from $55.4 million in the current trends case to $45.4 million in EDAM and $43.9 million per year in Markets+.

Annual congestion revenues are higher in the EDAM case, at $25.6 million for day-ahead and real-time markets combined, compared with $14.3 million in the Markets+ case. Bilateral trading revenue in EDAM is $3.3 million compared to $0.7 million in Markets+, a reduction from $8.6 million in the current trends case.

EPE also sees a difference in congestion revenues between the two cases: $16 million in EDAM versus $12.5 million in Markets+, relative to $7.8 million in the current trends case. EDAM also gives EPE a big potential boost to bilateral trading revenue: $14.4 million a year in EDAM compared to $6.6 million in the current trends case. Bilateral trading revenue drops to zero in the Markets+ case.

Because of increased imports from the Four Corners trading hub in the EDAM case, New Mexico “becomes flush with low-cost power,” Tsoukalis said. EPE then has an opportunity to sell that power to TEP in the Markets+ footprint.

In response to a commission question, Tsoukalis said Brattle did not study a case in which TEP or the other Arizona utilities joined EDAM, saying the results would be almost a “no-brainer.”

“I tend to think it would skew the benefits more for EDAM, of course, by adding more to that footprint,” he said.

Building Transmission

Scott Dunbar, a partner with Keyes & Fox representing the Clean Energy Buyers Association, asked whether congestion revenues projected for the New Mexico utilities in the EDAM case were likely to fall as new transmission is built.

Tsoukalis said the congestion revenue is a signal that more transmission, or greater availability of transmission rights, would be valuable. He said more transmission would shift a number of metrics.

“If you build more transmission, my intuition would be that benefits would go up overall,” Tsoukalis said. “It just might shift from congestion revenue to adjusted production cost reduction.”

Emmanuel Villalobos, EPE’s director of market development and resource strategy, said the company is still reviewing details of the Brattle study. But a big takeaway was the $14 million in potential revenue from bilateral trading in the EDAM case.

“[It’s] really enough to kind of sway [us] back and forth between the EDAM decision and the Markets+ decision,” he said, noting the figure was potential revenue and not guaranteed.

EPE will weigh other factors such as governance and start-up costs in its day-ahead market decision. And the company may ask Brattle for analysis of additional scenarios, which could include EPE and PNM choosing different markets.

The PRC’s Aug. 28 meeting was the third workshop the commission has held on regional markets. Commissioner Gabriel Aguilera said he now plans to work with his staff on a set of guiding principles for market participation, which will come to the full commission for a vote.

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ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024

ERCOT has told stakeholders it may move up the real-time co-optimization project’s go-live date from its previous September 2026 target, welcome news about a mechanism that will be integral to the future market design. 

“We’re not going live in September 2026. It’s well ahead of that,” ERCOT’s Matt Mereness, chair of the Real-time Co-optimization + Battery Task Force (RTC+B), told the Technical Advisory Committee during its Aug. 28 meeting. “There is a possibility for getting this in by the end of 2025. By next month at this time, we should have a better feel for what that date is.” 

Mereness said several sequenced issues need to be resolved before going live. They include parameters for ancillary service (AS) demand curves, readying the real-time co-optimization (RTC) simulator and market readiness. 

ERCOT’s Matt Mereness | ERCOT

“We’re on the eve of having the project schedule. Some of the details are still working out,” he said. 

Cautioned by stakeholders that RTC’s go-live date could have a large effect on forward prices, Mereness agreed. 

“I think part of it is, will the program have a date? And then there’s the risk management around it … what are the dates that have the confidence in it?” he said. “So yes, that’s part of the vetting process.” 

RTC is used by most other grid operators in North America and has been on ERCOT’s market design and policy radar for more than 10 years. The market tool procures energy and ancillary services every five minutes, automating many processes that currently are managed manually. 

A previous task force, also chaired by Mereness, secured approval for seven nodal protocol revision requests (NPRRs) and two other changes that will guide the tool’s implementation. The task force was disbanded in 2020, but the disastrous 2021 winter storm put further work on hold until 2023. (See “RTC Stakeholder Group to Form,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.) 

ERCOT’s Independent Market Monitor released a report in 2018 that evaluated RTC’s effect on the market. Using 2017 as its simulated operating year, it found a $1.6 billion reduction in total energy costs; an $11.6 million reduction in production costs to serve load; a $257 million reduction in congestion costs; a $155 million reduction in AS costs; and reliability improvements due to a reduced overloading of transmission constraints and a decrease in regulation up. 

TAC Tables Remanded NPRR

Members agreed to table a nodal protocol revision request (NPRR1215) after it was remanded back to TAC by ERCOT’s Board of Directors to correct an error that led to its withdrawal. (See “Error Forces NPRR’s Withdrawal,” ERCOT Technical Advisory Committee Briefs: July 31, 2024.) 

Staff said they pulled back the NPRR after they found an error in its formula calculation. They said they have since discovered potential issues that need further investigation and requested it be tabled. 

The rule change clarifies that the day-ahead market energy-only offer credit exposure calculation zeros out negative values. 

TAC also will have to take the bifurcated part of a Nodal Operating Guide’s rule change (NOGRR245) that was partly approved by ERCOT’s Board of Directors Aug. 20. While approving voltage ride-through requirements for inverter-based resources (IBRs), the directors ordered that a board priority NOGRR be drafted to clarify hardware modification requirements and exemption standards and processes. (See ERCOT Board of Directors Briefs: Aug. 19-20, 2024.) 

The subsequent rule change will address more details around NOGRR245’s exemption process, including the ability to supplement information if a resource entity makes an exemption request by April 1, 2025; appropriate criteria for some level of hardware upgrades for a “vintage” resource to meet relevant ride-through performance requirements or whether it be granted an exemption; and details about the reliability assessment process. 

TAC Chair Caitlin Smith, with Jupiter Power, said ERCOT staff is waiting until the Public Utility Commission approves NOGRR245, likely during its Sept. 26 open meeting, before beginning work on the bifurcated portion. Staff hope to bring a final version of the subsequent NOGRR to the board’s February meeting to meet the April 1 deadline for exemption requests. 

“Having something that’s done and approved and implemented by April, that’s a big lift,” Luminant’s Ned Bonskowski said. “I’m not saying we can’t do it. I just want us to be honest with ourselves about what’s possible.” 

Smith voiced similar concerns to the board during its August meeting. 

Ancillary Services Workshop

Following the morning TAC meeting, members gathered again in the afternoon for a workshop on the PUC’s ancillary services study. The commission will use the study in reviewing the type, volume and costs of the grid operator’s four AS products and evaluate whether additional services are needed (55845). 

The PUC asked both ERCOT staff and the IMM to collaborate on the study. They reviewed AS products for reliability needs and improvements in their procurement to improve efficiency and lower costs. 

Staff aren’t recommending additional AS products for the time being. However, it has proposed exploring two potential improvements: developing a probabilistic method to calculate the appropriate quantities of non-frequency responsive non-spin and ERCOT contingency reserve service (ECRS); and determining the final AS quantities closer to the operating day, rather than annually.  

The IMM used a model with a random probability distribution to perform its analysis. It found ECRS and non-spin quantities can be “substantially” reduced while maintaining reliability. The monitor said a 1-in-10 reliability standard still can be satisfied with 50 and 35% reduced procurements for ECRS and non-spin, respectively. 

A draft study will be filed at the PUC by October, opening a comment period for stakeholders. The PUC will host a workshop on the study Oct. 31. 

Lightening the Mood

American Electric Power’s Richard Ross, who also sits on SPP’s Markets and Operations Policy Committee and does his best to boost the levity in both committees, offered Smith a method to lighten the mood among members.  

“I understand someone said earlier we don’t have fun in these meetings anymore. One of the things some of us do is force the group in unison to read the [antitrust] attestation at their own pace,” he cracked. “It does give us a smile opportunity, should you feel the need to amp up the culture of the meeting.” 

Smith responded that she was open to Ross’ suggestion. 

“I was just told that at TAC, unlike SPP, we don’t have ‘cookies and laughter,’ so we will work on that,” she said. “Someone else said we do have snickering, so with that, let’s get started.” 

Consent Agenda OK’d

TAC endorsed a combo ballot that included three NPRRs, one NOGRR and a single change to the Retail Market Guide that, if approved by the ERCOT board, will:  

    • NPRR1221, NOGRR262: Align manual and automatic firm load shed provisions; clarify the proper use and interplay of under-voltage load shed, under-frequency load shed and manual load shed; and address reliability concerns over the extent of transmission operators’ manual load-shed capabilities. 
    • NPRR1227, RMGRR181: Align defined protocol terms and add five definitions (“acquisition transfer,” “decision,” “effective date,” “gaining competitive retailer” and “losing competitive retailer”) that previously were located in the Retail Market Guide (Acquisition and Transfer of Customers from one Retail Electric Provider to Another). The NPRR also replaces the broadly titled terms “decision” and “effective date” with the specific terms “mass transition decision,” “acquisition transfer decision,” “mass transition effective date” and “acquisition transfer effective date” to provide clarity. The change also expands the “gaining competitive retailer” and “losing competitive retailer” definitions to apply beyond the mass transition and acquisition transfer processes. 
    • NPRR1236: Reflects Real-Time Co-optimization Plus Batteries (RTC+B) Task Force’s modifications to the reliability unit commitment capacity-short calculations and addresses limits in the current calculations by considering ancillary service sub-types. It changes the calculation process involving regulation down service and addresses changes required to align protocol language with recently approved NPRR1204 (Considerations of State of Charge with Real-Time Co-Optimization Implementation). 
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CAISO IDs More Challenges in Refining Interconnection Process

CAISO dove into Track 3 of its Interconnection Process Enhancements (IPE) initiative Aug. 28, as staff and stakeholders grappled with how to solve problems related to the proposal’s allocation of transmission plan deliverability (TPD). 

In California, TPD refers to the amount of transmission capacity needed in an individual study area to allow proposed generation projects in the area to reach their expected deliverability status. CAISO will allocate TPD to the most viable projects in an area, which then will be reimbursed for their needed network upgrades. 

The initiative’s Track 2 proposal, approved by the board in June, will apply to Cluster 15 of the interconnection queue and beyond, but the ISO still struggles to address the “unprecedented volume” of interconnection requests for Cluster 14. (See CAISO Board Approves Interconnection Enhancements Proposal.)  

Although Cluster 14 projects already have been studied, they’re “log-jammed” behind major network upgrades, according to the Track 3 straw proposal, causing concerns about how to allocate TPD to projects with long lead times.

The ISO’s proposal identified three main issues with the TPD allocation process. 

The first is related to TPD allocation issues for long lead-time projects with delayed deliverability network upgrades (DNUs). The second involves allocations for projects with long lead-time reliability network upgrades (RNUs). The third is for long lead-time resources that have met defined resource policy goals of the local regulatory authorities (LRAs) in California for specific technologies and project locations. 

The structure for TPD allocation prioritizes projects that have a power purchase agreement. For those with longer lead times, the window of opportunity to seek an allocation can be several years before network upgrades are complete, making it challenging for such projects to know when to enter the queue. Projects will have three consecutive opportunities to seek an allocation; if they don’t receive one, they’ll be converted to “energy-only” (EO) projects, which are not included in resource adequacy counts.  

Bob Emmert, CAISO senior manager of interconnection resources, said projects with longer timelines and needed upgrades may struggle to execute a PPA.  

“It may be difficult for long lead-time network upgrades and long lead-time generation resources to actually get that PPA or be shortlisted before they’re converted to energy only, even if the number of opportunities were increased to four,” Emmert said during the Aug. 28 workshop. “We want to at least discuss ways that we might be able to rectify that situation.”  

Proposed Solutions

For projects with long lead-time DNUs, Emmert presented a potential interim solution: increasing the number of PPAs for projects to come online as EO while waiting for Full Capacity Deliverability Status (FCDS). 

“We definitely think that offering a pathway for early interconnection for energy-only projects is critical,” said Sushant Barave, senior director of grid integration at Clearway Energy Group. “I also think this pathway has to be paired with an interim deliverability framework because that’s what makes standalone energy-only projects coming online earlier financeable.” 

“I would encourage CAISO to think about it as part of the larger solution, where, because of long lead-time upgrades, even projects that have deliverability sometimes cannot get the contractual assurance and show up early on as energy only,” Barave added.  

Other stakeholders were concerned about the proposal’s implications for storage resources.  

“I see this being a struggle for storage projects, which are a lot of the projects that are seeking deliverability,” said Soumya Sastry, senior manager of structured energy transitions at PG&E. “I think that there would be a lot of challenges from a buyer’s perspective. I don’t know if we would want to pay the same price for something that is EO.” 

The proposal also raised concerns about the uncertainty of procuring on such long timelines.  

“I think this could lead to potential over-procurement in the reliability space or just stranding projects that there’s not a need for this sort of conversion from energy only to FCDS that far in advance,” said Michael Freeman, contract origination manager at Southern California Edison. “If you’re in a market where you’re procuring for long-term assets, how are you judging when a project is going to come online or get RA at year six, year eight, year 10? … It just makes planning for reliability more difficult, and I could see projects that have that sort of option be stranded because LSEs may not want to take that sort of risk.”  

Emmert reiterated concern about the risks associated with the proposal.  

“There may be certain project conditions that are just too risky, and you would not be willing to go down that road. But there may be other projects that the risk profile is less.”  

Regarding the second issue — projects with long lead-time RNUs — Emmert suggested that contracting with projects that won’t be in operation for five to seven more years could enable such projects to obtain a TPD allocation within the three or four opportunities provided.  

“From an LSE perspective, if there’s a path forward to getting TPD and there’s certainty and a robust pool to select from, I don’t see an issue,” Freeman said.  

The third issue considers whether special TPD allocation criteria should be developed for long lead-time resources that meet defined resource policy goals of LRAs. The idea is that unique criteria could allow these projects to avoid the risk of being converted to EO before procurement begins.  

“There may be infrastructure such as offshore wind that needs to be put in place before you can even start building it,” Emmert said. “The question is, will the central procurement entity be authorized and willing to contract for these resources within the period where these resources are eligible to seek an allocation? Or should we look in another direction to try and solve this problem?” 

Stakeholders showed support for the third solution.  

“Capacity needs to be reserved for generic long lead-time resources because developers don’t invest in remote resource areas where transmission doesn’t currently exist and isn’t being planned for,” said Nancy Rader, executive director of the California Wind Energy Association. “The 10-year timeline for planning and building those is just too far out to enable a PPA, so these resources really need to be treated separately from non-long lead-time resources in the intake process.”  

The ISO hopes to publish a revised straw proposal for Track 3 by October and is targeting a Board of Governors vote in March 2025.  

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BOEM Sets Oct. 15 Oregon Wind Lease Auction

The U.S. Bureau of Ocean Energy Management has set the first-ever Oregon offshore wind energy lease auction for Oct. 15. BOEM said in a news release that the two lease areas being offered hold a potential capacity of more than 3.1 GW of energy generation if fully developed. 

The Brookings Wind Energy Area (OCS-P 0567) totals 133,792 acres about 18 miles from the southern Oregon shoreline near the California border. The minimum bid is $6,689,600. The estimated installed generation capacity is 1.6 GW to 2.1 GW. 

The Coos Bay Wind Energy Area (OCS-P 0566) totals 61,203 acres about 32 miles offshore, closer to Reedsport and Florence than to Coos Bay. The minimum bid is $3,060,150. The estimated capacity is 0.77 to 1 GW. 

Water depth in the lease areas ranges from 1,860 to 5,022 feet — far too deep for the conventional fixed-bottom turbine foundations being installed in the first U.S. offshore wind farms, along the Northeast coast. 

Development instead would rely on floating tower and anchor/mooring systems that still are being designed, potentially increasing the timeline, cost and complexity of any offshore wind construction off the Oregon coast. 

In a July 2024 note to clients, research firm ClearView Partners said the immature technology, combined with the lack of a state-led solicitation and the uncertainty surrounding the November elections, could limit interest by potential bidders in an Oregon auction. 

On the other hand, the strong offshore wind ambitions in neighboring California could attract greater interest in Oregon, ClearView wrote. 

The final sale notice released Aug. 29 indicates that five entities are legally, technically and financially qualified to participate in the second Pacific Wind Lease Sale (PACW-2): Avangrid Renewables, BlueFloat Energy Oregon, OW North America Ventures, U.S. Mainstream Renewable Power and South Coast Energy Waters I. 

This compares with 43 entities pre-qualified to participate in PACW-1 in December 2022, which involved five lease areas off the California Coast. Only seven entities participated in that auction; Avangrid Renewables was among them but stopped bidding after the 23rd round. 

Five high bids totaling $757.1 million were submitted for the five lease areas, which span a combined 373,268 acres and hold a potential capacity of more than 4.6 GW. These, too, would require floating turbines. 

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WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027

The Western Resource Adequacy Program’s key stakeholder body on Aug. 29 approved a plan that would postpone the start of the WRAP’s penalty phase by one year, to summer 2027. 

The vote by the Resource Adequacy Participants Committee (RAPC) comes months after committee members issued an April 22 letter seeking to delay the “binding” phase of the voluntary program, which is operated by the Western Power Pool (WPP). (See WRAP Participants Seek 1-Year Delay to ‘Binding’ Operations.)   

That letter cited the “significant headwinds” many Western utilities face in securing enough resources to avoid incurring penalties. The difficulties listed included supply chain issues, faster-than-expected load growth and extreme weather events that have “further challenged” regional assumptions about the volume of generation needed to maintain reliable grid operations. 

Before circulation of the April letter, WRAP participants faced a May 31 deadline to commit to binding operations for summer 2026. The “transition plan” the RAPC approved Aug. 29 “outlines a gradual path to fully implement the WRAP” by pushing back the binding phase deadline and temporarily reducing program penalties for participants short on RA, according to a statement from the WPP. 

“The plan helps in three critical ways,” WPP CEO Sarah Edmonds said in the statement. “It moves the program forward with participants engaged and committed and on a path to fully binding in 2027, which was essential after the concerns they raised in April. It allows the program to pool resources and provide support for participants in need, helping reliability in the region. And it allows participants to work to address resource adequacy.” 

Under the new plan, WRAP participants will be required to provide their notice of intent to go binding for summer 2027 by January 2026, rather than the previous deadline of May 2025.  

“The extra time to resolve uncertainties may enable more binding participation. All participants will be binding for winter [2027]/28,” the WPP statement said. 

The plan also extends the WRAP’s “transition period” by one year to March 2029. During that period, participants who enter the binding phase but remain deficient in RA will be eligible to pay a “discounted deficiency charge” if they demonstrate “commercially reasonable efforts” to obtain WRAP Operations Program capacity but still fail to do so, what the program will consider an “excused transition deficit.” 

“Participants who are deficient and pay the charges would have the same priority access to surplus capacity as other participants in the Operations Program,” according to the plan. 

‘Critical Mass’

The new plan also introduces the concept of “critical mass” into the WRAP, defined as “the participating load volume and participant threshold for a [WRAP] subregion below which participants may participate in a nonbinding manner” after the conclusion of the transition period. The thresholds will be 15 GW of load and three participants for the Southwest/East Diversity Exchange (SWEDE) subregion and 20 GW of load and three participants for the Mid-C subregion on the Northwest. 

Accompanying that new concept are WRAP tariff changes that would allow participants in a subregion to choose to be nonbinding for seasons when critical mass is not achieved. 

“Once WPP has given notice to participants that their subregion does not have critical mass, such participants will have 30 days to provide notice to WPP if they intend to participate as nonbinding participants for that binding season,” the updated tariff would read. “Such notice and election will be given similarly for each season without critical mass participation.” 

Another change seeks to help participants in either WRAP subregion more easily meet their RA requirements by tapping the potential for “diversity sharing” across the WRAP’s entire footprint via transmission connectivity, allowing utilities to count more distant resources in their RA forward showings (FS).  

That part of the plan would assume that 500 MW of transmission capacity will be available for south-to-north flows between the subregions in winter, while the same volume would be available for flows in the opposite direction during summer. It would not reduce the WRAP’s total planning reserve margin. 

“The extent of any reductions in Subregion FS Planning Reserve Margins should not fall below the WRAP Region PRM,” the plan said. 

WPP also noted that it will work with the operators of CAISO’s Extended Day-Ahead Market and SPP’s Markets+ to replace the 500-MW figures with “more accurate numbers.” Those numbers likely will be significantly affected by the eventual geographical footprints of the two markets. The viability of the WRAP is particularly important for Markets+ because its participants will be required to participate in the program. 

Speaking at the spring joint meeting of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body in Denver in April, Edmonds said WRAP participants were still “unwaveringly committed” to the program and that the challenges utilities face in meeting RA requirements only further illustrate the need for the program. 

“The important thing is getting the program off the ground and addressing reliability in the region,” Edmonds said in the Aug. 29 statement. “These changes allow us to do that. Everyone can be part of and benefit from the program, while working to add resources to address any deficiencies. Meanwhile, we’ll continue to get critical insights about resource adequacy gaps from the nonbinding period.” 

The transition plan is open for public comment and will be reviewed by the WRAP’s Committee of State Representatives before going to a vote by WPP’s Board of Directors. The plan’s associated tariff changes also must be approved by FERC. 

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Changing System Drives MISO to Scrutinize Guiding Market Principles

CARMEL, Ind. — MISO is conducting a check-in with stakeholders to gauge whether its market design guiding principles are still valid in a changing industry.  

The RTO asked stakeholders at an Aug. 29 meeting of the Reliability Subcommittee to evaluate whether its 10-year-old principles are still in lockstep with the functioning of MISO markets.  

MISO’s five guiding principles are standing up an “economically efficient” wholesale market system, fostering nondiscriminatory market participation, maintaining transparent market pricing, facilitating efficient operational and investment decisions among market participants, and aligning market requirements with reliability requirements.  

MISO adviser Kim Sperry said the RTO references the decisions in its tariff filings to FERC, when designing new market products and when leading stakeholder discussion. “Maybe there’s an area where we can make an adjustment,” Sperry said.  

At the Market Subcommittee meeting, adviser Michael Robinson similarly approached stakeholders. He set the stage by describing 2014’s Polar Vortex, which ultimately led to the guiding principles and a redesign of MISO’s scarcity pricing.  

“The year is 2014, we just incorporated MISO South, operators still [are] getting their feet wet in operating this broader footprint,” he said.  

Robinson said the near emergency caused MISO to rethink its emergency pricing and led it to establish its two-step emergency pricing floors. He said examining the principles now makes sense given the industry’s reshuffle.  

At the meeting, Clean Grid Alliance’s David Sapper suggested MISO consider adding a sector dedicated to industry disruptors, whose innovative ideas could “breathe life into market principles” and further competition. Sapper pointed out that MISO accepts coal interests in its Affiliate Sector, which was created in 2020 and is MISO’s newest member sector. 

“This might be a missing puzzle piece. The point is not that there’s pent-up demand. The point is MISO opening doors,” Sapper said. He also suggested it include a nod to fairness and social welfare in the principles, something he said is missing today. 

Mississippi Public Service Commission consultant Bill Booth said the RTO could perform backward-looking check-ins to make sure the new market rules it establishes are effective.  

“It’d be nice if our guiding principles included a verification. … We don’t check our work. What do we do after the fact to validate that our theoretical choices are practical?” Booth asked.  

MISO staff said their market implementation team was created specifically to check in on whether MISO’s proposals are working as intended and perform tests after the fact. Dustin Grethen said the RTO has checked in recently on its fast-ramping product and its short-term reserve product. 

Sperry said MISO will accept stakeholders’ ideas through Sept. 13. 

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PUC Shortlists 17 Projects for Loans from Texas Energy Fund

The Texas Public Utility Commission has selected 17 generation projects for further review as part of a $5 billion loan program intended to add dispatchable, or thermal, generation to the ERCOT grid.

During its Aug. 29 open meeting, the commission delegated authority to its executive director to enter into loan agreements with those applicants who can show “they’re worthy” after a due-diligence review. The projects, if completed, would add 9.78 GW of new dispatchable generation for $5.38 billion in state loans (56896).

The portfolio was culled from 72 applications under one of four Texas Energy Fund (TEF) programs approved last year by voters, the In-ERCOT Generation Loan Program. The applications sought more than $24 billion in low-interest funding for projects representing over 38 GW of dispatchable generation.

PUC staff and the TEF administrator assessed each of the applications based on applicants’ experience and financial strength, the proposed projects’ technical and financial attributes, and five commission priorities: diversity among applicant types, diversity in siting location, speed to market, ability to relieve transmission constraints and diversity of resource type.

“I’m happy with the recommendation. I think it’s an amazingly good job of weighing all the issues that the five commissioners brought to you throughout this process,” PUC Chair Thomas Gleeson told staff during the open meeting.

Should any projects fail the due-diligence review, staff could recommend additional applications for review. However, there is a March 2025 deadline to advance those projects for review. Initial disbursements for approved projects will be made before Dec. 31, 2025.

The list of 17 projects includes heavyweights like Calpine, Constellation Energy, NRG Energy and Vistra. It also includes local entities like Kerrville Public Utility Board and Rayburn Electric Cooperative. The projects range in size from 1,350 MW to 122 MW.

“We had 72 folks who were interested and wanted to, if you will, kind of get in the game,” Commissioner Jimmy Glotfelty said. “They put a lot of thought into it and hopefully … there’ll be an opportunity for more to come.”

“We are eager to see these projects break ground and are confident that the commission will proceed in such manner to ensure that the fund is used efficiently to deliver the reliable power,” Tony Bennett, CEO of the Texas Association of Manufacturers, said in a statement. “Texas needs to maintain its top spot as the best place to do business, grow jobs and strengthen communities.”

The TEF’s other programs include the completion bonus grants, outside ERCOT grants and the Texas backup power package. The fund was established in March because of state legislation that passed last year, with the February 2021 winter storm serving as the catalyst. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.)

Stoic Energy principal and ERCOT observer Doug Lewin said in his weekly newsletter that 80% of the gas plants will be peakers and “will likely displace older, higher-polluting fossil fuel plants.”

“This was not unexpected, but it’s interesting to see that’s what actually happened,” he wrote, noting that gas availability was a “major problem” during the 2021 storm.

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Berkeley Lab Report Highlights Trends in Distributed Solar

Lawrence Berkeley National Laboratory has released the latest iteration of its “Tracking the Sun” report, which looks into the 3.7 million distributed solar systems installed through the end of 2023. 

The size and efficiency of installed residential solar systems has been growing over the past two decades, with the median size rising from 2.4 kW in 2000 to 7.4 kW in 2023, and the average efficiency from 12.7% in 2002 to 20.8% last year. 

“Increases in module efficiencies since 2010 closely track the rise in residential system sizes, suggesting that module efficiency gains have been a primary driver for growth in residential system sizing,” the report said. 

The roof-coverage ratio for residential systems has been relatively stable, ranging from 15 to 40%, with a median of 26% in 2023. Nonresidential rooftop systems have a lower median, but a much broader range. 

The report found that solar panels increasingly are being paired with storage systems over time, rising from nothing in the middle of the past decade to 12% of new residential systems in 2022 and 8% of new nonresidential. Hawaii has the highest storage attachment rate, at 95%, while new policies that went into effect in April 2023 in California have driven its rate to 14% — and most other states have attachment rates of 4 to 10%. 

The new net billing tariffs going into effect are driving more storage pairing in California, with the report noting 60% of systems paid under them are linked with storage. 

Third-party ownership for residential solar systems has been declining in general, falling from 60% in 2012 to 27% in 2023. There was a slight uptick in third-party ownership last year, which the report said could be from higher interest rates for solar loans. 

Residential systems overwhelmingly are deployed on single-family homes, but the nonresidential sector sees much more variety in customer type, with half on commercial businesses, one-third on agricultural sites and 15% on tax-exempt customers (government, schools, churches, etc.). 

Berkeley developed inflation-adjusted prices for standalone residential customers, which fell by 10 cents/W in 2023 — the same rate of price decline for the past decade. Median prices for nonresidential systems actually went up by 10 to 20 cents/W, which the report blamed on inflation.

Between 2021 and 2023, nominal installed prices were up 2 to 3 cents/kW across customer segments, but when controlled for inflation, they were down 50 cents/W for residential systems and 10 cents/W for others. 

“The fact that real prices fell suggests that PV pricing has thus far been less impacted by inflation compared to other consumer goods (as measured by the CPI), though the effects on installed prices for large nonresidential systems may have not yet entirely materialized,” the report said. 

Prices vary depending on a range of factors, from system size to state policy. The report said residential prices vary by about $1/W between the largest and smallest systems, while commercial generation varies $2.20/W between sizes.