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November 14, 2024

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Long-duration Storage Key to Calif. Energy Goals, Report Says

Long-duration energy storage (LDES) will play an essential role in cost-effectively decarbonizing California’s electricity grid, according to a report released by the state’s Energy Commission (CEC) Jan. 29.  

The study, prepared by researchers from Energy+Environmental Economics (E3), Form Energy and University of California, San Diego, explores how LDES can help California meet goals set out in Senate Bill 100, the 2018 law requiring the state to serve all retail electricity load with emissions-free power by 2045.  

Relying on modeling of the CAISO grid, it represents the most in-depth analysis to date of the crucial role the technology will play in California’s transition to renewable energy. 

The report also examines LDES’s ability to reduce air pollution in the Los Angeles Basin, as well as its role in supporting resilience in microgrids.  

Main Findings

The study found that California has made significant progress in its energy transition, with prior studies showing the electric sector could reach 80% or greater decarbonization with existing technologies. But achieving decarbonization and reliability won’t be cheap without innovations in LDES, which could be a viable replacement for the natural gas-fired power plants that are traditionally relied upon for dispatchable capacity to balance renewables and meet grid reliability standards.  

Under a business-as-usual SB 100 scenario, which allows for retainment of all existing gas resources, the study found that deploying 5 GW of LDES could cost-effectively bring CO2 emissions down to 12 million metric tons by 2045. LDES is far more cost-effective with up to 37 GW deployed by 2045 under a zero-emissions scenario that covers in-state emissions and electricity imports.  

Simulations across 35 historic weather years in the Los Angeles Basin case study showed that LDES enables retirement of gas plants in the CAISO system while maintaining reliable grid operation. By 2045, 21 GW of LDES could substitute for all of California’s existing gas plant capacity. Without LDES, the study found that the cost of using other resources to avoid reliance on gas plants increases by up to 87%.  

“Portfolios that retire in-state gas by using LDES were found to achieve cost parity, and in some cases cost savings, relative to those that retain existing in-state gas,” the study found.  

While researchers highlighted that further analysis is needed to evaluate the environmental justice benefits of retiring gas-fueled generation more quickly, they demonstrated that LDES will likely play an important role in cost-effectively maintaining local capacity requirements while reducing the need to rely on emitting resources in disadvantaged communities.  

“In Form’s study of the Los Angeles Basin as an example area, 2 GW of LDES and 1.3 GW of 4-hour lithium-ion storage is found to be the least-cost substitute for gas power plants located in disadvantaged communities, lowering system costs by 3%,” Form Energy said in a brief about the report. “This is the first time that the benefits of LDES to local reliability and environmental justice have been studied in the state, creating a model for how other local reliability areas can be studied in the future.” 

Support for Microgrids

In a case study of microgrids at the University of California, San Diego, the team also found that LDES can support high-reliability microgrids by pairing with other distributed energy resources to deliver 48-hour resilience capability, also known as “islanding,” and protecting against outages.  

However, LDES-supported microgrids may not be cost-effective. The study found that the customer value of lost load needed to justify its use ranged between $5-18 kWh for small campus buildings. Some larger buildings, though, demonstrated a negative value of lost load, showing that some microgrids improve reliability while reducing costs.  

Goals

In addition to demonstrating the distinct value LDES will bring to California’s energy transition, the study highlighted the need for modeling tools and approaches that can continue to accurately capture the value of LDES in future portfolio planning. It also emphasized the importance of optimizing resource needs with hourly time resolution across a full year and in varying weather scenarios.  

“By using these methodologies, grid planners can proactively identify resources that electric markets may not yet be fully valuing,” Form’s brief said. “From there, policy initiatives can be designed to ensure these resources are able to rapidly proliferate and deliver savings to the electric grid.” 

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NEPOOL Participants Committee Briefs: Feb. 1, 2024

BOSTON — New England power system emissions decreased by about 3.6% in 2023 compared with 2022, according to the underlying data from ISO-NE COO Vamsi Chadalavada’s monthly report to the NEPOOL Participants Committee.  

Natural gas emissions increased by about 3% in 2023, accounting for about 75% of all power system emissions. Oil emissions dropped drastically, ending the year at about 17% of their 2022 levels. Coal emissions also declined, decreasing by about 43%. 

Based on data through Jan. 24, Chadalavada said the energy market value for January totaled $712 million, an increase from $552 million in January 2023. He noted that the monthly peak load was 18,431 MW.  

ISO-NE annual CO2 emission estimates in million metric tons | ISO-NE

Capacity Market Recommendation

The meeting materials indicated ISO-NE has decided to recommend that it transition its Forward Capacity Market to a prompt and seasonal capacity market, which would reduce the time between the auction and the capacity commitment period (CCP), while splitting the annual CCP into seasonal periods.  

ISO-NE noted that its Board of Directors “concurred with management’s recommendation to transition to a prompt, seasonal capacity market, which it will discuss next with stakeholders.” 

At the NEPOOL Markets Committee on Feb. 7, ISO-NE will propose a two-year delay of Forward Capacity Auction 19 “to allow for time to design a prompt and seasonal market for CCP 19.” 

Votes

The PC voted to approve ISO-NE’s proposal to lower the Forward Reserve Market (FRM) offer cap from $9,000/MW-month to $7,100/MW-month and delay the publication of data from the auction. These changes were initiated in response to concerns raised by the ISO-NE Internal Market Monitor about market power in the FRM.  

The FRM is designed to procure reserve capacity and is held twice annually. In March of 2025, ISO-NE will replace the FRM with a new day-ahead ancillary services market. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.) 

The RTO initially proposed lowering the cap to $6,400/MW-month but adjusted its proposal to $7,100/MW-month following stakeholder feedback and a $7,200/MW-month counterproposal from LS Power that was supported by a vote in the Markets Committee.  

The PC also voted to approve changes to its interconnection planning procedures to improve the modeling of inverter-based resources and “update system modeling assumptions to align with the operating conditions expected with the clean energy transition.” 

The committee also approved tariff changes to assign responsibility to distributed energy resource aggregators to submit their aggregation’s metering information.

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FERC Grants AEP Utilities Waiver of Capacity Obligation

FERC on Jan. 31 granted American Electric Power waivers to alter the capacity obligation calculation for four of its vertically integrated utilities in PJM to not include load growth outside their territories (ER24-545).

In its Dec. 4 request, the company said its AEP Ohio affiliate, which participates in PJM’s Reliability Pricing Model (RPM), had submitted a forecast large load addition of about 1,860 MW largely attributed to data centers expected to be constructed in its footprint. Under PJM’s approach to allocating capacity obligations, AEP said the majority of the responsibility to procure the capacity to serve that load would fall on other affiliated utilities in the AEP transmission zone that participate in the fixed resource requirement (FRR) alternative to RPM. The company estimated that 1,039 MW of the increase would be allocated to Appalachian Power, Indiana Michigan Power, Kentucky Power and Wheeling Power.

“The AEP FRR entities seek this waiver so the forecasted peak load increase associated with the projected large load additions will appropriately remain in the PJM region reliability requirements addressed by the BRA [Base Residual Auction] for delivery year 2025/2026, instead of being shifted to the AEP FRR entities. The waiver will allow the AEP FRR entities’ customers to avoid rate impacts caused by the procurement of capacity not needed to serve them,” the company said in its request.

The company asked permission to excise the base zonal FRR scaling factor from the calculation of the FRR utilities’ capacity obligations, resulting in an equation that multiplies the obligation peak load by the forecast pool requirement (FPR). That would assign the entirety of the capacity obligation for the 1,860 MW to the electric distribution companies within the AEP zone.

FERC said in its order that the waiver “will allow the AEP FRR entities to avoid procuring unneeded capacity for purposes of its FRR capacity plan for the 2025/2026 delivery year.”

PJM commented that so long as the forecast large load additions are entirely within EDCs participating in the RPM, the waiver has merit, but it requested that the commission confine its approval to the issue at hand, as stakeholders are considering changes to how capacity obligations associated with forecast large load additions are split between FRR and RPM entities within the same transmission zone. The problem statement stakeholders are considering, jointly brought by AEP and Dominion Energy, states that high load industries are resulting in concentrated pockets of growth, often within single EDC regions.

“There is stakeholder support for revising the [Reliability Assurance Agreement] to eliminate this impact of the base zonal FRR scaling factor, which seems to be a relic of a time in which increases to load forecasts were more generally experienced across a transmission zone, as opposed to being concentrated within a single EDC’s service area,” AEP argued in its request.

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BPA Targets August for Draft Day-ahead Market Decision

The Bonneville Power Administration plans to issue a draft decision on its day-ahead market participation in August, followed by a final decision in November, the federal power marketing agency told stakeholders Feb. 1. 

The new timeline represents a shift from the one BPA initially set out last July when it launched a series of workshops to explore its potential participation in either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+ offering. 

At that time, the agency had targeted February 2024 for the release of a “policy direction” including a decision on whether to join any day-ahead market and a “leaning” on which of the markets it would likely choose. 

While the exact meanings of “policy direction” and “leaning” have been open questions for months, the expected content of both became somewhat clearer last week.  

BPA told stakeholders during its Feb. 1 day-ahead markets (DAM) workshop that it now plans to issue a “policy letter” in early April that will provide a “light touch” on the agency’s business case and legal authority to participate in a day-ahead market.  

The letter also will contain a “description of BPA’s strategic vision related to DAMs, including a staff recommendation on whether to pursue participation and which DAM may be the best fit for BPA at this time,” BPA said. 

In an emailed response to questions from RTO Insider, BPA spokesperson Doug Johnson said the letter “will provide a staff recommendation with an initial policy direction as to whether BPA sees value in joining a day-ahead market and, if so, which DAM option best meets its principles. BPA will include a brief description of its legal authority to participate, an initial evaluation of the value proposition and a discussion of other factors supporting its staff leaning.” 

BPA’s revised timeline now calls for the release of a “draft policy” on day-ahead market participation at the end of August, which will cover the agency’s business case and legal authority regarding participation. The draft will also “either validate BPA’s initial staff recommendation” on a market choice or “lay out an alternative direction,” the agency said. 

BPA has tentatively scheduled a public workshop on the draft policy for Sept. 19. It then plans to issue a final policy and record of decision in November.  

In the meantime, the agency said it will continue to engage with stakeholders on the day-ahead market issue. Another DAM workshop will be held in the first week of May to discuss the April policy letter, the staff recommendation and any comments received by the agency. Additional workshops are scheduled for June 5 and Aug. 6.   

Competing Concerns

The change in BPA’s timeline comes in response to the tangle of issues the agency confronts as it moves toward a decision. 

One of the thorniest relates to BPA’s “preference customers,” made up of publicly owned utilities across the Northwest, who are concerned that the agency’s deeper involvement in an organized market could compromise their rights to access low-cost power from the federal Columbia River hydroelectric system. They are seeking greater guarantees that protect their interests before BPA decides to join any day-ahead market. 

Another key issue relates to BPA’s choice of a market as CAISO and SPP compete for participants in their respective day-ahead offerings. BPA’s decision carries significant weight because it operates about 70% of the transmission in the Northwest and is the region’s largest power provider. 

It’s for that reason the agency has been under significant pressure on multiple fronts to slow down its decision-making process.  

At BPA’s second DAM workshop last September, stakeholders who support a single market for the West based on CAISO’s platform complained that the agency’s initial timeline was too aggressive. They were concerned BPA’s leaning effectively would constitute a final decision — and that the agency already was favoring Markets+.  

Key critics of the faster timeline include the environmental and consumer group Northwest Energy Coalition, as well as state energy officials from Oregon and Washington. They contend BPA should delay issuing a leaning until developments play out around the West-Wide Governance Pathways Initiative, a state-led effort to create the framework for an independent Western RTO that includes CAISO while addressing concerns about the ISO’s governance. In comments filed with BPA in November, municipal utility Seattle City Light questioned why the agency was not directly participating in the initiative given that it was designed to address many of BPA’s concerns related to CAISO governance. 

Others, including some public power representatives, have said a quick decision was necessary to ensure the agency exercised sufficient clout to shape market developments in the broader West. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.) 

BPA appeared to be touching the brakes on a decision during its November DAM workshop, when it told stakeholders it still would issue a policy direction during the first quarter of 2024, but that the content would change to cover the agency’s statutory authority to join a day-ahead market while also including a market leaning.  

During that meeting, Russ Mantifel, BPA director of market initiatives, acknowledged the agency still had “limited information” on which to base a market decision, saying the timing was “up in the air” in light of uncertainties around tariff timelines for EDAM and Markets+. (See Region Still Split as BPA Approaches Day-ahead Market Decision.) 

Since then, FERC has approved CAISO’s EDAM tariff and SPP has pushed back the schedule of its Markets+ tariff filing from early February. The Arkansas-based RTO now plans to put the tariff to a board vote in late March and hopes to win FERC approval within nine months, which then would allow the RTO to begin Phase II of the market’s development. (See SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)  

‘Sufficient Information’

BPA on Feb. 1 rebuffed concerns by Oregon and Washington state agencies that the agency still lacks the information needed to support a leaning. In a slide presented during the workshop, the agency affirmed that it “will issue its initial staff recommendation regarding Bonneville’s policy direction on potential DAM participation in a letter this spring and feels it has sufficient information to do so.” 

BPA told RTO Insider the staff recommendation “will inform customers and stakeholders about its policy leaning to aid in their assessments of the changing energy landscape, provide considerations regarding potential DAM participation, inform customer product choices and operational goals, and invite discussion on other salient issues that BPA should consider when developing a more formal policy direction and issuing a record of decision in late 2024.  

“Any decision to join a DAM would be dependent on BPA rate and tariff proceedings and contract updates,” it said. 

BPA said it continues to monitor developments taking shape across the West, including efforts around the Pathways Initiative. 

“BPA staff have been assessing CAISO’s EDAM and SPP’s Market+ day-ahead market designs, public power concerns and support regarding potential participation, and considerations regarding issues such as carbon emissions reduction goals, continuing to meet environment, fish and wildlife stewardship obligations, maintaining close relationships with states and tribes, and providing service in the most economical, efficient and reliable manner,” Johnson said. “BPA has interfaced with other potential DAM participants to understand potential market footprints.”

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SPP Directors Pleased with Progress of Markets+ Tariff

SPP’s two independent directors with backgrounds in the Western Interconnection both expressed relief and optimism at the grid operator’s collaborative efforts with stakeholders to develop Markets+ in the West.

The comments came during a conference call Feb. 2 with members of the Markets+ Participant Executive Committee (MPEC) and the Markets+ State Committee (MSC).

“Honestly, a year ago, I was probably a bit skeptical about the potential for being in this position of essentially the major tariff issues being resolved in less than a year,” said Steve Wright, a former Bonneville Power Administration administrator and CEO. “The progress is really amazing. An incredible array of folks have come to the table and found compromise on what have been intractable issues in the West in the past.”

John Cupparo, a former officer with PacifiCorp and experienced in several other western initiatives, pointed to stakeholder approval rates in the 90s on votes for tariff language and other issues and lack of appeals to decisions already made as evidence of a job well done.

“From my perspective, this is truly reflective of a market for the West, designed by the West and governed by the West,” he said.

Along with director Liz Moore, Wright and Cupparo constitute the Interim Markets+ Independent Panel (IMIP), the temporary body overseeing the day-ahead market’s development. The directors listened to several reports on last month’s MPEC meeting and approved 15 pieces of language related to the Markets+ tariff and its attachments.

The IMIP also approved modifications to the independent sector’s voting structure, previously approved by the MPEC. (See “Independent Sector Changes,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)

The primary remaining sticking point is what’s been called a “gap” with the accuracy of information to be shared with SPP’s Market Monitoring Unit under FERC’s duty of candor requirements. SPP, the MSC, the MMU and western legal groups are all involved in resolving the issue.

MSC member Ann Rendahl, a commissioner with the Washington Utilities and Transportation Commission, said “much” progress has been made since the January MPEC meeting. The various entities involved met the week after MPEC and are planning to resume discussions this week.

“We see this moving in a direction that will address the outstanding concern that we have. We’re optimistic that the language can be worked through the Markets+ process in the coming weeks and adopted into the tariff,” Rendahl said.

“Everyone engaged in this exercise is invested in building a robust, transparent market that earns the trust of parties throughout the West,” she added. “We’re all well aware and understand the long history of market development in the West. There’s considerable scar tissue in the West surrounding prior experience with significant adverse customer-rate impacts associated with price and market manipulation.”

A reference, perhaps, to the western energy crisis of 2001 instigated by Enron in California, and hopefully, soon to be forgotten.

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MISO to Relax Commercial Operation Deadlines in Interconnection Queue

MISO plans to revise its rules around commercial operation dates to allow interconnection customers to begin operating about a decade after they first enter the queue. 

MISO’s Brady Mann told stakeholders attending a Jan. 30 Interconnection Process Working Group that the RTO is considering working a few extra years into queue deadlines, recognizing that supply chain squeezes have impeded projects. 

That starts with MISO drafting rules specifying that interconnection customers must select a date up to five years on the horizon for their generation projects to reach commercial operation when entering the queue. After that, MISO said it will continue to employ a three-year extension of the original commercial operation date in generator interconnection agreements (GIAs). Additionally, the RTO will allow transmission owners the option to request an extra two-year extension of the in-service date during GIA negotiations. MISO’s current tariff language doesn’t allow transmission owners to request extensions to complete network upgrades for generation projects during negotiations. 

Finally, Mann said MISO will allow for 180 days between a generation project’s in-service date and the commercial operation date to account for delays transmission owners might encounter in constructing network upgrades.  

The new package of rules could be included in the MISO tariff and business practice manuals and could apply to projects that entered the queue beginning in 2020.  

Mann said MISO probably will rely on targeted FERC waivers of tariff provisions for the 2018 and 2019 cycle of queue projects that have been especially hard-hit by supply chain woes and stalled in coming online.   

MISO plans to make a tariff filing later this year after it weighs stakeholder opinions, which it solicited at the meeting. The RTO told stakeholders last year it would consider extending deadlines after EDP Renewables pointed out that generation developers increasingly are exceeding MISO’s allotted six-years-from-originally-planned commercial operation and having to turn to FERC for waivers. (See MISO Somewhat Open to COD Allowances in Interconnection Queue Rules.)  

Current MISO policy requires interconnection customers’ GIAs to contain a commercial operation date that’s within three years of the date originally requested in their queue applications. It also allows an up-to-three-year extension of the commercial operation date in initial GIAs after execution. When customers can’t meet either, MISO can terminate the GIA, causing generator developers to lose their place in line unless they can secure a waiver of their commercial operation dates from FERC.

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NYISO CEO Previews 2024 After ‘Successful’ 2023

NYISO CEO Rich Dewey on Jan. 31 spoke to the Management Committee about the ISO’s priorities for 2024 and its accomplishments in 2023. 

Dewey called 2023 “a very successful year” and praised NYISO’s staff and stakeholders, urging continued collaboration as the ISO continues working on the challenge of balancing fossil fuel retirements with the introduction of new renewable resources in New York. 

“As we look ahead at this grid in transition and the change that we’re seeing across the industry,” Dewey said, “the pace with which we need to navigate these changes is only increasing, which means that we’ve all had to adapt, be flexible and think creatively about how we adapt our market rules and our processes in the year ahead.” 

Dewey said improvements made last year to the ISO’s interconnection queue already have ed to a 200% increase in the pace of study completions compared to historical performance. NYISO’s continued work to comply with FERC Order 2023 will be a significant effort in 2024. He also said proposals already submitted to the commission would help remove many of the barriers existing in the interconnection process. (See FERC Approves NYISO Waiver on Interconnection Study Requirements.) 

A top priority this year is monitoring the integration of new projects with the grid and managing the phaseout of existing supplies, while simultaneously accommodating the growing demands of the electrification of housing and transportation. (See NYISO’s 10-Year Forecast: Challenges Ahead, but No Immediate Needs.) “Whether it’s offshore wind or other renewable resources, we’re still seeing supply chain issues, as well as interest rate issues,” he said. 

Dewey also discussed the public policy transmission need (PPTN) solicitations initiated by the state’s Public Service Commission to bring OSW from Long Island into New York City. Wind power would help fill predicted reliability shortfalls and achieve the state’s goal of generating 9,000 MW from OSW by 2035. (See New York PSC Seeks Rehearing of RTO Adder for Offshore Tx Project.)

He said NYISO is “well positioned” to launch the next OSW PPTN, which would be the largest it’s undertaken. He remains “optimistic” the effort will be “groundbreaking in terms of the ability to provide new transmission infrastructure that will maximize both the performance of OSW and help mitigate the costs of the buildouts necessary to interconnect them.” (See NYISO Previews New York City Transmission Needs Assessment.) 

Market development and talent acquisition also will be key priorities for 2024. Dewey said he will “continue to position NYISO’s markets at the top of the stack nationally in terms of efficiency and performance.” This can’t be done successfully, he said, without first attracting, retaining and leveraging the “creative, highly intelligent, dedicated and motivated individuals that remain the primary assets for [NYISO].” 

He noted that sector meetings will be held in the first weeks of March, and interested parties must register before Feb. 16. The two-day joint Board of Directors and MC meeting is set for June 10. Dewey also encouraged market participants to sign up for the strategic planning sessions in 2024, which will culminate in the annual board meeting in June. 

Fast-start Pricing in DAM

The MC voted to approve and recommend that NYISO’s board approve proposed tariff revisions that would provide all fast-start resources with their physical schedules for the day-ahead market (DAM). 

The revisions, approved by the Business Issues Committee earlier in January, stem from FERC orders requiring the ISO to modify how it reflects and prices fast-start resources in its energy markets to ensure they’re not scheduled below their minimum generation levels. (See NYISO Approves Update to Fast-start Pricing in Day-ahead Market.) 

NYISO had implemented the changes but realized it inadvertently extended DAM eligibility to some units that now are receiving ideal schedules below their minimum generation level, potentially causing operational inefficiencies or market imbalances. The approved revisions would provide these units with physical schedules, respecting their minimum generation constraints and preventing them from operating inefficiently. 

Following board approval, NYISO plans to submit the revisions to FERC in March. 

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Texas PUC Closes 1st Phase of Market Overhaul

Texas regulators last week celebrated the closure of the first phase of their blueprint for reliability reforms to the ERCOT grid, cautioning that it’s only a first step.

The Public Utility Commission closed two dockets during its Feb. 1 open meeting, 52373 and 53298. The former encompassed initial revisions to the market design, and the latter covered the development of a firm-fuel supply service.

“The ERCOT grid is more reliable than it’s ever been, and getting to this point has been a total team effort,” PUC Chair Thomas Gleeson said in a statement, thanking ERCOT staff, industry stakeholders and lawmakers. “This doesn’t mean we’re done improving the grid. We’re just closing the book on this first chapter.”

A result of legislation passed after the devastating 2021 winter storm, the first phase reforms included two expansions of the PUC’s weatherization rules, requirements for generators to secure backup fuel supplies’ new consumer protection measures and market changes that focused on price stability and reliability.

In a memo, commission staff said modifications to the operating reserve demand curve, emergency response service reforms, and development of fast frequency response service and ERCOT contingency reserve service have been completed.

They recommended new projects be opened for a firm-fuel product and voltage support compensation. Two other projects are in progress: demand response and setting higher performance standards for energy efficiency programs. The PUC already has received approval for three positions to manage the latter project.

Commissioner Jimmy Glotfelty said he supported the voltage-support docket.

“This is becoming more and more an issue as we have more inverter-based resources. This might be an issue that we need to address in the future, and it’d be good to get positions on it.”

Meanwhile, several Phase 2 projects already are running full bore.

The commission reacted positively to staff’s suggestion that the interim value of lost load (VoLL) that will be used in ERCOT’s reliability standard be set at $25,000/MWh and that any study using the metric as an input conduct sensitivity analysis, varying VoLL between $20,000/MWh and $70,000/MWh (55837).

VoLL was reduced to $5,000/MWh from $9,000/MWh and decoupled from the system-wide offer cap after high prices during the winter storm. According to the grid operator’s market monitor, the $9,000 cap resulted in $16 billion of incorrectly priced market transactions during the storm. Staff noted that Potomac Economics said in its 2022 state-of-the-market report that the $5,000 value “likely underestimates VoLL by a substantial amount.”

Staff carefully reiterated the interim VoLL value is for study purposes only and will not affect consumers’ cost of electricity. The Brattle Group is beginning a survey of ERCOT retail customers in March to determine their value of lost load. (See “VoLL Study to Begin,” Texas PUC Sends ESR Change back to ERCOT.)

Staff also presented a draft scoping document for a review of ancillary services, as required under the Public Utility Regulatory Act. The review’s report, a collaborative effort with ERCOT and Potomac Economics, is due to the PUC in September (55845).

Protocol Changes Approved

The commission also approved nine protocol changes approved by ERCOT’s Board of Directors, but not before probing one revision (NPRR1181) that requires qualified scheduling entities to notify the grid operator when inventories drop to critical levels (55445).

“These are things that ERCOT wants to know, but these are not critical for market operations,” Glotfelty said. “It’s the individual generator’s responsibility to know how much coal they have, how much energy they have. … I think this is kind of an overreach, quite frankly.”

Dan Woodfin, ERCOT’s vice president of system operations, agreed the NPRR isn’t needed for market operations. He reminded commissioners that as the region’s reliability coordinator, the grid operator needs situational awareness of future reliability risks.

“If we’ve got a plant that has coal, they’re running out of coal or maybe some rail issue or something, we shouldn’t be approving transmission outages that depend on one or more of those units at that plant being available,” he said. “That’s something where that information is critical to us to be able to make good decisions and avoid reliability problems.”

Gleeson Chairs 1st Meeting

The meeting marked Gleeson’s first as PUC chair. He was appointed to the position by Gov. Greg Abbott (R) last month. (See Abbott Names PUC Executive Director as Chair.)

“I’ve spent almost my entire professional career at this agency. I’ll be honest, when I started here 15 years ago, this was definitely not something I saw in my career plan,” he said.

Gleeson had been the PUC’s executive director since December 2020. He replaces Kathleen Jackson, who was named interim chair when Peter Lake resigned last June.

“We’re proud to have you up here with us,” Glotfelty said. “We’re excited to see you move from representing the entirety of the staff to representing the entirety of all of the people in the state, and we know you’ll do a great job each and every way.”

“It’s quite the transition to having about four people in my office to 240 people,” Gleeson said.

Following a brief executive session, the commissioners approved the appointment of Connie Corona, the PUC’s deputy executive director, as interim executive director. Corona first joined the commission in 1997, returning in 2017 after a 14-year stint in NRG Energy’s regulatory affairs group.

The commissioners also agreed to request the state legislative board set their salaries at $225,000 for the remainder of the 2024 fiscal year and at $230,000 for 2025. The request will include setting the executive director’s salary at $245,559 for the remainder of 2024 and $257,858 for the 2025 fiscal year.

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NM Utilities to Pursue More Analysis Before Day-ahead Decision

Two New Mexico utilities said they need to conduct more analysis before they make a choice between competing day-ahead markets in the West, despite the results from a key study on the financial impacts.

The comments from representatives of Public Service Company of New Mexico (PNM) and El Paso Electric (EPE) came during a Jan. 25 workshop hosted by the New Mexico Public Regulation Commission. 

The focus of the workshop was a cost-benefit study conducted for the Western Markets Exploratory Group (WMEG) by Energy+Environmental Economics (E3). 

E3 analyzed two different footprints across the West for participation in either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+. The study examined production costs under two different market participation footprints as compared to a business-as-usual scenario. 

EDAM and Markets+ are both expected to launch in 2026, and potential participants are scrambling to understand what choice would be best. 

Emmanuel Villalobos, director of market development and resource strategy at EPE, said the utility is planning “very involved, robust studies” as a follow-up to the WMEG analysis. 

The next step will be to layer onto the WMEG study real-world operational constraints and resource adequacy considerations, he said. That work, expected to take place this year, will be followed by a gap analysis. EPE expects to choose a day-ahead market in 2025. 

Kelsey Martinez, PNM’s director of regional markets and transmission strategy, said in a previous PRC workshop that the footprint of each day-ahead market would be a major deciding factor — a point she reiterated during the latest workshop. (See New Mexico Contemplates Organized Market Choice.) 

“The market footprint is a key factor in determining the realization of a lot of the benefits that come with day-ahead market participation,’ Martinez said. “So [are] the production and trade benefits, the resource diversity and increased reliability as well.” 

Martinez called the WMEG study “one tool in our toolbox.” She said PNM is gathering information on each market’s rules for third-party transmission usage and the rules’ impact on PNM benefits. 

Another issue, she said, is the likelihood that either market will evolve into an RTO, which PNM strongly supports. 

Martinez said PNM is following closely the West-Wide Governance Pathways Initiative for changes that might allow “wider adoption of the CAISO markets and evolution of those markets.” (See Western RTO Initiative Outlines Governance Options.) 

Footprint Analysis

The workshop was part of the PRC’s effort to develop guiding principles for utilities when deciding whether to join a day-ahead market or RTO. (See NM Commission to Set Standards for RTO, Day-ahead Participation.) More workshops on the topic are possible. 

During the workshop, Jack Moore of E3 gave an overview of the WMEG cost-benefit study. E3 presented the findings previously. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.) 

One of the two footprints evaluated was the EDAM Bookend, a single combined day-ahead and real-time market covering the entire Western Interconnection except for British Columbia and Alberta.  

Under the EDAM Bookend, the West as a whole would save $60 million a year compared with a business-as-usual case, although results varied among individual balancing area authorities.  

The second scenario is called a Main Split footprint, in which most of the West would participate in Markets+, but CAISO, PacifiCorp, Los Angeles Department of Water and Power, Balancing Authority of Northern California, Turlock Irrigation District and Imperial Irrigation District would join EDAM. 

In the Main Split, West-wide costs would rise by $221 million relative to business as usual. Results again varied by agency. 

‘EDAM Island’

PNM and EPE asked E3 to analyze an additional scenario similar to the main split footprint, but in which New Mexico goes with EDAM rather than Markets+. This would create a “New Mexico EDAM island,” with neighboring Arizona in Markets+. The scenario is just a “what if,” E3 said, and not an indication of which market the states will ultimately join. 

In the EDAM Island scenario, a New Mexico-California transaction might face wheeling charges between New Mexico and Arizona, and again from Arizona to California. The impacts potentially could be reduced if transmission arrangements or market-to-market coordination agreements were in place, E3 said, but such agreements weren’t included in the modeling.

E3’s analysis found PNM would see a $41 million cost increase in the EDAM Island scenario compared with business as usual, excluding wheeling revenue. PNM was modeled as being a “heavy exporter” of low-cost wind and solar resources. 

For EPE, costs would decrease by $23 million in the EDAM Island scenario, as the utility would be able to buy energy from the PNM zone at lower prices. 

WEIM Impacts

PNM and EPE both are participants in CAISO’s Western Energy Imbalance Market (WEIM), a regional real-time energy market. 

Martinez of PNM noted that selection of a day-ahead market would be “bundled” with participation in a real-time market. So if PNM decided to join Markets+, the utility would leave WEIM and instead enter SPP’s real-time market. 

From the time it was launched in 2014 through the end of 2023, WEIM participants achieved $5 billion in benefits, including $392 million in benefits in the fourth quarter of 2023 among its 22 participants, CAISO reported Jan. 31. 

Fourth-quarter benefits were $6.1 million for PNM and $4.0 million for EPE. 

During the workshop, Vijay Satyal, deputy director of regional markets for Western Resource Advocates, asked whether the analysis of the Main Split scenario considered the impact of PNM and EPE leaving WEIM if they joined Markets+. 

“Was that potential loss of benefits factored into the net total cost impact?” he said. 

Moore said the study accounted for those factors. 

Michael Barrio, a senior principal with Advanced Energy United, pointed to what the group considers to be limitations of the WMEG study. 

“The study focuses narrowly on operational costs, failing to account for broader benefits, like reliability, capacity savings and resource diversity, which could be much larger,” Barrio said during the workshop. 

Despite all the effort going into choosing a day-ahead market offering, Martinez of PNM noted that the barrier for leaving either market will not be high. 

“If there are major topological changes or generation changes or market footprint changes, that could very easily trigger another benefit analysis from us, and we could shift to a different market operator,” she said. 

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Washington Renewable Developer Rankled by Siting Board Alterations

The developer of a large and controversial wind and solar farm in southeastern Washington contends the state’s siting body has ordered unscientific changes that make the project unviable.

Scout Clean Energy, the Colorado-based developer of the proposed Horse Heaven Hills Energy Center, submitted a letter to the Washington Energy Facility Site Evaluation Council (EFSEC) on Jan. 19 that showed the company correctly anticipated how the state board would seek to alter the design of the project during a public meeting Jan. 31.

In the letter, Scout Clean Energy President Michael Rucker said the “ad hoc” changes proposed by EFSEC “are an arbitrary, drastic departure from established council precedent. Further, they are unsupported by scientific or any other evidence in the record and would render the project both technically and economically non-viable without substantial amendment to the application.”

During the Jan. 31 meeting, EFSEC issued a requirement that Scout create a two-mile buffer around each known ferruginous hawk nest within the project’s 112-square-mile site. In 2021, the Washington Fish and Wildlife Commission unanimously heightened the status of ferruginous hawks from “threatened” to “endangered.”

EFSEC also ordered that Scout not locate turbines in areas considered culturally significant to local tribes. The council agreed to the strictest environmental options presented to it by its staff.

Scout’s plans call for either 222 wind turbines up to 500 feet tall or 141, 657-foot turbines along a 24-mile east-west stretch of the Horse Heaven Hills just south of Kennewick. EFSEC’s Jan. 31 decision potentially would cut from the project up to 116 of the shorter turbines or 73 of the taller ones. The exact numbers are imprecise because the developer could shift the locations of some of the removed turbines.

Scout’s proposal also includes two 500-MW solar farms on the east and west sides of the 24-mile stretch. EFSEC ordered that the eastern solar farm be removed because of its proximity to sensitive tribal cultural sites.

EFSEC environmental planner Sean Greene said there are roughly 60 to 70 hawk nests and significant cultural sites within two miles of the turbines to be eliminated.

“It won’t eliminate all the impacts, but there will be a significant reduction in impacts,” EFSEC Chair Kathleen Drew said.

‘Guessing Game’

The project has drawn strong opposition from many Tri-Citians because the turbines would show up in a currently pristine view of the hills from the urban area and because of the proximity to the ferruginous hawk nests. EFSEC staff noted the altered plan would remove turbines from along the north slopes of the hills, eliminating many residents’ concern about their views.

If built, the wind project would be the second in Benton County. Richland-based Energy Northwest, which owns and operates the 1,216-MW Columbia Generating Station nuclear plant north of the area, operates 63 wind turbines several miles southeast of the northern face of the Horse Heaven Hills. Completed in 2007, that site covers about 8 square miles and produces almost 96 MW. It is not visible from the Tri-Cities and has sparked no controversies.

In its Jan. 19 letter, Scout said the changes would trim the nameplate capacity of the wind portion of its project from 1,150 MW to 236 MW.

The letter contested the buffer zones around the hawk nests, arguing most are remnants that no longer are used by the birds.

“The decline of ferruginous hawk in Washington has been primarily the result of foraging habitat loss due to agricultural conversion,” Rucker wrote. “This factor is apparent in the Horse Heaven Hills, where nearly all previously documented nests have less than 30% available foraging habitat within 2 miles. Even before the project was proposed, ferruginous hawks have been essentially eliminated from the Horse Heaven Hills through this landscape-level conversion of habitat and encroachment of residential uses.”

The letter argues that it has been nearly five years since active nests were recorded within two miles of the project.

“No active nests have been documented since then, despite ongoing annual surveys by qualified biologists,” Rucker wrote.

Regarding the buffers around cultural sites, Rucker said, “the implications of this decision for future energy facility siting in Washington State are dire. It suggests that the council could redesign the project and prohibit any portion of a project based on [tribal cultural sites] that are undisclosed to an applicant. … Energy siting in Washington would become a guessing game, one few developers will be willing to play given the substantial at-risk costs involved.”

Wildfire Concerns

Addressing another matter related to the project, EFSEC staff told council members Jan. 31 that airplanes dropping water or flame retardants on range fires must fly within 500 feet above the ground. Consequently, those planes cannot fly over range fires among the wind turbines. EFSEC directed Scout to come up with a plan for fighting fires on its property to compensate for firefighters not being able to use planes.

Southeastern Washington is mostly shrub-steppe and grasslands that are susceptible to fast-moving range fires. Rural fire departments routinely fight those fires with state help, including planes, on the larger fires.

During the meeting, EFSEC also granted Scout’s request that the agency delay its final decision on the project until April 30 to give the company time to regroup and consider its options. EFSEC’s role is to make recommendations to Gov. Jay Inslee, who will issue the final decision on the project.