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November 17, 2024

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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. 

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3rd ‘Issue Alert’ Compares Pricing Practices in Markets+, EDAM

Enhanced protections against uncompetitive market behavior are among several tools to ensure fair and accurate pricing under a Markets+ framework, according to an “issue alert” published Aug. 28 by 10 entities that back development of the market.

The alert is the third published in a series of seven notices intended to highlight Markets+’s purported advantages over CAISO’s Extended Day-Ahead Market (EDAM) and Western Energy Imbalance Market (WEIM). The first covered differences between how the two markets would be governed, while the second focused on reliability.

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Company of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.

In their third alert, the backers argued that Markets+’s “conduct-and-impact” framework ensures prices are fair and not distorted by the exercise of market power. The approach also is used in MISO, ISO-NE, NYISO and SPP’s RTO, according to the alert.

“Under this framework, a bid is mitigated if it materially exceeds an established reference level and that bid would have a material impact on market prices, absent mitigation,” the alert said. “This two-part assessment applies mitigation when needed to ensure market prices are not distorted by the exercise of market power, while providing market participants with flexibility to submit bids that reflect their own evaluation of their costs (including opportunity costs).”

Meanwhile, EDAM’s price controls are not as fine-tuned and kick in whenever there is a possibility of price manipulation without a thorough examination, according to the alert.

The Markets+ backers contend EDAM’s approach risks leading to “more frequent, and overly broad, mitigation to price levels that can be below a market participant’s actual costs.”

The parties also argue that Markets+ supports reliability and market efficiency by adopting a graduated scarcity pricing method. Scarcity pricing encourages resources to be available during tight energy conditions and helps “ensure prices reflect actual system conditions during periods of tight supply and that customers receive the benefit of the most optimal market clearing solution,” according to the alert.

EDAM, on the other hand, does not have a scarcity pricing method designed for its full market footprint, the parties said. Instead, EDAM relies on CAISO’s existing pricing method designed to handle shortfalls of ancillary services within the CAISO balancing authority area, the alert stated.

“The effectiveness of this approach is frequently undermined by extensive manual interventions that commonly occur in the CAISO BAA during scarcity conditions, including deploying out-of-market supply and emergency demand response,” the parties said. “This behavior puts inaccurate downward pressure on market prices, producing pricing results that are inconsistent with actual system conditions and limiting shorter-term and longer-term market participation incentives.”

The alert also highlighted that Markets+ uses a so-called fast-start pricing approach, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.

Of the six FERC-jurisdictional organized markets, only CAISO doesn’t use fast-start pricing, according to the alert. (See WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’.)

“Failing to include fast-start pricing negatively impacts Northwest and Southwest ratepayers, and impedes long-term efficiency by discouraging investment in new flexible resources and storage that could displace the use of gas peaking units in the future,” the parties said.

The parties similarly targeted EDAM’s approach to virtual bidding, noting it’s not automatically applied across the entire market but is an optional feature each BAA can adopt.

“This BAA-by-BAA approach introduces uncertainty for load-serving entities and other market participants on their ability to hedge real-time energy costs across the market footprint, potentially limiting the tools that can support market efficiency in EDAM,” the alert stated.

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Truckers Group Opposes Wash. Clean Trucks Timeline

Washington has adopted California’s Advanced Clean Trucks (ACT) program to govern the Evergreen State’s long-term transition to zero-emissions trucks, but a group representing truckers argues the timeline for doing so is faster than is practical for the industry.

Under ACT guidelines, 7% of medium- and heavy-duty trucks sold in Washington in 2025 must be zero-emission vehicles, increasing to 20% by 2028, 30% by 2030, 40% by 2032 and 55% by 2035. 

That schedule is too aggressive, according to the Washington Trucking Associations (WTA). 

“While ACT is meant to move industry toward zero emissions for medium and heavy-duty (M/HD) trucks, WTA members have concerns about vehicle costs, operational challenges and low to non-existent vehicle adoption,” wrote WTA President Sheri Call in an Aug. 15 letter to Gov. Jay Inslee (D).  

Washington does not have the regulatory infrastructure in place to discourage companies from using out-of-state outside trucks that do not comply with emissions-reduction standards, she wrote. 

“Artificially manipulating the market to mandate ZEV truck sales will have a profound impact on the industry and lead to unintended consequences,” Call wrote. “California officials wrote, adopted and implemented the ACT program for the state of California. But Washington is not California.”

California has been building support for decarbonization for decades, including funding incentive programs for clean commercial trucks. And its ramp-up of zero-emission sales is more gradual than the Washington schedule, she added. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.) 

“A zero- emission truck costs about two and half times more and sacrifices about two and half tons of payload compared to a clean diesel truck today. Electric M/HD trucks also compromise range, while only providing about 150-200 miles per charge,” Call said in the letter. “Fueling infrastructure is also expensive and can take up to two years for permitting and installation. There is also the ongoing uncertainty of electric grid capacity as examples of officials asking vehicle owners to avoid charging cars during hot summer days continue to become more commonplace.” 

Call also pointed to the 12% federal excise tax on new trucks and trailers — “a policy the industry has long thought to inhibit adoption of newer, cleaner diesel trucks.” 

The ACT’s timeline is too aggressive and does not accommodate innovation or current technological limits, she wrote.

“WTA respectfully asks you and the Legislature to reconsider the link to California’s emission standards and adopt the federal standards that are more suitable to Washington’s unique needs. Washington employers should not have to face policies created by another state, with no input from stakeholders or analysis for its impact here,” Call wrote. 

In an email to NetZero Insider, Mike Faulk, spokesperson for the governor’s office, said the state is studying the issue.  

“These regulations were thoughtfully crafted to make compliance feasible. There are a variety of compliance options, including giving credit from previous years sales to meet the first target in 2025 and credit-sharing across weight classes allowing for manufacturers to ramp up availability,” Faulk wrote.

“The state is committed to supporting the trucking industry in this transition,” Faulk continued, noting it has provided more than $130 million in funding from the Climate Commitment Act — the state’s cap-and-invest program — to help truck owners cover the costs of electric trucks and charging infrastructure. 

“We continue to work with California and Oregon to pursue federal funding to build an electric truck charging corridor along I-5. And we’ve secured over $60 million in state and federal funding to electrify drayage trucks operating in and around ports,” he wrote. 

California, Oregon and Washington recently secured $102 million in federal funding for the West Coast Truck Charging and Fueling Corridor project, a joint effort to install a network of chargers between the borders with Canada and Mexico. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.)