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August 11, 2024

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SPP Markets and Operations Policy Committee Briefs: July 10-11, 2023

Members Endorse Winter Resource Adequacy Requirement for 2024/25

OMAHA, Neb. — SPP stakeholders last week endorsed a tariff revision request that adds a winter resource adequacy requirement for load-responsible entities (LREs) bound by the grid operator’s recent planning reserve margin (PRM) increase.

However, the measure approved by the Markets and Operations Policy Committee during its July 10-11 meeting is likely to encounter headwinds from SPP’s state regulators and the Board of Directors when they hold their quarterly meetings next week.

The revision request (RR549) applies the same level of validation, study and assessment requirements to the winter season (December through March) that currently applies to the summer season, including a deficiency payment for capacity shortfalls. The measure also assigns an annual deficiency payment to prevent duplicate payments for the same capacity within an annual timeframe.

The tariff change met MOPC’s 66% averaged approval threshold at 67.2%, with 87.5% of transmission owners and 47% of transmission users voting for the revision. It is effective for the 2024/25 winter.

MOPC chair and ITC Holdings’ Alan Myers (middle) guides the discussion flanked by SPP’s Emily Pennel and Lanny Nickell. | © RTO Insider LLC

Director Steve Wright signaled to committee members that RR549 almost assuredly will meet resistance before the Regional State Committee and board next week. He said he was concerned about modified language that American Electric Power offered during the discussion and was accepted by the sponsoring stakeholder group as a friendly amendment. He said adding the PRM’s calculation to the tariff “exposes it to litigation at FERC.”

“That was a tough discussion with respect to whether to move forward now or try to perfect the resolution,” Wright said. “The discussion is there; the debate is there; the members came to a decision. Rather than adding a process requirement regarding the calculation of the PRM with a fairly vague standard and putting that into the tariff … I think that deserves a lot more discussion. For me, it takes us in a different direction. I hope there will be a continued discussion in the next two weeks.”

Richard Ross, AEP | © RTO Insider LLC

MOPC Chair Alan Myers, with ITC Holdings, said the Cost Allocation Working Group’s (CAWG) original version of the tariff change could be offered up to the RSC and board. Staff secretary Lanny Nickell said the time between the MOPC and RSC meetings will give staff and legal an opportunity to develop alternatives to the amended language.

AEP’s revisions require transmission providers to detail the methodology used in loss-of-load expectation studies and to determine the final PRM value based on their results. It said it was concerned the CAWG’s proposed language facilitates PRM changes without providing LREs adequate time to comply and that neither the tariff nor the planning criteria provide a transparent process for stakeholders to validate SPP’s determination or, on their own, forecast future PRM values.

“‘The final results of the LOLE study’ implies it is a simple formulaic result, when in fact it requires the application of judgment among many results,” AEP’s Richard Ross said.

The PRM was raised last summer and added to SPP’s planning criteria despite pushback from members. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

The summer requirement already is in place this year. According to SPP’s 2023 resource adequacy report, all LREs complied with the summer RAR. Sixty LREs met the new 15% PRM requirement passed last year, and one met the 9.89% PRM requirement because its capacity is at least 75% hydro-based generation.

SPP’s Market Monitoring Unit supports a winter RAR but recommended remanding RR549 back to the CAWG to address its concerns. The MMU said that, as written, the tariff doesn’t include language requiring a reasonable expectation of availability for resources used toward RAR; it doesn’t achieve the policy’s goal for the deficiency payment; and the deficiency calculation does not send the appropriate signal to improve available accredited capacity.

MMU Comments Bypassed in Order 881 Compliance

MOPC endorsed a tariff change that SPP legal staff believe complies with FERC Order 881, which directs transmission providers to use ambient-adjusted ratings (AARs) for short-term transmission requests — 10 days or less — for all lines that are affected by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.)

RR565 is a response to FERC’s deficiency letter in May. The commission ruled SPP was noncompliant and directed it to use AARs for any seams-based transmission service; explain its timelines for calculating or submitting AARs; and address systems and procedures so TOs can update their line ratings at least hourly (ER22-2339).

The MMU said the measure does not address some of FERC’s determinations and recommended its own edits. It proposed replacing three sentences approved by the Operating Reliability Working Group (ORWG) with six paragraphs that it said address line ratings’ and methodologies’ “transparency and accuracy.” It also recommended adding transparency indicating the market processes that will use the line ratings.

However, MOPC declined to consider the edits. It passed the ORWG’s recommended version with a 95.56 average.

ORWG Vice Chair Jeff Wells, with Grand River Dam Authority, agreed that the measure’s language doesn’t address all that was required by FERC. He said a procedure manual will outline the process for implementing AARs and “address the unknown.”

“We were trying to keep the tariff concise, to be concise with the wording and what’s required by the tariff,” Wells said, adding that “accommodations” were made to give TOs the flexibility they need to adhere to the requirements “without being burdensome beyond what was required.”

Addressing concerns over the validation process, Keith Collins, vice president of the MMU, said Order 881 requires market monitors to be included. He said SPP will ensure appropriate line ratings or replacements up front, with the MMU taking over after the fact to look at gaming opportunities or market inefficiencies.

MMU’s Keith Collins (right) explains the monitor’s position on Order 881 compliance as SPP’s Yasser Bahbaz listens. | © RTO Insider LLC

“FERC requires the market monitors to validate and have a role in the process. It’s not optional,” Collins said.

He said RR565 likely will be on the board’s consent agenda when it meets next week. MMU staff will evaluate whether to ask that it be pulled off and considered separately, Collins said. The Monitor also could intervene at FERC, which it has done in the past.

“That’s our general practice,” he told RTO Insider. “However, if we’re going to raise a concern with FERC, we would like to ensure that the board has had an opportunity to understand our concerns.”

The commission has granted the RTO an extension to Aug. 1 to make its second compliance filing.

GI Backlog Halfway Completed

SPP celebrated the halfway point of clearing its generator interconnection queue by issuing a press release highlighting its mitigation strategies as paving the way “for the construction of dozens of new resources.”

The RTO credited the backlog mitigation plan with executing GI agreements that will add more than 14.5 GW of new generation to the system over the next four years. SPP has added almost 28 GW of capacity to the system since 2017, when the backlog began.

FERC approved SPP’s backlog mitigation plan, designed to simplify and reduce study timelines, in January 2022. It has completed two cluster studies since, with the five remaining clusters on track to be finished next year. (See “GI Backlog Plan Approved,” FERC Denies Co-ops’ $79M Complaint vs. SPP.)

The queue still has 561 active requests for 112 GW of generation (108 GW of renewable resources) left, with about 220 of the requests submitted last year.

MOPC separately approved RR493, which consolidates language from several existing business practices and the Definitive Interconnection System Impact Studies (DISIS) manual into a standalone GI manual. It also adds GI special studies to the manual and a fuel-based dispatch option to the second study phase.

The measure revises the existing fuel-based dispatch methodology to dispatch non-legacy ITP generators without firm transmission service at the same percentage as non-ITP generators with higher queue priority.

Staff said they had some concerns about RR493’s additional responsibilities in resolving the queue’s backlog, but they supported the measure and would provide a more thorough impact assessment during MOPC’s January meeting.

“SPP staff can support this particular motion because it baselines the manual. … We’re going to have to go through an exercise to determine the overall impact,” said Casey Cathey, SPP’s director of grid asset utilization. “We have actually doubled the very next DISIS, so we’re kind of going into it with eyes wide open.”

SPP Self-reports to FERC

Nickell drew some smiles when he told the committee SPP had filed a self-report with FERC in March. The smirks turned into chuckles when he admitted he had forgotten to pass along the information during the committee’s April meeting.

“My mistake. I’m just now catching up,” he said.

Staff discovered this year that in 2020, they had incorrectly assigned Kansas City Board of Public Utilities (KCBPU) as a transmission-owning member in its electronic ballot tool, rather than as a transmission-using member. Staff reviewed the votes taken since then and discovered the error affected only one vote: approving the PRM’s increase to 15% during the October MOPC meeting. (See “Members Address Resource Adequacy,” SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)

MOPC votes require a two-thirds vote, equally weighted between TOs and TUs, for approval. The PRM measure passed with 66.29% approval, with KCBPU voting “yes” as a TO. Nickell said had the utility been assigned correctly as a TU, the PRM vote would have failed at 65.63%.

The board and state regulators approved the PRM’s increase last July. The October vote simply endorsed RR516 as implementing the increase.

“We think the outcome is inconsequential,” Nickell said. However, because staff changed the vote, SPP reported the change to FERC.

SPP General Counsel Paul Suskie said the industry makes similar self-reports “all the time.”

20-year Tx Assessment Endorsed

Stakeholders unanimously endorsed a 20-year assessment of long-range extra-high-voltage (EHV) transmission needs that says SPP will need between 900 and 1,200 miles of new EHV lines that could enable carbon dioxide reductions of up to 93%.

The study team evaluated 463 solutions during its 35-month analysis. It found the solutions could cost as much as $1.55 billion in engineering and construction costs across its reference case and emerging technologies cases, with a benefit-to-cost ratio of $1.57 billion to $4.35 billion. The assessment does not request notifications to construct, but it did recommend 13 new transmission projects to resolve congestion and other constraints.

The study was due before the end of last year. The next 20-year assessment is targeted for 2027.

“For us to really realize the [20-year assessment’s] value, we’ve got to do these much faster,” said David Kelley, vice president of engineering. “This becomes much more valuable information because, as we all know, our industry is changing much faster than any of us thought was ever possible just a few years ago.”

After receiving feedback from members about media reports that focused on the assessment’s costs, SPP staff clarified that the 20-year study is intended to develop a long-range EHV (considered 300 kV or more) transmission road map for the SPP region. It also identifies projects that economically deliver energy and addresses future industry uncertainty; the identified projects will provide candidates that inform shorter-term planning assessments.

Winter Models to Reflect Uri

The Transmission Working Group updated MOPC on its discussions with the Economic Studies Working Group over the 2024 ITP’s winter weather assessment.

A strike team decided that regional winter models should be more reflective of the February 2021 winter storm (also known as Uri), which had a large impact on the natural gas supply and limited renewables’ production.

Stakeholders have chosen accuracy over precision in using historical data to model the effects on the footprint’s different subregions, similar to a load-forecast approach.

Several other stakeholder groups also briefed the committee:

    • The Project Cost Working Group has created an in-service date delay report that will be added to the quarterly project tracking report and list network upgrades with estimated in-service dates at least one year past. Staff will review the new report with the working group each quarter and provide updates to MOPC and other stakeholder groups as needed. The increased awareness already has resulted in 18 completed and previously delayed upgrades at a cost of $146 million, said group Chair Brian Johnson, with AEP.
    • The Strategic and Creative Re-engineering of Integrated Planning Team’s Consolidated Planning Process Task Force is drafting a white paper to “button up” the first phase of its proposed consolidated planning process following “a lot of healthy discussion,” SPP’s Sunny Raheem said. The stakeholder group still must determine an entry fee rate-structure design for cost-sharing and recovery and transition plan recommendations, and continue developing phase 1 policy recommendations.

Zonal Criteria Voting Changed

Members unanimously approved its consent agenda, but not before National Grid Renewables Energy Marketing pulled RR557 for separate consideration. The measure, which passed with opposing votes from National Grid and two other transmission users, updates the zonal planning criteria voting process so absent and abstention votes no longer are counted as “no” votes and are not included in the final tally.

National Grid’s Margaret Kristian said the smaller denominator creates a low bar for approval with abstentions or absent votes. “We think that the recording of approval should really be in the affirmative on the new policy, and that the kind of default action should not necessarily be to approve without the majority,” she said.

The consent agenda included scope updates to the 2024 ITP that document a new vendor for the long-term natural gas pricing outlook and defining extreme winter weather model scenarios needs; endorsement of a sponsored upgrade study for 161-kV work in Omaha; and nine additional RRs that would:

    • RR521: clarify that market participants registering auxiliary load must ensure that it is consistent with any legal or regulatory requirements applicable to the auxiliary load or the entity serving the load.
    • RR542: define aggregator of retail customers (ARC) and differentiate between certification and attestation requirements for ARCs and other aggregators registering under FERC Order 719.
    • RR543: require market participants registering demand response resources (DRRs) to verify that critical load is not being registered as a DRR and that the registered capacity does not exceed the load’s hourly maximum within the previous year; and clarify the dispute process between the market participant, retail provider and relevant retail regulatory authority for DRRs.
    • RR547: eliminate the need for the MMU to pass an annual revision request updating the variable operations and maintenance escalation index that can be computed from publicly available Bureau of Labor Statistics data.
    • RR548: eliminate the rarely used screening study processes for long-term service requests (LTSR) and delivery point transfers (DPT) and incorporate the DPT into the consolidated planning process.
    • RR552: do away with the ITP manual’s requirement removing the firm service requirement for resource inclusion in the base reliability power-flow models.
    • RR553: ensure all uncertainty product revision requests (RR449, RR496, RR535) are implemented correctly.
    • RR561: clarify the overall multiday reliability assessment (MDRA) process and how the day-ahead market will consume its commitments, how they are compensated through settlements and which resource offer costs are used for recovery.
    • RR569: correct the settlements protocols to ensure multiday minimum run time and settlement calculation cleanup are implemented accurately.
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DC Circuit Sends SEEM Back to FERC

The D.C. Circuit Court of Appeals on Friday remanded FERC’s approval of the Southeast Energy Exchange Market (SEEM) back to the commission for additional proceedings.

The three-judge panel agreed that FERC was wrong to deny initial requests for rehearing of the approval because of the dates on which they were filed, but Judge Neomi Rao split with her two colleagues in a partial dissent and agreed with the commission’s reasoning on two of the specific rules that came before the court.

SEEM members include Associated Electric Cooperative, Duke Energy, Southern Co., Tennessee Valley Authority and others in the Southeast. The market has an algorithm to match excess supply with free transmission every 15 minutes, enabling more frequent transactions among its members. It ran into opposition from parties who argued it was anti-competitive compared to the Western Energy Imbalance Market, let alone a full ISO/RTO.

FERC was unable to agree on whether to approve the SEEM proposal, splitting 2-2, which allowed the SEEM tariff to go into effect automatically. Now it returns to another iteration of the commission with four votes, though with acting Chair Willie Phillips instead of former Chair Richard Glick. (See SEEM to Move Ahead, Minus FERC Approval.)

The case presented a test of a recent change to the Federal Power Act that made such split decisions reviewable by the courts. One issue was whether parties had submitted their required rehearing requests to the commission on time. FERC argued that it had to rule on the case by Oct. 10, 2021, which started the 30-day countdown for rehearing that would end Nov. 9.

However, Oct. 10, 2021, was a Sunday, and it was followed by Columbus Day on Oct. 11, when FERC was shut down. Thirty days after was Veterans Day, which meant FERC was closed again. Advanced Energy United and other parties sought rehearing in filings submitted Nov. 12.

The court ruled in 1989 that deadline dates exclude Saturdays, Sundays and federal holidays, which made Nov. 12 the due date for rehearing requests.

“Accordingly, the commission erred in finding the petition for rehearing of the deadlock order untimely below, and the related orders finding as such are therefore vacated,” the court said.

FERC will have to deal with the rehearing requests’ merits on remand, the court said.

While FERC was split on the order approving SEEM, it was able to vote out a related order on the market’s nonfirm energy exchange transmission service (NFEETS); it also rejected requests for rehearing of that order. The court was able to weigh the merits of those requests. (See FERC Again Rejects Efforts to Overturn SEEM.)

SEEM requires that entities transacting in it have a source and sink inside its footprint, which goes against FERC’s pro forma open-access transmission tariff from Order 888. The old bilateral market was different from the pro forma tariff as well, but the new SEEM rules excluded 65 existing bilateral trading partners that cannot participate in the new market.

SEEM’s backers argued that the geographic limits were needed to implement the 15-minute trades, but the court noted that they could have designed the system differently to more efficiently handle such requests.

“The creation of a new service that — by its design — excludes existing market participants evokes the discriminatory practices against third-party competitors by monopoly utilities that prompted the commission’s adoption of Order No. 888,” the majority said.

It ruled that FERC failed to offer a good enough explanation on how the rules are better than the pro forma tariff and that it will have to explain that better, or explore rule changes, on remand.

Opponents argued that under Order 888, NFEETS made SEEM a loose power pool, which is required to be open to nonmembers. Order 888 qualifies loose power pools as arrangements between more than two utilities where they offer discounted power, specifically mentioning “non-pancaked” rates as a discount.

SEEM charges only one transmission rate for power to cross all of its members’ systems, so the majority found that FERC failed to adequately explain why it was not a loose power pool.

Rao dissented on the NFEETS issue, finding that SEEM’s backers had compelling technical reasons to limit participation to entities within its footprint and that FERC correctly determined it was not a loose power pool.

“NFEETS does not limit access to any currently existing service,” Rao wrote. “Rather, it provides an entirely new service that facilitates valuable short-term energy transactions, resulting in substantial cost savings across the Southeast. The tariff revisions are thus strictly preferable to the existing tariffs.”

She also agreed with FERC that SEEM did not qualify as a loose power pool because it creates the opportunity for new transactions; it does not “in any sense result in a discounted or special rate from existing arrangements.”

“SEEM provides a valuable service by establishing a new market for utilities in the Southeast to engage in short-term energy transactions,” Rao said. “FERC reasonably approved the no-cost transmission service necessary to implement SEEM.”

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Regulators Propose New Independent Western RTO

PORTLAND, Ore. — The competition for organized markets in the West grew Friday as the Bonneville Power Administration launched a process to choose between day-ahead markets proposed by CAISO and SPP and regulators from five Western states urged the establishment of a new, independent RTO covering the entire West.

“This group proposes the creation of an entity that could serve as a means for delivering a market that includes all states in the Western Interconnection, including California, with independent governance,” regulators from Arizona, California, New Mexico, Oregon and Washington wrote to the chairs of the Western Interstate Energy Board (WIEB) and the Committee on Regional Electric Power Cooperation (CREPC).

The entity “could provide a full range of regional transmission operator services, utilizing a contract for services” with CAISO including eventual “assumption” of CAISO’s proposed Extended Day Ahead Market (EDAM) and its real-time Western Energy Imbalance Market (WEIM).

The letter cited studies that have shown the greatest economic and environmental benefits for the West would come from a single Western RTO. A state-led market study in 2021 found that development of an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion a year in energy costs by 2030.

“We have identified a common commitment in seeking the benefits shown in multiple studies that demonstrate the most favorable electricity market for consumers is one that includes a West-wide market footprint,” the letter said. “Such a market would avoid the issue of ‘seams’ from separate markets across major portions in the West and result in optimized use of resources to meet loads across the entire interconnection.”

“In announcing our commitment, the group is inviting all Western states and associated stakeholders to join the effort and help shape the approach,” it said.

The planning process will begin this year, and implementation will start in early 2024 “with the formation of the independent entity, the seating of an initial founding board of directors, exploration of the relationship with CAISO for future services and the expectation of a small independent staff being put in place,” the letter said.

‘A Breakthrough’

The prospect of a single West-wide RTO has been growing less likely as CAISO and SPP compete for market share for their proposed day-ahead offerings, and SPP is making inroads on the development of a Western version of its Eastern RTO called RTO West. (See Western Day-Ahead Markets Debated at CREPC-WIRAB.)

At the same time, the latest legislative effort to allow CAISO to become a Western RTO appears to have stalled. Assembly Bill 538 was held by its author in committee in May because of staunch opposition from powerful labor unions in California.

The bill would let CAISO create a governing body free from oversight by California politicians. Currently, the state governor appoints members to the ISO’s Board of Governors, and the state Senate approves them. (See CAISO Regionalization Bill Put on Hold.)

In the past, lawmakers have refused to relinquish control of CAISO, and other Western states have said they will not join an RTO dominated by Californians.

The regulators’ proposal could offer a way out of the stalemate and an alternative to Western entities thinking of joining SPP’s RTO West. “The letter represents a breakthrough in efforts to advance the regions’ energy landscape and is key to creating a market that fosters collaboration, improved reliability and economic growth,” Advanced Energy United, a national clean-energy trade group, said in a statement. AEU is part of a coalition of business and environmental groups called “Lights on California” that advocates for creation of a Western RTO.

The Environmental Defense Fund also is a coalition member.

“The positive thing to me is that this is the loudest signal to date that the West is organizing, and that is extraordinarily exciting and encouraging,” said Michael Colvin, who leads EDF’s work on California energy policy. “It’s an alternative to the SPP front. Whether it goes this way or the CAISO way, it recognizes that the most affordable and reliable way to achieve our energy goals and to decarbonize is through collaboration.

“It is a signal to all the folks that are thinking of jumping ship to SPP that the West is here for you.

In a statement to RTO Insider, CAISO CEO Elliot Mainzer said, “We are pleased that utility regulators from around the West have come together to discuss how they can work more closely together to enhance reliability and benefit ratepayers throughout the region. … CAISO stands ready to support their efforts and work with a broad range of stakeholders to develop a long-term approach that meets the needs of California and the entire Western U.S.”

SPP Vice President of Markets Antoine Lucas struck at diplomatic note in his comments on the development, saying the RTO understands that Western regulators want to “explore every available option” in their efforts to ensure that regionalization occurs with the interests of ratepayers in mind.

“SPP is confident in its ability to provide an independently governed market designed such that it will help states ensure electric reliability, reach their renewable goals, and enable equitable trade across the Western Interconnection,” Lucas said. “We stand ready to prove the integrity and value of our proposed Markets+ service and to meet the needs of Western stakeholders.” 

BPA: Markets+ vs. EDAM

The commissioners’ letter came just hours after BPA kicked off a public process at its Portland headquarters to determine whether it will participate in a day-ahead market and, if so, which option to choose: SPP’s or CAISO’s.

BPA operates about 70% of the transmission in the Northwest and is the region’s largest electricity supplier.

Friday’s workshop was to be the first of five such meetings to be held every other month through the beginning of next year, with each followed by a public comment period. BPA plans to propose a “record of decision” on the issue shortly after SPP files its Markets+ tariff with FERC in February 2024. It expects to conclude with a final workshop to discuss its decision and address the last round of feedback.

“This is an open-ended process; BPA has not decided to join a day-ahead market,” Russ Mantifel, BPA’s director of market initiatives, told workshop participants Friday.

But multiple sources involved in Western regionalization efforts, who asked not to be quoted because they’re not authorized to speak for their organizations, told RTO Insider that BPA is leaning toward Markets+. They cite a number of factors that put BPA in the SPP camp, including more favorable treatment for hydroelectric generation in Markets+, a CAISO bias in favor of California load that restricts wheel-throughs in the ISO during critical periods and the unresolved issues around the lack of independent governance for CAISO.

Governance is an especially intractable issue for BPA, which, as a federal power marketing agency, cannot cede its authority to a state-run organization, prohibiting it from participating in a CAISO-run RTO that is not overseen by an independent board.

And while membership in a full RTO is not on the table, Mantifel pointed to the importance of joining a day-ahead market that eventually can integrate more functions — such as resource adequacy — as conditions evolve in the West.

“One of the things we think about [regarding] governance, market design, etc., is which options create the opportunity to create more verticality, potentially going to an RTO or adding these functions as part of it, and which ones have had that sort of limitation,” Mantifel said.

Alex Swerzbin, director of transmission and markets for PNGC Power, a Portland-based generation and transmission cooperative owned by 16 utilities in seven Western states, agreed on the need for “verticality.” He encouraged BPA to consider the “end state” of its decision, which is future participation in an RTO. Swerzbin said the WEIM can be viewed as “sunk cost to a degree” because real-time trading still constitutes a small percentage of the market.

“Once we move to a day-ahead market, that is a much larger footprint. It is much harder to transition from one day-ahead market to a separate [market] to get to an RTO/ISO,” Swerzbin said.

But Fred Heutte, a senior policy analyst with the Northwest Energy Coalition, urged BPA to put aside an “A-to-B” comparison between EDAM and Markets+ in favor of considering the “big-picture question” of whether to have one or two markets in the West.

“The issue is going to be delivered value,” Heutte said. “If we have two markets, the likelihood, at least initially, from what we can see, is to have a significant reduction in delivered value in terms of cost, in terms of reliability and in terms of longer-term issues” such as transmission planning and resource adequacy, “no matter how good each of the market offers may be.”

Heutte said “the really big picture” is the impact of two markets on the diversity inherent in the Western Interconnection.

“If you look forward with the changing resource mix, with changes in extreme weather conditions, the changes in demand profile, as we see more large loads and more decarbonization load coming on the system, the resource and the load diversity of the West is a really critical factor,” he said.

“The more diversity, the fewer seams you have, the more effective [a market is] going to be — I can’t disagree with that,” Mantifel said. “I think … the other reality is what it takes to get there, and sort of the sacrifices and compromises people are willing to make in order to achieve that, and whether that’s ultimately viable.”

BPA has scheduled its next day-ahead market workshop for Sept. 11-12.

BPA expects to conclude its process for deciding on a day-ahead market early next year. | Bonneville Power Administration

CAISO is expected to file tariff language with FERC on EDAM next month. It has been promoting the day-ahead market among potential participants as it faces stiff competition from SPP.

On Thursday, CAISO said it would co-host a market forum on EDAM with NV Energy, PacifiCorp and others in Las Vegas on Aug. 30.

“The forum, which aims to foster a dialogue on the evolution of the EDAM in the West, will bring together leadership from regional utilities to discuss and share their thoughts on the factors and processes in considering their participation, as well as utility regulators from across the West, who will share their perspective on the next step in market evolution and how they are actively engaging in its development,” CAISO said.

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OMS-MISO RA Survey Signals Potential for 9-GW Shortfall by 2028

MISO and the Organization of MISO States’ 10th annual resource adequacy survey warned that a more than 9-GW shortfall could loom by the decade’s end, though it painted an adequate supply picture for the coming year.

MISO and OMS found the footprint will have 1.5 GW of residual capacity beyond the summer planning reserve margin requirement in the 2024/25 planning year.

However, survey results in the four subsequent years are light on reassuring news.

The organizations said that without swift action, a 2.1-GW total shortage is possible the summer of the 2025/26 planning year, a 3.4-GW deficit by the 2026/27 planning year, a 4.8-GW gap in the 2027/28 planning year and a 9.5-GW shortfall by the 2028/29 planning year.

According to the survey, MISO Midwest’s potential capacity deficits start in the summer of the 2025/26 planning year, while MISO South shows a potential deficit brewing by winter 2027/28. MISO and OMS said so far, the seasons outside of summer show sufficient — yet declining — capacity.

MISO said about 90% of its generating fleet responded to this year’s survey.

This year, the survey was divided by season to reflect MISO’s new seasonal format and projected capacity values across four seasons for the next four years. Results were delayed by more than a month because of MISO’s monthlong auction delay on a FERC show-cause order.

MISO and OMS are betting that demand grows at a clip of 0.8 GW or 0.68% per year on average and the planning reserve margin requirements climb from 7.9% in the 2024/25 timeframe to 9.2% in 2028/29. MISO used its loss-of-load modeling to predict margin requirements.

The two also said the survey showed potential capacity additions of as much as 6.9 GW in the 2025/26 planning year, 13 GW in 2026/27, 17.1 GW in 2027/28 and 20.7 GW in 2028/29, which could offset the potential shortages. Historically, MISO grants grid access to about 2.5 GW per year on its system. As of last month, MISO’s generator interconnection contained 1,412 active projects totaling almost 241 GW.

“These results continue to illustrate the reliability risk we face and reinforce the need for dispatchable, long-duration resources to be maintained and brought online to manage the transition to weather-dependent, low-carbon resources,” MISO CEO John Bear said in a press release.

This survey’s potential deficits are marginally better than those from last year’s OMS-MISO survey, which projected the footprint could experience as much as a 2.6-GW capacity deficit below the 2023 planning reserve margin requirement. The 2022 survey showed possible capacity deficits thereafter of 4.4 GW in the 2024/25 planning year, 6.5 GW in 2025/26, 7.4 GW in 2026/27 and nearly 11 GW by 2027/28. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)

While last year’s results were affected by MISO’s 1.2-GW capacity deficit across all Midwestern local resource zones, this year’s survey results were influenced by the fact that all zones were resource-adequate starting June 1 and through May 30, 2024, according to the spring capacity auction. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

“With so many moving pieces involved with the changing electricity mix, regional assessments such as this one are becoming increasingly important to fully understand how the region will maintain reliable and affordable electricity delivery to customers,” Organization of MISO States President and Michigan Public Service Commission Chair Dan Scripps said in the release. “The increased transparency that comes with the seasonal granularity of this survey will undoubtably prove useful to state commissions, utilities and other market participants as they look to firm up their future resource plans to provide reliable and affordable electricity.”

MISO said this year’s survey reflected actions market participants took since becoming aware of the capacity deficit in the 2022/23 planning year, which included delaying unit retirements and making additional capacity available to the footprint. However, the grid operator warned that “these actions may not be repeatable in the future. It said the survey once again “highlights the need for additional resources and other solutions — such as market changes — to avoid potential capacity deficits in the future.”

During a Friday stakeholder teleconference to discuss results, Scripps stressed that the survey isn’t a carved-in-stone future, but an “aggregation of all the information that is available to us today.” He said it was “undeniable” that market participants’ reactions to last year’s shortfall moved capacity projections from in the red to black for the coming year.

“That said, this is a one-year response,” Scripps said, adding that the temporary remedies are not a substitute for long-term solutions for increasingly scarce capacity.

On the same call, Senior Resource Adequacy Engineer Nick Przybilla said MISO’s supply picture could improve if MISO makes headway on ushering projects through its interconnection queue faster, if supply chain snarls improve and if future planning reserve margins turn up lower than expected.

MISO also cautioned that “resource accreditation will continue to evolve based on performance during high-risk periods.” MISO is resolved to adopt a new marginal capacity accreditation style that values availability during forecasted hazardous periods and stands to lower many resources’ capacity values. (See MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours.)

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Do Batteries or Transmission Produce Greater Benefits?

Adding battery storage to wind and solar resources increased generator revenues more than expanding transmission, especially in CAISO and ERCOT, but transmission expansion could relieve congestion in rural areas with plentiful wind and solar capacity, a recent study by the Lawrence Berkeley National Laboratory found.

The first-of-its-kind study assessed the benefits and drawbacks of transmission expansion and adding batteries to renewables in areas with transmission congestion. It looked at the findings from the perspectives of grid operators and generation owners.

“Both storage and transmission can increase grid flexibility, which is critical to the task of balancing system demand with uncertain variable renewable energy supply in real time, though they engage in different types of arbitrage,” the authors wrote.

“Storage shifts energy over time,” they noted. Optimally, batteries charge when electricity is cheap and discharge when prices rise. “Transmission shifts energy from one place to another,” moving lower-cost electricity to where it is needed to meet demand.

“Congestion occurs when transmission limits are reached and prevents low-cost resources from being fully utilized,” the study said. “Even [renewable energy resources], which have extremely low marginal costs of generation, curtail their output due to negative prices in some locations.”

Renewable resources and storage each affect transmission value, and “transmission capacity affects the commercial viability of generation and storage projects,” the study said. “So, understanding the dynamics of interplay between these asset types is essential to effectively plan for the changing grid.”

That is especially important because renewable generation and storage “are increasingly being built at the same locations in hybrid configurations,” it said.

For example, in CAISO, 99% of solar capacity entering the interconnection queue in 2021 was coupled with storage, it noted.

“These changes raise critical questions such as, ‘Will the shift towards hybrid plant deployment reduce congestion on the nearby transmission grid or will the shift necessitate additional actions to alleviate congestion?’” it said.

‘VRE-rich’ Areas

The study analyzed data from 23 locations on the U.S. bulk power system that experience significant congestion and have standalone solar and wind plants. The locations were in CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM and SPP.

The findings from a grid operator’s perspective include:

    • Standalone wind and solar generators typically alleviate congestion near urban load centers and exacerbate congestion in rural areas with a high number of variable renewable energy (VRE) generators, which the study calls “VRE-rich” areas.
    • Standalone storage plants reduce transmission congestion in all areas.
    • Hybrid resources with renewable generation and storage alleviate congestion near load centers, but in VRE-rich areas, they can have different effects depending on their exact location and factors, such as whether batteries can charge from the grid.

For generation owners, the study found that:

    • Transmission expansion is generally a financial detriment to standalone wind and solar plants in load centers and a benefit to those in VRE-rich areas.
    • For hybrid resources in VRE-rich areas, expanding transmission typically increases revenue, but there are exceptions.
    • In VRE-rich areas, wind plants stand to gain “significantly more from transmission expansion,” while solar plants would benefit more from adding batteries.

“Solar plants in VRE-rich areas [could] expect to benefit from transmission expansion, but this benefit is dwarfed by the potential opportunity from installing storage, especially in CAISO and ERCOT, suggesting solar developers would be more invested in policies promoting hybridization than those focused on transmission,” the study said.

The solar plants in the study with the greatest per-MW revenue increase were in ERCOT ($200,000 to $380,000/MW-year) and CAISO ($50,000 to $91,000/MW-year) — both markets with a large share of solar generation.

The study’s authors said the results highlight the “different stakes that solar and wind developers have in local transmission expansion and how their priorities depend on a plant’s location and configuration.”

The results also “reveal previously unexplored ways in which policy, technology and contract terms related to hybrids can reduce the cost of congestion in local transmission systems,” the study said. “For example, policies incentivizing batteries at congested generation nodes may reduce congestion, since building storage alongside new VRE generators (either in hybrid or standalone configurations) is better, from a congestion perspective, than the standalone generator.

“Further, policies that allow hybrids to charge their storage component from the grid, instead of only from the VRE generator, result in lower costs due to congestion.”

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ERCOT Sets New Demand Mark, Will be Short-lived

ERCOT appears to have set another peak demand record on Monday, but if the grid operator’s projections hold out, the mark will be short-lived.

Demand averaged 81.56 GW on Monday during the interval ending at 5 p.m., according to preliminary data. That would break ERCOT’s current unofficial high for demand, when it averaged 81.41 GW July 13.

The grid operator’s six-day forecast indicates it will exceed 86 GW Tuesday, with average demand exceeding 83 GW through Friday. A high-pressure ridge and expanding heat dome have returned to the region and the southern U.S., diverting the jet stream away. Temperatures were forecast to be 5 to 15 degrees Fahrenheit above normal in much of Texas as excessive-heat advisories affect more than 100 million people from Washington state to Florida.

ERCOT says it expects to have sufficient generation to meet forecasted demand. It hasn’t called for voluntary conservation since June 20 and had more than 6.6 GW of operating reserves Monday afternoon. It did issue its third weather watch of the summer for Sunday through Tuesday due to the forecasted temperatures, electrical demand and potential for lower reserves.

The grid operator has averaged more than 80 GW demand for 18 intervals this summer. It reached the mark just once last year, setting a record that has been eclipsed 14 times already.

The clear skies again have led to near-record solar and renewable generation. Sun-powered resources averaged more than 12 GW for much of the afternoon; together with wind resources, they provided more than a third of ERCOT’s fuel mix for much of the day.

The U.S. Energy Information Administration says ERCOT’s solar and wind capacity will double by 2035, but it noted that without upgrades to the transmission system, its analysis finds wind and solar generation increasingly will be curtailed.

ERCOT had almost 10 GW of thermal outages on July 12. Staff use 8.3 GW as a high number in their modeling scenarios.

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MISO Monitor Again Sounds Alarm on Long-range Tx Planning

CARMEL, Ind. — MISO Independent Market Monitor David Patton appeared at this week’s Market Subcommittee meeting to again criticize the future resource mix assumptions the RTO is using to craft a second long-range transmission plan (LRTP) for its Midwest region.

Stakeholder reactions to his advice were mixed.

Patton has voiced concerns in this year’s State of the Market report over the capacity expansion model MISO is using to inform the portfolio, which could run the region several billion dollars. He said MISO isn’t considering enough future battery storage, hybrid resources, other dispatchable resource additions and grid-enhancing technologies as alternatives to an expensive transmission buildout. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

At the MSC’s meeting Thursday, Patton said battery storage is going to become “remarkably economic over time to reduce congestion caused by renewables.” He said MISO’s second transmission planning future’s projection that it will have 466 GW of mostly renewable nameplate capacity by 2042 is unrealistic. (See MISO Modeling Line Options for 2nd LRTP Portfolio.) MISO is anticipating having 31 GW of battery storage and 10 GW of storage-plus-renewable hybrid resources in that timeframe.

“Future 2 has almost no chance of happening, and yet we’re using it to plan tranche 2” of the LRTP, Patton said.

This is the first time Patton has raised concerns related to transmission planning in his report. MISO’s Board of Directors has wondered whether it’s appropriate for the Monitor to recommend a change in direction on transmission planning. Patton has argued that markets and transmission planning are inextricably linked.

American Transmission Co.’s Bob McKee and ITC Holdings’ Brian Drumm said Future 2 represents years of stakeholder debate and collaboration.

McKee asked whether Patton attended the stakeholder meetings to hash out the future planning assumptions. Patton said he “unfortunately” did not and wish he had.

“I’m all for consensus, but you can’t confuse consensus with fact. You can’t ignore that solar will have declining capacity value, and you can’t just imagine you’re going to keep building it and building it,” Patton said.

Michelle Bloodworth, of coal lobby group America’s Power, said she shared Patton’s concerns and that the second future should contemplate a realistic future resource mix.

Invenergy’s Sophia Dossin asked whether Patton has suggestions on how MISO can incent construction on batteries and hybrid resources.

Patton said the simple economics of MISO’s more attractive capacity accreditation for batteries, hybrid resources and natural gas plants will spur developers to build. He added that he isn’t expecting future bans on building new gas plants in every state in the footprint.

MISO will make a formal response to the recommendations in this year’s State of the Market report in December.

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Nevada Exits US Climate Alliance

Gov. Joe Lombardo has removed Nevada from the U.S. Climate Alliance, saying the group’s objectives conflict with his goal of developing a diverse energy portfolio for the state that includes natural gas.

The decision came to light as Arizona Gov. Katie Hobbs announced this week that the Grand Canyon State had joined the Alliance. Lombardo made no official announcement of Nevada’s exit from the Alliance, but Nevada’s absence from the group’s membership roster was noticed following Hobbs’ announcement.

“While the goals of the U.S. Climate Alliance are ambitious and well-intentioned, these goals conflict with Nevada’s energy policy objectives,” Lombardo said in a July 5 letter to U.S. Climate Alliance Executive Director Casey Katims, stating his decision to leave the coalition.

“These objectives are focused on developing and maintaining a diverse energy supply portfolio and utilizing a balanced approach to electric and natural gas energy supply and transportation fuels that emphasizes affordability and reliability for consumers,” Lombardo wrote.

Lombardo laid out his energy policies in a March executive order, including the state’s “advancement of energy independence.” (See New Governor Seeks Shift in Nevada Energy Policy.)

Nevada’s previous governor, Steve Sisolak, brought the state into the Alliance in 2019. Sisolak, a Democrat, was defeated in his reelection bid last year by Lombardo, a Republican.

Lombardo’s office didn’t respond to a request for comment.

Falling Short of GHG Targets

Formed in 2017, the U.S. Climate Alliance is now a bipartisan coalition with 25 members. Alliance members have agreed to work toward the Paris Agreement goal of keeping global temperature rise at less than 1.5 degrees Celsius. They collectively set a target to reduce greenhouse gas emissions by at least 26% by 2025 and 50% by 2030, compared with 2005 levels, and reaching net zero in 2050.

The GHG reduction goals are similar to those included in Nevada’s greenhouse gas inventory, an annual report required by state Senate Bill 254 of 2019.

The most recent GHG report, released this year, shows Nevada slipping further from those targets. The report details the state’s GHG emissions through 2020, with projections through 2042.

Nevada’s targets used as a benchmark in the report are a 28% reduction in GHG emissions by 2025 relative to 2005 levels; a 45% reduction by 2030; and zero or near-zero emissions by 2050. But the report projects only a 21.4% reduction in GHG emissions by 2025 and a 22.7% reduction by 2030.

And those reductions are slightly less than projections in the state’s GHG inventory from a year earlier, which forecast a 22.5% reduction in GHG emissions by 2025 and a 23.9% reduction by 2030.

In 2020, Nevada’s net GHG emissions totaled 37.3 million metric tons of CO2 equivalent, a 24.4% reduction from 2005 levels. GHG emissions in 2020 were less than the 2019 levels of 40.6 million metric tons. The report attributes the 2020 decrease to impacts of the COVID-19 pandemic, particularly on the transportation sector.

The transportation sector was the largest contributor to GHG emissions in Nevada, accounting for 32% of gross emissions in 2020, followed by electricity generation, which accounted for 31%.

For projecting future GHG emissions, the report makes several assumptions, including future retirements of natural gas-fired electric generating units. But the Public Utilities Commission of Nevada this year approved NV Energy’s request to postpone retirements of several gas-fired plants, as well as construction of a new 400-MW gas-fired peaker plant. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.)

Next year’s GHG inventory will likely factor in the recent PUCN decisions.

‘Door is Open’

Evan Westrup, communications director for the U.S. Climate Alliance, said Lombardo’s decision to leave the Alliance was disappointing, but “our door is open” if he changes his mind.

“As unprecedented wildfire smoke, record heat and catastrophic floods sweep across the country, we need every state and every governor — no matter their politics — confronting this crisis,” Westrup said in an email.

Westrup noted that newly elected governors in other Alliance states have opted to remain in the coalition, including the governors of Massachusetts, Hawaii, Oregon, Maryland and Pennsylvania.

Christi Cabrera-Georgeson, co-deputy director of the Nevada Conservation League, credited Lombardo for signing bills this year that will create more accountability and transparency in utility planning and promote clean energy.

But Lombardo’s decision to leave the U.S. Climate Alliance “contradicts these efforts and cedes Nevada’s leadership on clean energy and climate,” she said.

“This was a choice to prioritize utilities and their profits over everyday Nevadans who are already struggling to pay their energy bills amid record-breaking temperatures,” Cabrera-Georgeson said in an email. “By not prioritizing clean energy investments to diversify our job market and reduce greenhouse gas emissions, Nevada’s economy and environment will also suffer.”

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DTE, Activists Announce Agreement to Exit Coal by 2032

DTE Energy announced an agreement with Michigan officials and environmental and clean energy groups Wednesday to accelerate its emission-reduction efforts, add more renewable power and phase out coal use by 2032.

Under the agreement on DTE’s 20-year integrated resource plan, the utility will cut its power plant emissions by 85% in the next nine years, with the utility committing to net-zero emissions by 2050.

The proposed agreement (U-21193) will have to be approved by Michigan’s Public Service Commission, which is expected to consider it at its next meeting July 26. The PSC staff was among the parties to the settlement, along with Michigan Attorney General Dana Nessel and 21 environmental and clean energy groups and labor unions.

Coal Retirements

The deal will end the use of coal at the Monroe plant, the nation’s fourth-largest, by 2032, three years earlier than DTE had previously announced. In addition, DTE will convert its only other coal-fired generator, the Belle River plant in St. Clair County, to natural gas.

DTE will also close the gas peaker unit (11 MW) at the shuttered River Rouge coal plant and diesel peaker (5 MW) at the retired St. Clair coal plant in 2024.

The company agreed to begin conversion of Belle River within three years and to seek federal funding for the work under the Inflation Reduction Act.

Monroe Units 3 and 4 will be retired by the end of 2028 and Units 1 and 2 by the end of 2032, assuming no regulatory orders to keep them open or designation by MISO as system support resources. DTE said it will propose how to replace the power from the 3,400-MW Monroe plant in its next IRP, due in 2026.

The company pledged to offer retraining for employees impacted by the coal plant retirements and offer “economic development opportunities” for host communities.

Coal represented 77% of the company’s generation in 2005. For 2022, the company’s generation mix was 54% coal, 18% nuclear, 14% natural gas and 13% renewables.

15,000 MW of Renewables

The agreement was developed over two years of discussions. (See DTE CEO Hints at Accelerating Coal Plant Closures.)

There was some grumbling that the agreement was not as aggressive as Consumers Energy’s plan to end the use of coal by 2025. But overall, the advocacy groups were satisfied with the agreement.

DTE said the IRP also calls for developing more than 15,000 MW of renewable generation by 2042 and more than doubling its current storage capacity with the addition of 780 MW by 2030 and more than 1,800 MW by 2042. The storage plan will include 220 MW at the Trenton Channel Power Plant, a former coal plant.

Also, the company also will seek 150 MW of new demand response through competitive bidding in time for MISO’s 2027/28 planning year.

The IRP indicated no need for generation capacity in the next five years.

Nessel touted several other parts of the agreement:

    • $100 million in customer savings from securitizing at a lower rate more than $1 billion in early retired coal plant assets and reducing the return on equity on currently operating coal plants;
    • DTE’s donation of $8 million for energy efficiency and renewable projects for low-income customers and $30 million to reduce arrearages;
    • annual public disclosures of all contributions made by DTE and its regulated utilities that total $5,000 or more, including donations to tax-exempt 501(c)(3) and 501(c)(4) organizations;
    • increasing DTE’s cap on distributed generation from 1% to 6%; and
    • DTE’s allocation of at least $43.8 million to income-qualified electric energy waste reduction programs in 2024 and $53.8 million in 2025.

Activist groups said the agreement will reduce the health risks lower-income populations face from the power plants.

“This legal settlement commits DTE to an expeditious transition away from burning coal that is compelled by economics, public health and climate science,” said Earthjustice attorney Shannon Fisk. “With the Monroe coal plant — the third-largest climate polluter in the country — partially retiring in 2028 and fully retiring by 2032 (or possibly earlier), people in southeast Michigan will soon begin to breathe easier. Today’s settlement will accelerate the buildout of clean solar and wind power in Michigan, as well as battery storage, and it funds energy-efficiency programs.”

DTE CEO Jerry Norcia called the agreement “an investment in Michigan’s future.”

“We are grateful that 21 organizations from across Michigan have joined us in bringing our proposal one step closer to reality. This partnership and dedication have helped us build the best plan possible for our customers,” he said.

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MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours

CARMEL, Ind. — MISO is holding to its plan to enact a widescale marginal capacity accreditation while announcing this week that it will swap risky hours for peak load to calculate its reserve margin requirements.

Officials at a July 11-12 Resource Adequacy Subcommittee (RASC) meeting said as part of MISO’s move to a probabilistic, direct loss-of-load accreditation for most of its resources, it will identify periods that have the highest potential for reliability risks in its loss-of-load modeling and set requirements from them. That process is set to replace MISO’s current practice of margin requirements established on peak load.

MISO also proposed a three-year transition to the direct loss-of-load accreditation, which will be based on generator performance during predefined tight operating conditions. The grid operator hopes to file the changeover with FERC in October or November. (See MISO Accreditation Impasse Persists at Workshop; MISO Stakeholders Debate Capacity Accreditation, RA.)

MISO’s Davey Lopez said staff will reach out to market participants in the coming months with accreditation results under a direct loss-of-load approach. He said MISO is working with Astrapé Consulting to estimate accreditation trends into the future under a transformed fleet. MISO plans to use results from its annual Regional Resource Assessment to publish forward-looking accreditation and planning reserve margin requirement estimates. (See MISO: 200 GW in New Capacity Necessary by 2041.)

“We will only make a filing after you all have seen both the…accreditation and the notional trend of what accreditation will look like under a different resource mix,” Executive Director of Market and Grid Strategy Zak Joundi pledged. He said MISO will build in its filing how it will share accreditation data from “a future-looking standpoint.”

Joundi said it makes sense for MISO to leverage the annually updated Regional Resource Assessment to predict the fleet mix MISO will be accrediting.

Joundi also said though MISO’s reserve margin calculations will be adjusted to focus on risky hours, they still will incorporate seasonal peak loads and still will solve to meet them.

“It’s just signaling that’s not where we’re seeing risk happening,” Joundi explained of MISO’s new calculation route.

So far, the accreditation change will not apply to load-modifying resources. Lopez said MISO plans to address LMR accreditation later.

MISO officials are wedded to the direct loss-of-load accreditation as stakeholders continue to have qualms with the lowered capacity credits for most resources and eventual near-zero capacity credits for solar generation that the design is likely to produce within a decade.

Stakeholders’ motion in spring to oppose a marginal approach to capacity accreditation passed with 31 members in favor, six voting against and eight abstaining from the email vote.

MISO’s Dustin Grethen said he “invited people to think of” MISO’s accreditation philosophy as what capacity is actually earned, versus the cruder, nameplate capacity-minus-forced outages MISO previously employed for its thermal resources.

During the May Resource Adequacy Subcommittee meeting, Joundi said MISO and stakeholders already have been debating accreditation design elements for the better part of two years.

“The way we landed on the proposal on the table was not by luck,” Joundi said, adding that MISO staff underwent months of analysis on the most beneficial accreditation design for the system. “We believe the current proposal…meets where we need to be to be ready for the future and is the most appropriate.”

Stakeholders pushed back on the timeline, saying that though discussions were held on accreditation concepts, MISO only settled on a draft design since early 2023.

Lopez said it just makes sense that accreditation should be directly derived from loss-of-load expectations.

“They’re in the same currency,” he told stakeholders at the May RASC.

MISO Independent Market Monitor David Patton said that MISO must continue its effort to assign realistic capacity accreditation to all units, despite stakeholder protest. (See MISO Accreditation Impasse Persists at Workshop.)

“There’s a lot of folks behind me that aren’t going to like an efficient accreditation regime because these resources are expensive to build, but if we’re not honest about that, we’re going to accredit resources that have no hope of meeting the planning margin,” Patton said during the spring MISO Board Week.

Patton said without an honest accreditation method, MISO runs the risk of not having “the resource base that we need to keep the lights on.”