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November 5, 2024

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PJM Presents Preliminary 2023 Reserve Requirement Study to Stakeholders

Reserve margins would increase significantly based on the preliminary 2023 Reserve Requirement Study (RRS) results PJM presented to the Resource Adequacy Analysis Subcommittee (RAAS) on Aug. 29.

The installed reserve margin (IRM), which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year (DY) in the 2022 study to 17.6% for the 2027/28 DY using PRISM modeling software. The forecast pool requirement, which considers forced outage rates, also would increase from 9.18% to 11.65% for the corresponding DYs.

When comparing RRS results, PJM looks at the furthest year out, as that would be the year a Base Residual Auction (BRA) would be run under a three-year advance auction schedule. (See “Stakeholders Endorse 2022 Reserve Requirement Study Results,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

This year’s study also engages in a second analysis using software developed to perform hourly loss-of-load modeling used in effective load-carrying capability (ELCC) studies to calculate the IRM and FPR. Both results will be presented to stakeholders, who will be asked to endorse one of the sets of results.

The hourly analysis yielded an IRM of 18.3% for the 2027/28 DY and 12.31% FPR, with much of the difference between the PRISM values arising from the load model.

In addition to setting an initial IRM and FPR value for the 2027/28 DY, the study resets the figures for the previous three years. The preliminary results would be increased by a similar margin for each of those years.

PJM’s Patricio Rocha-Garrido said the drivers of the higher margins in the preliminary results are increased uncertainty in the peak load forecasts in the data and a higher generation forced outage rate in the winter owing to the December 2022 winter storm and the November 2013 polar vortex being included in the data. Shifting to hourly modeling of peaks also increased the expected peaks.

Minimal coincidence between the PJM peak load period and the “world” peak — which is defined as MISO, NYISO, TVA and VACAR — led to the capacity benefit of ties (CBOT) value more than doubling to 2.2% from the 1% value in the 2022 study. To reduce volatility, PJM elected to average the CBOT values from 2017-22 and use that figure, which landed at 1.5%, instead.

While the RTO opted to shift the world peak to not fall on the same week as PJM’s peak in the load model, spokesperson Jeff Shields noted that a similar shift was made last year. (See “Stakeholders Endorse RRS Load Model” PJM PC/TEAC Briefs: Aug. 8, 2023.)

“So, shifting the world peak week is not the whole story — the peak load coincidence in weeks other than the PJM peak week, as well as the magnitude of the world peaks on those weeks (as well as during the PJM peak week), also play an important role,” Shields said in an email.

The load model, which included data from 2013-19, contributed to a 2.1-percentage-point increase in the IRM, while the winter peak week caused a 1.1-percentage-point increase under the PRISM modeling. The values were slightly lower for the FPR drivers.

The CBOT contributed to a 0.5-percentage-point decline in the IRM value and 0.58-point-lower FPR.

Under the hourly analysis, the load model contributed to a 3.1-point increase in the IRM and 2.95-point increase in the FPR. The winter peak week increased the IRM by 0.7 points and the FPR by 0.66 points. The CBOT lowered the IRM by 0.5 points, which was about the same for the FPR.

The non-winter peak week had a smaller impact on the IRM under both approaches, 0.2 under PRISM and 0.3 in the hourly model, and had no contribution to the FPR. PJM used a larger amount of data to determine the expected winter peak capacity models, drawing on aggregate outage data from the 2007/08 DY through 2022/23. The remainder of the capacity model data used Generating Availability Data System (GADS) outages from 2018-22.

Rocha-Garrido said PJM is in the process of using coincidental peak distributions to calculate additional values to compare to the PRISM and hourly results to inform staff’s recommendation of which model to use in the final study results.

James Wilson, a consultant to state consumer advocates, said he calculated the PRISM values would lead to around a 3,700-MW increase in the summer reserve margin. Rocha-Garrido agreed that likely would be about right. Wilson questioned what has changed about PJM’s understanding of resource adequacy in the summer to drive such an increase in the amount of capacity that would be procured.

“The explanations just say we made a bunch of changes. … Why are we buying a lot more when we don’t have any reason to think the same isn’t enough?” Wilson said.

PJM’s Andrew Gledhill said staff worked with Itron to improve their load forecast modeling, leading to the hourly approach and an overall modeling which they believe has a tighter fit to the data available. The old modeling appeared to be underforecasting load certainty, in the winter in particular.

Wilson said PJM historically had not included data from the polar vortex in its modeling, believing the issues that led to high forced outage rates during the event had been addressed by winterization efforts. He called on PJM to provide additional analysis justifying the data’s inclusion in the RRS, saying PJM had relied only on the impact of Winter Storm Elliott to make that change.

First reads of the IRM and FPR values are scheduled for the September Planning Committee (PC) and Markets and Reliability Committee (MRC) meetings. The PC is expected to vote on endorsement the following month, while the MRC and Members Committee (MC) are anticipated to vote October through November. The values are expected to be presented to the Board of Managers in December.

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NERC’s DeFontes Calls for Industry Balance

AUSTIN, Texas — The Texas Reliability Entity’s Board of Directors hosted top NERC official Ken DeFontes during last week’s quarterly meeting.

Or, as Board Chair Milton Lee said in introducing DeFontes, “Thanks for visiting Texas at the height of summer.”

NERC Board of Trustees Chair Ken DeFontes | © RTO Insider LLC

DeFontes, who chairs NERC’s Board of Trustees, brought with him the grid’s three competing objectives: reliability, affordability and the environment. Objectives, he said, that are being thrown out of whack by policymakers focused on environmental legislation.

“I think we’ve done a really good job over the years of figuring out how to get to that right balance, to do the job economically, to be responsive and attentive to the impact on the environment at the same time,” he told the board during its Aug. 23 meeting. “We need to get back to that balance, and part of NERC’s job is to better inform policymakers, not only at the federal level but also at the state level because a lot of the impacts are coming from state policy matters.”

Part of the answer lies in the agency’s biennial reliability risk report. The report, released last week, added engagement in energy policy as one of NERC’s five risk profiles. (See ERO Adds Energy Policy to Risk Priorities List.)

DeFontes said he and CEO Jim Robb already are making the rounds on Capitol Hill. He said they’ve been impressed with the level of understanding they’ve seen from Sen. Joe Manchin (D-W.Va.), chair of the Energy and Natural Resources Committee, and other key legislators.

“That’s encouraging to me that there are leaders in Congress who are understanding that as we transition away from dispatchable coal plants and replace them with intermittent renewable resources without a path to get us to whatever the future is going to be,” DeFontes said. “Part of the challenge is our message in the short run is manage the transition. Don’t lose sight of the fact that we’re more dependent on natural gas, so solve the interdependency issue between gas and electric.

“The problem with that message is what happens after that. We don’t really have an answer.”

To help find it, NERC also is conducting an interregional transfer capability study that is due in December 2024, a joint effort with FERC, the regional entities and the industry. NERC says the study, a directive from Congress as part of the recent Fiscal Responsibility Act, could provide “important insights for industry, regulators and policymakers.”

“I don’t think the issue with transmission is a lack of desire or a lack of financing to build it. The issue is getting sited and getting it approved,” said DeFontes, who said he has the scars from building transmission dating back to his utility days. “People really don’t like to see the transmission lines through their neighborhood. We need to move power across state lines, and when that happens, getting the approval to build the line is complicated, particularly for the states in between … there’s no benefit for them. It comes down to the siting and permitting.”

Addressing the Texas RE’s board and leadership, DeFontes continued: “I would love to have you help me figure out what we can do to make that work better, but we need more. The rate at which we’re investing in transmission right now by all indications is far less than what it needs to be.”

ERCOT CEO Pablo Vegas brought a similar reliability message to the meeting. He also focused on the industry’s pace of change.

“The systems are becoming complex because of that pace of change and the need for all of us in positions of accountability or various parts of the electric industry to be able to respond,” he said, “and to adapt our thinking or methods or technologies or processes in our organizations in ways to be able to take advantage of incredible innovation that’s ahead of us and also to be ready for the big challenges that are ahead of us.”

At the top of Vegas’ to-do list is developing a reliability standard. ERCOT staff have proposed a three-part framework that considers the duration and magnitude of a loss-of-load event, along with the occurrence’s frequency. They say this will better quantify LOLE risks when intermittent resources are a large percentage of the generation fleet. (See “ISO Prioritizes Market Changes,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)

“We’re operating at a 1-in-10 standard,” Vegas said. “The last time there was a load shed event [before 2021’s disastrous winter storm] was 2011. One in 10. Was everybody happy with that? Not even close. There’s clearly a lot of opportunities to better define what reliability means, the cost implications and frankly, to be able to have a conversation with constituents.”

Using such a conversation as a hypothetical example, Vegas said, “’This is what reliability standard means. This is what you should expect if we were to get into a situation like this because there is no such thing as zero risk. There is no such thing as no contingency.’ So let’s be upfront. Let’s be realistic.”

Spaulding to Serve 2nd Term

The Texas RE board’s Nominating Committee told directors it’s recommending Suzanne Spaulding be approved for a second three-year term as an independent director. The board will consider her nomination during its December meeting.

Spaulding is a senior adviser for Homeland Security at the Center for Strategic and International Studies and a member of the Cyberspace Solarium Commission. She previously was with the Central Intelligence Agency and the Department of Homeland Security, where she was undersecretary for cybersecurity and critical infrastructure protection.

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DOE Announces $300M for Tx Siting, Community Development

The Department of Energy on Tuesday announced a $300 million grant opportunity for states, tribes and local governments to strengthen their transmission siting and permitting processes.

Funding for the Transmission Siting and Economic Development (TSED) program comes from the Inflation Reduction Act and is administered by DOE’s Grid Deployment Office. The program is meant to accelerate the construction of new transmission infrastructure, which is vital to the Biden administration’s net-zero goals.

“To meet our ambitious clean energy goals, we need to expand the nation’s transmission capacity by 60% over the next seven years,” said Secretary of Energy Jennifer Granholm. “Now, thanks to President Biden’s Investing in America agenda, we have the funding to build out a grid chock-full of clean, cheap, reliable electricity and accelerate transmission expansion while creating good-paying jobs across the country.”

The $300 million is the first tranche of a total $760 million for the TSED program under the IRA and is available for permitting processes and economic development in affected communities. The program covers siting for any onshore transmission lines at 275 KV and above and offshore lines of 200 KV and above.

Independent estimates project that transmission will need to expand by 60% by 2030 and may need to triple by 2050 to meet the demand for clean electricity and resiliency. The TSED program will provide financial support to siting authorities to fund studies, modeling, environmental planning and analysis to assess alternatives, better inform decision making and cut application processing time.

Government siting agencies will be able to use the money to study up to three alternate siting corridors for transmission projects. Regulators can use it to participate at FERC or other agency proceedings for determining the rates and costs of a project they site.

The program also can support robust engagement with members of the public, participation in regulatory proceedings and other activities as approved by the secretary of Energy.

The program’s community-based projects can include energy investments such as microgrids, renewable power integration and electric vehicle charging infrastructure. They can support essential community facilities for public safety, health care, education and transit, or community centers and parks.

TSED funds can also be used for job training and apprenticeship programs. DOE wants communities to submit unique projects that are suited to local needs.

Transmission developers are not eligible for the grants, but they can partner with government agencies that are. Developers can work with siting and permitting agencies to propose improvements to cross-jurisdictional coordination, strengthen permitting processes and resolve permitting bottlenecks.

DOE wants initial concept papers from potential grantees by Oct. 31 and full applications by April 5, 2024.

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NYSERDA Backs Inflation Adjustments for Renewable Projects

The lead agency in New York’s clean energy transition has come out in favor of inflation adjustments for renewable projects under contract but not yet under construction.

Inflation and interest rate hikes have emerged as a significant threat to the state’s statutory emissions-reduction goals, as developers of 91 projects totaling 13.5 GW of capacity are seeing construction costs soar. Some are saying they may not be able to proceed under terms negotiated, and three petitions representing numerous developers were submitted to the state Public Service Commission in June seeking relief.

More recent solicitations by the state have offered adjustment mechanisms to account for cost changes, but the solicitations these developers bid into did not.

A flurry of comments was submitted Monday, the PSC’s deadline for input in Case 15-E-0302.

The sentiment fell largely along predictable lines: Those who are fighting for decarbonization and those who would profit from it favored a retroactive boost for the earlier contracts. Opposition came from those who would pay for it or fear they would lose a competitive edge because of it.

The New York State Energy Research and Development Authority submitted a lengthy analysis of options, costs, benefits and risks and concluded that a price adjustment could help maintain New York’s forward momentum toward the goals of the Climate Leadership and Community Protection Act (CLCPA), which requires renewable power make up 70% of the state’s generation mix by 2030.

If developers walk away from their contracts to provide it, the state will have to seek new contracts; bids will inevitably come in higher, perhaps higher than the adjustments the current contract holders seek. These new contracts inevitably will take longer to complete, and the delay will prolong the damaging effects of greenhouse gas emissions generated by burning fossil fuel.

NYSERDA said bid prices submitted in the latest solicitations are significantly higher than those in the earlier contracts.

More Money

Developers of nearly all of New York’s offshore wind portfolio and much of the onshore wind and solar pipeline sought relief through similar petitions submitted to the PSC on the same day in June.

Soon after, Clean Path New York — an $11 billion portfolio of wind and solar projects with an underground transmission line to carry the power they generate to New York City — said it needed the same adjustment if the PSC grants it to the Tier 1 generation projects. Two-thirds of its generation portfolio is Tier 1, so Clean Path would be paying them more.

Another shoe dropped this week: The Champlain Hudson Power Express asked the PSC in a petition Monday to level the playing field and make any inflation-related price adjustment apply to all new-build project components.

The underground HVDC line to carry emissions-free power from Quebec hydropower plants to New York City was first proposed in 2010. Early cost estimates were in the $2 billion range, but the PSC in 2022 authorized up to $6 billion in debt to build it. Construction began this year.

Champlain Hudson said in its petition it has suffered the same unforeseeable cost increases as everyone else, mentioning a converter station whose cost jumped 40% in less than a year. The adjustments it is seeking would not make it whole, it said, and would mean only a modest increase in costs.

A spokesperson for developer TDI told RTO Insider the issue is one of fairness: Any inflation relief must be extended equally to all participants in the state’s renewable energy certificate (REC) program. “CHPE’s petition reflects the necessity that large-scale renewable developers who participated in competitive NYSERDA solicitations and have all faced the same economic and geopolitical challenges are treated equally,” it said.

Reactions

Comments ranged from hundreds of the same supportive message from individual members of unions that expect to work on clean energy projects, to NYISO, which has warned of potential shortfalls in generation capacity amid the transition.

The ISO took no position on whether or how the REC agreements should be modified. Instead, it emphasized the importance of continued progress in the buildout. If development of renewables is not “rationally coordinated” with retirement of fossil fuel resources, system reliability is jeopardized.

As NYSERDA and others commented, losing the existing contracts would slow progress.

NYISO already has identified a potential deficiency of up to 446 MW in New York City on peak summer days, and its warnings about the slow pace of the state’s energy transition have grown increasingly firm in recent months.

In its comment to the PSC, NYISO wrote: “A sufficient fleet of new generation resources that satisfy the CLCPA must be available before more of the existing, traditional generators retire voluntarily or are forced out of service.”

The Public Utility Law Project of New York laid out a different set of priorities: a consistent and transparent review of the developers’ requests for more money, and an effort to cushion ratepayers from the impact of any increase.

“We strongly believe that ratepayers, especially those who are low-income or who live in disadvantaged communities, cannot and should not be left to shoulder the financial burden, especially unexpected cost adjustments,” it wrote.

The state Department of State’s Utility Intervention Unit came out in opposition to the increase.

“For markets and competition to function efficiently, contracts and obligations should be honored,” it wrote. “Altering contracts after terms are defined can diminish the competitive process that potentially disadvantages those bidders not selected in a respective solicitation and consumers who are paying for the project.”

The unit also urged that the PSC scrutinize each project’s costs carefully, and that it limit any adjustment mechanism to those projects more likely to succeed: “Ratepayers should not be throwing good money after potentially bad projects.”

New Yorkers for Clean Power urged the adjustment be granted, as the projects in question are critical for not only meeting the CLCPA’s goals, but also boosting the state’s economy. “The petition demonstrates that failing to redress the economic circumstances will result in both years of material delay and substantial additional cost,” it wrote.

Offshore wind developer Rise Light & Power dismissed the idea of giving other offshore wind developers more money than they agreed to. “It is unprecedented and unwarranted to ask the commission to direct NYSERDA to change ex post facto the most material terms of a competitively bid contract to benefit a petitioner and increase the cost and risk of such contract to NYSERDA.”

Rise had a similarly dim view of the onshore wind and solar petition, saying an increase would be “unfair to prior and current bidders in Tier 1 solicitations, harmful to ratepayers and would violate bedrock principles of competitive public contracting.”

The New York City Mayor’s Office of Climate and Environmental Justice led off with a pointed observation: The process is already too slow. Since 2016, NYSERDA has entered into 115 contracts totaling 13,730 MW of renewable generation and storage, it wrote. But only 14 of those projects have come online, delivering just 681 MW.

For this reason, the city endorsed relief for renewable developers, though not as much as was requested, because of the likely effect on ratepayers. “There is much work to do, and time is of the essence to achieve the state’s 2030 goal,” it said.

Nucor Steel Auburn — whose electric arc furnace is one of the largest loads on the New York State Electric & Gas system — blasted the request for an inflation adjustment for the Tier 1 onshore contracts as unsubstantiated, unjust and not in the public interest. It wrote: “The added cost to New York consumers from such a measure would approach $10 billion over the 20-year life of REC contracts.”

New York’s investor-owned utilities, commenting jointly, made a similar point, warning of billions in extra costs for ratepayers. “These petitions, if approved without modification, would create a perverse incentive and weaken the effectiveness of future NYSERDA REC contracting cycles and create unnecessary costs for customers throughout New York state,” they said.

The Sierra Club and Environmental Advocates of New York backed the idea of inflation adjustments weighed with impact on consumers, the market and the environment.

“While we do not endorse any particular level of support for contracted at-risk renewable energy projects, an inflation adjustment of the type requested by petitioners should be strongly considered as part of a least-cost approach to achieving New York’s renewable energy commitments.”

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NERC Utah Event Report Underlines Ongoing IBR Issues

The ongoing performance issues with inverter-based resources in the Western Interconnection show that “proactive industry action” is needed to prevent “a significant risk to [electric] reliability,” NERC and WECC said in an incident report released last week.

The 2023 Southwest Utah Disturbance, which occurred April 10, 2023, is the first major widespread loss of solar output to occur in the Western Interconnection outside of California. In the event, which involved nine solar facilities operated by PacifiCorp-East (PACE), the utility lost 921 MW of generation. This passed the 500 MW threshold to qualify the disturbance as a Category 1i event in NERC’s event analysis process, like the summer 2021 disturbances in Southern California that the ERO discussed in a report last year. (See NERC, WECC Repeat Solar Performance Warnings.)

The disturbance began at 8:51 a.m. Pacific time, when a single-line-to-ground fault occurred on a 345-kV transmission circuit in southwest Utah. While protective relaying cleared the fault within 3.5 cycles, PACE supervisory control and data acquisition records showed that aggregate solar output in the utility’s footprint dropped significantly; overall, PACE lost more than half the 1,600-MW total output of its solar fleet in less than half a minute, and the system frequency dropped from 60.01 Hz to 59.89 Hz.

WECC system frequency (in red), along with total output of the PACE solar fleet (in gray), during and after the disturbance. | NERC

Nine solar facilities were involved in the event; the lowest loss reported was 17 MW, and the highest was 234 MW. WECC and NERC found multiple reasons for the output reduction at all but one of the facilities:

    • Inverter phase lock loop (PLL) loss of synchronism — five facilities;
    • Instantaneous AC overvoltage (ACOV) — four facilities, all of which also suffered PLL loss of synch;
    • DC reverse current protection — two facilities, both of which also suffered PLL loss of synch and ACOV;
    • Inverter instantaneous AC overcurrent protection (ACOC) — two facilities; and
    • Passive anti-islanding — one facility.

The facility that tripped on passive anti-islanding also suffered ACOC. In addition, two facilities tripped for unknown causes, which NERC and WECC attributed to “poor data retention and/or quality.”

All of the causes reported “have been well-documented in past disturbance reports,” NERC and WECC said; while they did not cite specific incidents, most of the same issues were cited in last year’s Southern California event report, as well as the ERO’s reports on the Odessa, Texas, disturbances of 2021 and 2022. (See NERC Repeats IBR Warnings After Second Odessa Event.)

The ongoing issues reiterate “the strong need for inverter-based resource (IBR) performance issues to be addressed by generator owners (GOs) in a timely manner,” the report said. One of its key findings was that NERC’s Project 2023-02 (Performance of IBRs) remains important, because it promises to require “analysis and mitigation of unexpected or unwarranted protection and control operations” from IBRs when such potential issues are identified.

In another of the report’s recommendations, the ERO noted the “reiterated need” for a comprehensive ride-through standard to replace PRC-024-3 (Frequency and voltage protection settings for generating resources). Revising this standard is the objective of Project 2020-02, which aims to ensure that generators remain connected to the electric grid during system disturbances.

Finally, the report said the incident illustrates the importance of following NERC’s Level 2 alert on IBRs, which the ERO issued this year. (See NERC Issues Level 2 Alert on IBR Issues.) The alert provided recommendations to GOs for addressing known performance issues with IBRs and requested information on existing facility protection and control settings.

Responses to the Level 2 alert were due by July 31; the ERO is analyzing the results and will publish key findings and recommendations by the end of the year. The report reminded GOs that these alerts “help ensure that [utilities] are aware of potential risk issues” with their grid-connected equipment and can develop corrective actions when possible.

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FERC Order 2023 Gets Rehearing Requests from Around the Industry

FERC received rehearing requests Monday from around the industry on Order 2023, which mandated changes to its pro forma interconnection rules. (See FERC Updates Interconnection Process with Order 2023.)

MISO, PJM and SPP filed a joint request for rehearing, saying they want to ensure that they can continue to innovate with their own changes to their interconnection processes.

The RTOs took issue with the order’s requirement that planners use operating assumptions supplied by energy storage developers, unless they go against good utility practice. Ensuring that storage owners actually follow those assumptions in their operations would be burdensome and impractical, they said.

“Storage would be incentivized to lower their costs by stating in their interconnection application their intent to charge to relieve constraints, when in actuality in real time they will not always be capable of fulfilling that commitment,” the RTOs said. “As a practical matter, there is no effective enforcement of the commitment, and the final rule does not purport to address this critical reliability issue.”

FERC at least should allow ISOs and RTOs to develop standard procedures for dealing with storage projects in their queue, rather than the case-by-case approach in the order, which would at least promote uniformity in treatment of similarly situated interconnection customers.

PJM, MISO and SPP all use multiphase interconnection processes, but Order 2023’s pro forma rules have just one phase, used to base the deadlines and related fines that grid operators face for late studies. That makes it unclear how the rules should apply in their markets, the RTOs said. Rather than making them liable for deadlines in each phase, they asked to have it apply to the aggregate timeline of their multiphase queue processes.

Ultimately interconnection customers want their final studies on time, so as long as the full process is timely, it should not matter if some earlier phases experienced delays that were made up later, the three said. Late penalties also should apply to entire clusters, rather than having planners face them for every project they work on individually.

ISOs and RTOs are nonprofits, so another issue the three raised was how to recover their costs, asking for additional ways beyond collecting fines from their members. If a delay is because of one interconnection customer, as opposed to the grid operator itself or a member utility, then it should be liable for any fines, they argued.

NYISO filed its own request for rehearing, which also questioned the fines, but it focused on the timelines that Order 2023 set out for interconnection studies. The 150-day time frame for a cluster study is not tailored to the realities of New York’s grid and its stricter-than-average reliability requirements, but it still could be used to assess fines.

“These stringent criteria are driven by, among other things, the unique complexities of the transmission system in New York City and Long Island, with their condensed geographic footprint and high population density,” NYISO said. “This existing complexity is being further challenged by the influx of significant offshore wind generation.”

NYISO is working on a package of changes to its queue, and its goal is to speed up the process, but 150 days would prove too tight for it.

New York PSC Argues in Favor of Fines

The New York Public Service Commission filed comments arguing that FERC should make sure that ISOs and RTOs cannot get out of the fines that Order 2023 requires for transmission planners who are late with interconnection studies. The order suggests grid operators could file one-off requests to recover the fines from market participants, it said.

“Allowing RTOs/ISOs to simply pass along penalties to market participants, which will ultimately be borne by customers, would undermine [FERC’s] goal by making RTOs/ISOs indifferent to penalties and failing to induce the intended behavior,” the New York PSC said. “Moreover, forcing market participants/customers to pay increased costs attributable to penalties incurred by an RTO/ISO that failed to comply with the tariff time deadlines would be unjust and unreasonable.”

FERC has expressly prohibited non-ISO/RTOs from recovering the penalties through transmission rates, and it should do the same for the nonprofit grid operators, the PSC said. It also should reverse its finding that they can make a one-off filing to recover penalties from market participants.

“The commission should instead limit RTO/ISO recovery options to alternative mechanisms that do not involve customer funding but could elicit the desired behavior, such as adjustments, both positive and negative, to RTO/ISO salaries/bonuses,” the PSC said.

Utilities Lobby for ‘Reasonable Efforts’ Standard

The Edison Electric Institute also took issue with FERC’s decision to eliminate the “reasonable efforts” standard for getting interconnection studies in on time and the imposition of fines. FERC cited the lengthy interconnection delays experienced around the country as the main reason for eliminating the standard, but it did not connect those delays to the standard.

“Only after the commission has had an opportunity to evaluate the efficacy of other reforms intended to streamline the interconnection process (e.g., reforms to incentivize interconnection customers to reduce interconnection delays) can it determine that the reasonable efforts standard is unjust and unreasonable,” EEI said.

A rapidly changing resource mix, market forces and emerging technologies are among the many factors contributing to the increasing number of interconnection requests and related delays. Transmission owners can control none of those factors, and assigning them penalties will not change that, EEI said.

FERC never has found a transmission provider at fault for interconnection process delays, nor shown that any specific transmission provider was contributing to delayed studies, it said.

“Nonetheless, the commission seems intent on establishing a strange kind of parity in its reforms: If the threat of penalties is appropriate for eliciting certain behavior from one set of stakeholders, then penalties must be appropriate for all stakeholders in the interconnection process,” EEI said. That does not make sense because many factors, including the number of requests and the need to follow reliability standards, are outside transmission providers’ control, it said.

Clean Energy Groups Seek Changes

The American Clean Power Association, Advanced Energy United and Solar Energy Industries Association filed a joint request for rehearing, which applauded FERC for its work to reform the queues. But given how large the order was, the groups said they have some issues where the order would benefit from rehearing.

The groups’ first ask is to remove a change to the definition of “standalone network upgrade” that would limit their construction to cases where one interconnection customer builds them. FERC reasoned the change would reduce disputes by avoiding situations where multiple interconnection customers seek to build the same transmission. But cluster studies for interconnection have occurred for years and have not led to major disputes between projects seeking to build the same standalone upgrade, they said.

“The revised definition of standalone network upgrade removes the ability of interconnection customers to determine whether and how to exercise their discretion or the option to build for the majority of upgrades that will be identified through a cluster study,” the groups said. “It further modifies the status quo by reducing the number of network upgrades that would qualify as standalone network upgrades for which interconnection customers could exercise their discretion.”

The groups generally pushed for more flexibility for interconnection customers, also seeking more time to modify a proposed project’s size and to push back when they have to pick a definitive point of interconnection. The commission required both when the “customer engagement window” ends, reasoning that developers would have enough information at that point to make final decisions.

The three lobbies argued more flexibility was warranted because requiring final decisions so early would lead to more withdrawals later on and risk “cascading restudies.” That would be more disruptive than allowing minor changes later in the process, they said.

Heat Map Value Questioned

Several utilities outside of RTOs — Dominion Energy South Carolina, NextEra Energy’s Florida Power & Light and Xcel Energy’s Public Service Company of Colorado — filed jointly asking for a change to the requirement that grid planners place interactive “heat maps” on their public websites. The maps would offer interconnection customers and others a way to explore available interconnection capacity on transmission providers’ systems.

The utilities said FERC failed to perform a cost-benefit analysis on the requirement, which would cost $7.4 million upfront in non-RTO regions and $666,000 annually for maintenance. The requirement will have “dubious value” for interconnection customers in non-RTO regions, they said.

Such heat maps make financial sense when done at scale for several utilities, so it could make sense to require ISO/RTOs to host them, but the three utilities said the lack of scale on individual systems made it too costly.

“Due to the significant cost asymmetry — 37 individual websites required in non-RTO regions versus seven websites in ISO/RTO regions — the cumulative expense and administrative burden on constrained engineering labor caused by the heat map mandate on transmission providers in non-RTO regions is at least five times as significant as the burden on ISOs/RTOs, even though transmission providers in non-RTOs only oversee generator interconnections for roughly one-third of the nation’s transmission systems,” they said.

Flexibility Sought

PacifiCorp spent much of its rehearing request focused on the penalties for transmission providers, but it also argued for more flexibility for it and others to implement the rules. The utility noted that it already has adopted many of the changes required by Order 2023.

FERC set up a transition process for providers still using its old pro forma rules but not for early actors such as PacifiCorp, the utility said. If it does not seek a variance from the pro forma rules, it would have to implement them suddenly regardless of the existing queue, it said.

“PacifiCorp and many of the early adopters are currently in the process of one or more cluster studies,” the utility said. Not allowing early adopters to use a transition cluster study process is both unworkable and goes against FERC’s assurance that Order 2023 would not interfere with interconnection studies in progress, it added.

On rehearing, FERC should find that PacifiCorp and other similarly situated transmission providers can process existing interconnection customers under current, or transitional rules, while applying new reforms to interconnection customers once those are completed, it said.

PJM filed an individual request for rehearing that also was focused on flexibility, given that it has started to implement its own changes, which it said should satisfy Order 2023’s requirements or be superior to them. While FERC said it did not want to disrupt such efforts, PJM said it wants a clearer signal before any lengthy compliance processes that its work will not be overturned.

Without that clarification, FERC will be responsible for creating uncertainty at the very point where certainty around the rules for expeditious processing of queue requests is so critical, the RTO said.

“In short, now, when PJM is ‘mid-flight’ with its new interconnection process, is not the time to require PJM to substantially retool its interconnection processes or to cause substantial uncertainty as to how to comply with the final rule that will last for months and distract from the vital effort to process backlogged interconnection requests as expeditiously and efficiently as possible,” the RTO said.

PJM also wants clarification that it will not be required to implement the final rule in a way that would modify or undermine its recently approved new rules. The commission should consider those changes as a package and not require PJM and stakeholders to engage in “an item-by-item justification of every variation from the minutiae of the final rule’s requirements.”

Along with most other transmission providers filing for rehearing, American Electric Power wants FERC to reverse its decision on imposing fines for delayed studies, but the company also asked for some changes on how new projects can be built at sites owned by retired power plants.

“Generation retirement replacement programs take advantage of current land use and interconnection facilities to swap generation units set for retirement with newer, more efficient capacity,” AEP said. “Such programs will support the reliability of the grid and enhance the efficiency of interconnection study processes by allowing for the timely interconnection of needed new capacity resources.”

AEP and a few other parties brought up the issue in comments, but it was not part of the Notice of Proposed Rulemaking that led to Order 2023, it said, and FERC said it lacked the evidence to approve any pro forma rules around how to replace retiring generators. The utility disagreed, saying the idea is one of the most vital tools to maintaining resource adequacy, as they can quickly connect new supplies of power.

“Ensuring replacement projects are considered outside the cluster study process will help reduce the number of projects within, and increase the efficiency of, the cluster study itself — supporting the timely interconnection of projects consistent with one of the primary purposes of Order 2023,” AEP said.

WATT Coalition Lobbies for DLRs

The WATT (Working for Advanced Transmission Technologies) Coalition filed for rehearing on two issues involving dynamic line ratings (DLRs), which take into account the conditions around power lines such as wind speed and temperature to get a more accurate picture of how much capacity they have.

FERC excluded DLRs from its list of alternative transmission technologies (ATTs) that can be considered in cluster studies. It also allowed transmission providers to “disregard and disadvantage” alternative technologies for traditional upgrades even when alternatives would be more cost effective.

DLRs were part of the alternative technologies to be considered in the NOPR, but in the final rule, FERC removed them despite them being proven, mature technologies that have saved interconnection costs in other countries, WATT said.

One WATT member was quoted $190 million in upgrades for one projected 4% transmission line overload during the shoulder season, with the grid operator assuming it would charge during the worst-case contingency events.

“The battery would provide energy to an area of anticipated economic development but would be uneconomic with quoted upgrades,” WATT said. “DLR is a solution that could bring the project back into viability if permitted by the transmission owner.”

FERC got comments for and against every ATT brought up in the NOPR, but it only removed DLRs, saying their temporary impact “may not be an adequate substitute” for steel in the ground, WATT noted.

“DLRs should be treated on equal footing with the other ATTs included in the final list, and as the NOPR proposed,” WATT said. “Equally, it is arbitrary and capricious, and contrary to law, to give transmission providers unfettered discretion regarding whether ATTs should in fact be used.”

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CARB Starts Mandated Carbon Capture, Storage Program

California regulators have started developing a program to manage carbon capture and storage projects in the state, as mandated by legislation passed last year.

Senate Bill 905 of 2022 directed the California Air Resources Board (CARB) to create a carbon capture, removal, use and storage program.

The program will regulate carbon capture: projects in which carbon dioxide is either captured from industrial or energy-related facilities or removed from the atmosphere. Storage involves injecting the captured CO2 into underground geologic reservoirs.

CARB kicked things off with two public meetings Aug. 15.

Under SB 905, CARB must create a streamlined permit application for carbon capture or storage projects by Jan. 1, 2025. CARB will also develop a database so the public can track the projects.

Other state agencies will be involved too. The California Natural Resources Agency (CNRA) will develop a framework for situations in which a CO2 storage reservoir lies beneath two or more parcels of land.

The framework, known as the Common Reservoir Operation Plan (CROP), will cover issues such as fair compensation for landowners and allocation of liability.

SB 905 requires the framework to be published by July 1, 2025; agency officials said they’re hoping to complete it a year sooner, by June 2024.

“Given the deadlines for other actions under SB 905, including CARB’s regulations, the framework will be more relevant and more supportive of other agencies’ actions if we do it sooner,” Lisa Halko, CNRA’s chief counsel, said during the Aug. 15 meeting.

Also under SB 905, the California Geological Survey has been tasked with identifying “high-quality, suitable locations” for CO2 injection wells.

Through its Geologic Carbon Sequestration Group, CGS will recommend monitoring techniques, such as plume tracking, to make sure the CO2 stays underground. The group will report earthquakes at storage sites or CO2 leaks to CARB, potentially with recommendations to change project operations.

Climate Package

The legislature passed SB 905 as a package with Assembly Bill 1279, which codified the state’s goal of achieving net-zero greenhouse gas emissions by 2045. (See Newsom Signs 40 Climate Bills.)

AB 1279 also set a target of reducing human generated GHG emissions by 85% compared to 1990 levels. It calls for maintaining net-negative GHG after the net-zero goal is met.

Carbon capture and sequestration (CCS) from industrial facilities and carbon dioxide removal (CDR) from the atmosphere both will be needed to achieve the AB 1279 goals, CARB concluded in its 2022 climate-change scoping plan.

Rajinder Sahota, CARB’s deputy executive officer for climate change and research, said the agency has long been aware of CCS — technology that is being used across the U.S. and Europe.

“But it wasn’t until very recently that all the scientists realized that the climate impacts are increasing at rates faster than we expected,” Sahota said during this month’s public meeting. “And so, in addition to reducing emissions, we also have to remove emissions. … That is what is called for by hundreds of scientists.”

Sahota said it’s critical to start deploying and scaling CCS and CDR technology this decade, to hit 2030 milestones on the way to the 2045 net-zero target.

As for the SB 905 requirements, Sahota said CARB plans to create a program portal to help with streamlining the permit process. CCS projects often need an array of permits, she said.

In addition, CARB must adopt protocols to support additional ways to store or use carbon dioxide, including carbon capture for use in products.

CARB already regulates carbon capture through its low carbon fuel standard; those regulations will be updated to meet SB 905 requirements, Sahota said.

Public Weighs In

One meeting attendee was Lorelei Oviatt, planning director for Kern County, where applications for several CCS projects are being processed. Oviatt said the geological survey might have a different view of site suitability compared to local government, which must consider issues such as setbacks and community concerns.

“Kern County has hundreds and hundreds and hundreds of acres that could be used, but they probably will not meet the local government’s requirements,” Oviatt said.

Another member of the public voiced concerns that SB 905 would open the door to widespread use of CCS.

“CCS projects must not be an end run around the primary statewide efforts to reduce and phase out fossil fuels,” she said.

According to the text of AB 1279, studies have found that CO2 removal methods and carbon capture, use and storage technologies are available, “but they do not negate the need to make drastic reductions in fossil fuel use.”

“Prioritizing direct emission reductions will help California to meet both its air quality standards and net zero greenhouse gas emissions,” the bill said.

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TVA Resists Congressional Call to Achieve 100% Clean Energy Sooner

The Tennessee Valley Authority does not appear ready to fast-track its decarbonization plans despite receiving a letter this month from 10 members of Congress urging it to chart a path to 100% clean energy by 2035.

The legislators asked TVA to decarbonize 15 years faster than it is currently planning, telling the utility it has a duty to “thoughtfully re-evaluate and further develop TVA’s long-term energy and decarbonization strategies” through its upcoming integrated resource plan and its ongoing Valley Pathways Decarbonization Study. It is disconcerting that TVA has the second-highest planned natural gas buildout of all major U.S. utilities, they said.

“As the country’s largest public power producer, the Tennessee Valley Authority should be leading the nation’s transition to a clean, renewable energy future, not dragging its feet,” the group of senators and representatives wrote. “Yet TVA continues to rely on fossil fuels that are not only supercharging the climate crisis but are subjecting TVA customers to electric grid blackouts and energy insecurity. It is long past time for TVA to begin the transition to a renewable and reliable electric grid.”

TVA plans to construct a natural gas plant and contract a new pipeline in Cumberland, Tenn., despite a lawsuit from environmental groups. (See TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.)

The legislators said that according to its last IRP in 2019, TVA will generate 34 million tons of carbon emissions by 2038 and likely will not meet a net-zero emissions goal until sometime after midcentury. They said TVA is forcing its ratepayers, who already have some of the highest energy burdens in the U.S., to shoulder the “costs of its delayed transition to clean, renewable power.”

The congressional members also said TVA leaned on MISO’s wind output during December 2022’s wide-ranging winter storm. They said TVA’s aging grid assets are vulnerable to ever-increasing climate risks.

TVA, however, insists it is a “national leader in carbon reduction” and continues to work to decarbonize. In a statement to RTO Insider, TVA said that since 2005, it has reduced carbon emissions by 54%, “one of the largest increases in the industry.”

Spokesperson Elizabeth Gibson said TVA will adhere to its existing plans to reduce carbon emissions 80% by 2035 “without impacting reliability or affordability.”

“We are working towards being carbon neutral by 2050 through an accelerated plan of increasing our solar and energy storage capacity and exploring new technologies, such as small modular reactors [SMRs], that can provide carbon-free power to meet demand at all times,” Gibson said. “We will continue working with our federal, state and local partners as we move forward to the clean energy system of the future.”

Gibson pointed out that eight of the letter’s 10 signatories are from either the Northeast or California, with only Rep. Steve Cohen (D-Tenn.), of Memphis, hailing from TVA’s territory. The letter included signatures from Sens. Bernie Sanders (I-Vt.) and Elizabeth Warren (D-Mass.) and Rep. Alexandria Ocasio-Cortez (D-N.Y.). Sen. Jeff Merkley (D-Ore.) also signed.

This year, TVA signed a multinational agreement on SMR development with GE Hitachi Nuclear Energy, Ontario Power Generation and Synthos Green Energy, a Poland-based wind and nuclear generation developer. The quartet will develop and invest in a standard design for GE-Hitachi’s BWRX-300 that they hope will be licensed and deployed in the U.S., Canada and Poland, among other countries. (See TVA Signs Multinational Nuclear Investment Pact on SMR Technology.)

Gibson also said TVA last year issued one of the nation’s largest requests for proposals for clean energy, at 5 GW, and has pledged to bring 10 GW of nameplate solar capacity online by 2035. She also said that over the first nine months of the year, 60% of its generation was from carbon-free sources, including nuclear, hydroelectric and renewables.

But the Southern Alliance for Clean Energy (SACE) said that if TVA continues its current trajectory and includes new fossil fuel-sourced plants in its upcoming IRP, it will struggle to reach net zero by 2050, “let alone 2035.”

“As an extension of the federal administration and the nation’s largest public power provider, TVA should be leading the way toward our energy future and the Biden administration’s carbon-free goals. Instead, TVA is planning to expand fossil fuel infrastructure and make long-term commitments to fossil fuels, which is a direction that’s clearly out of alignment with reaching our nation’s carbon-free goals,” SACE Executive Director Stephen Smith said in a statement supporting the letter.

Smith said TVA’s determination to build new gas plants is an indication that the public utility “has run afoul of its mission and the administration’s goals and must have oversight from an independent body.”

SACE said much is riding on TVA’s upcoming IRP because the next plan isn’t due until the 2028/29 timeframe, too late for a decarbonization overhaul in the utility’s fleet by 2035.

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Minnesota PUC Mulls Lifting Ban on Aggregated DR in Wholesale Markets

Minnesota regulators last week discussed whether now is the time to allow aggregators of retail customers to bid demand response into wholesale markets.

The Minnesota Public Utilities Commission weighed a decision to lift its 13-year-old ban on the practice at its Aug. 24 meeting (E999/CI-22-600). The commission also considered whether to direct its utilities to develop tariffs to allow third-party aggregators to participate in utility demand response programs, how it might verify or certify aggregators of retail customers for demand response or distributed energy resources before they are permitted to operate, and whether allowing aggregators to operate will require it to establish additional consumer protections.

Minnesota’s regulated utilities said a decision to lift the 2010 ban would be unwise, while commissioners and aggregators said it could move the needle on the sluggish amounts of demand response in the state and leave it better prepared for the clean energy transition.

The commissioners ultimately didn’t vote on removing the ban, instead tabling the docket, though they promised more exploration on demand response going forward.

Otter Tail Power Co.’s Cary Stephenson said he opposes lifting the ban. He said his utility already has made major investments to grow its own successful demand response programs. Stephenson said Otter Tail backs a structure where demand response is treated as a fully regulated program in a utility model.

“In our view, it’s not in the public interest to introduce [aggregators of retail customers] into that structure. … Customer confusion is one of our big concerns [and] cannibalization of the existing DR programs which have worked very well,” he said.

Stephenson predicted “significant administrative costs” associated with utilities coordinating with aggregators.

“Overall … we think there are significant material downsides,” he said.

Stephenson also said it’s premature for the PUC to decide on aggregation before FERC has issued an order in MISO’s Order 2222 compliance plan, which will open its wholesale markets to aggregators of distributed energy resources.

Minnesota Power’s David Moeller said aggregators could erode the state’s legal definition of service territories and the state’s authority to require tariffs. He said he wasn’t sure if the commission had the authority to force regulated utilities to file tariffs for noncustomers to incorporate aggregator participation, which would undercut their own DR offerings.

Xcel Energy’s Ian Dobson said his utility is working to achieve the state’s 2017 directive for Xcel to add 400 MW of additional demand response to its existing, 1,000-MW program. Dobson said to date, Xcel has added a net 170 MW in demand response after it lost some subscribed load.

Xcel Energy’s failure to meet the commission’s 400-MW additional demand response goal set in 2017 sparked the PUC’s discussion on unraveling the aggregator ban.

“We understand, obviously, the reasoning behind wanting to see if aggregators can help as well. … Our concern is just wanting to make sure that however the commission wants to go with this … that it provides the most benefit for our customers,” Dobson said.

Matt Schuerger, Minnesota PUC | NARUC

Commissioner Matt Schuerger said evidence in recent commission dockets shows Minnesota doesn’t have the robust DR program utility executives described. Schuerger said Xcel repeatedly has missed the mark and could have increased DR capacity by 1,000 MW by now. He said there is “lots available we’re not accessing.”

Schuerger said the 400 MW DR target “was a low bar in 2016.”

Commission Chair Katie Sieben asked whether Xcel is planning to include virtual power plants as a resource when it files its next integrated resource plan in February.

Dobson said he wasn’t sure.

“There’s a degree, I think of frustration, that is bubbling up out of me. We’re in this position — all of the utilities — because Xcel hasn’t quite met the standards that were imposed on the company from the 2017 IRP,” Sieben said. She said maybe the commission’s frustration with Xcel Energy not doing enough on the demand response front should be handled in the utility’s upcoming IRP filing, and not handled by blowing up a prohibition on third-party aggregation that could “seemingly disrupt a lot of apples on the apple cart.”

Dan Lipschultz, representing the Minnesota Rural Electric Association, said commissioners should wait a few years to see whether utilities sufficiently expand their DR offerings. He said if they’re not satisfied, they can always take the more drastic step of rescinding the aggregator ban.

“When we look at the need for and the value of demand response, it’s really important that we don’t use the rearview mirror and use a standard of what was needed 10 or 20 or even five years ago,” Schuerger said. “We’re accelerating this energy transition that we’re in; the Legislature has laid out clear guidance that we’re going to go even faster than the fast pace that we’re already moving.”

Schuerger said advance demand response is not just emergency use or peak shaving and is critical moving forward.

“I’m hopeful that we’ll keep this door open. I think that we’ve got to explore all avenues, all hands on deck, all tools available to get the load flexibility and the demand response that the math is showing us we’re going to need,” he said.

Commissioner Joseph Sullivan said he also viewed demand response as “more than just an emergency resource.” He said DR programs could do more and that there are innovative companies developing products that “quite frankly, utilities haven’t really thought about.” Sullivan said he wasn’t sure that permitting aggregators to operate would be much different from Minnesota’s decades-old decision to allow utilities to source from independent power producers.

“Isn’t this just another entity that can bid into the utility platform so it’s not fundamentally a breach of the compact? It’s just the market has evolved and it’s transforming?” he asked.

Utility representatives said the fundamental difference hinged on that independent power producers enter into power purchase agreements with utilities, and don’t contract directly with customers.

Sullivan said the commission could create a model with tariffs and oversight for third-party aggregators. He also pointed out that aggregators of retail customers in the wholesale market would have to operate under the boundaries of the MISO tariff.

“It’s not a free-for-all. It’s not the Wild, Wild West,” Sullivan said.

Lipschultz said the MISO tariff doesn’t account for Minnesota policies or equality and protecting the public interest.

Jon Wellinghoff, former FERC commissioner and chief regulatory officer at Voltus, testified in favor of lifting the ban. He said it would put pressure on Minnesota utilities and the larger MISO footprint to lower rates.

Wellinghoff said it makes sense the utilities, as competitors in a wholesale market, would try to dissuade commissioners from a repeal to retain their monopolies.

“We’re not talking about retail services. We’re not talking about upsetting the regulatory compact at the retail level. It has nothing to do with that. At all. Nothing whatsoever,” he said. “We’re not talking about a monopoly retail service. We’re talking about competitive wholesale programs.”

Wellinghoff said aggregators behave exactly like merchant generation in the wholesale markets. He also said it’s clear FERC for years has wanted demand response participation in wholesale markets.

Ingrid Bjorklund, speaking on behalf of the Advanced Energy Management Alliance, said the time is right to allow aggregators in the wholesale market.

“So much has changed since 2010, when this issue was last revisited,” she said. “More and more flexible resources are going to be needed as we move towards the clean energy economy and clean energy future, and allowing nonutility aggregators of demand response on both the wholesale and retail levels is really necessary to get there.”

Bjorklund said the administrative costs of allowing aggregators participation are “de minimis” and will be far outweighed by customer savings. She also said the Advanced Energy Management Alliance would support the commission sunsetting the ban at a future date.

Sarah Johnson Phillips, representing several large industrial customers in Minnesota, said mines, mills and factories have been trying for years to convince regulators to undo the 2010 order.

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FERC Approves Lower MISO Reliability Payments to Ameren Coal Plant

FERC on Monday approved a settlement to reduce payments to a Missouri coal plant under its system support resource (SSR) agreement with MISO. The commission accepted a trimmed-down, $8.3 million monthly payment to keep the two-unit Rush Island Energy Center operating (ER22-2721). The new amount brings the total annual Rush Island SSR revenue requirement to almost $100 million.

MISO last year deferred Ameren Missouri’s planned retirement of its 1.2-GW Rush Island plant to keep the grid reliable. Ameren originally proposed a $9.3 million monthly SSR payment as part of the deal, but FERC at the time warned that amount might be too high. (See FERC: Rush Island Plant’s Extension Essential to MISO Reliability.)

Ameren offered the lowered amount in a settlement agreement in May. FERC said the settlement appeared to be fair and in the public interest.

In early summer, MISO said it likely will require the assistance of Rush Island for about two more years to avert reliability issues until members complete transmission upgrades and bring wind, solar and battery storage projects proposed in Illinois and Missouri online. The RTO plans to renew the SSR for another year beginning Sept. 1, and once more in 2024. (See MISO Poised to Extend Missouri Coal Plant’s Life.)