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August 4, 2024

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PJM Stakeholders Complete 2nd Phase of CIFP

VALLEY FORGE, Pa. — PJM last week wrapped up the second phase of its Critical Issue Fast Path (CIFP) process to address resource adequacy concerns with two meetings about proposed changes to the RTO’s capacity market.

At May 30’s meeting, Constellation Energy proposed shifting to a prompt capacity auction held closer to the corresponding delivery year; the Consumer Advocates of the PJM States (CAPS) discussed states’ priorities and concerns around overhauling the Reliability Pricing Model (RPM); and American Municipal Power (AMP) presented changes to its conceptual design.

PJM also provided additional information about its contemplated switch to an expected unserved energy (EUE) model for measuring risk. (See PJM Presents Lessons Learned from Elliott, More CIFP Presentations.)

Thursday’s meeting saw presentations from the Natural Resources Defense Council on creating a seasonal capacity market; a former market design architect from ISO-NE providing information on a conceptual market design; Cornerstone Research’s Roy Shanker on his concerns about the current market structure; and Vistra on creating a credit market to value resource upgrades providing added reliability.

Stakeholders will begin developing formal packages during the third CIFP stage beginning June 14, when PJM will present its proposal.

Constellation Proposes Tighter Auction Schedule

Constellation’s Bill Berg said many of the inputs to the capacity auction could be more accurate and price signals could be improved if PJM holds capacity auctions six months to a year in advance of a delivery year. The status quo of holding auctions three years in advance makes it difficult to accurately forecast load and for generators to be sure whether they can procure firm fuel supply — a parameter PJM is considering having generators report prior to the auction.

Several stakeholders said the rationale for holding auctions three years in advance has been to allow the reference resource, currently a combined cycle generator, to be built between the auction clearing and the start of the delivery year to shore up capacity procurement shortfalls. Berg said investors monitor resource needs regardless of auction timing and are likely to make investments if they believe a region will be short on generation, regardless of auction timing.

Ryann Reagan, of the New Jersey Board of Public Utilities (BPU), questioned how a shortened time frame would interact with state retail auctions, noting that New Jersey has a three-year forward capacity product.

Berg responded that there’s a balance between price certainty and accuracy, which he believes is best weighed in favor of accuracy. Resources participating in state auctions with a longer lead time than a prompt auction would have to estimate PJM capacity prices when participating in state markets.

Constellation also suggested that compensating capacity resources at the end of the delivery year could improve performance incentives and lead to higher collections of any performance penalties the generator may accrue over the year.

While Berg said his company supports PJM’s proposal to set a minimum number of performance assessment intervals (PAIs) each year, market sellers must be able to reflect all risks and avoidable costs in their capacity offers.

CAPS Executive Director Greg Poulos said expanding the costs included in capacity market offers could run afoul of FERC’s 2021 order on PJM’s market seller offer cap (MSOC). (See Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute.)

“This seems like a dead-end to us because FERC already ruled on this,” Poulos said.

Berg also urged stakeholders to consider changes to the energy market, where he said PJM has put the onus of addressing reliability risks posed by forecast uncertainty and resource constraints, but it has had to resort to out-of-market actions to maintain operational reliability.

CAPS Outlines Advocate Concerns

As stakeholders discuss an overhaul of the capacity market, Poulos said state advocates are concerned about the Base Residual Auction (BRA) schedule, as well as how to ensure that market power is kept in check, performance incentivized and proper price signals are sent.

Advocates also lack firsthand insight into how the markets functioned during the December 2022 winter storm, also known as Elliott, making it difficult for them to evaluate proposals being discussed in the CIFP process, he said.

When considering changes to Capacity Performance (CP) penalties, Poulos said, it’s important to balance having penalties so high that generators risk bankruptcy after one event and having them so low that they don’t lead to better performance during future emergencies. Though performance was an issue during both the 2014 polar vortex and Elliott, he said CP likely did lead to increased readiness.

“The goal is not to bankrupt people — that is not helpful — but if you can’t perform, I don’t know what your value in this mix is,” Poulos said.

AMP Presents Revised Proposal

AMP revised the proposal it has been building throughout the CIFP process, which would replace the CP construct with a process for testing generators and penalizing them if they are not able to meet the amount of capacity they cleared. The changes aired May 30 would marry that concept with the proposed reworking of the performance penalty structure endorsed by the Members Committee last month but rejected by the PJM Board of Managers.

The revisions would shift the penalty rate and annual stop loss from being based on the net cost of new entry (CONE) to the BRA clearing price. AMP championed the language in the MC as a way of aligning market sellers’ capacity revenues with any penalties they’re assessed, while retaining an incentive to perform throughout the year.

Opponents of the language when it was before the MC argued that it would pose a reliability risk by cutting the penalty rate and stop loss by 90% without adding to requirements like winterization requirements.

PJM Presents Risk Modeling Analysis

PJM presented preliminary results of its analysis on the impact of switching to a reliability requirement based on an EUE model, which measures the amount of load that would go unmet during outages. The RTO currently uses a loss-of-load expectation (LOLE) model, which is a count of the number of outages expected. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)

In past CIFP discussions, PJM has proposed shifting the metric as part of its effort to improve risk modeling.

PJM’s analysis found that the EUE equivalent to the current one-day-in-10 reliability threshold would be around 1,800 MWh of lost load, with 96% of the outage risk concentrated in winter. Under the LOLE model, PJM estimates that 78% of the risk is in the winter, with the remainder being in summer.

PJM’s Patricio Rocha Garrido said winter outages tend to last longer and lead to more lost load, which he said is captured as increased winter risk through the EUE model.

The largest summer supply loss represented in the data was about 15 GW in July 2012, Rocha Garrido said, while 46 GW of generation was lost during Elliott.

James Wilson, a consultant to state consumer advocates, argued that the change would exaggerate risk and said that if being conservative in resource adequacy is a goal, that should be done through policy rather than modeling. He noted the analysis shown May 30 doesn’t account for climate change, which he said is likely to reduce the amount of risk in winter relative to summer by leading to warmer temperatures in both winter and summer.

Bruno-Patrick-2019-01-09-RTO-Insider-FI.jpgPatrick Bruno, PJM | © RTO Insider LLC

 

PJM’s Pat Bruno said the RTO plans to continue improving the modeling, including by incorporating climate change into the data. He added that PJM had run sensitivities that found that climate change was unlikely to move the needle much for the type of modeling under discussion. Future analysis is also likely to include the impact on the installed reserve margin (IRM) and resource accreditation.

Bruno said the planning and market structures are currently based on an assumption that risk is concentrated in the summer, but the analysis suggests that a rethinking of those rules may be needed to maintain future reliability.

Vistra Presents Credit Market for Reliability Upgrades

During Thursday’s CIFP meeting, Vistra presented a proposal to create tradable credits to be awarded to generators that make investments to increase their performance, which would also raise their capacity accreditation.

Erik Heinle, Vistra’s director of PJM market policy, said that such investments may not lead to more capacity clearing in the BRA; however, it will increase a generator’s performance obligation, making it more likely to be subject to penalties and less likely to receive bonus payments.

The credits would be tradable in a PJM market and could be used by a buyer to excuse a performance shortfall equal to the increased capacity accreditation. PJM would create weekly risk assessments based on factors such as load and intermittent forecast variation, outages and fuel supply surveys, which buyers and sellers could use to determine their estimates of being subject to penalties.

Credits would only be awarded for facility upgrades on a list PJM would create during each quadrennial review.

Heinle said the proposal would add a financial product to allow generators to mitigate their non-performance risk, while still retaining an incentive to invest in upgrades.

Vitol’s Jason Barker said similar transactions exist today through bilateral transactions or within larger companies that maintain generation portfolios containing resources that can offset each other’s risks. Heinle said a PJM marketplace would increase transparency and improve price discovery.

Vistra’s Muhsin Abdur-Rahman said the proposal could also reduce the Capacity Performance quantified risk (CPQR) component of generators’ capacity offers to correspond with the reduced risk.

PJM Capacity Market Fuel Assurance Accreditation Concept

PJM’s Brian Fitzpatrick discussed a possible addition to the proposal being crafted by PJM that would create tiers of fuel security paired with the effective load-carrying capability (ELCC) model for each level. The proposal is currently focused on natural gas but would likely be expanded to other resource types as well.

Generators participating in the BRA would be required to indicate whether they will have dual fuel, single fuel with firm supply or single fuel without firm supply.

Fitzpatrick said the proposal is meant to help identify a lack of capacity on a gas pipeline or encourage greater fuel subscription to incentivize pipelines to expand, rather than creating another penalty structure for gas generators.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said fuel supply needs to be looked at holistically, incorporating issues being addressed by the Electric Gas Coordination Senior Task Force and examining other fuel types as well.

NRDC Proposes Seasonal Market

The NRDC presented a series of priorities it believes CIFP proposals must address around managing resources’ performance risk, including accurately accrediting resources and avoiding double-penalizing resource characteristics through CP and accreditation.

Tom Rutigliano, senior analyst for the NRDC, said accounting for resources’ characteristics through accreditation is the most effective option, rather than creating eligibility criteria for capacity resources, penalties or combining approaches. He supported PJM’s proposal to expand the use of the ELCC model to all resource types on the basis that it can weigh generators’ performance against the disparate risks the grid faces for each hour throughout the year.

Creating a system like ELCC to evaluate multiple gas generators fueled by a single pipeline to determine the marginal capacity value could also improve accreditation by revealing whether a pipeline is likely to be oversubscribed during an emergency, he said.

Though he said it would likely be topic to explore after the CIFP process, Rutigliano suggested moving to a seasonal capacity market to resolve some of the issues that expanding ELCC would not address, including variable transmission constraints, price signals incentivizing winterization investments, and treatment of planned and maintenance outages.

Rutigliano said that subjecting resources, particularly intermittent ones, to penalties for underperformance owing to characteristics already priced into their accreditation amounts to penalizing them twice. During Elliott, he said, wind and solar both performed as expected, but solar resources were generally assigned penalties, while wind resources receive bonuses based on attributes included in their ELCC analyses.

Shanker Highlights Concerns with Market Structures

Consultant Shanker presented a series of suggestions for stakeholders to consider throughout the CIFP process impacting all proposals, including:

  • how the must-offer requirement relates to auction planning parameters and performance obligation during PAIs;
  • how power exported from PJM during emergencies affects the balancing ratio;
  • who is the beneficiary of export premiums if the capacity benefit of ties is removed;
  • how many of these issues result in hidden future transmission charges; and
  • how stochastic generation and common mode outages could cause locational impacts adverse to reliability.

The forecast pool requirement (FPR) and associated IRM are determined with the assumption that all resources holding capacity interconnection rights (CIRs) will offer into the capacity market; however, excepting intermittent resources from the must-offer requirement skews both parameters, Shanker said.

Shanker cited Independent Market Monitor studies showing that about half of such resources hold CIRs but have not been offering in auctions. Because the variable resource requirement (VRR) curve is derived from the FPR and IRM, this leads to overstatement of the reliability of the capacity procured through the BRA. He said the calculation of the capacity emergency transfer objective (CETO), capacity emergency transfer limit and locational deliverability areas’ reliability requirements cause the same issue. The issue also raises market power issues regarding holding CIRs but not using them, he contended.

Shanker also said that many market components, including the FPR, IRM and CETO, incorporate an infinite transmission assumption, which can also lead to overstated reliability by not taking location and intermittency into account, causing additional hidden transmission costs.

Shanker also called for eliminating the capacity benefit margin (CBM) and capacity benefit of ties (CBOT) when determining PJM’s reliability requirement in order to ensure the RTO can meet its own needs at a capacity price that matches the cost of resources required to reliably meet grid requirements. He noted that this should logically change the price of emergency assistance and that associated export revenues would flow to native load rather than into any potential penalty and bonus structures added to the current CP design.

Conceptual Capacity Market Exchange Presented

Dick Brooks of Reliable Energy Analytics presented how PJM could use an always-on capacity exchange (AOCE) with further development of the concept.

A former software architect of ISO-NE’s forward capacity market clearing engine, Brooks said the project was developed as a strawman design for the clean energy transition and was being brought before the CIFP to demonstrate that other paradigms are being created.

The market would use a shorter auction advance timeline with capacity prices determined using an exchange and clearing price similar to day-ahead energy markets. Capacity resources would be approved by the RTO and enter offers into the market to be bid on by customers.

The RTO would continue to determine the total amount of capacity needed for a location and time, which the RTO would issue its own reliability bids to meet needs in the short or long term. Bids exceeding the total amount of capacity needed wouldn’t be cleared to receive capacity payments.

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DOE Releases National Clean Hydrogen Strategy and Roadmap

The Department of Energy released a comprehensive Clean Hydrogen Strategy and Roadmap Monday that shows an “all-of-government” approach to making hydrogen key to not only radical decarbonization of the U.S. economy, but also to the center of ongoing industrial policy.

The release came at the start of an annual DOE five-day technical review of hydrogen research and development projects, attended by more than 2,100 people.

DOE first announced it intended to develop a comprehensive plan in September when it announced it would fund regional hydrogen hubs. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)

“President Biden’s clean hydrogen strategy is all about achieving the administration’s climate and economic goals to decarbonize our electricity sector by 2035 to reach net-zero emissions across the economy by no later than 2050 and to accelerate an American manufacturing boom,” Ali Zaidi, director of the Biden administration’s Climate Policy Office, said Monday.

“Clean hydrogen has the potential to dramatically reduce emissions from a variety of sectors as either a fuel or a feedstock, but particularly in the hardest to decarbonize: the industrial sector, heavy parts of the transportation sector, and some of the peaking elements of our power sector,” he said.

“Many of these applications have been seen as out of reach for near-term decarbonization. No more. We are rapidly advancing timelines for clean hydrogen deployment and deep decarbonization.”

Noting that up to $8 billion in matching grants were authorized in the Infrastructure Investment and Jobs Act, Zaidi said the clean hydrogen production tax credit will provide up to $3/kilogram for low-carbon hydrogen.  

“These programs are driving unprecedented levels of investment in building a clean hydrogen economy for the first time in this country,” he said. “There are already 12 million tons of clean hydrogen production facilities under development in the United States.”

Energy Secretary Jennifer Granholm, appearing electronically, described the road map as far more than just a government plan.

“Our road map lays out roles for the entire federal government. But this is also an all-of-America strategy. It’s a call to action for state and local and tribal governments for businesses in the nonprofit sector. It’s an invitation to environmental groups and energy justice advocates and more to help us shape this industry in a sustainable, holistic way,” she said.

Monday’s program introducing the 99-page document included interagency panels.

The report itself notes that the work is the result of months of workshops with government agencies, as well as industries, environmental groups and others.

“This inclusive and collaborative approach is critical to the success of this expansive technology. The report is meant to be a living strategy that provides a snapshot of hydrogen production, transport, storage and use in the United States today, as well as an assessment of the opportunity for hydrogen to contribute to national decarbonization goals across sectors over the next 30 years. The report will continue to be updated with collaboration across government through interagency coordination,” the study’s introduction states.

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NJ Legislators Probing Whale Deaths Hear No Clear-cut Conclusions

Mammal experts have found no evidence that a series of whale deaths on the New Jersey shore in recent months are related to preliminary undersea testing for offshore wind (OSW) projects, speakers told a New Jersey legislative committee May 18.

Several of the speakers who addressed the Assembly Science, Innovation and Technology Committee said there’s clearly more whale activity on the New Jersey shore now than a few decades ago. But why that is and how it is linked to the deaths requires careful and lengthy scientific analysis, which has yet to be completed.

“In all cases, including those animals in which evidence of ship strike was found, the pathology results are still pending,” said Sheila Dean, director of the Marine Mammal Stranding Center (MMSC), of Brigantine, N.J. She said the organization is investigating the deaths under a permit from the federal National Oceanic and Atmospheric Administration (NOAA) Fisheries, and the work is ongoing.

“This means that the final cause of death has not been determined,” she said. “To assign blame before the scientific data is analyzed, interpreted would be premature.”

Of nine whale deaths under scrutiny, three were floating out at sea, so the MMSC could do little in the way of analysis, she said. The organization did necropsies on the remaining six, she said.

Historically, studies have shown that whale injuries and deaths on the East Coast are commonly the result of being hit by ships, becoming entangled in cables or fishing nets or being felled by disease, speakers told the committee.

Danielle Brown, lead humpback whale researcher for Gotham Whale, a New York City-based advocacy organization, said whale sightings in the New York Harbor began to increase around 2011, and strandings began escalating soon after.

“The most recent mortality event may have begun in 2016,” she said, referring to the pattern of deaths. “But strandings and interactions between humpback whales and human activities have been on the rise long before that.”

The difficulty in understanding whale activities and their interactions with humans is that data is scarce, she said.

“Ultimately, the takeaway here is that things are changing rapidly in New Jersey, especially when it comes to humpback whales, and there are many data gaps,” she said. “These whales are now a consistent part of our ecosystem.”

OSW Moratorium

The hearings were triggered by the persistent suspicion raised by some project opponents that the whale deaths are somehow tied to offshore wind projects. No construction has begun on any New Jersey shore wind projects, and the developer of the first project, Ørsted, is conducting only preparatory sea floor analysis.

Ørsted’s 1,100-MW Ocean Wind 1, which is the state’s first offshore wind project and was approved in 2019, is scheduled to begin construction next year. The state Board of Public Utilities (BPU) subsequently approved two more projects, the 1,148-MW Ocean Wind II and 1,510-MW Atlantic Shores, in the state’s second solicitation in 2021. (See NJ Awards Two Offshore Wind Projects.)  

The projects have faced opposition from the tourism and fishing industries, as well as some residents, who are concerned about the impact and fear turbines will mar the view of the sea and deter visitors. The commercial fishing sector fears they will not be able to fish as much in the areas they work at present.

The whale deaths have provided opponents with another issue to raise. Republican Reps. Jeff Van Drew and Chris Smith in March held a hearing on the issue. Van Drew has called for a moratorium on the OSW project development while the whale deaths are investigated.

The issue was one of many raised by Cape May County in a resolution passed May 23 stating that the county “objects to and opposes” Ørsted’s two New Jersey projects” and wants to stop the projects unless the developer agrees to mitigate the impact. The county also has appealed a ruling by the New Jersey Board of Public Utilities granting Ørsted an easement across Cape May property so an underground cable could be installed linking Ocean Wind 1 with the grid. (See County Contests Tx Easement for NJ’s 1st OSW Project.)

The resolution said the “recent, unprecedented deaths and strandings of marine mammals” on the Jersey coast are of “utmost concern” to the county, adding that the State of New Jersey’s claim that there is no connection between the deaths and the OSW projects is “inconsistent with reality.”

The resolution says that in a 2018 lawsuit filed in federal court, the state itself opposed offshore drilling by arguing that “seismic testing activities” would have a “negative impact on marine mammals’ health and abundance” and hurt tourism. The resolution says the county does not find “acceptable” the state’s argument that it does not know what is causing the whale deaths “but that they somehow know for certain that the deaths are not related in any way to the activities” of Ørsted.

Prey Fish Migration

Yet the state’s position is shared by federal officials. A spokeswoman for NOAA, which in a January press conference said it did not believe the survey work on offshore wind projects could be tied to the whale strandings, told NetZero Insider in an email two weeks ago that it has not changed that position.

“At this point, there is no evidence to support speculation that noise resulting from wind development-related site characterization surveys could potentially cause mortality of whales, and no specific links between recent large whale mortalities and currently ongoing surveys,” said NOAA spokeswoman Andrea Gomez.

The Final Environmental Impact statement for Ocean Wind 1, which the U.S. Bureau of Ocean Energy Management (BOEM) released in May, concluded that the impact of the project on whales would be “moderate” but that the cumulative impact of the project, along with others, would be moderate to major for the North Atlantic right whales. (See BOEM: Major Visual, Scientific Impacts from NJ’s 1st OSW Project.)

A federal judge on May 17 rejected the argument that an offshore project could harm whales, including the North Atlantic right whales, an endangered species, in a lawsuit against the Vineyard Wind 1 offshore wind project. The judge ruled that the originators of the lawsuit, Nantucket Residents Against Turbines, had not made their case. (See Lawsuit Against Vineyard Wind over Threat to Whales Tossed.)

Shawn M. LaTourette, commissioner for the New Jersey Department of Environmental Protection, told the Assembly committee hearing that one explanation for the increased number of whale strandings is that one of the prey fish that whales eat, menhaden, are moving “landward,” as the habitat of the small fish gets disrupted by climate change.

“And as these prey fish move landward, their predators are following them. Their predators include whales,” he said. “The culprit is a changing climate, and our inability societally to get it under control.”  

But one lawmaker was skeptical of the argument.

“It’s a little hard for us to just assume that that affirmation is real,” said the lawmaker, who was not identified in the audio feed of the meeting, asking for scientists to testify who could “confirm your affirmation.”

LaTourette said the explanation was the product of work by state-employed scientists who compiled the state’s Scientific Report on Climate Change released in June 2020.   

Sound, Vessel Strike, Disease Impact

Douglas Nowacek, a professor of conservation technology and environment and engineering at Duke University, told the committee he didn’t agree with the argument that undersea sonar used to analyze the sea-bed floor could be severely damaging the whales.

Nowacek, who said he has spent 20 years looking at the effects of noise on cetaceans — aquatic mammals such as dolphins and whales — said there could be two types of noise sources at use undersea. But neither would have a major impact on disorienting a whale, he said, adding that he agreed with NOAA Fisheries on this issue.

One type of sound, high-resolution geotechnical, is used to map the ocean bed and also to look at babies in the womb, he said. But the frequency of that source would be too high for a whale to hear, he said.

“Those high frequency sources I would consider de minimis [of little importance] in their potential for impact on basically all marine mammals,” he said. “They are extremely high frequency, which is out of the hearing range of these animals, and they’re also … absorbed extremely quickly.”

The second source, boomer markers or chirpers, which are used for oil and gas exploration, would be too weak to harm a whale when used for OSW projects, he said. These need to analyze only the top 50 meters or so of sea-floor sediment, and so the intensity is perhaps 100,000 times lower than the intensity when they are used to look for fossil fuel sources thousands of meters into the sea bottom, he said.

“Can the sources disorient animals such that they would die instantly? No?” he said. “Do we worry about them getting a little disoriented and deviating around a path? That could certainly happen.”

Robert A. DiGiovanni Jr., chief scientist at the Atlantic Marine Conservation Society, said that when he began studying whale strandings in the New York area in the 1990s, he would see one about every 617 days. The frequency began to increase in about 2007, and by 2017 there was one about every 63 days, he said. It has been “hovering” around one every 26 days for a number of years, he said.

“We are currently in the middle of three unusual mortality events for large whales: the North Atlantic right whale, the minke whale and the humpback whale. All of them have started since 2016,” he said.

“Vessel strike and entanglement are the leading causes of mortality for the humpback whales and for the right whales,” he said. The minke whales are felled more by a “biological process, more of a disease process,” he said.

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NERC’s Standards Process Changes Pass on Second Ballot

NERC’s second attempt to gain industry approval for proposed changes to its Standards Processes Manual (SPM) succeeded last week, as stakeholders gave overwhelming consent to the revisions.

The measure passed with 183 votes out of 260 members of the ballot body and only seven votes against it. Taking into account NERC’s weighting of the segments in the ballot pool, that gave the proposal a 97.49% approval. Twenty-eight members of the ballot body abstained, and 42 did not cast a vote.

The large number of positive votes is a significant turnaround from January when the first version of the SPM revisions went before industry. That proposal failed in March after garnering only 76 affirmative votes and 118 against it, for a weighted value of 37.7%.

NERC’s Board of Trustees issued an order to revise the SPM at its November meeting because of concerns that the ERO’s “deliberative” standards development process was not keeping up with the increasingly rapid pace of industry change. (See NERC Board Member Argues for Increased Authority.)

The initial proposal would have, among other things, removed the requirement for a final ballot to confirm the results of the most recent successful ballot and allowed standard authorization requests (SARs) proposed by the board to be posted for an informal rather than formal comment period. The latter change would have meant the SAR drafting team would not be required to provide a formal response to industry comments.

However, the negative reaction from industry was strong, with commenters such as the Northern California Power Agency fearing that the proposals would undermine “due process, openness and balance of interests.” Respondents objected to shortening later ballot periods on the grounds that this would give industry less opportunity to weigh in and to eliminating the final ballot, arguing that industry needed to be able to approve of any changes the standard drafting team made following a successful ballot. (See EPSA Forum Speakers Focus on Hurdles to Energy Transition.)

The newest set of changes were intended to allay these objections. Updates included clarifying that formal comment and balloting periods following the initial 45-day period “may be as few as 30 days” but must be at least that length, as opposed to the last proposal, which did not specify a time limit. The new revisions also removed language suggesting that SARs proposed by NERC’s board would not be subject to a 30-day formal comment period.

A standards action may still conclude after a successful ballot without requiring a final ballot, but only under very specific circumstances. The previous ballot must have achieved at least 85% weighted segment approval. In addition, the drafting team must have “made a good faith effort at resolving” industry objections, have responded in writing to comments and be proposing no further changes to the balloted documents.

These changes mostly met with approval from those who withheld their support last time, but some still registered objections to the second round of revisions. For example, Kimberly Turco of Constellation said that while removing the idea of allowing board directives to bypass the initial formal ballot was a good step, letting any SARs avoid the normal process should still be considered going too far.

“SARs that bypass formal posting/commenting are in direct conflict with the concept of ‘working with all stakeholder segments of the electric industry … to develop reliability standards,’” Turco said. “Allowing the latitude to bypass the existing input from the industry is not in the spirit of collegial development of the NERC reliability standards and may propagate a bias of individuals involved, including the Standards Committee, that may not recognize or appreciate specific nuances of the draft SAR when evaluated by the industry.”

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FERC Partially Approves PSCo’s Queue Changes

FERC on Friday partially approved Public Service Company of Colorado’s (PSCo) proposal to amend its generator interconnection process with changes intended to prevent unready projects from clogging the queue (ER23-629).

The Xcel Energy (NASDAQ:XEL) subsidiary in 2019 received commission approval to transition its interconnection process to a cluster study approach, but projects not ready to move forward have continued to slow the process for those that are ready. The unready projects end up withdrawing, leading to problems such as unreliable study results, cascading restudies and delays.

The most recent study cluster has been delayed for two years, PSCo noted, preventing the utility from meeting customers’ requested in-service dates and hindering future projects from estimating their interconnection costs.

Under PSCo’s existing rules, projects can qualify for the queue if they have offtake agreements, are part of a resource plan or have an in-service date. Developers can also enter a project into the queue if they submit additional security in lieu of making a “readiness demonstration.”

In its initial filing, PSCo sought to remove the option for projects to submit additional security, contending that developers picking that option have often wanted to use a large generator interconnection agreement to market their projects but wound up subverting the goal of a speedier processing of interconnection requests, even causing more advanced projects to withdraw from the queue process altogether.

The initial proposal would have replaced the security option with a “generation deployment plan” that would require a developer to have a plan to secure permits, build the facility and finance it. The generation deployment option would also include a $7.5 million deposit, along with withdrawal penalties that vary by project size and rise the later in the queue a project pulls out.

The Solar Energy Industries Association, Avangrid and HQC Solar argued the changes were too stringent and would prevent independent power producers from entering the utility’s queue. But they did win support from NextEra Energy, which said that while the outcome would be more restrictive than FERC’s pro forma rules, the changes make sense in Colorado, where generators generally transact with load-serving entities that can trigger clusters of resources in the queue.

PSCo came back with a later filing that added an option for developers using the generation deployment option to pay a $7.5 million security payment and face the heightened withdrawal penalties, without requiring them to meet the other requirements, effectively restoring the security option — which SEIA said was better than the first proposal.

The proposal led to a deficiency notice from FERC, with staff asking how PSCo would evaluate what constitutes a reasonable permitting plan under the generation deployment plan. The utility said it would accept permitting plans that demonstrate an understanding of the land use and environmental permitting process in Colorado.

Staff also asked how the utility arrived at the $7.5 million security amount and associated withdrawal penalties. PSCo said the old withdrawal penalties were capped at $2.5 million, which was not enough, and that $7.5 million is still lower than average interconnection costs.

Security Option Remains

FERC rejected PSCo’s initial proposal, but it accepted the alternative in which projects can put up $7.5 million in lieu of being ready to deploy.

“We find that PSCo’s proposal to require interconnection customers to either meet the requirements under the proposed generation deployment option or one of PSCo’s three existing, unchanged, commercial readiness demonstration options alone is likely too stringent for independent power producers to meet,” FERC said. “Based on the record in this proceeding, many independent power producers currently use the security in lieu of a commercial readiness demonstration option in PSCo because it is difficult for them to meet the requirements for the other existing commercial readiness demonstration options.”

FERC also agreed with protesters that the milestones in the generation deployment option might be misaligned with typical development cycles and business practices for IPPs.

But allowing projects to post $7.5 million and raising withdrawal penalties will help speed up the queue because PSCo has shown that speculative projects are slowing the process down, FERC said. The higher security requirement will cut the number of speculative projects and thus the associated withdrawals and restudies.

In the two clusters run in 2020, projects representing 66% of the requested interconnection capacity withdrew from the queue, as did 30% the next year, which shows that the current security and withdrawal penalties are not enough to deter unviable projects from getting in line.

Other Penalties

PSCo had also asked to increase to $5 million the security and penalty for projects that sign an interconnection agreement but do not enter service (except for those posting the higher $7.5 million security). It had penalized such projects under a formula of nine times study costs, which topped out below $1 million.

FERC approved the $5 million figure, saying it will increase the likelihood that projects with an interconnection actually get built. The amount is justified because projects that pull out are especially problematic because they cause more restudies than earlier withdrawals, the commission found.

None of the new fines or security requirements will go into effect until 120 days after the rules become effective, which FERC said gives projects that entered the queue under the old rules enough time to pull out in light of the new risks. PSCo initially filed for a 30-day transition, but then offered the 120 days in a subsequent filing to avoid favoring its own generation when it holds upcoming resource solicitation that projects presently in the queue can participate in, FERC said.

Commissioner Allison Clements concurred with the order, saying further changes might be needed to make PSCo’s interconnection process fairer when it comes to how penalties are distributed. Withdrawal penalties are currently used to fund generation interconnection studies, but the tariff does not address how such funds should be distributed when they exceed relevant study costs — a risk that is now higher, she said.

“I encourage PSCo to assess whether further changes to its [large generator interconnection procedures] may be necessary in light of the commission’s approval of increased withdrawal penalties,” Clements said. “If PSCo’s proposal renders its existing mechanism for distribution of withdrawal penalties unjust and unreasonable and further changes are not forthcoming, then action pursuant to Section 206 of the Federal Power Act may be appropriate.”

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Berkeley Seeks Rehearing of Gas Ban Reversal

Attorneys for the city of Berkeley, Calif., have asked the 9th Circuit Court of Appeals to rehear a case overturning the city’s effective ban on natural gas appliances in new buildings, a first-of-its-kind rule that led to two dozen other local governments adopting similar restrictions.

On April 17, a three-judge panel reversed a district court’s ruling and agreed with the California Restaurant Association that the city’s gas ban is preempted by the federal Energy Policy and Conservation Act (EPCA), which gives the U.S. Department of Energy authority to set energy conservation standards for appliances such as furnaces and water heaters.

The ruling called into question building decarbonization efforts in the 9th Circuit’s nine Western states and raised the possibility of the ruling having a national effect. (See Impact of Berkeley Gas Ruling Debated.)

On May 31, Berkeley’s city attorney and outside law firms asked the 9th Circuit to rehear the case before an 11-judge en banc panel.

“The panel’s invalidation of the City of Berkeley’s prohibition on natural gas infrastructure in newly constructed buildings is based upon fundamental legal errors that threaten vital health, safety, and environmental regulations throughout the Circuit,” the lawyers wrote in their rehearing petition.

The decision could “disable state or local regulations” that limit the use of gas appliances, they said.

“That ruling is seriously wrong and highly consequential,” the petition says. “Indeed, the [legal] regime the panel discerned in this unheralded 35-year-old provision [of the EPCA] is in every way extraordinary. It makes the federal government’s establishment of an efficiency standard for an energy-consuming product the trigger for automatic displacement — but not replacement — of vast swaths of health and safety protections that serve purposes wholly unrelated to conserving energy.”

Berkeley adopted its ordinance prohibiting the installation of natural gas piping in new buildings in 2019, making it the first U.S. jurisdiction to effectively ban new natural gas use. Since then, more than 70 jurisdictions have required or incentivized all-electric new buildings, according to the Building Decarbonization Coalition, with about 25 following Berkeley’s approach. Most are in California.

The city said its ordinance was meant to reduce the environmental and health hazards of using natural gas for cooking and heating.

The California Restaurant Association sued, saying the EPCA preempted the ordinance.

A federal judge dismissed the case, saying the federal law preempted only ordinances that facially or directly regulate covered appliances.

A three-judge panel of the 9th Circuit disagreed, saying “such limits do not appear in EPCA’s text.”

“By its plain text and structure, EPCA’s pre-emption provision encompasses building codes that regulate natural gas use by covered products,” the panel said. “And by preventing such appliances from using natural gas, the new Berkeley building code does exactly that.”

In their rehearing petition, Berkeley’s lawyers argued the three-judge panel had wrongly interpreted the law and 9th Circuit precedent, arriving at a conclusion that undermined cities’ ability to enact health-and-safety ordinances.

“The en banc court should disavow this vast and unauthorized preemption regime and the decision’s federalism-denying interpretive approach,” they wrote. “The decision disrupts the coherent and effective administration of an important federal statute, overrides many existing measures similar to Berkeley’s, and improperly denies States and municipalities authority to address matters at the core of traditional state authority.”

The restaurant association and other interested parties next have an opportunity to respond.

States and cities that filed amicus briefs supporting Berkeley previously included California, Maryland, New Jersey, New Mexico, New York, Oregon, Washington, Massachusetts, Washington, D.C. and New York City. They, too, can weigh in on the rehearing request.

The rehearing petition and responses will be sent to all of the 9th Circuit’s 28 active judges, who will vote on whether to grant the request.

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Lawmakers, White House Promise More Work on Permitting After Debt Deal

Even before the Senate on Thursday passed the Fiscal Responsibility Act (H.R. 3746) — the bipartisan deal to lift the U.S. debt ceiling that also included provisions related to energy infrastructure permitting — lawmakers on both sides of the aisle were talking about the work still ahead to truly streamline and accelerate the process and construction.

Signed by President Joe Biden on Saturday, the new law sets time and page limits on environmental reviews under the National Environmental Policy Act (NEPA) and calls for designation of a single federal agency to lead reviews and issue the final environmental evaluation, provisions that already had general bipartisan support. It also expands the use of “categorical exclusions” exempting projects from NEPA evaluations but does little to advance the buildout of vitally needed interregional transmission, a top Democratic and industry priority. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)

“As it sits right now, I feel like we just lost two years,” Rep. Sean Casten (D-Ill.), co-chair of the House Sustainable Energy and Environment Coalition, told E&E News on Wednesday.

While crediting Biden for getting the deal done and averting a potentially disastrous U.S. default, Casten said White House negotiators “totally messed up the transmission piece, and they didn’t deal with us on the level about what they had. And so, we didn’t know how bad they botched it until after we saw the text.”

Casten was referring to the FRA’s call for a study on the need for transmission to support interregional transfers of power for grid resilience and reliability, which NERC and FERC now have two and a half years to complete.

“There is absolutely no good reason why anybody needs to spend two years studying a problem that has been asked and answered 15 times,” Casten told E&E after his attempt to amend the bill was killed in the House Rules Committee.

Casten was one of several lawmakers quoted in post-deal analyses of the next moves, if any, on “permitting reform,” as the issue is commonly referred to.

On the Republican side, Sen. Kevin Cramer (R-N.D.) saw the permitting issue going “one of two ways.”

“One way might be to check the box — ‘We did this’ — and then never think about it again,” Cramer said, according to The Hill. “The other possibility would be that we create a little bit of momentum and say, ‘OK, now let’s get serious and drill down a little bit.’ I hope it’s the latter.”

Similarly, Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee, described the FRA as a “jumping point to start off again in our bipartisan talks,” The Hill reported. Her particular target is “judicial reform”: cutting down the six-year time frame now allowed for legal challenges to NEPA reviews, which the FRA did not include.

Industry trade groups also urged Congress to move ahead with more comprehensive initiatives on permitting and transmission.

Christina Hayes, executive director of Americans for a Clean Energy Grid, said her organization “believes that setting timelines for federal environmental reviews is a helpful first step but is only the beginning. While we do not believe that an interregional transmission study is needed, we hope that it can be completed quickly, building on efforts already underway at FERC, to ensure buildout of the transmission we need to keep the lights on.”

The American Clean Power Association seconded the motion. “ACP is appreciative of the steps taken to include much-needed reforms to improve efficiency of the permitting process for clean energy projects,” said CEO Jason Grumet. But “it’s critical that Congress build upon these initial steps and tackle comprehensive, meaningful reform to improve our nation’s clean power transmission capabilities and bring about the clean energy future America needs.”

BIG WIRES Nixed 

A drive for bipartisan permitting legislation had been a key focus in both the House and Senate in May, before the tense negotiations on the debt ceiling overwhelmed work on other issues in Congress and at the White House.

Biden issued a fact sheet outlining his permitting priorities, and Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources (ENR) Committee, declared his intention to have bipartisan legislation hammered out before Congress begins its August recess. (See Podesta Lays out Biden’s Priorities for ‘Permitting Reform’.)

House Republicans’ original debt ceiling package, the Limit, Save, Grow Act (H.R. 2811), included a previously passed energy bill, the Lower Energy Costs Act (H.R. 1), with provisions that would accelerate permitting of fossil fuel projects, but without any mention of clean energy or transmission.

Capito and ENR Ranking Member Sen. John Barrasso (R-Wyo.) also introduced bills primarily focused on accelerating the leasing and permitting of oil and gas projects and slashing the window for NEPA legal challenges from six years to 60 days.

On the Democratic side, Manchin and EPW Chair Tom Carper (D-Del.) each introduced bills that called for two-year time limits on NEPA reviews but also contained provisions on transmission. Manchin’s bill would cement FERC’s authority to permit transmission deemed in the national interest. Carper’s would authorize millions in federal funding to support broad community engagement in permitting processes, as well as training programs to ensure federal agencies are able to hire staff with the needed expertise. (See Carper Throws Progressive Bill into Senate Permitting Debate.)

Sen. John Hickenlooper (D-Col.) and Rep. Scott Peters (D-Calif.) added to the ongoing debate with their Building Integrated Grids With Inter-Regional Energy Supply (BIG WIRES) Act, which would require transmission planning regions, as defined by FERC, to be able to transfer at least 30% of their peak demand between each other. The bill calls on regions to pursue a range of options to achieve this target, from building new transmission and upgrading existing lines to cutting demand through energy efficiency.

BIG WIRES was on the table as part of the debt ceiling negotiations, according to The Washington Post, but was nixed by Reps. Cathy McMorris Rodgers (R-Wash.) and Jeff Duncan (R-S.C.), arguing that Republicans needed more time to review the bill. McMorris Rodgers is chair of the House Energy and Commerce Committee, while Duncan leads the committee’s Energy, Climate and Grid Security Subcommittee.

The law’s much-criticized transmission study was the result.

Without directly mentioning his bill, Hickenlooper expressed disappointment with the FRA’s permitting provisions. “I don’t feel that we got what I’d hoped we would get, and I feel like we gave up a little more than I would’ve wanted to give up,” he told E&E.

Green Pivot Ahead?

The FRA’s provisions calling for expedited completion of the Mountain Valley Pipeline (MVP) were another flashpoint during Senate debate on the bill Thursday. The 303-mile, 94% complete natural gas pipeline has been a top priority for Manchin, who until now had been unsuccessful in getting it into must-pass legislation.

Sen. Tim Kaine’s (D-Va.) amendment cutting the project out of the bill was voted down, with some Democrats saying they agreed with Kaine but did not want to threaten quick passage of the FRA, The Post reported.

A key question now is whether, with completion of the MVP finally secured, Manchin will still push for a more comprehensive bipartisan permitting bill. As ENR chair, he has a formidable track record as a gatekeeper on issues and nominations he does not support, and he is facing a potentially tough re-election campaign against West Virginia Gov. Jim Justice (R) in 2024.

White House press secretary Karine Jean-Pierre on Friday included permitting in a list of issues Biden still hopes to tackle, but the president did not mention it in his prime-time address to the nation that evening.

Administration officials speaking at The Economist’s Sustainability Week US conference in D.C. on Wednesday stressed that work on permitting and transmission will continue.

“The job [on these issues] is definitively not done,” said Andrew Mayock, federal chief sustainability officer. “Permitting remains a really important piece of the agenda … and I think it’s safe to say that there is more to do, and the White House will continue to push on that until we get where we need [to be].”

Answering a question about the FRA-mandated transmission study, Gene Rodrigues, the Department of Energy’s assistant secretary for electricity, said the study could have a positive impact by bringing “more people to the table to start thinking about what grid modernization means, and it’s not changing out just poles and wires. It’s about everything to do with how we plan, operate and invest in our system.”

But, he said, “does that mean … everything else stops, and then we wait for that [study] to be done? Absolutely not. … Let’s bring more people into the conversation, but let’s continue moving forward with what needs to be done to support the reliability, resilience, affordability and security of America’s grid.”

Industry analysts ClearView Energy Partners even see a possible “green pivot” now that the debt deal is done and “the White House may not worry as much about alienating fossil-friendly Democrats or the GOP. … The White House may also seek to balance its support for MVP with new strictures on fossil fuels.”

ClearView pointed to a Friday notice from the Interior Department withdrawing 336,404 acres surrounding Chaco Culture National Historical Park in New Mexico from potential mineral leasing and mining. The park marks the site of a once-thriving center of Pueblo culture, which existed between the 9th and 12th centuries.

‘Reasonably Foreseeable’

The implementation of the FRA and its likely impacts on permitting and clean energy deployment in general also will likely become a matter of close political scrutiny in the months ahead, especially for GOP lawmakers.

While the bill calls for slashing time for NEPA reviews, from more than four years to two years for a full environmental impact study, hitting those deadlines may prove challenging.

The permitting provisions of the law are largely based on the Building U.S. Infrastructure through Limited Delays & Efficient Reviews (BUILDER) Act, which Rep. Garret Graves (R-La.) first introduced in 2021.

A chief GOP negotiator on the debt deal, Graves has said the new law would cut not only the time, but also the scope of NEPA reviews to “reasonably foreseeable environmental impacts,” language taken from the BUILDER Act.

Speaking at a press conference announcing the deal May 28, Graves said, “NEPA has grown to just study all these things that don’t have anything to do with the environment, which I would argue … has worked against the protection of the environment. So, we’re trying to refocus the scope back on that, on the environmental impacts, and making sure we get the best environmental outcomes.”

However, while the FRA incorporates many provisions of the BUILDER Act, it does not include that bill’s definition of “reasonably foreseeable environmental impact.” As defined in the U.S. Code, it is one that is “sufficiently likely to occur such that a person of ordinary prudence would take it into account in reaching a decision.” Whether this definition is broad enough to include climate change or public health impacts will likely be a matter of ongoing debate and litigation.

The impact of the FRA’s page limits also is uncertain. The law does limit each EIS to 150 pages, or 300 for “extraordinarily complex” projects, but it places no limits on appendices for such reports, which can run into hundreds or even thousands of pages. For example, the Bureau of Ocean Energy Management’s recently released final EIS for the Ocean Wind 1 offshore wind project comes in four volumes, with 570 pages for the EIS itself (Vol. 1), plus 1,760 pages of appendices (Vol. 2-4). (See BOEM: Major Visual, Scientific Impacts from NJ’s 1st OSW Project.)

Another question raised at The Economist conference was whether the FRA’s clawback of $20 billion in Inflation Reduction Act funding for the Internal Revenue Service might affect the agency’s ability to deliver the needed guidance for all the IRA’s clean energy tax credits.

Heather Boushey, a member of the White House Council of Economic Advisers, cautioned that the clawback could send “a signal that that’s maybe a cookie jar we can keep pulling from.”

“It is clear in the short term — at least we are hearing from our Treasury colleagues — that they will be able to do their work, even with these cuts,” Boushey said. “But I do think that we, as people who are concerned about climate, given how much of this is being done through the IRS, we need to be making sure that [Treasury] is on our checklist of agencies that we are watching very closely.”

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MISO Wants Tougher Obligations on Queue Entry and Exit

CARMEL, Ind. — Faced with an exponential rise in interconnection requests, MISO last week announced that it is aiming to make its queue a more exclusive club through new rules.

The grid operator said it needs stricter requirements for developers to enter and exit the generator interconnection queue so it can make its studies more manageable.

“We need to govern the rules for exit and entry. We believe that will improve our queue,” MISO’s Andy Witmeier said at the Planning Advisory Committee’s meeting Wednesday. He said that if MISO imposes more requirements on land ownership, restricts the conditions for penalty-free withdrawals and increases some fees, it will shrink annual queue entrant classes.

Witmeier said 2022’s 171-GW queue class alone eclipses the typical systemwide 123-GW summer peak. MISO is bracing for another record-setting queue volume in 2023.

“It’s significantly more generation than would ever be built in MISO over the next few years, and there are concerns over how to study it,” Witmeier said. “More requests mean more points of interconnection and more study. There are more [hypothetical] overloads because of the sheer amount of capacity. That requires more engineering study.”

If MISO could cut down on the amount of “speculative requests,” it would result in study assumptions that better resemble the actual future dispatch, he said. “Smaller queue sizes mean faster results.”

Witmeier said it currently does not cost that much to enter MISO’s queue. And he said the RTO’s penalty-free withdrawal policy allows most interconnection customers who withdraw requests to get most of their money back. The $4,000/MW first milestone payment MISO requires of its projects is a “low bar” and represents only about 4% of the RTO’s approximate $100,000/MW financial feasibility threshold for the cost of network upgrades, he said. MISO’s deposits were last upped in 2018 and need to be increased, he said.

MISO will propose a package of alterations at the Planning Advisory Committee meeting in July, Witmeier said. After that, the RTO hopes to file a proposal with FERC in the third quarter and receive approval with enough time before year-end to close the 2023 queue application window. The RTO said it will keep the deadline open-ended until it receives FERC approval on the changes.

MISO was already planning to postpone the application deadline for its 2023 cycle of projects past its usual September cutoff. (See MISO: No Deadline Yet for 2023 Queue Applications.)

Witmeier said MISO is aware that enacting stricter requirements on queue entry can be perceived as it hindering generation development. But he said the real impediment to generation development is the flood of requests — with uncertain project plans among those — that bog down the study process and shift network upgrade costs to other projects. He added that only about 20% of the interconnection requests that enter the queue ever become realized generation projects.

Brattle Group Principal Johannes Pfeifenberger asked if MISO was worried that by restricting the entry of interconnection customers, it will raise the costs of network upgrades because there are fewer generation developers to split them.

Witmeier said he does not believe MISO will encounter that problem because it performs adequate backbone transmission planning through its long-range transmission plan (LRTP) portfolios. He said MISO avoids using its interconnection queue as a means to build major transmission. He also said the first, $10 billion LRTP portfolio likely drove up interconnection requests in 2022.

Witmeier said he plans to reach out to stakeholders to get their ideas on how to make queue entrances and exits less heavily trafficked.

The Sustainable FERC Project’s Natalie McIntire said she is concerned that MISO plans on privately discussing the changes with individual stakeholders.

“I think there needs to be a fairly lengthy stakeholder dialogue on this, and not behind closed doors,” McIntire said.

“We need to be able to work expediently on this. This is not a full-fledged redo of the queue,” Witmeier responded. “However, because we have so many requests, we have issues with speed and cost certainty. So, we have to adjust those rules.”

Witmeier said MISO’s penalty-free withdraw provision is akin to being able to play see the “river” card in Texas hold’em poker without matching a bet. “That’s just not right.”

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FERC Approves New Rules to Enhance Battery Performance in CAISO

FERC on Thursday approved new rules for CAISO intended to improve the performance of energy storage resources and ensure reliability (ER23-1533).

The first of the four new rules will pay storage resources their opportunity costs when they get an exceptional dispatch to hold a state of charge for use later when they are most needed by the grid.

FERC also approved changes to the day-ahead default energy bid for storage to avoid a situation where mitigated bids were causing storage resources to be dispatched in the afternoon, rather than the evenings, when they are needed most. That will be fixed by adding an opportunity cost like the one used in the calculation of real-time default energy bids for storage resources.

The third change relates to how storage resources bid into ancillary services markets to ensure they have enough charge to provide what they bid for. Storage resources will have to submit accompanying energy bids in the real-time market that cover at least any capacity awarded for ancillary services from the day-ahead market.

If a resource deviates from the state of charge anticipated in the day-ahead market and is in danger of not meeting its ancillary services award, then the real-time bid will ensure the resource will still be able to charge or discharge.

FERC approved the first three proposed rules, which did not lead to any debates in the docket.

The final rule change makes it so storage resources are scheduled to provide only the regulation they are capable of, given their constraints.

Vistra, which owns two large storage facilities in CAISO, protested that last rule, saying it gives the ISO broad discretion to account for how regulation awards affect state of charge when determining regulation commitments without providing any detail regarding the parameters and rules that will be used to determine states of charge.

FERC agreed with CAISO that the revisions clarify its responsibility to provide storage resources with achievable regulation awards, given their constraints. The new rules clarify the ISO’s responsibility to continue to refine its optimization software based on storage’s inputs and operational experience in providing regulation, it said.

The commission was not persuaded by Vistra’s protest, saying the language the ISO filed is similar to other parts of the tariff describing how the grid operator optimizes its system. Such provisions require the ISO to take numerous dynamic factors into account in market optimization, but they do not establish new static parameters or standards.

CAISO included examples of how the rule might work in its Business Practice Manuals, which FERC said are also consistent with current practices. The manuals are meant to be guides for internal operating procedures and to inform market participants of the ISO’s practices.

The manuals do not affect any rates, terms or conditions, and the examples in question do not belong in the actual tariff as Vistra contended, FERC said.

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MISO Puts 2 Tx Planning Improvement Suggestions on Hold

CARMEL, Ind. — MISO last week said it will salvage two to-do items from its effort a few years ago to better link up interconnection trends with annual transmission planning.

But the RTO warned that it will likely be years before it has the time to work out possible solutions for them.

The grid operator will keep two unaddressed stakeholder suggestions on hold: one to develop more robust analyses to recommend alternative projects to transmission owners’ proposals, and another to devise a method to evaluate network upgrade projects for potential regionally allocated market efficiency projects.

Jeanna Furnish, MISO’s director of expansion planning, said the two items are the only ones left unaddressed from the project it launched a few years ago to better match its annual transmission planning with the projects that generation developers submit to the interconnection queue. (See MISO Begins Bid to Merge Tx, Queue Planning.)

Since then, MISO has begun recommending and planning portfolios under its long-range transmission planning (LRTP) initiative, satisfying most of the endeavor. The RTO had suggested dropping the listing altogether as part of a cleanup of old stakeholder recommendations, but the Environmental Groups sector protested the deletion. (See MISO Proposes Review of Improvement Ideas’ ‘Parking Lot’.)

“At this time, we don’t foresee having enough resources to be able to work on this until at least 2025,” Furnish warned stakeholders at the Planning Advisory Committee meeting Wednesday. She said MISO’s LRTP effort is already dominating the manpower needed to create an alternatives or evaluation process. It will consider the recommendations “inactive” until 2025.

Earlier in spring, the Sustainable FERC Project’s Natalie McIntire argued the concerns that gave rise to MISO’s retired Coordinated Planning Process Task Team (CPPTT) remain: “MISO has no process to evaluate whether a transmission project required for either generator interconnection or a transmission service request also meets the criteria” of a baseline reliability project or market efficiency project. She argued that the RTO’s tariff demands due diligence across its planning practices.

McIntire said she believes MISO has a duty under FERC Order 1000 to look for more cost-effective transmission alternatives that combine planning needs. But she said MISO simply assures stakeholders it is already doing that, though not much is known about the process.

“MISO must comply with its tariff and create a process by which projects can be evaluated to see if they meet the criteria of other project types,” McIntire said.

The RTO closed out the CPPTT in 2020 when it began working on the first of its LRTP portfolios. At the time, it reasoned that the hefty, comprehensive transmission portfolios would cover the need for an examination into the depth and interconnectedness of its transmission planning amid the clean energy transition.

McIntire said her concerns would be assuaged if MISO committed to conducting the LRTP on a regular basis, but the RTO has not said it has a frequency in mind for long-range planning. She also said LRTP studies take multiple years to finish, making a cadence difficult to establish. Interconnection requests in the intervening years between LRTP studies could turn up network upgrades that would be better suited as regional or reliability projects, she said.

MISO’s newly revived Stakeholder Governance Working Group is working on how it can have a structured process for closing out stakeholder-submitted ideas for improvement. Today, the RTO doesn’t have a formal process for removing stakeholders’ recommendations from its to-do list.