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September 16, 2024

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Vistra, EPSA Protest MISO’s Show-cause Order

Two competitive electricity organizations have protested FERC’s recent show-cause order to MISO that will ultimately downsize resources’ capacity accreditation values.

Vistra (NYSE:VST) and the Electric Power Supply Association (EPSA), a trade group representing competitive suppliers, said the commission should terminate its proceeding and immediately issue an order preventing MISO from updating the unforced capacity to intermediate seasonal accredited capacity ratio and lowering capacity credits.

They said a reworked ratio would upend load-serving entities’ supply plans that have been based on the capacity values MISO first published.

The grid operator is recalculating the ratio it uses to gauge supply in the capacity auction after FERC issued the show-cause order. It has delayed the first seasonal planning resource auction (PRA) until it can complete the calculation and notify market participants of any lowered accredited capacity values. (See FERC Order May Delay MISO’s 1st Seasonal Capacity Auction and Danly Addresses Capacity Auction Snafu at MISO Board Meeting.)

EPSA said a recalculated ratio “will create uncertainty by undermining bilateral agreements for the sale of capacity that have been entered into in advance of the PRA and upset the settled expectations of market participants that justifiably relied upon the ratio and seasonal accredited capacity values calculated by MISO.”

“The effect of recalculating the ratio will be to reset the seasonal accredited capacity values of [planning] resources over three months after these values were first posted and just days before the PRA offer window was scheduled to open,” Vistra said.

It said MISO’s commitment to revise seasonal accredited capacity values at the 11th hour “has cast a cloud of uncertainty over the MISO market.” It said revising the ratio at such a late stage will “fundamentally undermine” LSEs’ “carefully crafted supply plans” by decreasing resources’ accreditation.

Some LSEs’ self-supply and bilateral contracts made in advance of and outside the PRA will now be insufficient to cover resource adequacy obligations, Vistra said. It described a situation where LSEs are “forced to scramble to cover their now unmet resource adequacy requirements at the same time that other LSEs across the region are doing the same and as capacity values are decreasing — likely forcing LSEs to purchase capacity at a premium to its existing bilateral transactions and supply arrangements.”

“No amount of delay in the PRA will remedy the harm done to LSEs or customers by recalculating the ratio,” Vistra said.

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NY Climate Justice Panel Sets Disadvantaged Community Criteria

More than 1,700 of New York’s 4,918 census tracts are slated to be designated as disadvantaged communities (DACs), prioritizing them for future state and federal resources to address environmental justice issues as the state advances its clean energy transition.

On Monday, New York’s independent Climate Justice Working Group, which was created by the state’s Climate Leadership and Community Protection Act, unanimously approved the final environmental, population, geographic, health, historical and individual criteria for determining the 35% of census tracts that will be designated as DACs. (See NY CJWG Poised to Select a 35% DAC Coverage Threshold.)

The final criteria, which were developed in consultation with state agencies, environmental justice groups and the public, are based on 20 environmental and climate risk indicators, including pollution exposure, proximity to waste or processing sites, and flood risk. The criteria also consider 25 population and health indicators, including education, race, health sensitivities or housing, as well as individualized considerations for low-income households.

Census Tract Score (New York DEC) Content.jpgOverview of CJWG calculations of criteria indicators to achieve census tract score | New York DEC

 

The criteria also included the 19 census tracts that are federally designated as more than 5% tribal and indigenous land.

Several indicators were considered but not included in the final criteria, including prevalence of diabetes or lead contamination data, but these factors could potentially be considered for future evaluations.

Designating DACs was done through a process where weighted factor scores, which were calculated from indicator percentile ranks, were combined into two weighted component scores that were then added together to generate an overall score.

Census tracts whose overall score was in the top 29% of either statewide or regional scores were then designated as a DAC.

Roughly a dozen other tracts that contained at least 100 people but had insufficient census data to obtain appropriate scores will be designated as DACs.

The CJWG’s approval of the final criteria is a significant step in addressing evolving environmental risks and historical burdens by ensuring future clean energy or climate-resilience projects go to communities most in need.

The CJWG will review the DAC criteria annually to consider updating the indicators or methodology and track how DAC provisions are being implemented. It will discuss this iterative process at its meeting on April 4.

Public Support

CJWG member Sonal Jessel, director of policy at the environmental justice group WE ACT, said she voted in favor of the criteria because even if the CJWG did not “fill in all the gaps,” the group “did really great due diligence in moving through all of the concerns that came in.”

Statewide or Regional (New York DEC) Content.jpgTop 29% of census tract scores either statewide or regionally designated as a DAC | New York DEC

 

Jill Henck, clean energy program director with the Adirondack North Country Association, voted yes because, as a rural area representative, she appreciated how members were “cognizant of the fact that New York is a unique state,” and made efforts to include stakeholders living in rural communities just as much as those in New York City.

Eddie Bautista, executive director at NYC Environmental Justice Alliance, said CJWG members “all get the period of time we’re living in and understand that climate change will affect everyone, but its impacts are not evenly felt, and the [approved criteria] is a big step to rectifying that.”

Elizabeth Furth of the New York Department of Labor said the votes of approval ensure “disadvantaged communities throughout New York State can realize the many benefits from our transition to a green economy.”

Two CJWG members, who despite voting in favor, took time to share several issues about the criteria in its current form.

Rahwa Ghirmatzion, executive director at PUSH Buffalo, spoke on behalf of the Seneca Nation of Indians, who submitted a letter that outlined significant concerns, particularly about industrialization near their territories and representation.

The Tribe wrote that it rejects “the idea that destruction of territory can be offset by benefits provided by the state or a developer,” and the “cumulative impacts of industrial development on the nation, its cultural resources, and its environment cannot be counterbalanced by economic development, financial support, jobs or other forms of monetary financial benefit.”

Elizabeth Yeampierre, executive director of UPROSE, a Brooklyn-based sustainability organization, was disappointed that diabetes, which can disproportionally impact disadvantaged populations, did not make it into the final criteria.

However, Neil Muscatiello, director at the Bureau of Environmental and Occupational Epidemiology at the New York Department of Health, emphasized during his vote that, although there were “limitations and gaps,” these can all be addressed in the next annual update and diabetes will be among the first considered.

CJWG Chair Alanah Keddell-Tuckey cast her affirmative vote saying she was proud to work with a group who “did not create these problems,” but were “willing to stand up regardless of the pushback and criticism to fix the thing that they did not break.”

Keddell-Tuckey said there were “cynical” people who, particularly during the pandemic, “lay the blame on the victims, rather than admit we were dealing with generations of redlining, income inequality and malicious zoning practices.”

Basil Seggos, commissioner of the Department of Environmental Conservation, said in a statement after the vote that the CJWG’s work ensures “no less than 35% with the goal of 40% of the Climate Act’s benefits are directed to disadvantaged communities.”

Doreen Harris, CEO of the New York State Energy Research and Development Authority, said “the final adoption of this criteria solidifies New York State’s commitment to climate justice for those underserved communities,” and the CJWG’s “clearly defined guidance will help us realize the equitable distribution of benefits from clean energy investments.”

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Industry Says DOE Proposal Would Exacerbate Transformer Shortages

The U.S. Department of Energy received pushback this week on its proposal to increase efficiency standards for distribution transformers, with industry comments arguing that the new rule would create additional problems for already shaky supply chains.

“If this proposal is implemented as currently contemplated, it would have serious consequences to NRECA members’ ability to provide affordable, reliable electric service to millions of Americans,” the National Rural Electric Cooperative Association said in comments filed Monday. “We urge the agency to reconsider the [proposed rules] as currently drafted and to issue a final rule that maintains the current standard.”

DOE estimated that its new standards would save utilities between $260 million and $5.3 billion between 2027 and 2056, which is based on savings in operating costs minus the increased product cost for the new transformers. The department has the authority to periodically update standards for transformers, and other equipment, as long as the new requirements are economically justified and technically feasible.

But NRECA said the proposal rests on flawed assumptions and ignores the challenges facing the distribution transformer market that are impacting all electric utilities, not just co-ops. DOE could focus on incentivizing amorphous steel core transformers, the group said.

Amorphous steel is a type of electrical steel that is produced by rapidly cooling molten alloy so that crystals do not form, which produces a thinner product than the more standard grain-oriented electrical steel (GOES). Electrical steel is a special iron alloy that includes small percentages of silicon to enhance its magnetic permeability.

“DOE’s top priority should be finding ways to support domestic distribution transformer manufacturers to increase production immediately and to sustain that output over the long term as electrification of the U.S. economy grows,” NRECA said. The current distribution transformer manufacturing base is struggling to meet demand, and DOE’s proposal would make that worse, it said.

“All segments of the utility sector have been sounding the alarm for more than a year about the supply chain constraints around multiple types of equipment they require to keep the lights on, with distribution transformers being the most acute challenge,” NRECA said. “It now takes more than a year on average for utilities to receive distribution transformers, compared with 60 days just a couple of years ago. Some domestic transformer manufacturers have stopped taking orders altogether.”

That backlog is only expected to increase absent government support as utilities invest in grid resilience and modernization projects, while federal and state policies drive more electrification, it added.

One of the potential fixes for the backlog is to signal to manufacturers that GOES will be increasingly needed going forward, and DOE’s standard would work directly against that, NRECA said. Manufacturers would have to change their production systems and where they source input materials, taking attention away from increasing supply to deal with the backlogs.

The U.S. Chamber of Commerce also cautioned DOE in comments last week from moving ahead with the standard because of supply chain concerns. GOES represents 95% of new distribution transformer production, so amorphous steel production would need to expand greatly to meet the new standards.

“While there are only singular domestic sources for each of GOES and amorphous steel, GOES is at least already produced in levels that support the majority of domestic transformer production,” the chamber said. “Thus, shifting all distribution transformer production to rely exclusively on amorphous steel will require a dramatic increase in capacity for such steel, which will take time and will further constrain already limited transformer supplies.”

The only places amorphous steel can be imported from are China and Japan, which would only increase the industry’s reliance on components from China, the chamber said.

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NY Utilities to Seek $900M from DOE

Six New York utilities have indicated they will apply for roughly $900 million in federal loans and grants made available from the Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act (IRA) (22-M-0149).

The utilities are acting in response to Feb. 27 letters sent by the state’s Public Service Commission, which directed them to seek IIJA and IRA funds to support clean energy investments. (See Biden Signs $1.2 Trillion Infrastructure Bill.)

In the letters, PSC Chair Rory Christian wrote that he “views these federal programs as a singular opportunity to reduce costs to New York ratepayers, make critical reliability and resiliency investments in the electric grid, and further the attainment of the state’s energy policies as outlined in the state’s climate law.”

The PSC sent the letters to Orange & Rockland (O&R), Central Hudson Gas & Electric, Long Island Power Authority (LIPA), Consolidated Edison (ConEd), National Grid, New York State Electric and Gas and Rochester Gas & Electric (NYSEG/RG&E), and National Fuel Gas Distribution Corporation.  

In responses submitted March 24-27 National Grid (NYSE: NGG), ConEd (NYSE: ED), ConEd subsidiary O&R, NYSEG/RG&E and Central Hudson said they will collectively be pursuing hundreds of millions in U.S. Department of Energy loans or grants for enhancing the future grid, energy storage development, and resiliency upgrades.

National Fuel (NYSE: NFG) said it would not tap into DOE funds, since as “a gas-only utility” it does “not currently have any fully developed projects that would be eligible for federal funding,” but confirmed its was investigating hydrogen opportunities, which may be eligible in the future.

LIPA had yet to submit a response as of Monday.

The National Grid and Central Hudson letters included project spending plans, while the other three confirming utilities redacted much of that information, citing confidentiality, although they did briefly dive into monetary estimates.

ConEd anticipates “pursuing approximately $244 million in DOE funding;” O&R, about $125 million. NYSEG and RG&E will be jointly applying for $260 million.

Those utilities all plan to apply for funds from the Preventing Outages and Enhancing the Resilience of the Electric Grid program, while ConEd and O&R will apply to both the Smart Grid Investment Matching Grant and Long Duration Energy Storage Demonstration Initiative and Joint programs. ConEd and NYSEG/RG&E will also seek to tap the Clean Hydrogen Hubs program.

National Grid anticipates applying for $50 million from the Increase Capacity & Enhance Flexibility program for its “Future Grid” project, which the utility says will allow it “to deploy digital technology solutions to maximize the value of third-party distributed energy resources for customers.”

Additionally, the utility is applying for $200 million through the Preventing Outages and Enhancing the Resilience of the Electric Grid program, with $100 million to be invested into energy storage facilities in rural northeast New York around Ticonderoga and another $100 million spent on “weatherization of existing grid structures in eastern and western New York State and the hardening of existing infrastructure to improve resilience and speed of recovery in the face of climate change.”

National Grid said Ticonderoga “often experiences electrical outages,” so it proposes three battery storage systems be developed in the area to “improve reliability by carrying the energy load until crews arrive to make the necessary repairs.”

Central Hudson seeks roughly $8 million for the rehabilitation of two hydroelectric projects: the Dashville Dam and the Sturgeon Pool Hydroelectric Plant, which would be funded through the Hydroelectric Efficiency Improvement Incentive and the Maintaining & Enhancing Hydroelectricity Incentive, respectively.

The Public Utility Law Project on March 15 submitted a letter to the DOE in support of the New York utilities, saying “every dollar received from these funds can lower the revenue requirement impact on ratepayers.”

The DOE’s Loan Program Office has outlined processes to apply for IIJA and IRA loans or grants and some programs have started accepting applications.

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NYISO Receives ‘Exceptional’ Customer Survey Scores

NYISO obtained its highest recorded customer satisfaction and performance score in Siena College Research Institute’s seventh annual assessment, researchers told the ISO’s Management Committee meeting on Wednesday.

Siena, a well regarded pollster, assesses two important aspects to the ISO: customer satisfaction, which measures basic consumer interfacing and engagement; and assessment of performance, a measure of whether NYISO is “realizing [its] mission through [its] performance.”

Survey participants include both market participants and senior executives of market participants.

NYISO scored a 92.3 on satisfaction and 77.6 on performance, both of which were the ISO’s highest recorded scores, Institute Director Don Levy said. Its 86.4 overall score — which Levy termed “exceptional” — combines the two with 60% weighting for satisfaction and 40% for performance.

“The satisfaction score really is quite impressive,” Levy said. “You know, we have worked with a couple of the other ISOs across the United States, and their program is not as extensive as yours. … Clearly your numbers are really standing out.”

Levy cited ISO staff’s professionalism and desire to “meaningfully address” feedback from previous surveys.

The customer inquiry satisfaction score — a measure of whether customers instituting a “ticket” with the ISO is handled efficiently and professionally — was a “near perfect” 98.7, Levy said.

The only measure that declined in 2022 was executives’ assessment of performance, which declined to 74.8 from 75.8 in 2021. Scores for market participants, by contrast, increased from 78.2 to 80.4.

Levy said the ISO could improve its explanation of its procedures and policies but added that the ISO has “already been making improvements in these areas.”

The survey also found room for improvement on considering individuals’ input, advancing its technological infrastructure and “administering open and competitive markets.”

“I think [NYISO’s] team deserves some kudos” he said. “There really is no area that has a glaring need.”

Board Compensation

NYISO CEO Rich Dewey told the MC that the Board of Directors approved a $5,000 increase in directors’ annual retainer to $76,500, based on results from a benchmarking review.

The approved adjustment will be effective in April, when the new board calendar starts.

The review resulted in no changes to:

      • chair retainer: $50,000/year;
      • vice chair retainer: $12,500/year;
      • board committee chair retainer: $12,500/year;
      • board meeting compensation: $3,750/meeting day; or
      • board committee meeting compensation: $5,500/meeting day.
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Washington Confirms $300M Take for 1st Cap-and-Trade Auction

Washington’s Department of Ecology confirmed Tuesday that it raised almost $300 million from the state’s first quarterly cap-and-trade auction held in February.

According to the public proceeds report released Tuesday, the auction’s exact take was $299,983,267, in line with initial estimates released March 7. The report is intended to double-check those figures and provide state lawmakers with a clear picture of how much revenue is available to spend on programs to be supported by the auctions. (See Washington’s 1st Cap-and-Trade Auction Nets Nearly $300M.)

The proceeds have been deposited into the state’s treasury, according to the Ecology Department.

All 6,185,222 current vintage allowances were sold at a settlement price of $48.50 during February’s auction. The agency’s auction summary report issued earlier this month showed that 56 companies, utilities and public institutions bid into the auction, but it did not indicate which bidders were successful. Each allowance entitles a holder to emit one ton of greenhouse gases.

The 2021 Climate Commitment Act (CCA) created Washington’s cap-and-trade program and also established three funds to receive the revenue raised, including the:

  • Carbon Emissions Reduction Account, for projects that reduce transportation carbon emissions and support public and alternative transportation.
  • Climate Investment Account, used for the administration of the CCA and projects “that support the transition to clean energy, ecosystem resilience, and carbon sequestration.”
  • Air Quality and Health Disparities Improvement Account, for projects that help reduce criteria pollutants and health disparities in disadvantaged communities.

Programs funded from all three accounts are subject to appropriation by the legislature.  

In January, Washington officials told the Washington Senate Transportation Committee that the cap-and-trade auctions could raise almost $1.5 billion through fiscal 2024 and reiterated their contention that a new low-carbon fuel standard will raise gas taxes by about one penny per gallon.

Later this legislative session, the state Senate and House plan to allocate revenue from the first cap-and-trade auction. The Ecology Department estimates $484 million in cap-and-trade revenue for fiscal 2023 (July 1, 2023 to June 30, 2024) and $957 million in fiscal 2024.

Robert Mullin contributed to this article.

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MISO Board of Directors Briefs: March 23, 2023

Waivers May be Necessary to Retain Directors Past Term Limits

[Editor’s Note: An earlier version of this article said Director Nancy Lange is serving her final term on MISO’s Board of Directors. Lange is actually eligible to serve a third term on the board after her current term expires in 2024.]

NEW ORLEANS — Todd Raba, chair of MISO’s Board of Directors, said last week that it may pursue special term waivers next year to enable term-limited members to continue providing guidance and avoiding their loss of institutional knowledge.

Raba said during the board’s March 23 meeting that more than half of the independent directors will reach term limits next year and could begin leaving the board.

Director Phyllis Currie said the board needs to be “intentional” about its succession planning to avoid gaps in expertise. She said she would like the board to conduct an annual, nonpublic discussion about the talents it needs.

MISO’s board consists of nine independent directors and the RTO’s CEO. The independent directors are limited to three three-year terms, but its bylaws allow some board members to serve an additional term under certain circumstances.

Currie and fellow directors Mark Johnson were re-elected to their final terms that began in 2022. They will hit their three-term limit at the end of 2024.

Raba, H.B. “Trip” Doggett and Barbara Krumsiek were also re-elected late last year. Their final terms conclude at the end of 2025.

Director Theresa Wise will be up for her third and final election at the end of the year for a term that runs into 2026. Director Robert Lurie is currently finishing out his first term and will be up for his second election. Lurie joined the board in 2020 to serve the one-year remainder of a former director’s term, which does not count against his three-term limit.

Nancy Lange will complete her second term at the end of 2024 and is eligible to serve a third term that would run through 2027. Jody Davids joined the board at the beginning of 2021.

MISO last used a waiver for board members in 2017, when it retained Baljit “Bal” Dail for an additional three-year term. Dail served 12 years on the board. (See MISO Board of Director Briefs: Dec. 10, 2020.)

Board Approves MISO-PJM Project

The board unanimously approved a targeted market efficiency project with PJM.

The $200,000 project will upgrade a wavetrap on the Powerton-Towerline 138-kV tie line in Ameren Illinois and ComEd territory. It is expected to produce more than $7 million in avoided congestion benefits over its first four years of operation. (See MISO, PJM Staffs Endorse 1 TMEP Joint Project.)

Project costs will be split 72% to PJM and 28% to MISO. Ameren Illinois’ transmission pricing zone will cover all of MISO’s $57,000 tab.

The PJM board has already authorized the project.

Budget Reflects Hiring Uptick

MISO CFO Melissa Brown said the grid operator is poised to exceed this year’s budget for new hires.

“That’s really great for MISO that we’re getting back to a pre-COVID level of employment,” she told board members.

Staff expects to spend about $2 million more than its allotted $310.5 million base expense budget.

Given recent bank collapses, staff reassured the board and stakeholders that MISO’s financial relationships are with large, secure institutions and said they don’t foresee any risk.

Membership Applications Approved

Directors unanimously approved two membership applications, allowing City Water and Light of Jonesboro, Ark., to join as a transmission owner and Invenergy Transmission as a non-transmission owning member.

Jonesboro was already a market participant but sought TO status after acquiring transmission facilities. Invenergy Transmission will become a competitive transmission developer within MISO.

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FirstEnergy Hires Tierney as New Chief Executive

FirstEnergy’s (NYSE:FE) board of directors on Monday announced the appointment of a new CEO who is currently a senior executive at the investment company Blackstone (NYSE:BX).

Brian Tierney, 55, will join the Ohio-based company as president and CEO on June 1, succeeding board Chair John Somerhalder II, who has held the top management spot since September in addition to his board responsibilities.

Tierney has spent 28 years in the utility industry, 23 of them with American Electric Power, serving as executive vice president and CFO from 2009 to 2020. He was executive vice president of strategy in 2021 when he joined Blackstone as senior managing director and global head of infrastructure operations.

“Brian Tierney is a proven leader with deep experience in the energy industry, a unique blend of operational, financial and strategic skills, and a sterling record of driving growth and transformation within our sector,” Somerhalder said in a statement. “Over the last several years, we have taken decisive actions to reposition FirstEnergy for the future. The board’s search committee set out to identify a leader who could continue the important work underway to drive the company forward while bringing critical outside expertise and perspectives.

“We could not have selected a better suited candidate than Brian. We look forward to working closely with him to build on FirstEnergy’s momentum and enhance value for our shareholders and other stakeholders.”

Tierney is the company’s third CEO since the company fired Charles Jones in October 2020 after an internal investigation determined that he and two other top executives had violated the company’s code of conduct in a bribery scheme involving former Ohio House Speaker Larry Householder and the passage of legislation bailing out the company’s nuclear power plants in the state. (See FirstEnergy Fires Jones over Bribe Probe.)

The company appointed CFO Steven Strah as CEO the same day it fired Jones. Strah abruptly retired in September 2022 following the board’s announcement that it had completed a review of its top management team in accordance with the settlement of shareholder federal lawsuits. (See FirstEnergy CEO Abruptly Retires, Without Severance.)

Tierney’s appointment comes a little over two weeks after a federal jury in Cincinnati found Householder and a former Ohio Republican Party chairman guilty of racketeering conspiracy. (See Householder Convicted in FirstEnergy Bribery Case.) Both are planning to appeal as the Justice Department continues its investigation.

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California Bills Seek to Expedite Transmission Projects

SACRAMENTO, Calif. — Two bills introduced in the California legislature this year are intended to speed up approval and construction of transmission projects necessary for the state to meet its goal of supplying 100% clean energy to retail customers by 2045 while maintaining grid reliability.

One measure, Senate Bill 420 by Sen. Josh Becker, would require the governor to identify a lead agency to “monitor clean energy and electrical transmission facility planning and deployment” needed to achieve the targets of Senate Bill 100, which established the 100% clean energy mandate in 2018, and last year’s SB 1020, which set interim goals of using 90% carbon-free electricity by 2035 and 95% by 2040.

A project that the agency identifies as necessary to meet the goals would qualify for streamlined government approval and faster court review of lawsuits filed against it. It could also receive expedited review by the California Public Utilities Commission if CAISO’s Board of Governors determines it is the most cost-effective solution to a “specific transmission expansion need” identified by the CPUC in its resource planning role.

Lawsuits and “duplicative review” by CAISO and the CPUC can delay transmission projects for years, Becker said in a news release.

“This isn’t about cutting corners,” the state senator said. “It’s about streamlining the process and getting power where it needs to go in a reasonable timeframe. We talk a lot about bringing new clean energy projects online, and while that is critical, it’s only one piece of the puzzle.  We need to be able to get that power from the plant to the homes and businesses that need it.”

The bill will be heard in the Senate Environmental Quality Committee on March 29.

CEC Certification

Another measure, SB 619 by Sen. Steve Padilla, would expand the California Energy Commission’s power to certify transmission projects entailing a capital investment of at least $250 million over five years.

Legislation signed by Gov. Gavin Newsom in June allowed the CEC to consolidate permitting for generation, storage and transmission lines that carry clean power to junction points with existing transmission. The CEC approval generally bypasses other federal, state and local permitting processes. (See California to Pass Sweeping Energy Policy Changes.)

Padilla’s bill would remove the requirement that power lines connect with existing transmission and allow the CEC to approve projects “regardless of whether the electricity is carried to a point of junction with any interconnected electrical transmission system,” the state Legislative Counsel’s office said in its summary of the measure.

The bill is short and vague on details. It is “intended to be the starting point for a much larger and overdue conversation within the Legislature on how to meet our climate goals, deliver reliable power to homes and businesses, manage costs, and add transparency to modernizing California’s electrical grid,” Padilla’s office said in a statement.

Padilla and Becker both cited CAISO’s inaugural 20-Year Transmission Outlook, released in February 2022, as support for their bills. To meet SB 100’s goals, the ISO projected the state needs $30.5 billion in new high-voltage lines to transport renewable power from remote areas to urban load pockets. (See CAISO Sees $30B Need for Tx Development.)

The amount includes an estimated $12 billion for 500-kV AC and HVDC lines to carry 10 GW of out-of-state wind power from the Great Plains and Rocky Mountain states; $11 billion to upgrade CAISO’s system with 230- and 500-kV lines to transport solar and geothermal power; and $8 billion for 500-kV and HVDC lines to carry 7 to 13 GW of California offshore wind to major urban areas.

“Meeting this unprecedented demand will require California to simultaneously accelerate planning, siting, permitting and construction of a modern electrical grid, while carefully managing its costs,” the statement by Padilla’s office said. “Current transmission projects are delayed by almost five years and have run up tens of millions of dollars in extra costs.

“Absent substantial changes to the state’s current planning and permitting processes, California will not meet its visionary climate goals, and the state’s fragile energy grid will experience unprecedented strain,” it said.

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PJM MRC/MC Briefs: March 22, 2023

Markets and Reliability Committee

PJM Gives Update on December Winter Storm Report

VALLEY FORGE, Pa. — Adam Keech, PJM vice president of market design, told the Markets and Reliability Committee last week that the RTO is delaying its estimation of when it will be publishing a report on the December winter storm to July.

In committee meetings following the storm, also known as Winter Storm Elliott, PJM initially stated that it was planning to release the report in April. But Keech said that staff are diverting resources to a data request related to the storm from NERC and FERC, followed by a visit from the two organizations in April. Staff are also working to address a list of compliance filings FERC required in its conditional approval of PJM’s proposal to allow aggregated distributed energy resources to participate in its markets.

The report will likely be structured similarly to the paper PJM released following the 2014 polar vortex, with chapters on generation performance and gas availability, load forecasting, timing and criteria for emergency procedures, Capacity Performance, dispatch, and the cost offer verification process.

In the meantime, Keech said PJM plans to provide lessons learned from the storm during stakeholder meetings in mid-May, focusing on the capacity market to inform changes being considered through the Critical Issues Fast Path (CIFP) process. He said many of the major items that will likely be presented have already been under stakeholder discussion even before the December storm. (See PJM Board Initiates Fast-track Process to Address Reliability.)

“We’ve been working on many of the issues you will see already for the past year,” he said.

Stakeholders Support New Default CONE and ACR Values

Both the MRC and Members Committee supported the proposed default cost of new entry (CONE) and avoidable-cost rate (ACR) through advisory votes. The changes are now set to be filed with FERC, with the goal of being in place for the 2026/27 delivery year. PJM elected for a same-day vote for the MRC and MC to give the Board of Managers more time to review the information before the filing. (See “Updated Default CONE and ACR Figures,” PJM MRC/MC Briefs: Feb. 23, 2023.)

The gross CONE values for all resource types, except storage, would increase, which PJM’s Skyler Marzewski said is largely because of changes to investment tax credits under the Inflation Reduction Act. The CONE changes also include new reference resources for combined cycle and onshore wind resources.

The most significant changes to ACRs include adding steam oil and gas as a new default unit type, including more data from the Nuclear Energy Institute for calculating nuclear costs and refined estimates of property taxes and insurance costs. All gross ACR values increased except single-reactor nuclear facilities.

PJM, Monitor Present Renewable Dispatch Proposal

Joel Romero Luna of Monitoring Analytics and PJM’s Darrell Frogg presented a first read of a joint proposal to create new dispatch protocols for renewable resources, with the aim of increasing visibility of what level renewables can be reduced to. Frogg said as more intermittent resources come online, it is likely that there will be more dispatch required, and those resources will not be able to provide their maximum output whenever they are available.

The proposal would use basepoints currently available through the Inter-Control Center Communications Protocol (ICCP) rather than curtailment flags, and intermittent resources would be directed to follow their economic basepoints even when they are curtailed because of the prevalence of inadvertent curtailments. Resources would be required to update critical parameters in real-time security-constrained economic dispatch (SCED) every five minutes and on an hourly basis for parameters in intermediate-term SCED cases.

The current lost opportunity cost (LOC) structure for wind resources would be extended to solar generators, making them eligible for LOC when they follow SCED dispatch and have the ability to receive instructions from PJM.

Frogg said the proposal is an effort to require intermittents to offer their median or expected output into the day-ahead market, based on forecasts of both weather and equipment availability.

Responding to stakeholder questions, Luna clarified that there is currently a requirement that units must offer into the market, and while most intermittents already follow the practice being proposed, there is insufficient clarity in the manuals codifying the process.

Economist Roy Shanker questioned how generators’ forecasts will be reviewed for accuracy by PJM, saying that outside forecasts should be checked for accuracy to avoid a bias being developed.

Monitor Joe Bowring said they believe the right amount of review is already included in the proposal and no further changes are needed.

Members Committee

Deficiency Notice Interrupts Timeline on CP Penalty Payments

Just the day before the committee meetings, FERC issued a deficiency notice on PJM’s filing to allow market participants that have defaulted to continue operating in its markets under certain conditions, including their contribution to reliability, the ability to generate revenues in the future and capability to post collateral (ER23-1058).

A fourth factor recognizes that certain transmission customers cannot have their service terminated without FERC approval. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022)

The notice “is of concern for those following Winter Storm Elliott, because we are getting ready in April to send out the invoices for the Capacity Performance penalties,” PJM General Counsel Chris O’Hara told the MC.

In its response to the notice, filed Thursday, the RTO said it had accidentally included the last four words in the phrase, “PJM may permit a defaulting market participant to continue to participate in PJM markets in a limited manner,” in the proposed revisions to the Operating Agreement; they had been in an early draft but deemed too vague — as FERC noticed — and were meant to be removed.

PJM also stated that the four factors it identified consisted of an exhaustive list of the circumstances under which it would allow market participants to continue operating while in default.

The RTO asked FERC to implement a shortened five-day comment period and to rule on the proposal by April 7, with an effective date of April 8.

“PJM requested these dates purposefully,” the RTO said in its response. “PJM is required to issue the March monthly bill by April 7, 2023. Those monthly bills will include any nonperformance charges related to Winter Storm Elliott. The aggregate nonperformance charge will be between $1 [billion] to $2 billion. While PJM has proactively acted to reduce the risk of capacity market seller default by proposing to amend the manner in which the Winter Storm Elliott nonperformance charges may be billed, the risk of default will remain, even if those revisions are accepted,” referring to a separate filing that would allow market participants to opt to make their payments over a longer period.

O’Hara said PJM is concerned about the possibility of defaults stemming from the nonperformance charges, not just in terms of the absolute number of megawatts affected, but also the potential for generators providing critical services such as black start or critical load units being at risk. Should owners of those facilities be considering default, he said PJM wants a conversation to be opened so that they can seek a waiver request at FERC to allow them to continue operating.

Stakeholders Question CIFP Process

Steven Lieberman of American Municipal Power said he believes the PJM board has not met the requirements for initiating the CIFP process that it began in February, arguing that it has not set a firm deadline for resolving the issue.

While the board has identified Oct. 1 as the date for PJM to make a filing to address reliability concerns identified in about five years, Lieberman argued that the deadline is arbitrary. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF)

“It’s our opinion at least that it doesn’t satisfy the requirements for starting the CIFP process in the first place. … We think this process was elected in a way that conflicts with Manual 34,” he said.

Lieberman also said the board’s letter opening the CIFP is vague and does not lay out a process that fosters the kind of open and transparent dialogue that the letter states the board hopes to have with stakeholders as they create proposals. He noted that stakeholders had requested that the board attend future MRC or MC meetings to speak about the scope it envisioned for CIFP proposals and what its largest concerns are, but that PJM determined it would not be proper to have individual members potentially speaking on behalf of the entire board.

Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), said generator performance is the key issue for many state advocates, but he believes it will be hard to create a proposal addressing the issue when the data on performance during Elliott won’t be available until July.

“When you look at what our dates are and what we’re trying to achieve, it is hard to match it up,” he said.

Susan Bruce, representing the PJM Industrial Customer Coalition, agreed that the deadlines are optimistic, and attempting to address too many portions of the capacity market on a short time frame may prove difficult. She said stakeholders should have a disciplined mindset rather than allow the process to become “an invitation for a Christmas tree.”

Erik Heinle, Vistra’s director of PJM market policy, said he believes the board letter was well written and provides enough clarity on the areas it believes that proposals must address, while also leaving stakeholders discretion to include other topics as well. He noted that any issues not addressed by the CIFP could be open for continued discussion through the Resource Adequacy Senior Task Force, which is currently on hiatus through the CIFP deliberations.

Other Stakeholder Discussions

MC Chair David “Scarp” Scarpignato said stakeholders are considering whether to start MC meetings earlier on days when the MRC adjourns significantly earlier than scheduled. He said that in some cases, stakeholders must wait for hours before the MC starts. Those with comments or suggestions were encouraged to reach out to Scarp or PJM Director of Stakeholder Affairs David Anders.

The MRC tabled a vote on proposed revisions to Manual 11: Energy & Ancillary Services Market Operations because of amendments offered in an attempt to better align the manual with PJM’s other governing documents. Monitor Bowring and some stakeholders suggested that the proposed changes to the revisions may be substantive at first glance and it would be better to wait a month to review before taking a vote.