Search
`
November 5, 2024

Posted on

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.

Posted on

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.

Posted on

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.
Posted on

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.

Posted on

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.

Posted on

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.

Posted on

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.

Posted on

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.

Posted on

New York Considering Standards for IBRs

[EDITOR’S NOTE: A previous version of this article made it unclear that PRR-151 has not been fully approved by the NYSRC; the council approved publishing the proposed rule for comment.]

The New York State Reliability Council (NYSRC) has proposed establishing a uniform set of requirements for inverter-based resources (IBRs) over 20 MW to connect to the NYISO grid, leaving the ISO concerned that its generator interconnection queues could become even more clogged.

PRR-151, published March 10, is based on IEEE Standard 2800-2022, itself approved by the Institute of Electrical and Electronics Engineers’ board of directors in February 2022. It would direct NYISO to adapt the IEEE standard’s specifications for IBR performance criteria, databases and model validation methods — among other requirements — for use in its territory.

IBRs in the state would be required to be able to provide dynamic active support services during abnormal voltage or frequency situations, operate in active or reactive power control scenarios, and quickly communicate with NYISO during disturbances. Resource owners would be required submit self-certified compliance verifications to the ISO.

In its posting of the rule, the NYSRC cited the expected increase in the state’s renewable resources and the disturbances in California and Texas during which “IBRs failed to perform reliably, creating system supply deficits.” (See NERC, WECC Warn of Inverter Modeling Gaps and NERC Repeats IBR Warnings After Second Odessa Event.)

It also cited FERC’s Notice of Proposed Rulemaking to direct NERC to develop standards for IBRs (RM22-12). The commission noted IEEE 2800, along with several other related efforts, as “voluntary industry standards.”

“These efforts may enhance the operating performance and control capabilities of IBRs; however, these efforts remain at relatively early stages, do not apply to all relevant IBRs, and require adoption by state or other regulatory authorities,” FERC said. “The proposed directives to NERC to develop new or modify existing reliability standards are intended to complement existing voluntary efforts underway and are not intended to supersede or interfere with these efforts.” (See FERC Addresses IBRs in Multiple Orders.)

Comments on PRR-151 are due April 27.

NYISO, Stakeholders Tepid

The ISO presented the proposed rules to hesitant members of the Transmission Planning Advisory Subcommittee and Electric System Planning Working Group on Friday.

Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, told the groups that PRR-151 was developed because of “the poor reliability performance of like-devices in Texas and California,” and “the cumulative amount of IBRs in NYISO’s interconnection queue … warrants the implementation of IEEE 2800 to govern the interconnection of these devices.”

According to the council’s posting, as of Jan. 5, more than 50,000 MW of IBRs were in NYISO’s queue.

Clayton said the requirements are “for new generators, and the intent is for PRR-151 to not be looking backwards,” noting that they would likely be effective after the current NYISO Class Year.

NYISO had told the council it was concerned that PRR-151 would increase the amount of time required for IBRs to complete interconnection studies; could require lengthy manual and tariff revisions; and did not specify a clear timeline for generator owners to begin demonstrating compliance. Many of these sentiments were shared by stakeholders at the meeting.

Doreen Saia, an attorney with Greenberg Traurig, said developers need to understand how the rules would affect them “because otherwise all we’re going to have an unholy mess on our hands.”

In response to the unease, Chris Wentlent, chair of the NYSRC’s Executive Committee, said PRR-151 “is a draft rule” and that the council’s goal “was to get [PRR-151] to the surface so everyone is paying attention to it,” as well as “allow folks to start commenting.”

Wentlent later promised to consider giving stakeholders an in-depth technical presentation on the proposed rules.

Posted on

TVA Signs Multinational Nuclear Investment Pact on SMR Technology

The Tennessee Valley Authority last week struck a multinational agreement on small modular reactor development with GE Hitachi Nuclear Energy, Ontario Power Generation and Synthos Green Energy, a Poland-based wind and nuclear generation developer.

Under the partnership, the companies will develop and invest in a standard design for the GE-Hitachi BWRX-300 small modular reactor (SMR) that they hope will be licensed and deployed in the U.S., Canada, Poland and other countries. GE Hitachi expects the companies to invest $400 million in the SMR’s development.

“It’s a great collaboration that spans three countries. … This is just the beginning, the foundation,” GE Hitachi Nuclear Energy CEO Jay Wileman said during a March 23 press conference in D.C. “This is really the launch of a platform going forward to help solve climate change.”

Wileman said nuclear energy will inevitably become part of the equation to reach net-zero carbon emissions by midcentury.

“Nuclear has to have a seat at the table, but we’ve got to earn that seat at the table,” he said. “To do that, we’ve got to be on-schedule, on-budget, and it’s got to be a competitive cost.”

He said the BWRX-300 SMR’s common design will allow it to be replicated at varied sites.

“I hope in 10, 20 years from now, people look back on this day and it will have aged well,” TVA CEO Jeff Lyash said. “What you should see here is partnership between a great technology company and three great industrial companies in the power sector.”

Lyash said energy security and decarbonization are challenges that the U.S., Canada, Poland and every other country in the world must face. “You cannot sacrifice one for the other,” he said.

“Nuclear is one of the critical solutions” to reach a secure, decarbonized energy future, Lyash said.

TVA GE Hitachi Agreement Panel (TVA and GE Hitachi) Content.jpgFrom left: GE Hitachi CEO Jay Wileman, Ontario Power Generation CEO Ken Hartwick, Synthos Green Energy CEO Rafal Kasprow and TVA CEO Jeff Lyash | TVA and GE Hitachi

 

TVA announced last year that it will build a BWRX-300 SMR by 2032 at the Clinch River Nuclear site near Oak Ridge, Tenn. The federal agency received a voucher from the Department of Energy’s Gateway for Accelerated Innovation in Nuclear to study future sites for advanced nuclear reactors. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry; TVA Receives Federal Assist on Future Nuclear Plans.)

Its Board of Directors in 2021 approved a nearly $200 million investment for a New Nuclear Program that will examine advanced reactor technology options for future deployment at Clinch River and other potential sites.

GE Hitachi small modular reactor render (GE Hitachi) Content.jpgArtist’s rendering of a GE Hitachi small modular reactor | GE Hitachi

TVA holds the country’s only early-site permit from the Nuclear Regulatory Commission. The federal utility has said it could seek licensing for Clinch River as early as this year.

Lyash says the utility’s goal is to demonstrate that it can build a fleet of SMRs in its footprint. TVA hopes to help design the next generation of reactors that will be ready to deploy in the 2040s, he said.

It plans to preserve and extend the operational life of its existing nuclear fleet, exemplified by last year’s replacement of the steam generators at Watts Bar Nuclear Plant Unit 2.

Ontario Power Generation also plans to install a BWRX-300 SMR as early as 2028 at its existing Darlington Nuclear Generating Station site on Lake Ontario. The project broke ground three months ago.

“We have a technology, we’ve got a project, we’ve got a plan to deliver new, clean electricity to our grid before the end of this decade,” Ontario Minister of Energy Todd Smith said, adding that the process began with more than 100 potential designs.

Synthos’ Orlen project aims to install 10 GW of capacity with dozens of small modular reactors across Poland between 2029 and 2036. The first 10 sites will use the BWRX-300 SMR technology.

Ontario Power Generation CEO Ken Hartwick said he hopes the partnership will inspire confidence to develop SMRs in other countries.

“I think this has been a long time coming,” he said. “This is what it’s going to take to succeed with a nuclear build. It’s going to be strong partnerships; it’s going to be stakeholder engagement and a lot of hard work, but we will succeed.”

Kathryn Huff, assistant secretary for the U.S. Office of Nuclear Energy, called the partnership a “model” for cutting-edge private investment efforts.

“It takes a lot of dollars to make real change happen, and the federal government can’t provide all of those dollars,” she said. “Our one dollar needs to turn into trillions of dollars on the private side, and this group of individuals is doing just that. This partnership is precisely what will result in commercial liftoff for small modular reactors, which the [Department of Energy] is really excited about as a technology.  … We love a public-private partnership, but a private-private-private-private partnership is even better.”

Huff said to meet climate goals, the world will need to double or possibly triple its current nuclear capacity by 2050. She said the partnership’s companies are proving it’s “implementation season.”

Poland’s ambassador to the U.S., Marek Magierowski, said that while he was trying to shy away from bold statements, he said he believed “nuclear is the future.”

“I believe this is something we can all agree on, you as producers of energy and us, the consumers,” he said. “If we want to breathe cleaner air, if we wish to satisfy our society’s ever-growing energy needs, if we want to survive global economic turbulence, we need to put more chips in on nuclear.”

Magierowski admitted that acronyms are not his forte and said he initially thought the BWRX-300 SMR sounded like a cute robot from “Star Wars.”

“I’m confident that Poland, the U.S. and Canada will become even closer to each other through such deals. As close as Luke Skywalker, Han Solo, R2-D2 and BWRX-300,” he said, jokingly.