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November 14, 2024

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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.

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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.

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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.

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NERC: Cyber Intrusions Affected Multiple Regions in 2022

Electric utilities reported eight attempts to compromise their cyber systems to NERC last year, according to the ERO’s annual cybersecurity report.

And while none of the incidents affected reliability, the evidence of attackers’ ongoing efforts to destabilize the grid “highlights the continued need for vigilance,” NERC said.

NERC published the report last week in accordance with FERC’s Order 848 of 2018, in which the commission directed the development of a reliability standard to “augment mandatory reporting of cybersecurity incidents.” The initiative resulted in CIP-008-6 (Cybersecurity — incident reporting and response planning), which FERC approved the following year. (See FERC OKs Cyber Reporting Rule.)

The standard expanded mandatory reporting of cybersecurity incidents to a wider range of intrusion attempts, along with specifying the minimum information that must be reported. Responsible entities must send their reports to the Electricity Information Sharing and Analysis Center (E-ISAC) and the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team by the end of the next calendar day, or within one hour depending on the seriousness of the incident.

FERC’s order also directed NERC to submit an annual, anonymized public summary of the cyber incident reports received each year based on the reports received through the E-ISAC. NERC delivered its first annual cyber report last March after CIP-008-6 became mandatory on Jan. 1, 2021.

WECC, MRO, Texas RE Report Incidents

According to last week’s report, entities sent eight CIP-008-6 cyber incident reports to the E-ISAC in 2022, compared to two the previous year. Four of the reports were submitted by entities in WECC, and two each from the Midwest Reliability Organization and Texas Reliability Entity.

NERC withheld some incident data from the report, such as the utilities involved in the incidents or details about when and where they occurred, in order to prevent potential threat actors from gaining information on how to target critical infrastructure. However, the ERO emphasized that “none of the reported [incidents] successfully compromised a BES [bulk electric system] cyber system or affected reliable operations.”

Four of the reported attacks involved malware, a category that includes malicious code, Trojans (a type of malware disguised as legitimate code or software), and ransomware. Two of the malware incidents involved the exploitation of “known vulnerabilities to attack EACMS [electronic access control or monitoring systems] assets” — in one case a vulnerability in Apache’s Log4j product and in the other a weakness in software from information security company Fortinet.

Another malware incident saw the attacker attempt to use a Trojan to compromise an interactive remote access asset. For the last one, NERC said that it “only affected a few systems on the entity’s corporate IT [information technology] network” and that the Supervisory Control and Data Acquisition (SCADA) network did not appear to have been affected.

Two further incidents involved attacks on third parties — both in the WECC region — that provided support services for BES cyber systems. One third party provided backup SCADA monitoring services for two wind power facilities. The attack caused outages to its email and phone systems, and loss of access to SCADA. The other incident was a distributed denial of service attack against the internet service provider of a vendor that provided third-party forecasts for a balancing authority.

NERC also reported an attempt to remotely open a physical gate at a facility, which failed, and a final incident “of unknown origin” that led to loss of visibility in an entity’s EACMS and physical access control systems. The last incident is still under investigation.

Further Vigilance Needed

The ERO’s analysis indicated that last year’s cyber incidents “seem to have targeted specific systems related to cybersecurity defenses and BES monitoring.” Though none of the attacks affected reliability functions or successfully compromised BES cyber systems, two did succeed in compromising cyber assets associated with BES cyber systems — the one of unknown origin and one in which the attacker “was able to change several firewall rules and create administrator accounts on the affected devices before being detected.”

The attacks on vendors “impacted entities to various degrees,” but had no operational impacts on the grid. Likewise, the attack on an entity’s corporate IT system had no impact on cyber systems, cyber assets or operations. While another attacker did succeed in sending a signal to open the gate, the attempt was ultimately unsuccessful because the gate did not open.

Finally, NERC said the attempted exploit of the Log4j vulnerability seemed to be trying to find vulnerable targets rather than aiming at the responsible entity itself. There was no penetration of the entity’s electronic security perimeter and no apparent further traffic occurred other than the system sending the attacker an “awake” message.

Though NERC said it was “encouraged that there were no operational impacts from the reported incidents … and that entities reported these attempts to the E-ISAC,” it found more work is needed to improve vigilance against cyber threats. A new standards development effort is underway to enhance the reporting requirements in the form of Project 2022-05 (Modifications to CIP-008 reporting threshold). The ERO said this project is intended to “provide a minimum expectation for reporting attempts to compromise.”

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Kentucky Law Raises Hurdle for Fossil Fuel Generation Retirements

Newly enacted legislation in Kentucky could make it more difficult for the state Public Service Commission to approve retirements of fossil fuel generators or replace them with renewables.

Senate Bill 4 — filed with the secretary of state’s office on March 24 without the signature of Gov. Andy Beshear — prohibits the PSC from approving applications to retire fossil fuel generators unless the unit will be replaced with capacity that is dispatchable, “maintains or improves” grid reliability and maintains the utility’s “minimum reserve capacity requirement.”

Generation operators are required to provide the commission with the costs of retiring the facility and demonstrate that its closing will result in cost savings for customers. It also stipulates that retirements cannot cause the utility to incur “any net incremental costs … that could be avoided by continuing to operate” the generator. The decision to retire cannot be based on financial incentives from the federal government.

The legislation states that coal generators are retiring at an “unprecedented rate,” creating an emergency that could impact employment rates, tax revenue and utility rates, while also reducing reliability. The emergency clause allows the bill to take effect immediately.

Supporters of the bill in the General Assembly pointed to a whitepaper published by PJM in May 2022 that found government policies were among the largest reason for generators retiring. Opponents said keeping aging facilities online would limit the ability of utilities to keep rates low.

The bill was opposed by utilities and environmental groups, who said it would increase ratepayer costs and could harm reliability by keeping aging facilities on the grid rather than replacing them with newer technologies.

“Senate Bill 4 jeopardizes the best interests of our customers — including safety, reliability and affordability,” utility group Kentuckians for Affordable & Reliable Energy said in a statement.

“For nearly 90 years, the Public Service Commission has applied principles of least-cost to approve fair, just and reasonable rates and services. SB 4 is a fundamental departure from this proven method of regulation that will only increase rates higher than necessary to achieve safe, reliable service. This change risks Kentucky’s current competitive advantage to attract and retain the manufacturing industries essential to our economy. A diverse generation portfolio is extremely important to meeting customers’ needs and allows utilities to enhance reliability, reduce risks, and keep costs down.”

The group was formed by investor-owned utilities and generators in opposition to the bill, including Duke Energy (NYSE:DUK) and PPL (NYSE:PPL) affiliates Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Co. (KU).

In an announcement following the bill’s passage, PPL said it does not believe the legislation will affect its business outlook nor its projection to receive a PSC answer on its generation replacement filings by Nov. 6, 2023. LG&E and KU are retiring nearly one-third of their capacity by 2028, to be replaced by two 621-MW natural gas plants, nearly 1,000 MW of solar and a 125-MW battery storage facility.

“We followed a well-defined and rigorous process to ensure delivery of safe, reliable and affordable energy for our customers. We’re confident that our plan exceeds the standards set out by this new law and is the best path forward for our customers. We look forward to continuing to engage with stakeholders in Kentucky and completing the process before the KPSC to demonstrate why that is,” said Vince Sorgi, PPL President and CEO.

Chris Whelan, spokesperson for LG&E and KU, said she does not believe the bill will impact the companies’ ability to obtain certificates of public convenience and necessity for the new generators.

“We had opposed this bill because we felt it … had an impact on rates and reliability for our customers,” she said.

Lane Boldman, executive director of the KY Conservation Committee, said the December 2022 winter storm demonstrated that fossil fuel generation is not as reliable as its proponents have argued. She said the ability to import wind power from other regions was central to limiting the storm’s impact.

“If you’re going to focus on reliability then you need to be focused on the transmission and the storage issue, and this was not part of the conversation that I saw,” she said. “It’s a shame there’s not more focus on resiliency at a broader portfolio of solutions, rather than just to maintain older less efficient power plants as the only option. There are other options.”

Much of the discussion in the Senate’s Natural Resources and Energy Committee focused on maintaining the coal economy in the state. Boldman acknowledged that mining communities have suffered from the industry’s decline.

“But slowing down the retirement of these coal plants only serves to impact ratepayers more, and that’s already been a problem in some of these regions … Locking people into these older coal plants is actually making it harder on the economy in those coal field regions because they have higher power bills now,” she said.

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Monitor Seeks Access to PJM Liaison Committee Meetings

The PJM Independent Market Monitor on Monday filed a complaint to FERC alleging that the RTO is in violation of its tariff by not permitting the Monitor to attend Liaison Committee meetings (EL23-50).

“It is inconsistent with the independence of PJM, the PJM board and the independence of the Market Monitor to exclude the Market Monitor from any stakeholder process,” the IMM argued. “PJM should be directed to permit the Market Monitor to register for and participate in meetings of the Liaison Committee.”

The next LC meeting is scheduled for April 3.

The Monitor was able to attend the committee’s meetings until 2018, when the Members Committee voted to enforce the LC’s charter and restrict participation to RTO members and the Board of Managers, also preventing state regulators and FERC staff from attending. The Monitor quoted the PJM tariff in arguing that it is allowed to participate in stakeholder meetings when it determines its participation to be “appropriate or necessary to perform its functions,” and that charter provisions in violation of the tariff cannot be enforced. (See “Liaison Committee Meeting to be Closed to Nonmembers,” PJM MRC/MC Briefs: Sept. 27, 2018.)

The West Virginia Public Service Commission has also filed a complaint against PJM over its exclusion from LC meetings, arguing that the tariff requires that ex officio, nonvoting members be allowed to observe and that preventing them from doing so is also a violation of nondiscrimination provisions in the Federal Power Act Sections 205 and 206 (EL23-45). (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

After also being excluded from LC meetings in 2018 alongside the Monitor, West Virginia PSC staff attended two MC meetings in September and November 2021 to push for stakeholders to vote on a rule change to permit their attendance. A motion was made during the Nov. 17 meeting to open the LC, but stakeholders narrowly voted to indefinitely table discussion.