Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Members Committee meeting Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
The Markets and Reliability Committee also is scheduled to meet from 9 to 9:40 a.m. ET, but its agenda does not contain any endorsements or voting items. RTO Insider will cover the discussions and votes.
Members Committee
Consent Agenda
The committee will be asked to endorse as part of its consent agenda:
B. tariff and Operating Agreement revisions to implement PJM’s proposed overhaul of its regulation market. The new design would use a single price signal and rely on two products representing a resource’s ability to adjust its output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.)
Texas Gov. Greg Abbott on Jan. 19 appointed Thomas Gleeson, the Public Utility Commission’s executive director and a 15-year staffer, to chair the PUC in a term that expires Sept. 1, 2029.
Gleeson replaces Kathleen Jackson, who has served as the PUC’s interim chair since June. The appointment also brings the commission to four members, one short of capacity.
In a statement supplied by the PUC, Gleeson said he was “deeply honored” by the appointment and that his three years as the commission’s executive director had prepared him for the moment.
“I know full well the magnitude of the responsibility being placed upon me,” Gleeson said. “The [PUC’s] work touches every Texan by ensuring reliable, affordable and accessible electric, water and telecom service. I look forward to working with my fellow commissioners and the extraordinary [PUC] team … to continue strengthening utility services critical to the daily lives of all Texans.”
“Thomas Gleeson’s longtime service at PUC and wealth of knowledge make him the ideal choice for chair of the commission,” Abbott said in a statement.
Texas lawmakers overhauled the PUC after the disastrous and deadly winter storm in 2021, raising the commission’s membership from three to five and serving staggered, six-year terms. Prior to that, the commissioners reached quorum under the state’s open meeting laws when in one-on-one discussions with each other.
A veteran of 15 years on the commission staff, Gleeson was named the commission’s executive director in December 2020. He previously served as the commission’s COO, as its director of finance and administration, and as a fiscal project manager. Gleeson also was a legislative analyst for the Texas Senate and a budget analyst for the Legislative Budget Board.
He holds a bachelor’s degree in business administration from Southwestern University and a master’s in public administration from The Bush School of Government and Public Service at Texas A&M University.
Gleeson’s appointment still must be confirmed when the Senate next meets in a special session or during the 2025 Legislature.
Potomac Keeps IMM Contract
The PUC also said Jan. 19 it has finalized a four-year, multimillion-dollar contract with Potomac Economics to serve as ERCOT’s Independent Market Monitor through 2027.
The contract, signed Dec. 28, is not to exceed $22.5 million, with Potomac responsible for any overage.
According to its language, Potomac must hire a director and staff to carry out day-to-day monitoring functions. However, Potomac has agreed to use its “best efforts” to avoid any staffing changes and also to remove any IMM staff the PUC “finds unacceptable for reasons related to their experience, qualifications or performance of services in the [PUC’s] sole discretion.”
The commission must vote during an open meeting to request Potomac to remove the IMM director.
Carrie Bivens resigned as the IMM’s executive director in November. ERCOT pushed back against several of the IMM’s reports last year that indicated the grid operator’s heavy use of ancillary services created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion through November. (See Bivens Resigns as ERCOT’s Market Monitor.)
ERCOT’s staff plans to revisit its use of ancillary services and report back to stakeholders in April.
David Patton told RTO Insider he expects to announce a director in the very near future. “The search is well underway,” he said. “The IMM team is doing a great job as we search for a new director.”
Potomac has held the ERCOT contract since 2007. It also monitors the ISO-NE, MISO and NYISO markets.
CARMEL, Ind. — MISO said it has landed on a final design in its quest to move to a sweeping capacity accreditation that will better measure generators’ availability based on predetermined risky hours.
That’s despite stakeholders’ calls for MISO to push back a FERC filing until later in 2024.
MISO last week said it will file by March to employ a direct loss of load approach to accreditation by the 2028/29 planning year, when capacity credits will be determined by a combination of individual past performance and a resource-class average performance during risky hours for different types of generation. Most MISO resources will see their capacity values shrink under the new method. (See MISO Defers Unpopular Capacity Accreditation Filing, Remains Committed to Design.)
At a Jan. 17 Resource Adequacy Subcommittee meeting, MISO’s Neil Shah said the RTO began discussions on accreditation two years ago, right after it rolled out its first attempt at availability-based seasonal accreditation for thermal resources only.
Since RASC meetings in 2023, MISO has modified its proposal to include an expanded set of hours beyond loss of load hours that it will draw on to gauge generator availability for accreditation. Those will include low-margin hours where the reserve margin comes within 3% or less of load. The inclusion of more hours is meant to cut down on volatile accreditations year over year. Nevertheless, the loss of load hours will carry more weight in establishing capacity credits.
MISO’s FERC filing will leave some unfinished business with stakeholders: The RTO won’t define resource classes in the filing or how it will divvy up its planning reserve margin requirement into obligations among load-serving entities.
“MISO’s plan is to not define specific resource classes in its tariff. The idea is we will include criteria on how to define resource classes, and we will work with you all in the coming months to flesh out details,” Shah told stakeholders.
Shah said MISO’s final definition for resources classes will be contained in business practice manuals only.
MISO likewise will hold off on detailing exactly how it will allocate its planning reserve margin requirement (PRMR) to load-serving entities, leaving that to a later, separate filing. MISO previously said its direct loss of load accreditation could change how MISO allocates its PRMR among its load-serving entities. Today, MISO metes out its PRMR on a load-ratio share.
A new allocation would depend in part on how MISO ultimately defines resource classes. Shah said there’s no need for MISO to include the PRMR allocation in filing, as it originally proposed.
Sustainable FERC Project’s Natalie McIntire said she worried MISO’s resource class definitions would be too vague at the time of filing for stakeholders to be confident in how their resources would be classified and therefore accredited.
Shah said working out how resources would be grouped is a matter of technical details.
“The details are what stakeholders are going to judge for whether we can support this proposal,” McIntire countered.
WPPI Energy’s Steve Leovy agreed that MISO’s proposed tariff language to group resources by similar technologies and operating characteristics is “extremely slim.”
Minnesota Power’s Tom Butz said MISO seemed in a rush to file the accreditation, while Entergy’s Wyatt Ellertson asked MISO to allow a few more months to get stakeholders more comfortable with the proposal.
“I’m hearing honest requests from stakeholders. These are not delay tactics,” Ellertson said.
“I’m hoping that by now we’ve made the case as to why capacity accreditation is an important step to mitigate, especially in the resource transition,” Executive Director of Market and Grid Strategy Zak Joundi said.
Joundi said utilities appear to be in the midst of integrated resource planning and charting future portfolios. He said it’s valuable for market participants to be able to make investment decisions with a clear view of future accreditation values.
“That’s what the rush is all about,” Joundi said.
But MidAmerican Energy’s Dehn Stevens said the accreditation’s implementation date in the 2028/29 time frame seems to set LSEs up for “failure” because they won’t be able to get new resources lined up in time in MISO’s generator interconnection queue. Stevens said a date closer to 2030 is more appropriate and would allow LSEs time to prepare different types of resources if necessary to meet summer requirements in five years.
Shah said though some LSEs “will be in a bind” and should plan better, the accreditation would give valuable investment signals to utilities. He said though stakeholders might want a later implementation, the 2028/29 target date strikes the right “balance” between MISO, utilities and the energy transition.
Joundi agreed a three-year transition will give companies time to adjust investments.
Alliant Energy’s Jamie Niccolls said MISO could find itself in a “real weird situation” if FERC were to approve the PRMR allocation method based on the new accreditation but not the accreditation filing itself.
Shah said MISO will make sure FERC approved the accreditation process before it proposes a PRMR allocation to LSEs.
Shah also said MISO will tackle how to manage data transparency in the new accreditation process, devising measures to share data and modeling with utilities in the coming months.
Staff and stakeholders will continue to discuss the accreditation plan leading up to MISO’s filing.
FERC didn’t completely buy into MISO’s package of stricter rules to lighten its gridlocked interconnection queue, rejecting the RTO’s proposed annual megawatt cap on project submittals.
The commission last week denied MISO’s proposal to use a formula to calculate an annual megawatt cap on the generation projects it will accept into its generator interconnection queue (ER24-340). MISO intended for the cap to help solve its project backlog and prevent annual surges of project entrants.
However, FERC signaled it might be open to a cap with different design elements. The commission said it couldn’t greenlight MISO’s cap because of concerns over a section of the cap’s formula, proposed exemptions to the cap and MISO’s lack of attention on resource adequacy when designing the cap.
“MISO has provided evidence that a cap in some form could be beneficial,” FERC said.
FERC OK’d other provisions on queue entry and exit that MISO submitted to reduce the size of its generator interconnection queue. In addition to its request to place an annual megawatt limit on project proposals, MISO proposed to double entrance and staged fees; institute automatic and escalating penalty charges; and require developers to confirm they’re able to obtain land for projects. (See MISO Relaxes Proposal on Stricter Queue Ruleset; MISO’s More Stringent Interconnection Queue Rules Go Before FERC.) FERC said the trio of new rules “will help improve the readiness and quality of interconnection requests” and can go into effect Jan. 22.
FERC said MISO demonstrated that its current queue requirements “are not stringent enough to deter interconnection customers from submitting speculative interconnection requests into the queue, nor strong enough to prompt unready projects to exit the queue at the earliest opportunity, as underscored by the volume of submitted interconnection requests and withdrawals that MISO has experienced in recent queue cycles.”
Though MISO proved it has a problem on its hands, FERC said the megawatt cap proposal is faulty because it allowed an unlimited number of exemptions to the cap.
MISO wanted to allow developers to exceed the cap when projects are intended for load-serving obligations, have a power purchase agreement, are an approved generator replacement facility or are requesting to convert their unguaranteed level of interconnection service to firm service.
“Although MISO’s initial proposed formula includes a 5% margin to account for exemptions (which would have the effect of decreasing the cap value to be established), MISO proposes no limit on the exemptions that may enter a queue cycle beyond the established cap,” FERC explained.
FERC said it was concerned the exemptions on certain projects could create “priority access” to MISO’s queue and violate the commission’s open access requirements for generator interconnections.
FERC also said the formula MISO planned to use to calculate the cap for each of its study regions annually was a headscratcher. It said MISO’s formula inexplicably called for calculating load remaining to be served after existing generation and higher-queued generation proposals are dispatched at the lowest possible megawatt output while remaining online. FERC said the minimum output levels don’t mimic actual or expected system conditions, and it’s unclear why MISO would use them in its cap formula.
MISO intended the megawatt cap formula to be based on its ability to develop a reasonable dispatch for studying interconnection requests based on the existing system and considering regional and subregional peak loads.
Finally, FERC said MISO needed to factor its own future resource adequacy needs into the cap’s design, especially with capacity shortfalls on the horizon.
FERC said it agreed with National Grid and Steelhead that a cap must strike a “balance between limiting the volume of requests to a level that can be processed efficiently and avoiding unnecessary barriers to entry that will delay the development of the generation capacity needed to meet growing supply shortages within the MISO region.”
However, Commissioner Mark Christie said he supported the controversial cap in a partial dissent to the order.
“Faced with a tsunami of interconnection requests from generation developers — many speculative, and which will never be built — MISO seeks to ameliorate its interconnection studies process in the near term with a cap on applications,” Christie wrote. “A cap is admittedly a blunt instrument, but it is also a logical one if the goal is to enable MISO to focus its undeniably limited resources to maintain an orderly and efficient interconnection process.”
Christie said FERC’s concern that the exemption provision would be so heavily used that it would dilute the cap was pure speculation. He also said cap exemptions for generation projects necessary to serve load are appropriate because they keep resource adequacy decisions in the hands of states.
CARMEL, Ind. — MISO said it will file by the end of the month to scrap a clunky and all-but-abandoned generator offer style from its tariff.
The RTO hopes to eliminate the unused weather curve offer function and associated software by March with FERC’s permission. The grid operator said no market participant has ever used the option since its inception in 2009.
“When I say little-used, I mean never-used,” MISO’s Dave Savageau said during a Jan. 18 Market Subcommittee meeting. “It’s actually less usable, less flexible than normal hourly offers.”
Until now, MISO combustion turbine and combined cycle generators could have selected a “weather point” — or their megawatt limits according to temperature — during asset registration and submitted weather curves to dynamically set their hourly economic maximum and emergency maximum values in the real-time market based on forecasted temperatures. However, it would have been up to the unit owner to submit a daytime and nighttime temperature estimate apiece daily through MISO’s market user interface.
The tool wasn’t a “set and forget,” MISO said, because it still was on market participants to submit two temperature points daily for MISO to create hourly maximum limits based on the unit’s weather curve.
MISO said the two single daytime and nighttime temperature points produced less-accurate forecasts compared to its normal hourly offer parameters. And since the weather curves covered only economic maximum values, market participants still had to submit minimum hourly offers separately.
Stakeholders attending the subcommittee meeting had no comments or questions on MISO’s plan to discard weather curve functionality.
MISO dodged the need for emergency procedures during a mid-January cold blast that brought consecutive days of subzero temperatures to the Midwest.
And both MISO and the Independent Market Monitor credit the wind fleet with playing a key role in keeping the system reliable.
MISO likely achieved its systemwide winter peak of 106 GW as the arctic air dragged on Jan. 17.
At a Jan. 18 Market Subcommittee meeting, MISO’s Tim Aliff said the South region set a new wintertime peak of 32.3 GW on Jan. 17, unseating the previous 31.8-GW record set in late 2022. That day, Baton Rouge bottomed out at 19 F, outstripping the day’s previous record of 20 F set in 1905. Other Louisiana cities logged record low temperatures for the day, toppling previous records set either nearly 120 years or more than 50 years ago.
MISO enacted a cold weather alert and conservative operations beginning Jan. 13 and lifted them Jan. 18 and Jan. 17, respectively. The grid operator never was forced to escalate instructions to a maximum generation alert or warning as cold gripped the entire footprint.
Aliff said MISO experienced “robust reserve margins” during the storm that varied between 14-19 GW and were generally available within four hours or less. He said thermal generation performed well throughout the event, with up to 2 GW of derates, compared to the approximately 10 GW in derates that occurred in late 2022 during Winter Storm Elliott.
Wind generation also made healthy contributions during the storm, Aliff said, varying between 12-20 GW.
Potomac Economics’ Carrie Milton, representing MISO’s Independent Market Monitor, said the week’s weather qualified as an extreme event that the Monitor analyzes in seasonal assessments for emergency potential. Milton said high wind output kept MISO out of emergency conditions; the Monitor had predicted ahead of the season that MISO would require emergency actions if it experienced nearly identical conditions to the storm.
“We got a lot of support from wind, much higher than [unforced capacity] values,” Milton said. She said there were fewer instances of cold weather cutoffs and icing among the wind fleet than the Monitor anticipated.
MISO will deliver a more comprehensive picture of its operations during the event at the Jan. 25 Reliability Subcommittee meeting.
FERC on Jan. 18 partly granted two formal challenges against AEP utilities arguing that benefits from filing consolidated tax returns were not properly reflected in the utilities’ 2021 formula rates in SPP and PJM.
The challenge to the rates filed by AEP subsidiaries in SPP — AEP Oklahoma Transmission and AEP Southwestern Transmission — argued that AEP’s calculation of accumulated deferred income taxes (ADIT) inflated the annual transmission revenue requirement (ATRR) in its 2021 rates by around $22 million. That complaint also argued that AEP incorrectly designated several expenses as falling into the ADIT bucket, increasing the net operating losses that can be used to offset income in future tax years.
The SPP challenge was jointly submitted by Arkansas Electric Cooperative Corp., East Texas Electric Cooperative, Northeast Texas Electric Cooperative and Golden Spread Electric Cooperative. (ER17-405, ER18-194.)
In PJM, several electric cooperatives submitted a challenge arguing that the ADIT calculation inflated the ATRR by $55.9 million.
The PJM challenge was jointly filed by American Municipal Power, Blue Ridge Power Agency, Indiana Municipal Power Agency, Mishawaka Utilities, Old Dominion Electric Cooperative and Wabash Valley Power Association against rates detailed in the annual update submitted by AEP Appalachian Transmission, AEP Indiana Michigan Transmission, AEP Kentucky Transmission, AEP Ohio Transmission and AEP West Virginia Transmission.
FERC’s Jan. 18 order found that AEP’s approach of including net operating loss carryforward ADIT as deferred tax inputs to its rate base did not pass the “benefits and burdens” test, which requires that tax benefits resulting from expenses paid by ratepayers be assigned to those ratepayers. The commission found that by not accounting for the benefits of filing consolidated tax returns in the net operating loss carryforward, AEP had calculated inflated ADIT input adjustments that resulted in higher transmission rates.
AEP argued that the benefits of filing consolidated tax returns do not result from a burden to ratepayers and therefore should not be assigned to them.
The challenge to rates filed by AEP’s SPP subsidiaries disputed several expenses the utility included in Account 928, which is meant to record regulatory commission expenses. The commission denied the challenge in part, finding that in most cases, AEP had properly explained the expenses, but required compliance filings within 60 days to provide more detail on others, such as the use of the allocation of fees to transmission using a gross plant allocator.
The challenge to the AEP subsidiaries in PJM argued that the utilities also improperly included ADIT assets in its rate base that were the result of over-recovered ratepayer funds. The commission granted the challenge, finding that “because the underlying refund amounts associated with the ADIT asset recorded in Account 190 are not included in rate base, the associated ADIT asset and excess or deficient ADIT should not be included either. The related ADIT must be excluded if the associated refund amounts are excluded from rate base.”
The commission’s order required AEP to submit a compliance filing within 60 days that details the calculations for the formula rate billings in the 2020 and 2021 annual updates and issue refunds for any improperly collected revenues. It also directed AEP to submit a compliance filing explaining how it includes ADIT related to contributions in aid of construction (CIAC) in its formula rate.
NERC laid out its plan for developing standards to improve the reliability of inverter-based resources, primarily wind and solar generation facilities, in a filing with FERC on Jan. 18 in response to Order 901, issued by the commission in October (RM22-12).
The ERO’s work plan is meant “to provide a detailed roadmap to guide the effective and orderly development of reliability standards addressing IBR issues through 2026” in accordance with Order 901, NERC said in its filing. The order directed NERC to develop rules addressing IBR data-sharing, model validation, planning and operational studies, and performance standards, and submit the standards in annual tranches over the next three years starting in 2024. (See FERC Orders Reliability Rules for Inverter-Based Resources.)
FERC gave NERC 30 days to submit a standards development and implementation plan for informational purposes. The commission recognized in its order that the ERO had “already expended considerable effort” thinking about its approach to IBR-related standards; FERC therefore felt it was “not … necessary to approve NERC’s final work plan.”
The plan “contemplates a broad, cross-functional effort” involving ERO staff and industry stakeholders working together to identify gaps in current reliability standards, review NERC’s ongoing standards development projects, suggest new projects as needed, and “provide additional support and analysis” as development continues.
The organization identified four key milestones to be completed over the next three years, the first of which is the submission of the work plan itself. The remaining targets comprise the filing of reliability standards to address the following requirements:
Performance requirements and post-event performance validation for registered IBRs (2024);
Data-sharing and model validation for all IBRs (2025); and
Planning and operational studies requirements for all IBRs (2026).
The standards associated with each milestone are to be filed by Nov. 4 of the respective year. NERC plans to assign projects under the 2024 milestone the highest priority; projects addressing the other two milestones “will be elevated in priority to assure timely completion” as the earlier projects are finished.
NERC identified three active projects as “essential for meeting [Order 901] directives” relating to the first milestone: Project 2021-04 (Modifications to PRC-002 – Phase II), Project 2020-02 (Modifications to PRC-024) and Project 2023-02 (Analysis and mitigation of bulk electric system IBR performance issues). The plan noted that these projects “may require some small adjustment to assure a timely completion,” and that the teams will need to coordinate throughout the year.
Additional goals for NERC in 2024 include identifying and defining, “from a technological standpoint,” the terms that will likely be used in the standards developed to address FERC’s directives, such as “inverter-based resource” and “distributed energy resource.” Establishing consistent technical understandings of these terms will reduce the need to harmonize the efforts of the various standard drafting teams working on similar topics, it said.
For the remaining milestones, NERC said “additional gap analyses” will be needed to incorporate currently active projects into the work. NERC’s standards development staff will work with the organization’s engineering teams and the Reliability and Security Technical Committee to identify the appropriate projects and determine what additional projects may be needed to address FERC’s objectives.
The New Mexico Public Regulation Commission will dive into a report on the financial implications of a Western day-ahead electricity market during a workshop Jan. 25.
The workshop is part of the PRC’s research into the pros and cons of utility participation in a regional day-ahead market or RTO. The PRC plans to develop “guiding principles” for utilities to consider in deciding whether to participate.
During the workshop, the regulators will hear a presentation from Energy+Environmental Economics on the cost-benefit study, which E3 prepared for the Western Markets Exploratory Group. WMEG is a coalition of transmission-owning entities covering most of the Western Interconnection. (See Study Shows Uneven Benefits for Calif., Rest of West in Single Market.)
E3 also conducted additional economic analysis for individual WMEG members. Results for two New Mexico utilities — Public Service Company of New Mexico (PNM) and El Paso Electric (EPE) — will be shared during the workshop.
Commissioner Gabriel Aguilera said there are several issues to consider in an RTO or day-ahead market decision, including transparency, seams and reliability.
But from a regulator’s perspective, the most important questions are “will the market design lead to financial benefits to ratepayers?” and “will the benefits outweigh the costs?” Aguilera told RTO Insider.
The commission doesn’t currently have a timeline for finalizing its guiding principles, but Aguilera acknowledged the need to act quickly.
PNM has said it expects to decide this year on joining a regional day-ahead market. The two options are CAISO’s extended day-ahead market (EDAM) or SPP’s Markets+ offering.
The upcoming meeting is a follow-up to a workshop in September that featured presentations from PNM, EPE and Southwestern Public Service Co. (SeeNew Mexico Contemplates Organized Market Choice.) PNM and EPE will give an update during the upcoming meeting, according to the agenda.
Aguilera said the commission is seeking as much input as possible.
The workshop will begin at 2 p.m. MST. Those who wish to comment may attend in-person or via Zoom.
To attend the meeting via Zoom, email public.comment@prc.nm.gov or call (505) 490-7910. The deadline to sign up for public comment is 5 p.m. Jan. 24, or 5 p.m. Jan. 19 for those who want to participate in the meeting’s question-and-answer session.
The meeting will also be streamed on the PRC’s YouTube channel.
Pacific Gas and Electric’s Diablo Canyon Power Plant will be the first recipient of federal funds being made available to shore up operations at U.S. nuclear plants that face imminent closure.
The Department of Energy on Jan. 17 awarded the California utility $1.1 billion to help maintain operations at the 2,200-MW nuclear plant, whose two units had been slated for closure in 2024 and 2025.
DOE is providing the money through the Civil Nuclear Credit (CNC) Program, established in 2022 with $6 billion from the Infrastructure Investment and Jobs Act (IIJA) to head off the shutdown of nuclear plants from economic factors. Under the terms of the program, applicants must commit to “best efforts” to use uranium produced in the U.S. and seek to rely on domestic providers of other services.
PG&E is the first plant operator to win money under the first funding cycle of the CNC program. The utility will receive credits in installments paid over four years, “with the amount of the annual payment to be adjusted based on a number of factors, including actual costs incurred to extend the operation of the Diablo Canyon Power Plant,” according to DOE.
The first payment is scheduled for 2025 and will be based on the plant’s operations over 2023/24.
“Preserving the nation’s nuclear fleet is critical not only to reaching America’s clean energy goals, but also to ensuring that homes and businesses across the country have reliable energy,” Maria Robinson, director of DOE’s Grid Deployment Office, said in a statement about the award. “Today’s announcement demonstrates the [Biden] administration’s commitment to domestic nuclear energy by preserving existing generation while we continue to support a stronger nuclear power industry.”
Located on the West Coast near Avila Beach, Calif., the 2,200-MW Diablo Canyon plant provides about 9% of California’s in-state generation and 15% of its emissions-free energy.
The plant had been scheduled to close in stages starting this year, largely in response to concerns about its vulnerability to earthquakes. Those concerns increased sharply in the aftermath of the 2011 major accident and radiation release at the Fukushima Daiichi nuclear plant, which was caused by an earthquake and ensuing tsunami.
But since California’s rolling blackouts of 2020, state officials — including Gov. Gavin Newsom — have expressed growing worries about how to maintain grid reliability without the plant as the state works to meet ambitious targets to reduce its economywide carbon emissions. In 2022, Newsom signed Senate Bill 846, which directed the California Public Utilities Commission to authorize an extension for Diablo Canyon by December 2023.
The CPUC last month voted 3-0 to keep Units 1 and 2 at the plant running until 2029 and 2030, respectively. In approving the extension, the commission said it would continue to evaluate whether the cost of continued operation becomes “too high to justify incurring,” as outlined in SB 846. (See California PUC Votes to Extend Diablo Canyon Nuclear Plant 5 Years.)
PG&E is still awaiting approval for an extension to its operating license from the U.S. Nuclear Regulatory Commission after filing a renewal application last November.
