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November 17, 2024

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CAISO Board Approves Nevada Transmission Line to Access Idaho Wind

CAISO’s Board of Governors on Dec. 14 approved the inclusion of the Southwest Intertie Project-North (SWIP-N) — a 285-mile, 500-kV line in Nevada that would enable access to Idaho’s wind resources — in to the ISO’s 2022-2023 transmission portfolio.

The project is the only proposed line that would connect California’s load-serving entities to Idaho wind power. (See CAISO Pursuing Approval of New Line to Tap Idaho Wind.)

“This is a really exciting opportunity to open up some … really valuable resource diversity indexed straight to the California [Public Utilities Commission]’s integrated resource plans … and build on that legacy of transmission connectivity that exists across the West,” CAISO CEO Elliot Mainzer told the board before its vote.

The approval of SWIP-N diverges from the standard transmission planning process. The board already approved the ISO’s transmission plan in May. (See CAISO Board Adopts Revamped Transmission Plan.)

“This is a unique project, and it has quite a few differences from a conventional transmission plan approval decision … both because of the nature of the project and because of our negotiated arrangements with Idaho Power to access the capacity jointly,” Neil Millar, CAISO vice president of infrastructure and operations planning, told the board.

The project would require CAISO to assume entitlements from LS Power subsidiary Great Basin Transmission (GBT) on the existing One Nevada Transmission Line, which connects to the ISO via the Harry Allen substation north of Las Vegas. SWIP-N would connect with the existing line at the Robinson Summit substation near Ely, Nev. Both the ON Line and Robinson would need upgrades to accommodate the new project.

SWIP-N could be online by 2027, but the board’s approval is conditional on the Idaho Public Utilities Commission’s by Sept. 30. The CPUC also would have to reaffirm the need for Idaho wind power as part of its consideration of CAISO’s 2024-2025 transmission plan. And FERC would have to approve GBT’s tariff as a participating transmission owner and transmission revenue requirement.

Assuming everything is approved, CAISO expects it would file a project sponsor agreement with FERC in January 2025.

Jeff Billinton, CAISO director of infrastructure planning, reported that stakeholders generally supported the project, but some were concerned about costs. Millar noted the approval timeline allowed for plenty of opportunity for comment throughout 2024.

“Only after the FERC approves the project sponsor agreement do any cost-commitment issues arise; termination provisions go into effect,” he said. CAISO also then would begin a quarterly cost review process with LS Power. “So we believe that these gating checkpoints provide the right milestones, the right transparency [and] the right visibility.”

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Texas RE: Winterization Activities in ‘Good Shape’

The Texas Reliability Entity’s chief engineer, Mark Henry, told the organization’s Board of Directors last week that ERCOT generators’ winterization efforts are in “pretty good shape” in preparing for a NERC cold-weather standard. 

“We found that people who did have issues in our region during [the December 2022] winter storm generally are following through with the actions that are expected here and of course with the things that are part of the state rules now,” Henry said during the board’s Dec. 13 meeting, promising Texas RE will follow up with some of the entities to ensure “we’re not missing something.” 

NERC gathered the data last year from balancing authorities, transmission operators, and 1,160 generation owners and operators. They were asked to identify specific actions determined to be essential to the bulk power system’s reliability and the status of those actions. 

Henry said 245 ERCOT generators were surveyed, with 82% saying they didn’t experience a cold-weather reliability event during last winter and 86% saying they have completed or partially completed essential actions identified by NERC. 

ERCOT generation owners have calculated the extreme cold weather temperature (ECWT) for their facilities, with 96% saying they can operate at that temperature, Henry said. The ECWT is higher than 10 degrees Fahrenheit, which is higher than the February 2021 winter storm’s extreme conditions. 

Texas RE staff has shared some of the information gathered with ERCOT that could boost the ISO’s weatherization-inspection program. 

“We’re going to stay plugged into what they’re doing and let the folks in the other NERC regions know how we’re prepared down here in Texas,” Henry said. 

The cold-weather standard (EOP-012-2, extreme cold weather preparedness and operations) is hung up in NERC’s approval process, having failed two rounds of voting. NERC’s Board of Trustees have said they may have to take matters into its own hands if the standard fails another vote. (See NERC Board May Force Action on Cold Weather Standard.) 

Corbett to Chair Board

The board approved the nominations of Jeff Corbett and Suzanne Spaulding as its chair and vice chair. They will replace Milton Lee and Crystal Ashby in 2024. 

Corbett was a senior executive with Duke Energy after 30 years at Dominion Virginia Power and Progress Energy. Spaulding, who recently was elected by Texas RE’s membership to another three-year term as an independent director, has cybersecurity experience at the federal level and also spent six years at the CIA. She currently is senior adviser for homeland security at the Center for Strategic and International Studies (CSIS). 

The Member Representative Committee selected its 2024-25 representation in November. It will vote on its leadership in January. 

The MRC members are: 

      • Chad Thompson, ERCOT; 
      • Daniela Hammons, CenterPoint Energy; 
      • Lance Spross, Oncor; 
      • Frank Owens, Rayburn Country Electric Cooperative; 
      • Shari Heino, Brazos Electric Power Cooperative; 
      • Curt Brockmann, CPS Energy; 
      • Brock Carter, Austin Energy; 
      • David Hodges, RWE Renewables; 
      • Kristina Marriott, Miller Bros. Solar; 
      • Jeremy Carpenter, Tenaska Power Services; and  
      • Venona Greaff, Occidental Power Services.

    Brockmann, Greaff, Hammons and Heino are incumbents. 

    Texas RE Wins Workplace Award

    Texas RE CEO Jim Albright celebrated the organization’s inclusion among the top workplaces in the greater Austin area, as nominated by employees and recognized by the Austin American-Statesman. The reliability entity placed 14th among organizations with between 50 and 149 employees. 

    “This is a great achievement. Over the past three years, we’ve worked together to enhance our workplace culture,” Albright said during the annual membership meeting. “We believe this award … provides us some evidence that we’re going in the right direction. We were just 14 out of 66, so we still have room for improvement.” 

    Staff also reported Texas RE had a net gain of 17 members during the year to push its membership to 125. Generation accounts for most of the total with 89 members, followed by municipal utilities (11) and transmission and distribution providers (10). 

    As of Nov. 1, Texas RE had 335 registered entities, a gain of 32 from a year ago. 

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Texas Public Utility Commission Briefs: Dec. 14, 2023

ERCOT staff last week shared additional details with Texas regulators on the Sept. 6 frequency drop that lead to the grid operator entering emergency operations for the first time since the disastrous 2021 winter storm.  

Dan Woodfin, ERCOT’s vice president of system operations, told the Public Utility Commission during its open meeting Dec. 14 that more than 500 MW of the system’s physical responsive capability (PRC) was incorrect and/or unavailable at a time when PRC was dropping to 2,100 MW (54444). 

Woodfin said staff issued a request for information to entities contributing to PRC because “we had reason to believe” the information it was receiving from participants to calculate the reserves “was probably too high.” He said when frequency was at its lowest, calculated PRC was about 564 MW higher than what it should have been. 

Thermal generators were reporting about 200 MW of capacity they could reach, an incorrect reading based on ambient air temperatures, Woodfin said. 

“There’s always a little bit of error there,” he said. 

Woodfin said another 200 MW were unavailable from curtailed wind resources that were unable to respond to frequency because their automatic controls didn’t work properly. Another 158 MW were unavailable from energy storage resources (ESRs) that had depleted their state of charge (SOC) and couldn’t regain their SOC quickly enough. 

The frequency drop led to a dip in operating reserves below the 2,300-MW threshold, forcing ERCOT to issue a Level 2 energy emergency alert to maintain critical system frequency. The grid operator limited transmission from South Texas, trapping available wind generation along the Gulf Coast. (See ERCOT Voltage Drop Leads to EEA Level 2.) 

Demand peaked at 82.7 GW on Sept. 6, setting a new high for September. The ERCOT grid was without 10.5 GW of unplanned outages at PRC’s lowest point, below the summer’s typical daily outages of about 12 GW, Woodfin said. 

“I think these are things that are going to be more normal than not, at least until the transmission line from the south gets completed and some of the reliability issues get resolved. Long term. I hope this was a lesson,” commissioner Jimmy Glotfelty said. 

The PUC has approved a pair of transmission projects designed to increase capacity between South Texas and the rest of the grid. 

Jimmy Glotfelty shakes hands with Will McAdams during latter’s last PUC open meeting. | Admin Monitor

SOC Discussion Deferred Again

The commission granted ERCOT’s request to defer further discussion of a proposed rule change that sets a one-hour SOC for ESRs participating in two ancillary services and that Glotfelty has called “totally discriminatory” to the resources (54445). 

The grid operator told PUC staff that the delay would give it a chance to better prepare its materials and give the commission and market participants to review and comment on its presentation materials. ERCOT is committed to filing a detailed presentation no later than Jan. 4. 

The nodal protocol revision request (NPRR1186) has drawn opposition from storage developers during the stakeholder process. The PUC declined to approve the change during its last meeting and will take it up during its next open meeting Jan. 18. (See Texas Public Utility Commission Briefs: Nov. 30, 2023.) 

Glotfelty accepted the delay, questioning whether ERCOT staff’s time couldn’t be better spent on other work. 

“We want to make sure that we get all the information that ERCOT can provide before we take action on it,” Commissioner Lori Cobos said. “I really do hope that we get some good information from ERCOT to help us better understand the issues they’re seeing from their perspective.” 

The PUC did approve two consulting firms’ work plan for a value-of-lost-load survey and study to determine the estimated value of reliability in the ERCOT region (55837). 

The Brattle Group and PlanBeyond plan to survey retail customers using contact information provided by the grid operator in competitive areas and historical kilowatt-hour energy usage in competitive areas. The firms will have to depend on ERCOT’s relationships with non-opt-in entities, such as municipalities and cooperatives, and partner with them in their service territories to gather the same information. 

The firms plan to complete the survey and deliver its results to the commission by the end of June. They say the study will be “fundamental” in supporting the PUC’s market design initiatives, including the development of a reliability standard.  

Permian Basin Reliability Plan

Cobos and commission staff hosted a public workshop for oil and gas representatives, transmission and distribution utilities, and ERCOT staff in Midland on Dec. 12 to discuss reliability and electrification needs in the petroleum-rich Permian Basin (55718). 

“Texas is the No. 1 energy-producing state in the United States, Texas energy powers the world, and the Permian Basin is a critically important part of this success,” Cobos said.

Legislation passed earlier this year requires ERCOT to work with transmission service providers to develop a reliability plan for the Permian Basin region. The plan must address the region’s transmission needs, additional generation to meet the energy industry’s demand and streamlining interconnection processes.

The plan is due to the PUC in July for stakeholder feedback. The commission then will consider the plan for its approval.

345-kV Project Approved

The PUC approved revised certificates of convenience and necessity for a 345-kV double circuit transmission line in West Texas needed to address reliability issues driven by rapid oil and gas load growth and to improve import capability into the Delaware Basin.

The joint project between Lower Colorado River Authority Transmission Services Corp. and Wind Energy Transmission Texas involves 68 miles of new circuits and substation upgrades. It’s estimated to cost $370 million and be in service in 2026, when the region’s load will exceed 4,000 MW (55120).

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PJM MRC/MC Preview: Dec. 20, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings. 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.

RTO Insider will be covering the discussions and votes. See the next newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse conforming revisions to Manual 12, Balancing Operations; Manual 13, Emergency Operations; and Manual 14D, Generator Operational Requirements to implement a renewable dispatch package. (See “Other Committee Business,” PJM MIC Briefs: Nov. 1, 2023.)

Issue Tracking: Renewable Dispatch

C. Endorse proposed revisions to Manual 14B, PJM Region Transmission Planning Process as a part of its periodic review. The changes include specifying that the 300-MW load loss rule is meant to apply to possible outages that would affect a large number of consumers, rather than a single large industrial customer. (See “First Read of Periodic Review of Manuals 19 and 14B,” PJM PC/TEAC Briefs: Oct. 3, 2023.)

D. Endorse conforming revisions to Manual 21A, Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing Hybrids Phase II Market Participation of Hybrid Resources and other Mixed Technology Facilities instituting the second phase of PJM’s rules for hybrid resources.

Issue Tracking: Solar-Battery Hybrid Resources

E. Approve sunsetting the Energy Price Formation Senior Task Force (EPFSTF).

Issue Tracking: Operating Reserve Demand Curve (ORDC) & Transmission Constraint Penalty Factors

Endorsements (9:10-9:55)

  1. Performance Impact of the Multi-schedule Model on the Market Clearing Engine (9:10-9:30)

PJM’s Danielle Croop will present the proposal endorsed by the Market Implementation Committee on Aug. 9 to revise how some resource offers are entered into the market clearing engine (MCE) to allow multi-schedule modeling to be implemented without overloading the engine with an exponential increase in the number of schedules it must consider. Croop also will present an alternative approach which received lesser MIC support, but still a majority. (See “Endorsement of Multi-schedule Modeling Solution Deferred,” PJM MRC/MC Briefs: Nov. 15, 2023.)

The committee will be asked to endorse the proposed solution and corresponding tariff and Operating Agreement revisions.

Issue Tracking: Performance Impact of the Multi-Schedule Model on the Market Clearing Engine

  1. Regulation Market Design Senior Task Force (RMDSTF) (9:30-9:55)

Croop will present a proposal to shift the regulation market to have a single price signal with two products representing a resource’s ability to adjust its output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Nov. 15, 2023.)

The committee will be asked to endorse the proposed solution and corresponding tariff and OA revisions.

Issue Tracking: Regulation Market Design

Members Committee

Endorsements (10:10-10:20)

PJM’s Michele Greening will present the proposed sector representatives for the 2024 Finance Committee, 2024 sector whips and 2024 MC vice chair.

The committee will be asked to elect the proposed representatives.

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Treasury Releases Guidance on Sustainable Aviation Fuel Tax Credit

The Department of the Treasury and the Internal Revenue Service on Dec. 15 released guidance on the sustainable aviation fuel (SAF) tax credit from the Inflation Reduction Act, meant to encourage clean fuel for airplanes.

Treasury worked closely on the guidance with other cabinet agencies, including EPA and the departments of Transportation, Agriculture and Energy, Treasury Secretary Janet Yellen said in a statement.

“The Biden administration is driving American innovation to create good-paying jobs and help the U.S. clear hurdles in our clean energy transition,” Yellen said. “Incentives in the Inflation Reduction [Act] are helping to scale production of low-carbon fuels and cut emissions from the aviation sector, one of the most difficult-to-transition sectors of our economy.”

The credit incentivizes production of SAF that achieves lifecycle greenhouse gas emissions cuts of at least 50% compared to standard jet fuel refined from oil. Producers of SAF are eligible for a tax credit ranging from $1.25 to $1.75/gallon.

Fuel that cuts GHG emissions by 50% will be eligible for a $1.25/gallon credit and an additional cent per gallon for every 1% more, up to 50 cents/gallon, Treasury said.

Multiple kinds of fuels are eligible for the credit, including biomass-based diesel, advanced biofuels, cellulosic biofuels and cellulosic diesel, all of which have been approved by EPA under its Renewable Fuel Standard.

Fuels that achieve a 50% or greater reduction in lifecycle emissions under the most recent Carbon Offsetting and Reduction Scheme for International Aviation will continue to qualify for tax credits.

EPA, DOT, USDA and DOE also committed to releasing a new version of DOE’s Greenhouse gases, Regulated Emissions and Energy Use in Transportation (GREET) model by March 1, 2024. Pending additional guidance from Treasury, the new model will offer other ways for SAF producers to determine the lifecycle emissions for their fuels, the department said.

The updated model will use new data and science, including new modeling of key feedstocks and processes used in aviation fuel. It will also integrate other categories of indirect emissions, like crop production and livestock activity, and carbon-abatement strategies such as carbon capture, renewable natural gas, renewable electricity and climate-smart agricultural practices.

“President Biden’s Investing in America agenda is creating pathways and incentives for innovators to create a cleaner, more sustainable future,” said Energy Secretary Jennifer Granholm. “Sustainable aviation fuel will provide low-carbon fuel made here in America to help decarbonize the hardest-to-reach areas in the transportation sector, and DOE is committed to supporting this effort, which will lead to cleaner skies for all.”

The Clean Air Task Force said the guidance on the SAF credit further capitalizes on the Inflation Reduction Act’s enormous potential to mitigate climate change by requiring fuel producers to show their products actually deliver clear environmental benefits.

“The climate impact of the SAF credit depends in large part on Treasury’s ability to identify and reward those biofuels that actually reduce net emissions to the atmosphere,” CATF Director of Transportation Decarbonization Jonathan Lewis said in a statement. “Today’s guidance shows that the government is taking that job seriously.”

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California Approves $30M to Build a 100-hour Battery Storage System

The California Energy Commission has awarded $30 million to Form Energy to build a 5-MW, 100-hour long-duration energy storage system in Mendocino County — the state’s largest LDES project yet. And in another first for the state, the project will deploy iron-air battery technology, which is described as “reversible rusting.”

CEC Chair David Hochschild said that although California is the largest and fastest-growing energy storage market in the world, most storage built so far has been four-hour, lithium-ion battery systems.

“A multiday battery system is transformational for California’s energy mix,” Hochschild said in a statement. “This project will enhance our ability to harness excess renewables during nonpeak hours for use during peak demand, especially as we work toward a goal of 100% clean electricity.”

The commission voted to approve the grant to Form Energy during its Dec. 13 business meeting.

Form Energy will develop and operate the demonstration project, collecting data that utilities may use in future deployments. Pacific Gas & Electric will provide land and a substation interconnection. The project is expected to be online by the end of 2025.

The project will be funded through the CEC’s Long Duration Energy Storage program, a $330 million fund aimed at spurring the development of nonlithium-ion energy storage technologies.

California is expected to need 4 GW of LDES to meet the goal of 100% clean electricity by 2045. But reliance on lithium-ion technology could impede the state’s ability to meet its clean energy goals, the CEC said during a workshop in June.

During the Dec. 13 meeting, CEC mechanical engineer Yahui Yang said that as California gains renewable energy resources, the amount of curtailment has been increasing, to as much as 2.4 TWh of solar and wind last year.

“Energy storage, particularly long-duration energy storage, can mitigate this issue and further reduce the cost of renewable energy,” he said.

Yang described the battery chemistry in Form Energy’s system as “very safe,” saying there’s no pathway for thermal runaway. And the cost of iron-air systems could be as low as $20 per kWh, compared to $200 per kWh for a lithium-ion battery.

Form Energy’s LDES project will use reversible rusting, in which iron that is exposed to oxygen rusts, releasing electrons that can be sent to the grid, according to Form Energy’s website. When there is excess power, electrons can be sent back into the battery to reverse the rusting. Oxygen is released in the process.

Form Energy also has pilot and demonstration projects underway in Minnesota, Colorado, Virginia, New York and Georgia, with projected in-service dates of 2024 to 2026. (See Form Energy Wants to Bring Long-duration Storage to New England.) The Somerville, Mass.-based company has an engineering facility in Berkeley, Calif.

Jason Houck, senior manager for policy strategy at Form Energy, said the California project would support the local grid in a transmission-constrained area with wildfire risks.

The project “will operate every day of the year to balance the hourly, multiday and seasonal variability of renewable energy resources,” Houck told the commission.

“By making the best use of our renewable energy supply and our transmission and distribution systems, we’ll lower the overall costs of the electric system and the land use impacts of achieving our clean energy goals,” he said.

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Texas Appeals Court Clears Generators of Uri Lawsuits

Texas generators may escape further litigation for their inability to meet demand during the 2021 winter storm after a state appeals court ruled Dec. 14 that wrongful death, personal injury and property damage cases against the generators have “no basis in law or fact” (01-23-00097-CV, 01-23-00102-CV, 01-23-00103-CV, 01-23-00392-CV and 01-23-00393-CV).

The 1st Court of Appeals in Houston ruled that wholesale power generators in ERCOT’s deregulated market are “statutorily precluded by the Legislature from having any direct relationship with retail customers” and “can have no legal relationship with retail customers as a matter of law.”

“Texas does not currently recognize a legal duty owed by wholesale power generators to retail customers to provide continuous electricity to the electric grid, and ultimately to the retail customers, under the allegations pleaded here by the retail customers,” the court said.

According to Texas Lawbook, the decision will lead to the dismissal of Luminant, NRG, Exelon, Sempra Energy Resources and other generators from the hundreds of lawsuits filed in the wake of Winter Storm Uri.

The storm brought sub-freezing temperatures and precipitation to much of the state that shut down thermal and nonthermal power plants alike. The state says almost 250 people died during the resulting dayslong outages, although it’s thought that number is much higher.

Hundreds of retail customers sued hundreds of entities involved in the ERCOT market for damages sustained due to the outages. They alleged negligence and gross negligence for failing to winterize and maintain their equipment, failing to ensure adequate fuel supplies and failing to properly train workers to ensure against the generator outages that occurred.

The lawsuits were consolidated into multidistrict litigation before Harris County District Judge Sylvia Matthews, who dismissed all the allegations except the negligence claims. The judge then selected five bellwether cases as representative of the cases filed.

The generators filed a petition with the appeals court, arguing that Matthews had abused her discretion in not dismissing the negligence charges. The court agreed, saying the charges should have been dismissed because the retail customers’ arguments alleged actions “have no basis in law or fact.”

The opinion applies to the five bellwether cases. The plaintiffs’ legal counsel has said they plan to appeal.

The Texas Supreme Court ruled in June that ERCOT, which operates 90% of the state’s grid, enjoys sovereign immunity and cannot be sued over the blackout. (See ERCOT Sovereign Immunity Affirmed by Texas Supreme Court.)

The state high court will hear arguments next year from Luminant (23-0231) and RWE Renewables (23-0555) over the Public Utility Commission’s emergency pricing order following the winter storm. The PUC directed prices be maintained at the $9,000/MWh cap to incent more generation to come online and end load shed.

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Standards Committee Authorizes Shortened Ballots

NERC’s Standards Committee agreed Dec. 13 to send a twice-rejected cold weather reliability standard to industry for another ballot round after the organization’s Board of Trustees made clear this week that it was prepared to take action on its own if the standard failed another vote. 

The EOP-012-2 (Extreme cold weather preparedness and operations) standard has been under development since February, after FERC approved its predecessor standard EOP-012-1 but ordered a revised version to be submitted within a year. Two ballot rounds have failed to produce enough industry support to submit the standard to the board; the most recent round ended with a 58% segment-weighted vote for approval, short of the necessary two-thirds majority. 

At the Standards Committee’s monthly meeting this week, held at NERC headquarters in Atlanta, members voted unanimously to grant a waiver to the ERO’s Standard Processes Manual shortening any additional formal comment and ballot periods for the standard “to as little as 10 days” from the usual 45, with ballots to be conducted during the last five days of the comment period. 

This action was urged by the board at its meeting on Dec. 12, with Chair Ken DeFontes warning that if the committee did not pass the waiver the board would invoke its authority under section 321 of NERC’s Rules of Procedure to approve the standard without a successful ballot. (See related story, NERC Board May Force Action on Cold Weather Standard.) While the board has never used this authority before, DeFontes said it could be necessary in order to avoid missing FERC’s February deadline. 

While no members objected to the shortened comment period, Marty Hostler of the Northern California Power Agency noted that reports by FERC and NERC on previous cold weather events have recommended a three-pronged approach to improving winter reliability. This approach consists of improved reliability standards, outreach to generator owners and operators, and market rule changes where needed; however, Hostler said most of the effort so far has been in the first two areas, with apparently little action on market rules. 

“I understand we’re up against a deadline here, but to my knowledge there has been nothing done about market rule changes,” Hostler said. “I know NERC doesn’t do that, but that’s one of the prime recommendations for helping reliability, and I think there needs to be something on that as well, because that will improve … reliability [somewhat] and not just rely strictly on standards all the time.” 

A NERC representative confirmed that the shortened ballot period for EOP-012-2 will begin in January, after the winter holidays. 

Accelerated Timelines Approved

EOP-012-2 was just one of the proposed standards for which the committee approved shortened comment and ballot periods on Wednesday, reflecting the group’s desire to shorten development timelines and reduce what Chair Amy Casuscelli called “an all-time high number of standards development projects in flight.” 

Three of the projects in question are operating under the timeline imposed in FERC’s Order 901, issued in October. The order directed NERC to submit to the commission over the next three years three tranches of standards to improve the reliability of inverter-based resources. (See FERC Orders Reliability Rules for Inverter-Based Resources.) 

The first tranche — covering disturbance monitoring data sharing and post-event IBR performance validation and correction — is due in November 2024. Jamie Calderon, NERC manager of standards development, told the committee that the ERO had identified three projects affected by the deadline: 

For the first two projects, NERC staff proposed to authorize shortening the initial formal comment and ballot periods “from 45 days to as few as 25 calendar days.” Project 2021-04 was not included in this request because it has already had its initial formal comment period. NERC’s additional proposals, to authorize shortening additional formal comment periods to “as little as 15 days” and reduce the final ballot period from 10 days to five calendar days, applied to all three projects. 

Calderon acknowledged that the requests were being made far in advance of any of these projects having a draft standard to send out for ballot. She explained that because of the “very tight timeline” of FERC’s order, the ERO wanted to request the process waivers ahead of time to ensure the standard drafting teams will not need to request them later if needed. 

Committee members approved the proposals for all three projects, albeit with some minor wording changes: clarifying that the shortening of additional comment periods applied to calendar days, and authorizing reducing the final ballot period to “as few as five calendar days.” This change was introduced because members felt that the suggested wording would make the reduction to five days mandatory rather than optional. 

Members also authorized the process waiver for Project 2023-07 (Transmission system planning performance requirements for extreme weather) with the same changes as the previous three projects. In addition, they voted to authorize the initial posting of reliability standard CIP-007-X, the result of FERC’s order to develop standards requiring internal network security monitoring at high- and medium-impact cyber systems, for a 35-day formal comment and ballot period. 

Casuscelli Hands over the Reins

This week’s meeting marked Casuscelli’s retirement both as the chair of the committee and a member. Current Vice Chair Todd Bennett, of Associated Electric Cooperative Inc., was elected in September to succeed her, with Troy Brumfield of American Transmission Co. chosen to serve as vice chair. 

Casuscelli has served as chair for two consecutive two-year terms. During the meeting she recalled some of the challenges the committee has faced during her tenure, including the COVID-19 pandemic and the record workload that the ERO’s standards development teams are facing. She thanked members, along with NERC staff and trustees, for their support over the last four years, and said she “can’t wait to see what’s next under [the new] leadership.” 

“I have just a few final words for Todd before we adjourn,” Casuscelli added before delivering her last lines as chair. “Tag: You’re it.” 

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California PUC Votes to Extend Diablo Canyon Nuclear Plant 5 Years

California utility regulators on Dec. 14 approved extending operations at the Diablo Canyon nuclear power plant through 2030, a move intended to bolster reliability as the state continues its clean energy transition.

The California Public Utilities Commission voted 3-0 to authorize an extension for Diablo Canyon, which is owned and operated by Pacific Gas and Electric. The 2,200-MW power plant provides about 9% of California’s in-state generation.

Diablo Canyon had been slated to close in stages in 2024 and 2025. But state officials, including Gov. Gavin Newsom (D), called for keeping the state’s last nuclear power plant open to support reliability. Energy shortfalls led to rolling blackouts in California in August 2020 and close calls in subsequent summers.

Senate Bill 846, which Newsom signed in September 2022, directed the CPUC to authorize an extension for Diablo Canyon by Dec. 31, 2023. The bill described the extension as a “stopgap” measure of up to five years aimed at improving energy system reliability while more renewable and zero-carbon resources come online.

The extension approved by the commission runs through October 2029 for the power plant’s Unit 1 and October 2030 for Unit 2.

CPUC President Alice Reynolds noted that SB 846 included detailed directives for the commission to follow.

“We’re doing as much as we can to move quickly to reduce and eliminate the use of fossil gas to generate electricity while ensuring reliability and controlling costs for ratepayers,” Reynolds said before the vote. “But we’re also considering this decision before us today at the direction of the legislature.”

PG&E still needs approval from the Nuclear Regulatory Commission to extend operations. The company filed a license renewal application with the NRC on Nov. 7.

CPUC plans to continue evaluating the costs of the extension as more information comes in, and whether those have become “too high to justify incurring,” as SB 846 directs. Additional costs could include the expense of meeting conditions for NRC license renewal or implementing recommendations of the Diablo Canyon Independent Safety Commission.

In making its decision, the CPUC considered a report from the California Energy Commission (CEC) on whether the Diablo Canyon extension was needed to support reliability.

The analysis, completed in February, found that ordered procurement is sufficient to meet current resource adequacy planning standards through 2030.

But shortfalls are possible if the state experiences heat waves similar to those in 2020 or 2022, the report concluded. That risk is even greater if wildfires reduce transmission capacity at the same time.

In addition, new clean energy resources might be delayed due to supply chain, interconnection and permitting problems. Another issue is the ability of load-serving entities “to secure imports in an increasingly competitive Western market,” the report said.

“Extending [Diablo Canyon] has a decided advantage in the sense that it is a firm, low-carbon resource,” the CEC report said. “This extension allows the state to rely less on natural gas and more on clean resources for the grid.”

Before the vote, the CPUC heard from members of the public who opposed a Diablo Canyon extension due to concerns about the risks of earthquakes, terrorism or sabotage.

One speaker, who lives near the central coast nuclear plant, said the state has plenty of renewable resources and battery storage to meet its energy needs.

“Why put us at risk when we no longer need the nuclear plant?” she asked.

But others supported a Diablo Canyon extension, saying the state will rely more on natural gas resources if the nuclear plant closes.

One speaker said shutting down Diablo would be inconsistent with a pledge by the U.S. and more than 20 other countries during COP28 this month to work toward tripling global nuclear energy capacity by 2050.

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DOE Report, Funding Seek to Break down Barriers to Grid Innovation

The U.S. Department of Energy looks to be preparing for a full court press on grid-enhancing technologies in 2024, with a new report and funding opportunities aimed at removing barriers to the deployment of technologies like dynamic line ratings and advanced conductors that can quickly increase capacity on existing transmission and distribution lines.  

“We’re entering into an extraordinary time where many parts of the country are seeing rapid load growth, generation additions and resiliency threats all at once,” said Vanessa Chan, chief commercialization officer and director of DOE’s Office of Technology Transitions (OTT), during a Dec. 12 webinar. “So many solutions are already sitting right in front of us. We need to get the commercially available, innovative technologies out the door on the existing system today.” 

The key challenges are not the maturity of specific technologies, but “deployment barriers inherent in the market structure,” she said. “We need to ramp momentum. It will be a massive, massive miss if we don’t work together to break these barriers down today.” 

Chan’s call to action kicked off a preview of the department’s upcoming Pathways to Grid Innovation Commercial Liftoff Report, due early in 2024, while also sending some clear messages about the kind of projects DOE will be looking for in applications for the second round of its Grid Resilience and Innovation Partnerships (GRIP) program.  

“We’re really prioritizing in this round of funding projects that significantly increase transmission capacity, whether they’re using advanced conductors or [high-voltage, direct current lines] or grid-enhancing technologies,” said Maria Robinson, director of DOE’s Grid Deployment Office (GDO), which administers the GRIP program. The goal, she said, is to leverage federal funds “to catalyze a long-term transformation of grid systems and technologies.” 

DOE awarded $3.46 billion to 58 projects across 44 states in the first round of GRIP funding, and has announced $3.9 billion for the second round, with initial concept papers due Jan. 12. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.) 

While the Commercial Liftoff report will cover about 20 technologies that are ready or almost ready to scale, the webinar was strategically focused on the same technologies that the GRIP program will be prioritizing — dynamic line ratings, advanced conductors, HVDC lines and advanced distribution management systems (ADMS). 

All four provide the most bang for the buck, said Louise White, a policy advisor in DOE’s Loan Programs Office. 

“When we evaluate the impact of these solutions on the grid, we see that each contributes in multiple ways to enhancing grid capacity to make the most of existing rights-of-way today and toward achieving modern grid objectives by improving systems portability, environmental sustainability, reliability, safety and security,” she said.  

DOE funding — from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act — can buy down the high cost of the early projects needed to stimulate supply chain and further adoption, and bring down prices, she said.  

Some utilities have started deploying GETs, said Avi Gopstein, a GDO senior advisor, pointing to projects such as National Grid’s use of dynamic line ratings in New York to cut curtailment of wind projects and expand capacity on transmission lines.   

But he said, “There are more than 3,000 utilities in the United States, and a few excellent projects won’t get us where we need to be.”  

Utilities face “the competing priorities of maintaining an aging system while planning for future system upgrades, as well as the need for efficient capital allocation to minimize ratepayer impacts,” Gopstein said. The need now is for “new processes to better evaluate emerging technology benefits when technology is first deployed and for a future when it is utilized at scale. … 

“It’s clear that legacy approaches to capital allocation, which often depend on a maintenance framework built on the foundational assumption that existing infrastructure is sufficient to serve load, are no longer adequate,” he said. 

Lucia Tian, a senior advisor for OTT, agreed. “Given the pressures our electric grid is facing, stakeholders across the board are emphasizing the need to shift to a proactive, future-oriented approach for managing and investing in the grid to ensure system reliability in a rapidly changing energy system,” she said.  

“Both industry and regulators recognize that current regulatory and business models make it challenging to invest in advanced innovative grid solutions that go beyond the maintenance of existing infrastructure and development of traditional assets,” Tian said. “And the status quo here isn’t an option.” 

Innovation in Many Flavors

The main driver for GETs is burgeoning demand on the grid. According to new report from Grid Strategies, grid planners now see demand almost doubling over the next five years, requiring an additional 38 GW of capacity. (See Grid Planners Predict Sharp Increase in Load Growth.) 

Expanding capacity on existing lines is critical, but accelerating deployment will require a shift in business and regulatory models to develop standards and methods for valuing the benefits GETs can provide across a system, White said. Looking at dynamic line ratings (DLR), for example, White said, the technology “drives multiple capacity, reliability, decarbonization and affordability outcomes. 

“But to implement DLR requires installing sensors to measure real time environmental and land conditions, which also significantly [increases] system visibility,” she said. Advanced DLR also may require automating and digitizing substations, which “will enhance line voltage and current control, amplifying DLR benefits.” 

New communication and data management systems also may be needed, she said, but “being strategic about investment in these infrastructures can prepare a utility to unlock additional benefits down the road and improves cost-sharing between technologies.” 

Still, the way forward will be different for different utilities, she said. Not everyone needs best-in-class systems.  

“Innovation comes in many flavors, and considerable benefits can be realized with more basic technology investments,” White said. “So, a strategic investment plan must identify the appropriate level of innovation and supporting technical requirements to best support a diverse array of future applications to meet utilities’ current and future grid needs.” 

Angelena Bohman, a GDO technical analyst, also raised the organizational challenges adoption of new technologies can trigger. While an ADMS “increases visibility and situational awareness on the system and automates processes that exist manually today,” setting up the system “requires managing the migration of old workflows and databases into the system … [and] benefits may not be realized for many years.” 

The result is a misalignment between traditional planning and valuation based on short-term profit, and the need for more forward-looking, long-term perspectives. 

Deployment of advanced grid technologies suffers from “a lack of sufficient investment incentives to warrant the significant organizational effort required to deploy many of these innovative solutions,” White said. “This again highlights the need to shift from traditional cost-of-service models that often disincentivize these types of innovative investments and toward business models that reward utilities for these types of investments that are needed for a modern grid.” 

White ended the webinar with a list of critical takeaways: 

    • Valuing innovative grid technologies “requires looking at the system holistically to recognize complementary and stacking benefits and to strategically plan for the long term to ensure capital is deployed efficiently today.” 
    • Regulatory and business models must be updated to “address the meaningful misalignment between traditional incentive structures and the needs of a modern grid.” New structures must “value performance instead of capital expenditure [and] enable new risk- and cost-sharing models and encourage innovation.”  
    • Grid management also must change, from “legacy, reactive” approaches to “proactive, future-oriented strategies that serve the long-term interests of ratepayers.”