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July 26, 2024

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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.” 
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McAdams Honored During Last Texas PUC Meeting

Texas Public Utility Commissioner Will McAdams made good on his intention to resign from the commission by the end of the year, sitting through his last open meeting Dec. 14 as a member of the regulatory body.

McAdams, who told RTO Insider last month of his plans to resign before next year, wiped away tears as he thanked staff, his fellow commissioners and his family for what he called “one of the highest and true honors of my life.” (See McAdams Says He Will Resign from Texas PUC.)

“As I told the reporters, there comes a point for everybody when they evaluate their work-life balance and identify a need to take a step back; they need to heed that feeling,” he said. “That point has come for me. As I said then, this is a time for new blood to come in and continue to work on the momentum that we have created and started here.”

McAdams is the longest-tenured commissioner, having been appointed to the PUC in March 2021 shortly after the disastrous winter storm that nearly collapsed the ERCOT grid. His term was to expire Sept. 1, 2025.

The previous commission having resigned or been asked to step down, McAdams and the other commissioners who eventually joined him have spent that time implementing new rules after two legislative sessions, evaluating and redesigning the ERCOT market, and restoring staff confidence.

“As we have long said, this is not an easy assignment. The current commission was composed under extreme circumstances,” he said. “It seems to me that 2021 was a defined demarcation line and time. Especially for those working at this agency, there is now a pre-2021 history for the PUC and a post-2021 history that has yet to be made, and it’s never going back.”

“I feel privileged to have been here during that transition. The function that this agency serves is essential, and nothing’s going to change that,” McAdams added. “Our role as regulators is to instill and maintain confidence in the rule of law, the spirit of fair play and competitive neutrality in an environment with large and powerful corporate forces, all to ensure the best possible outcomes for Texas consumers.”

“Today is a bittersweet day,” interim PUC Chair Kathleen Jackson said as she opened the meeting. “On behalf of all Texans, I want to thank you for your tireless efforts since being appointed as the first new commissioner after Winter Storm Uri. You stepped up to the challenge with a desire to make a difference. … You’ve been an invaluable resource to me, the PUC and … the state of Texas.”

Cake presented to McAdams by PUC staff during reception in his honor | Texas Public Utility Commission

Commission staff recalled the day McAdams first appeared in the office. He was an industry outsider but had a strong working knowledge of the market through his policy work as a legislative staffer.

“My first thought when we were told Will McAdams was headed this way was, ‘Thank goodness! Someone who speaks electricity,’” said Connie Corona, deputy to Executive Director Thomas Gleeson. “We were well acquainted with you and your expertise and dedication to good public policy from working with you over the years. Thomas and I were sitting in a very lonely hallway on that day.”

“You strolled in and basically said, ‘We’ve got this,’ and never looked back,” she added.

“On March 15, 2021, Connie and I found ourselves with no one at the dais,” Gleeson said. “Being first is always difficult, and I’ve told you privately how much I appreciate that you were willing to go first and what that meant and how that helped with the 2021 [legislative] session. You really turned it around for us. Thank you for going first.”

“We all came in here and had a very challenging mission from Day 1: implementing all the legislation that got passed after Winter Storm Uri; engaging on several rounds of market reform discussions,” Commissioner Lori Cobos said. “The amount of work that we’ve accomplished over the last two years has been [immeasurable]. For that, I thank you for all of your leadership, your service, your support and your friendship.”

McAdams took a leadership role on ERCOT’s task force evaluating how aggregated distributed energy resources (ADERs) could participate in the wholesale market and their ability to serve as virtual power plants. He also threw himself headfirst into his SPP responsibilities, chairing a leadership team addressing the RTO’s resource adequacy issues.

“We had a great opportunity to work together on the ADER task force. That was your leadership and my nudging you in one direction, but you let your team lead that, and Texas is going to be much better for it,” Commissioner Jimmy Glotfelty said. “Having been in this business for 30 years, to watch the first few months and you grow your understanding of the market. Gosh, it was just great to see you stand up and be your own person and lead and lead and lead, and I know that’s to your core.”

The commission is now left with three members, two short of full capacity following Peter Lake’s resignation as chair in June. Gov. Greg Abbott’s press office did not respond to a question on when future PUC appointments might be made.

McAdams will chair the SPP Resource and Energy Adequacy Leadership Team’s final meeting of the year Dec. 18 before turning the position over to his likely successor, Kristie Fiegen, who chairs the South Dakota Public Utilities Commission.

Cobos will replace McAdams as Texas’ delegate on SPP’s Regional State Committee, with Glotfelty replacing Cobos on the Organization of MISO States.

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NYCA Surpasses 5,000 MW of Installed BTM Solar

RENSSELAER, N.Y. — New York now has more than 5,000 MW of behind-the-meter (BTM) solar capacity, bringing the state closer to its goal of installing 10,000 MW of distributed solar energy by 2030, NYISO announced at the Dec. 14 Operating Committee meeting.

Aaron Markham, NYISO vice president of operations, reported to the OC that an additional 59 MW of BTM solar integrated into the grid since the previous month, raising the total to 5,018 MW. (The New York State Energy Research and Development Authority reports a slightly higher 5,037 MW of distributed solar from 211,083 projects through Sept. 30.)

Markham added that in November, NYISO implemented improvements to the BTM solar forecasting system, which allows for forecasting on a 15-minute instead of an hourly basis. “The expectation is this will improve the performance and accuracy of these forecasts,” he said.

Markham also noted that November’s peak load reached 21,305 MW on Nov. 29. (See “October Operations,” NYISO Braces for the Coming Winter.) The month’s minimum load was recorded Nov. 5 at 12,471 MW.

Central East Limits

The OC voted to approve a draft report presented by NYISO re-evaluating the impact of a loss of a New England capacity source on Central East voltage limits.

The report concludes that the recent energization of the Nos. 351 and 352 Edic-Princetown 345-kV lines on the Segment A project allows Central East to support a loss of 1,500 MW, an increase from 1,320 MW.

The Central East interface is a key part of New York’s transmission that regulates the flow of electricity from New England to the central parts the state, in particular Mohawk Valley (NYISO Zone E) and the Capital region (NYISO Zone F).

Raj Dontireddy, a manager of operations engineering at NYISO, said that because NYISO operators cannot monitor or control ISO-NE’s sources and dispatch, it is crucial for the ISO to manage imported energy without compromising Central East.

Matt Cinadr, a power systems operations specialist with The E Cubed Co., asked whether the interface could handle more than the 1,500-MW limit.

Dontireddy responded that while 1,500 MW is the maximum allowed based on current limits, NYISO operators can permit a higher ISO-NE source if the total capacity of the Central East interface is not fully used. Markham added that analyses suggest this could increase to around 2,000 MW if the interface has room.

Order 2023

Thinh Nguyen, NYISO senior manager of interconnection projects, informed the OC that the ISO plans to file its proposed interconnection cluster study process to comply with FERC Order 2023 on April 3, 2024.

Nguyen provided a detailed review of the cluster study, addressing stakeholder questions and concerns, and shared a comprehensive overview chart that details the interconnection timeline and requirements developers must meet to proceed through the queue process.

Stakeholders continued to press NYISO on various aspects of the cluster study process, but the nature of their questions suggested an increasing understanding and acceptance of the proposal compared to previous times the cluster study was discussed. (See NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules.)

NYISO will continue developing its proposal into the early part of next year and anticipates reviewing specific tariff language soon.

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NY PSC Limits Gas Utility’s Network Expansion

The New York Public Service Commission barred a major gas utility from proactively expanding its gas mains starting early next year, trying to move the company closer to the state’s climate-protection goals.

The Dec. 14 decision labels as insufficient the long-term plan proposed by National Fuel Gas and makes multiple modifications beyond the ban on network enhancement (Case 22-G-0610).

NFG’s final plan, submitted in July 2023, was itself the third iteration, incorporating feedback offered by the state, its consultant and stakeholders on earlier versions submitted in December 2022 and May 2023.

But a consensus could not be reached on the final version of the plan.

Voicing some confusion about what they were actually doing — approving the plan, approving it with changes, rejecting it — members of the PSC voted 5-1 to attach more than a dozen directives to the plan and ordered NFG to move forward with it, to provide annual updates and to submit its next long-term plan in December 2026.

Later Dec. 14, NFG said it could not provide an immediate response to the 120-page order. It said via email:

“Having just received the order from the Public Service Commission, officials at National Fuel need time allowing for a careful review of the Long-Term Plan findings to determine next steps. National Fuel has provided very real solutions for decarbonization that will have an immediate and long-term impact.”

The state’s landmark Climate Leadership and Community Protection Act of 2019 mandated substantial reductions in greenhouse gas emissions. The CLCPA sets no specific target for gas utilities, but reduction of natural gas use and decarbonization of buildings both will be central to any wholesale reduction.

The failure after more than a year to reach consensus on NFG’s long-term gas plan speaks to the challenge of balancing conflicting priorities and evolving regulations while following through on the mandates.

The gas industry, regulators and advocates from all corners are working to carve out a new business model, plan the clean energy transition, save the planet, address socioeconomic problems and avoid crushing the state’s utility customers with a tab that will run into at least the tens of billions of dollars.

As they do this, the Legislature and governor periodically will roll out new mandates that may change whatever equations have been hammered out.

Sea Change

In March 2020, the PSC ordered what it called a “fundamental shift” in the way gas utilities do business in New York (Case 20-G-0131), moving them toward a more transparent and comprehensive process that emphasizes alternatives to new infrastructure investment.

NFG’s long-term plan was the first proposal in response; other major New York gas utilities are preparing long-term plans as well.

PSC Chair Rory Christian commended NFG for its efforts and acknowledged the challenges of going first — particularly as a gas-only utility.

“I think looking at it in a broad scale, this plan has done a good amount of what we had hoped it would do, and the planning process as a whole looks to me to be working as intended,” he said at the meeting.

“But despite all that hard work, ultimately what NFG provided fell short. In its current form, the plan is not aligned with our mandates. … There are just too many deficiencies.”

NFG serves roughly 500,000 customers in one of the colder, poorer parts of New York state, plus 250,000 more across the border in Pennsylvania.

It built its plan on an all-of-the-above approach that includes increased efficiency and hybrid gas-electric heating systems that keep its existing infrastructure in service while reducing greenhouse gas emissions. Thermal energy networks, renewable natural gas and hydrogen also would play a role.

The monthly bill impact would be substantial. NFG said “nonparticipating customers” — those not participating in billing or efficiency programs — would see their monthly costs jump from less than $100 to anywhere from $217 to $335, depending on the scenario used.

Stakeholders found many aspects of the plan unacceptable.

The PSC sought to address some of these questions in its order Dec. 14. Among the modifications it imposed, the PSC told NFG to:

    • Explain how it arrived at its system design of 74 heating degree days, which would equal an average 24-hour temperature of minus-9 degrees, something that has not happened since 1982.
    • File by May 31 a proposal for one or more demand response programs for implementation in the winter of 2024-25.
    • Cease by March 31 any further network expansion or enhancement — it can continue to hook up new customers who request service, as directed by current regulations, but it cannot proactively extend or enhance existing gas mains.
    • File within 90 days a proposal explaining how it will revise its Partnership for Urban Revitalization in Western New York to encourage electrification and remove incentives for additional natural gas use.
    • File by July 31 a report listing infrastructure upgrades and extensions planned in 2025 with a budget greater than $1 million.
    • Meet with stakeholders and develop and issue requests for proposals for at least two capital projects employing nonpipe alternatives in calendar year 2024.
    • Schedule a technical conference and develop a benefit-cost analysis.
    • Provide details on its energy efficiency programs and quantify their benefits to disadvantaged communities.
    • Formulate a pilot project to test hybrid heating options that include both cold climate and standard heat pumps by June 30.

The all-of-the-above approach is not a favorite strategy of clean energy advocates, particularly when it includes RNG or hydrogen.

The Environmental Defense Fund praised the decision up to a point, and said PSC needs to go further.

“The Public Service Commission rightly found that the company’s 20-year plan fell short of New York’s climate goals and directed the utility to halt natural gas expansion programs and improve information transparency,” senior attorney Erin Murphy said via email. “But the regulators left important questions unresolved, such as the need for limits on deployment of biomethane and hydrogen. The PSC must do more to give utilities clear direction to plan for decarbonization.”

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Treasury Department Releases Guidance on 45X Credit for Manufacturing

The U.S. Department of Treasury and the IRS on Thursday released proposed guidance on the 45X Advanced Manufacturing Production Credit, which is available to producers of wind and solar components, inverters, battery components and critical minerals. 

The tax credit is part of the Inflation Reduction Act, which the department said already is creating manufacturing jobs. 

“These new investments across industries and throughout clean energy supply chains are creating good-paying jobs and driving down the cost of clean energy for Americans,” Secretary of the Treasury Janet Yellen said in a statement. “New manufacturing investments are disproportionately going to communities that have lacked opportunity and are key to increasing long-run growth and the productivity of our economy.” 

Treasury released a notice of proposed rulemaking (NOPR) on the 45X tax credit, which proposes clarifying definitions and confirms credit amounts for the components it covers. It proposes definitions for key terms meant to incentivize domestic production and clarifies the circumstances under which the credit can be claimed. 

The NOPR includes safeguards against fraud, waste and abuse, including ways to avoid double-credits for the same component, crediting of activities that add no value and extraordinary circumstances in which clean energy components are produced but never used productively. 

The tax credits will be in full effect through the end of this decade and, starting for components sold in 2030, they will ramp down to 75%, then 50% in 2031, 25% in 2032 and be phased out entirely in 2033. Only the 50 applicable minerals will be eligible for the 45X credit after 2032. 

Solar energy components include modules, photovoltaic cells, photovoltaic wafers, solar grade polysilicon, torque tubes, structural fasteners and polymeric backsheets. Modules or photovoltaic cells would get a credit based on their nameplate capacity in direct current watts under standard testing conditions. 

Wind energy components include blades, nacelles, towers, offshore wind foundations and related offshore wind vessels. Eligible ships would be those purpose-built or retrofitted for installing offshore wind turbines, while wind tower components would get credits based on the capacity of the completed turbines. 

Both utility-scale and distributed-energy-scale inverters would be eligible for the tax credits, the NOPR said. Eligible battery components include electrode active materials, battery cells and battery modules. 

Treasury also released new analysis from its economists using data from the Massachusetts Institute of Technology and the Rhodium Group showing how the IRA already has accelerated clean energy manufacturing.  

Since the bill was passed, 76% of investment dollars in clean energy manufacturing have gone to counties with average weekly wages below the U.S. average; 66% are in counties with college graduation rates below the U.S. aggregate rate; 54% of investment went to counties with lower employment levels than average; and 69% went to counties with incomes below the median. 

The American Clean Power Association welcomed the NOPR, noting that over the past 16 months the clean energy sector has announced 112 new manufacturing facilities that will employ more than 41,000 workers. 

“Today’s guidance is a critical next step for U.S. manufacturers as they work to make announced facilities a reality,” said ACP Chief Advocacy Officer JC Sandberg. “By creating and expanding supply chains to make clean energy technologies here at home, we will strengthen America’s energy security, create good-paying American jobs and boost the nation’s economy.” 

American Council on Renewable Energy Executive Vice President José Zayas also welcomed the new guidance, which he said would help clean energy manufacturing to continue growing. 

“The inclusion of key components, including emerging battery technologies and offshore wind vessels, in addition to prior guidance unlocking the direct pay option for the 45X credit, provides needed clarity for our sector as we work toward achieving the enhanced domestic manufacturing base we need to meet the growing demand for clean and renewable power, secure our grid, lower costs and maximize American competitiveness,” Zayas said. 

Advanced Energy United also welcomed the guidance, while highlighting that it includes recycled content and allows for innovative technologies to qualify. 

“By permitting recycled content, Treasury has further incentivized the development of a circular clean energy supply chain, something fossil fuels can never achieve, while also helping make imported content into American-made resources,” said AEU Managing Director Harry Godfrey. “By allowing new and innovative technologies, like permitting DC-optimized inverter systems to qualify as microinverters, Treasury is ensuring that this policy encourages, rather than stifles, innovation in this dynamic industry.” 

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NYISO BIC Stakeholders OK Modeling, Market Design

NYISO on Dec. 13 presented its market design for dynamic reserves to the Business Issues Committee, which endorsed the concepts on the condition that issues including cost allocation and congestion revenues be discussed next year, as the ISO tests the new design.

The ISO’s current operating reserve requirements are static, based on the largest single source contingency.

A NYISO white paper in December 2021 proposed that the grid operator explore dynamically scheduling reserves, saying it was feasible to set reserve requirements based on the single largest contingency systemwide and using available transmission headroom. The paper said determining reserve requirements based on grid conditions and topology would better align market outcomes with system conditions by, for example, shifting reserve procurements to lower-cost regions as permitted by transmission capacity. (See NYISO Outlines Timelines for 2023 Projects.)

The proposed design is composed of five concepts, including use of individual generator shift factors — the ability of a generator to relieve transmission constraints — to meet locational reserve needs, monitoring about 20 key transmission interfaces and considering the day-ahead market (DAM) forecast load.

The ISO’s static locational reserve requirements assume the transmission system is fully scheduled.

NYISO’s presentation also discussed how various market elements like thunderstorm alerts, scarcity pricing and the correlated loss of multiple generators might be impacted by the reserve market changes.

NYISO plans to prototype the proposed design and finalize tariff language next year, with the expectation that the concepts will be deployed in 2026.

The ISO said elements such as forecast reserve shadow prices and DAM congestion rents will not be included in prototyping but will undergo review with stakeholders next year.

BIC stakeholders commended the ISO’s efforts in establishing a dynamic reserve market design. David Clarke, director of wholesale market policy at the Long Island Power Authority, said “this is really good and really innovative work.”

Pallas LeeVanSchaick, vice president at the ISO’s Market Monitoring Unit, Potomac Economics, similarly praised the ISO’s work. “The scheduling and optimization components are truly innovative and are really going to be helpful to the market in terms of ensuring that the market design is adaptable to changing conditions,” he said.

LCR Optimizer Market Design

The BIC also voted to approve changes to make the locational capacity requirements (LCR) optimizer more transparent and produce more stable results.

The LCR optimizer, implemented in 2019, establishes the least-cost LCRs for several downstate NYISO capacity zones, including New York City and Long Island.

The ISO proposed three changes. First, it suggests determining least cost options by adding up the incremental costs of individual units, which it calls the investment cost — or “area under the curve” — as the optimizer’s objective function. The ISO currently seeks to minimize total procurement cost, in which every megawatt of capacity is priced like the last megawatt.

The ISO’s second recommendation calls for determining net CONE curves without the level of excess (LOE) adder to simplify the optimizer’s formulation.

The final recommendation is to develop additional energy and ancillary services revenue modeling test points in the current demand curve reset project. While NYISO acknowledges that this aspect of the optimizer’s formulation has not been tested, it committed to providing updates on these testing efforts next year.

Michael Mager, a partner at Couch White, representing Multiple Intervenors, a group of large industrial, commercial and institutional energy consumers, asked about the timeline for initial results from the new testing. NYISO staff responded that these results could be expected in February or March.

Assuming the proposed changes improve the LCR optimizer’s results, the ISO aims to seek approval from the Management Committee in mid-2024 and expects these improvements will be used to determine zonal LCRs applicable for the 2025/26 capability year.

Capacity Accreditation Modeling

The BIC voted to recommend that the MC approve proposed tariff revisions presented by NYISO, which aim to improve capacity accreditation modeling by more accurately capturing attributes like natural gas constraints and correlated derates, as well as address issues raised by Potomac Economics. (See NYISO MMU Calls for Improved Shortage Pricing, More Capacity Zones.)

Resource adequacy analyses indicate that current modeling misrepresents the marginal reliability contributions of some resources and fails to capture metrics not represented in installed reserve margins and LCRs, resulting in inaccurate capacity accreditation factors and capacity accreditation resource class (CARC) calculations for certain resources. (See NYISO Previews Capacity Accreditation Modeling Work.)

The revisions seek to align the compensation capacity resources receive with their performance, availability and marginal contribution to reliability needs.

To address gas constraints, the ISO developed a process allowing gas units to make a “fuel characteristic election” on Aug. 1 prior to the start of the next capability year. This is based on the unit’s ability to partly or fully meet requirements for entry into a firm fuel CARC. Units seeking to be firm on gas must have a transportation contract covering the megawatts elected, with a contract path from a liquid receipt point to the burner tip during December, January and February.

Units with on-site fuel are required to have enough to operate at max output for 16 hours a day for six days in those same winter months. The first fuel characteristic election must be made by Aug. 1, 2024, and units failing to substantiate their level of firm supply may face a shortfall penalty.

Howard Fromer, representing Bayonne Energy Center, asked about the impact of these revisions on generation using hydrogen as a fuel source. NYISO staff clarified that these new requirements apply to any unit burning on-site fuel or fuel being delivered through a pipeline.

For correlated derates, NYISO proposes addressing issues identified in the MMU’s annual State of the Market report by applying ambient water-related deratings to units with once-through water cooling, adjusting for humidity in units with inlet cooling systems like combined and simple cycle combustion turbines, and sunsetting the capacity-limited resource program, as these emergency capacity resources are rarely committed.

NYISO will finalize the approved tariff language with the Installed Capacity Working Group and continue discussions around correlated derates. The expectation is to present these revisions to the MC in the first quarter of next year for final approval before filing them with FERC.

Transmission Congestion Contracts

The BIC also voted to approve revisions to the transmission congestion contracts (TCC) manual presented by NYISO that incorporate updated technical bulletins addressing modeling assumptions for certain phase angle regulators (PARs).

The TCC manual was last updated in October 2021.

The revisions include updating the modeling descriptions for the “Internal Con Edison PARs” to include the Vinegar Hill PARs (Technical Bulletins Nos. 254 and 255) and revising the modeling assumptions for the “East Garden City PARs” and “Hurley Avenue PARs” from fixed schedules to schedules optimized by the optimal power flow (Technical Bulletins Nos. 257 and 258).

November Market Operations

NYISO Senior Vice President Rana Mukerji presented the November market operations report, saying a “slight uptick” in gas prices slightly increased locational-based marginal price, from $28.10/MWh in October to $34.90/MWh in November. The natural gas index price at Transco Z6 NY was $2.20/MMBtu in November, up from $1.30/MMBtu in October.

Year-to-date average monthly energy prices, however, were 55% lower than the previous year, dropping from $89.97/MWh to $39.32/MWh. This decrease was driven by the continued decline in gas prices throughout the year, with natural gas prices down 54.3% year-over-year at Transco Z6 NY.

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Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE

WESTBOROUGH, Mass. — ISO-NE should move to a prompt and seasonal capacity market to better accommodate the evolving mix of resources and reliability risks in the region, Analysis Group told ISO-NE stakeholders at the NEPOOL Markets Committee (MC) meeting Dec. 13. The consulting firm recommended the RTO make the move for the 2028-29 Capacity Commitment Period (CCP). 

In November, NEPOOL voted to delay Forward Capacity Auction (FCA) 19 — which corresponds to the 2028-29 CCP — by one year to complete resource capacity accreditation (RCA) changes and consider moving to a prompt and/or seasonal capacity market. (See NEPOOL Votes to Delay FCA 19.) 

While FCAs currently are held more than three years prior to the CCP, a prompt capacity auction would be held just months before the CCP. Changing the auction to a seasonal format would break up the yearlong CCP into distinct seasons. 

ISO-NE has commissioned Analysis Group to study and make recommendations on the potential move to a prompt and seasonal auction format. The study has a condensed timeline to leave time for stakeholders to contemplate the impacts of the changes. (See Analysis Group Details Methodology of ISO-NE Capacity Market Study.) The firm released its draft results prior to the December MC meeting.  

Moving to a prompt and seasonal capacity market would “allow the region’s capacity market to adapt to and support the transition toward a grid of the future for the region,” Todd Schatzki of Analysis Group told stakeholders. He added the changes would “improve resource adequacy outcomes in both economic and reliability terms.” 

One of the key benefits of holding the auction closer to the CCP would be more detailed information on both supply and demand, Schatzki said. It also would entail less deliverability risk for new resources coming into the capacity market, since all resources bidding into a prompt capacity market would need to be ready to provide capacity. 

While the forward capacity market initially was designed to align with the development timelines of new power plants, the current timelines for new resources vary significantly between resource types, Schatzki said. While battery storage can arrive as soon as nine months, gas plants and offshore wind can take up to 48 months, he added.  

A prompt auction could provide a “more neutral competitive platform for new investment,” Schatzki said.  

Regarding a seasonal format, “a seasonal market can account for differences in the value of capacity in reducing reliability risks across seasons,” the draft report found. “By accounting for these differences when procuring capacity in each season, so that more capacity is procured in seasons with greater reliability risks, it can lower the costs and improve resource adequacy.” 

Analysis Group performed a limited quantitative assessment of the financial impacts of the capacity market changes, which found that prompt and seasonal changes would reduce costs in most cases, with the cost benefits ranging from 2% to 10%.  

The firm also found that a prompt and seasonal market likely would provide more incentives for firm natural gas fuel arrangements, because these fuel commitments often are made in the summer and fall prior to the winter. 

“Compared to a prompt market, making commitments three-plus years in advance would be expected to raise costs of these commitments and reduce the scope of firm fuel arrangements,” Schatzki said, noting that the under-development RCA updates also could increase incentives for firm fuel commitments. 

One basic drawback of a prompt and seasonal market would be the time and effort required to make such major changes, and administering seasonal auctions would mean more work for ISO-NE, Schatzki said.  

The draft report also noted that no other regions that heavily rely on capacity markets to meet resource adequacy needs have a prompt and seasonal capacity market. 

“However, other regions have, or are in the process of assessing or implementing, prompt and seasonal market designs, and the technical risks of developing a prompt-seasonal market appear manageable,” the report concluded.  

Schatzki added that some aspects of the market may need to be reconsidered if the RTO elects to move to a prompt and seasonal auction to avoid unintended consequences. These include the resource qualification and retirement processes, supply offer components and market mitigation.  

Looking forward, Analysis Group will present the final report at the January MC meeting, and ISO-NE is planning to make a recommendation on the capacity market changes at the February MC meeting. 

RCA Updates

The MC also discussed updates to the accreditation methodology for oil and gas resources.  

In the new RCA format, resources will be compared to a theoretical perfect capacity resource that lacks operating constraints. This method is intended to create a neutral point of comparison for the reliability and resource adequacy attributes of all capacity resources on the system.  

In ISO-NE’s proposal, gas resources’ firm fuel arrangements will affect their accreditation value, while oil resources’ accreditation value will be affected by their storage capabilities.  

Oil capacity for both oil and dual-fuel resources will be judged on an individual basis, while gas capacity will be estimated at a fleet level to account for the region’s seasonal gas constraints, ISO-NE said.  

“An aggregate hourly profile will be used in the winter period to represent the hourly gas fleet generation using the daily gas available to the fleet subject to the gas system limitation,” ISO-NE said.  

The aggregated gas fleet capacity value then will be allocated to individual resources, which could improve their accreditation through firm arrangements including firm gas supply and pipeline contracts, as well as added dual-fuel capabilities or LNG vaporization capabilities. 

Additional firm gas contracts that reduce the total amount of gas available to the rest of the fleet would lower the accreditation values of non-contracted gas generators, ISO-NE noted.  

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Federal Court Rules in Favor of Transource Congestion Project in PJM

A federal court has ruled that the Pennsylvania Public Utility Commission violated the Constitution’s Commerce Clause in denying Transource Energy a certificate of public convenience to construct the Independence Energy Connection (IEC) transmission project, ruling that the rejection was rooted in economic protectionism rather than siting concerns (1:21-CV-01101).

To proceed, however, the project will have to clear a new PJM benefit-cost analysis that considers other transmission projects approved in the last several years. (See Transource Challenges Pa. PUC Decision in Court.)

“After carefully considering defendants’ arguments, the court is not persuaded that the PUC’s decision was, in substance, about siting. Much of defendants’ argument attempts to deconstruct PJM’s analysis, following FERC-approved methodology, for assessing the project. Defendants’ argument picks apart the FERC-approved methodology and whether it was sufficiently open, allowed for evidentiary hearings, permitted cross-examination or allowed argument by interested parties. But in making these arguments about the various flaws in PJM’s analysis of the need for the project, defendants have not provided a substantive basis for this court to conclude that the PUC’s decision actually related to siting as opposed to determining whether there was a need for the project,” Judge Jennifer Wilson wrote for the U.S. District Court for the Middle District of Pennsylvania in a decision released Dec. 6.

The project is aimed at alleviating congestion on PJM’s AP South interface by constructing two 230-kV lines between Ringgold substation in Washington County, Md., to the Rice substation in Franklin County, Pa., and between the Conastone substation in Harford County, Md., to the Furnace Run substation in York County, Pa.

The PJM Board of Managers approved the project in 2016, stating that it was the most cost-effective way of addressing congestion in Virginia, Maryland, D.C. and western Pennsylvania. (See “Transource Re-evaluation,” PJM TEAC Briefs: Nov. 30, 2021.)

The Maryland Public Service Commission also approved the Maryland sections of the project in June 2020 in a settlement that included a reconfiguration of the Harford County section of the project to run in an existing Baltimore Gas and Electric right-of-way.

Due to the denial and Transource’s subsequent litigation, the PSC has granted the company and BGE a series of extensions on the deadlines for beginning and completing construction of the lines.

On Dec. 13, the PSC approved a third extension, to Dec. 31, 2024.

Similar extensions have also been approved for another component of the IEC, a Potomac Edison rebuild of an existing single-circuit 138-kV transmission line to a 230-kV transmission line between the Ringgold and Catoctin substations in Frederick and Washington counties, Md. Speaking at the PSC meeting Dec. 13, J. Joseph Curran III, an attorney with Venable and counsel for Transource, said the litigation was the primary driver of the extension requests.

The PUC defended its May 2021 decision to deny siting and eminent domain permits by arguing that the benefit-cost analysis PJM conducted didn’t address all the requirements for a project deemed to be necessary under state law and didn’t take into account the full breadth of costs — namely the increased rates some will pay should congestion be alleviated.

PJM’s market efficiency process considers whether the reduction in rates attributed to the project would outweigh its construction costs at a 1.25-to-1 ratio. In a 2020 reanalysis of the project, PJM estimated that it would reduce congestion costs $845 million and cost $509 million to $528 million, which would be assigned to ratepayers in the regions benefiting from the reduced congestion. (See Transource Tx Project Rejected by Pa. PUC.)

Transource argued that the commission was seeking to preserve the cheap power enjoyed in some areas at the expense of others without access to that energy due to congested lines. The company told the court that if states were to be permitted to reject projects on the basis that they don’t benefit their ratepayers, it would defeat the purpose of transmission planning aimed at alleviating congestion resulting in regional price disparities.

“If states could override FERC by applying a conflicting method for determining need, solely to preserve the benefits of congestion for their own citizens, that would eviscerate FERC’s ability to plan the interstate transmission grid in an efficient and fair manner,” Transource said in court documents.

The court rejected the PUC’s jurisdictional arguments, stating that the federal government’s interests go beyond planning projects and extend to seeing that they are built, with the states’ role focused on enforcing local siting, environmental and public safety regulations.

“The PUC is attempting to supplant the role of the RTO and expand its state authority into the regulatory territory occupied by the federal government. If permitted, the PUC’s second-guessing of the methods sanctioned by federal law and employed by the RTO would severely handicap the ability of FERC to ensure just and reasonable rates. Because the PUC’s decision presents an obstacle to achieving federal objectives, it is conflict preempted and violates the Supremacy Clause,” the court wrote.

The commission also argued that the congestion had decreased since 2014 and the project’s benefits would be lower than presented in PJM’s 2016 approval of the IEC project. The benefits would be further diminished, the commission said, if the benefit-cost analysis included the increased rates that might manifest once the congestion was eliminated.

PJM Re-evaluates

While welcomed by Transource, the federal court decision does not mean IEC is out of the woods. First, the PUC has 30 days to file an appeal, and some local permitting remains.

However, Hector Garcia-Santana, senior counsel for American Electric Power, which partnered with Evergy to form Transource, told the PSC on Dec. 13 the IEC projects are “very mature at this point. Materials are in the United States, and they are specific for the project. They are already in hand. The transformers, which are long-lead items, are already in the United States as well. … They were acquired at a time prior to now; so, the price for that type of equipment has increased since then.”

Garcia-Santana added that 70% of the rights of way for the projects have been secured, as well as rights for substations in Pennsylvania. Pending final approvals from the PUC, construction could take 12 to 18 months, he said.

Garcia-Santana’s optimism was somewhat tempered by William Fields, deputy people’s counsel in the Office of the People’s Counsel, who cautioned that PJM will be re-evaluating IEC in the spring of 2024 to consider whether it is still cost-effective and necessary “because of all the tremendous activity going on in this general area of the grid.”

Since IEC was originally approved, New Jersey has selected its first projects under its state agreement approach with PJM, intended to start building out the transmission needed for offshore wind projects, and the PJM board approved Window 3 projects for its Regional Transmission Expansion Plan (RTEP) on Dec. 11.

PJM filed a waiver request asking FERC for more time to complete its required annual reanalysis of the project in November due to how the RTEP projects could interact with the project.

“Performing a reevaluation of the Transource IEC Project before year end with a base case that does not resolve the 2022 RTEP Window No. 3 reliability violations will produce incomplete results until the market efficiency model is updated for reevaluation purposes, which will frustrate PJM’s ability to provide meaningful updates to the [Transmission Expansion Advisory Committee] and the PJM Board. Either way, performing an analysis on incomplete data is an inefficient use of PJM engineers’ time,” the waiver request argues.

The waiver request states that PJM staff will need about three to four months to prepare a base case including the approved RTEP projects to run the analysis on whether the IEC project continues to pass the benefit-cost threshold. It asks that FERC extend the deadline for the analysis to the second quarter of 2024.

PSC members also raised concerns about the potential closing of the 1,238-MW Brandon Shores coal-fired plant outside Baltimore. PJM has said taking the plant offline in 2025, as planned by owner Talen Energy, could result in “degraded grid reliability.”

Commissioner Michael T. Richard queried Fields on whether OPC or PSC staff have “had a chance to hear from PJM about how this cluster of [IEC] projects interacts with these other projects, and really, if they are still needed and cost competitive.”

“We don’t know exactly where PJM is going to be on that,” Fields said. “But it seems a good chance that [the IEC projects] have been overtaken by events from these other activities. I think the real question is going to be, in the spring, when PJM runs the power flow models … [will] they look and say, ‘How much is this going to save in market prices over the future, from that point on?’ And you compare that to the cost of the project.”

Fields told RTO Insider his office would support the project if it continues to promise the benefit-to-cost ratio PJM has projected in the past. However, he noted that it was approved years ago and the grid in that region has seen a lot of change.

“There’s been a huge amount of activity in this part of PJM with respect to new transmission that’s already been built, transmission that’s planned to be built, generation retiring and I think it’s an open question whether when PJM reevaluates the costs and benefits of this plan, if it’s still going to be beneficial in reducing customers’ energy bill,” he said.

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PJM Board Approves $5 Billion Transmission Expansion

The PJM Board of Managers on Dec. 11 approved an estimated $5 billion package of transmission projects in the third window of its 2022 Regional Transmission Expansion Plan. 

In its announcement of the approval, PJM said it is forecasting 7,500 MW of new data center load in Virginia and Maryland, much of which is expected to be clustered around Dulles Airport in Northern Virginia. The RTO is also expecting about 11,000 MW in generator deactivations, most notably the 1,295-MW Brandon Shores plant outside Baltimore. 

The package is made up of dozens of components submitted by Dominion Energy, FirstEnergy, Exelon, PPL, NextEra Energy, Transource Energy and Public Service Enterprise Group. (See “Second Read of $5 Billion in RTEP Projects,” PJM PC/TEAC Briefs: Dec. 5, 2023.) 

The work includes constructing new 500-kV lines from Northern Virginia northeast to the Peach Bottom substation in Pennsylvania, northwest to the 502 Junction substation in West Virginia and south to the Morrisville substation in Southern Virginia. 

The board’s approval caps off a process that began with the opening of the competitive window for transmission owners to submit projects in February. The normal 90-day window was extended to close May 31, and PJM presented three shortlisted packages on Oct. 3 before an Oct. 31 presentation of the proposal to the Transmission Expansion Advisory Committee that it ultimately brought to the board. (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.) 

Maryland Office of People’s Counsel Deputy William Fields told RTO Insider that presenting the recommended set of projects at the end of October with the plan of bringing it to the board in December left little time for stakeholders and the public to evaluate the projects and draft comments to the board to allow them to come to a fully informed decision. 

“It’s certainly true that this general issue has been talked about for many months, but we saw this actual list of projects Oct. 31 … and here it is weeks later being approved,” he said Wednesday. 

Fields said his office had received high-level information about cost allocation from PJM on Dec. 12 and is in the process of evaluating the potential impact to Maryland ratepayers. 

The functioning of the cost allocation formula in PJM’s tariff is understood by stakeholders, but Fields said that the scale of the package will present that methodology with a test it has yet to face. 

“We’ve just gotten some preliminary information, and we’re trying to evaluate it and look at it in more detail. But the question is, does the usual allocation method produce reasonable results when you’re talking about extremely large amounts of new load?” he said. 

During the second read of the proposal at the TEAC meeting Dec. 5, several members of the public objected to the package, citing concerns about disruption to historic regions along the proposed route, the inclusion of greenfield construction components, the cost and the likelihood of requiring additional major transmission expansions should load growth continue in the region. 

PJM’s Sami Abdulsalam said the proposal represented the most efficient, cost-effective and resilient combination of the 72 project submissions received during the competitive window and that minimizing greenfield disruption and siting risk were among staff priorities. The RTO included with its TEAC meeting materials an FAQ detailing its role in selecting the proposals in the window.