INCLINE VILLAGE, Nev. – A relatively new California agency is working to transform utilities’ wildfire safety culture by shifting away from penalties and enforcement to a proactive, learning-based approach.
The California Office of Energy Infrastructure Safety was established through state legislation following devastating wildfires in 2017 and 2018, according to Caroline Thomas Jacobs, the office’s director. The agency got its start as the Wildfire Safety Division within the California Public Utilities Commission but became a standalone department in July 2021.
The office, known as Energy Safety for short, is now about three years old.
Thomas Jacobs talked about the new initiative during a panel discussion at last week’s joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body (WIRAB).
Energy Safety’s activities are based on a shift from “a compliance-based, reactive, penalty-enforcement approach to issues of safety to implementing a new, proactive planning-learning-improvement regulatory cycle,” Thomas Jacobs said.
Among its duties, the agency reviews utilities’ wildfire mitigation plans and assesses their safety culture each year. Wildfire mitigation plans are based on a “maturity model” in which utilities explain where they are in terms of wildfire prevention activities and where they expect to be as a result of safety investments.
In the safety culture assessment, utilities survey their employees and contractors — from frontline inspectors to senior managers — on their understanding of and approach to wildfire safety. Energy Safety then makes recommendations on how safety culture could be improved and follows up to see if the recommendations are being implemented.
But enforcement isn’t disregarded: Energy Safety also conducts inspections, audits and investigations to see whether utilities are complying with their approved wildfire mitigation plans.
Panelist Brian D’Agostino, vice president of wildfire and climate science at San Diego Gas & Electric, said the new framework is “having a real impact” on the utility’s culture and helping it maintain focus on priority safety areas.
“These safety culture assessments don’t come back and say everything’s great top-to-bottom,” D’Agostino said. “It gives us areas where we can really focus on and areas where we can improve.”
Panelist Sumeet Singh talked about how safety culture has changed at Pacific Gas and Electric, where he is executive vice president of operations and chief operating officer.
“Frankly, the wildfire risk is something that surprised PG&E,” Singh said. “One of the big reasons for the surprise was the significant drought that happened in 2014 to 2016 that completely changed the environment in which the overhead electric assets operated.”
The change was initially missed because of the utility’s focus on reliability and running assets to failure, Singh said. Now, he said, PG&E has adopted a mindset seen in high-hazard industries.
The Camp Fire, which destroyed much of the town of Paradise in November 2018 and killed more than 80 people, along with a series of Northern California wine country fires in October 2017, forced PG&E into bankruptcy and led to a multibillion-dollar settlement with fire victims.
In June 2020, the utility pleaded guilty to 84 counts of involuntary manslaughter and one count of arson in connection with the Camp Fire. In February, PG&E pleaded not guilty to 11 charges stemming from the September 2020 Zogg Fire. (See PG&E Pleads Not Guilty to Manslaughter Charges.)
Singh said that mitigations in the utility’s wildfire safety plan include plans for undergrounding 10,000 miles of distribution lines and replacing bare lines with covered conductor or insulated wire in high fire-threat areas. (See PG&E Scales Back Plan to Underground Lines.) PG&E is also turning to remote grids and microgrids in situations where a handful of customers in remote areas are served by distribution lines that run across risky terrain.
But Singh said PG&E is also working to change its safety culture. One goal is to make sure that employees who know the assets feel empowered to speak up if they spot a problem, he said.
Another issue has been the different perception of risk among employees ranging from inspectors to supervisors and executive leadership. The focus now is to “align on the perception of risk,” Singh said.
He gave as an example an employee who has been working on electric systems for a long time.
“They may have been OK at one point in time to look at [an] adverse condition in the health of a tree and say, you know what, we can actually remove or address that in six months,” Singh said. “That’s not the case anymore. That’s an immediate safety issue that actually needs to be addressed right away.”
House lawmakers heard from nuclear industry experts Tuesday as they get started on legislation aimed at helping the deployment of advanced reactors across the U.S.
“To expand the industry, it is vital we encourage regulatory certainty and make sure our reactor licensing processes enable the safe and broad deployment of nuclear technologies,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security. “This is especially important for advanced reactor technologies.”
Nuclear power now provides about 20% of the country’s electricity, including about half of its carbon-free energy, and it can help eliminate emissions on the grid, said the subcommittee’s ranking member, Rep. Diana DeGette (D-Colo.). But several things need to happen for nuclear to remain a key part of the generation mix going forward, she said.
“The United States must develop a comprehensive science-based strategy to dispose of spent fuel — a strategy that does not cause harm to public health or our environment,” said DeGette. “If we don’t have a long-term permanent solution for disposing of nuclear waste, then we will struggle to be able to use this source of carbon-free electricity.”
She said the other key challenge is figuring out what do with the existing fleet, which has seen some scattered retirements in recent years, but only one new nuclear plant coming online: Southern Co.’s Vogtle plant.
Once Vogtle’s units are online, the country will have 94 reactors operating, and it will be important to extend their operating lives while securing them a more stable source of uranium, said Idaho National Laboratory’s Jess Gehin.
“Currently, our nation imports 90% of our uranium needed for our reactor fleet,” Gehin said. “This includes imports from Russia; eliminating these imports from Russia requires us to establish an expanded uranium-enrichment capability domestically and with our close allies.”
Some of the proposed new reactors such as TerraPower’s natrium reactor in Wyoming and X-energy’s Xe-100 planned for deployment at a Dow Chemical facility on the Gulf Coast need a stable, domestic supply of high-assay, low-enrichment uranium that is not produced here at all, said Gehin.
Duke Energy (NYSE:DUK) has the largest fleet of 11 “regulated” nuclear units at its vertically integrated utilities in the Carolinas, and the North Carolina Utilities Commission has approved its early investment to consider building new, advanced reactors, said Regis Repko, the company’s senior vice president of generation and transmission strategy.
“We plan to add unprecedented numbers … of solar energy, storage [and] wind power to the grid as we continue to retire our aging coal fleet,” Repko said. “However, we must have firm, dispatchable resources, such as nuclear and natural gas, to support renewable energy resources. Our customers depend on us, and we must not jeopardize reliability or affordability in this transition.”
Duke’s 11 plants are all set to retire between 2030 and 2046. To avoid losing those plants, which produce half the energy and 80% of the clean energy for its utilities in the Carolinas, the company would like to extend their licenses another 20 years. Duke also plans to build 8 GW of new nuclear power.
The firm plans to work with stakeholders and the Nuclear Regulatory Commission to ensure the licensing process for those new reactors is effective, efficient and in line with the safety of the new reactor designs, Repko said.
The bipartisan support seen at the hearing, recent advances in Europe and California’s decision to extend the life of the Diablo Canyon nuclear plant all point to the increased support the technology has seen in recent years, said Clean Air Task Force Executive Director Armond Cohen.
“The problem is that we’re just not moving at any scale and pace that’s relevant to climate. To be relevant to climate, nuclear is going to have to be churning out something like 100 GW/year globally,” said Cohen. “That’s about in the range of where we were with coal and gas in a sustained way for a few years. We have to be really running at that scale. We’re about 10 GW/year, so, we need to be 10 times where we are.”
To have an impact on global climate change, the U.S. nuclear industry will need to export its technology because domestic emissions only amount to 15% of global emissions, he added.
NYISO on Monday presented the Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) with proposed methodology for measuring implied marginal emission rates (IMERs) to increase transparency around New York’s emissions output by providing real-time data.
The ISO chose the IMER “heat rate” methodology to measure emissions production over other options because, staff said, it is highly variable and granular, performs well in grids with clearly defined marginal fuel types, and helps identify persistent congestion patterns.
The methodology uses LMPs, fuel prices, emissions costs, and variable operation and maintenance costs as inputs to estimate the implied heat rate, which is then used to estimate the real-time zonal IMER in tons of carbon per megawatt-hour for a given implied marginal fuel.
Stakeholders requested NYISO publish real time marginal and average zonal emissions rates data to help them comply with state energy and climate legislation, particularly Local Law 97, which set strict carbon reduction standards for large New York City buildings. (See NYC Proposes Rules to Implement Building Emissions Law.)
Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, asked why stakeholders had requested this project, to which William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, responded that his organization, along with state agencies and other stakeholders, need this information to support LL97 compliance.
“We need to have at least hourly marginal numbers available for the accounting under [LL97], and secondly, it’s valuable to have something that is forward looking and that isn’t simply scorekeeping but is actually actionable by people managing buildings in New York City,” Acker said.
NYISO will return to the ICAP/MIWG either next month or in June to share additional information on the methodology’s inputs and is targeting the fourth quarter to deliver the functional requirement specifications.
Renewable Regulation Requirements
NYISO also presented the ICAP/MIWG with proposed revisions to the regulation requirements for renewable resources in the state.
As New York installs more wind and solar projects, the ISO has been required to regularly update its regulation requirements, starting in 2010 and again in 2016, to ensure that these resources are not negatively impacting its ability to balance the bulk power system or disrupting voltage requirements.
NYISO modeled two scenarios that predict the total amount of installed nameplate capacities of land-based wind (LBW), offshore wind (OSW) and solar at the end of a given year: Scenario 1 projects that 3,000 MW of LBW, 125 MW of OSW and 7,651 MW of solar will be installed by 2024; while Scenario 2 projects 3,700 MW, 125 MW and 9,768 MW, respectively, will be installed by 2026.
NYISO is proposing that Scenario 1’s set of new regulation requirements be implemented on June 1, and that Scenario 2 be implemented in 2025. The ISO would send stakeholders market notices in case capacity levels approach those in the scenarios earlier than projected.
NYISO will seek approval for its proposed scenarios and their implementation timelines at the Operating Committee’s meeting Thursday.
YAKIMA, Wash. — Washington Gov. Jay Inslee on Monday said he has approved plans by Cypress Creek Renewables to construct two large solar farms in Yakima County in the central part of the state.
Cypress Creek will build the two 80-MW projects — High Top Solar and Ostra Solar — just west of the border between Yakima and Benton counties. The remote area is home to a just a handful of farms and 20 miles from the nearest town of Sunnyside. The two farms are expected to provide enough energy to power roughly 30,000 homes in the region.
Speaking at a press conference in the city of Yakima, Inslee noted that no farmland will be displaced by the projects. “Our team took great care to micro-site each project,” Cypress Creek CEO Sarah Slusser added.
The two solar farms are expected to go online in 2025 and 2026, according to Tai Wallace, senior director of development at Cypress Creek. Wallace declined to provide a budget for construction, which is expected to create about 300 to 550 jobs, with about five to 10 remaining once the projects are completed.
Inslee has been leading to push to set up numerous wind and solar farms in Washington to wean the state from electricity produced by fossil fuels. His administration has calculated that the state will need to double its electricity production by 2050 to replace fossil fuel resources while accommodating an increasing population.
“We are the perfect place to lead the world in clean energy,” Inslee said.
When questioned on whether he would uncritically approve wind and solar projects because of his strong support for alternative energy sources, Inslee replied: “We don’t rubber-stamp these things. We look at them with a critical eye.”
Washington law allows energy project developers to pick whether they want the state government or the appropriate county government to review their permit applications. Many applicants choose the state approach of going through the Washington Energy Facilities Siting Evaluation Council, which makes recommendations to the governor on whether to approve a project.
High Top and Ostra join two other eastern Yakima County solar farms set for construction. They include the 80-MW Goose Prairie project, approved by Inslee in December 2021, and the 94-MW Black Rock project, approved by Yakima County officials in May 2022.
The Black Rock project will share space with sheep that graze on the grass on the site, making it the second agrivoltaic site in Washington. The first such project mingling solar with farming is already online on the Colville Indian Reservation north of the Grand Coulee Dam.
New Jersey has been slow to spend Regional Greenhouse Gas Initiative (RGGI) funds since returning to the program, but it is taking steps to accelerate the process, state officials said last week as they solicited public input on how to use the money over the next three years.
Speaking Tuesday at the second of four public hearings into future priorities for RGGI funds, Paul Baldauf, assistant commissioner for air, energy and materials sustainability at the state’s Department of Environmental Protection, said “there’s a lot of lessons learned” in the state’s handling of the $372 million allocated to the state over the past three years.
Baldauf spoke nearly two weeks after the state announced the expenditure of $70 million — about 30% of the funds expended so far, mostly on electric school buses and other battery-powered heavy-duty vehicles. The state still must spend about $100 million of the RGGI funds allocated in the three-year period. State officials said they expect the funding plan, with public comments incorporated, will be released in the next two months, by which time more RGGI funds should be available and investment in projects will begin.
“We’re going to make a commitment in the second three-year period to, quite honestly, do a little better job on our end,” Baldauf said, referring to the need to spend the funds sooner.
“We want that money flow to be constant so we can see the results out in the street versus the money sitting in an account somewhere,” he said. “We’ve changed a lot of internal processes along the way to help with that, but we still have steps to go … So it’s really more seamless than anything else, and as the money comes in every quarter, that money [should go] out every quarter with the right things.”
He added that the state will continue the strategy of “almost solely” focusing spending on environmental justice communities.
Shifting Perspectives
Yet the hearings showed clear potential for shifting the state’s priorities elsewhere, depending on public response. Although a founding member of RGGI in 2005, New Jersey left the program in 2012 at the direction of then-Gov. Chris Christie (R), then reentered in 2020 under current Gov. Phil Murphy (D).
While the first three years’ worth of funds were allocated to transportation, the state’s largest source of emissions at 37%, the state is looking to broaden that focus, officials said. (See NJ Allocates $70M in RGGI Funds for Heavy-duty EVs.)
Some of the funding will shift to building electrification, one of the “primary areas” for which the state’s Board of Public Utilities is seeking input, BPU Chief of Staff Taryn Boland said.
One reason is that 73% of New Jersey homes are heated by natural gas, with another 10% heated with delivered fuels such as heating oil and propane — about 30% higher than the national average, Boland said. Meanwhile, just 16% of the state’s residence are heated by electricity, compared with a national average of 41%, she said.
“As the country is beginning to shift to electric air and water heating, it’s important to know that New Jersey is also way behind in the pack,” she said. “We know that building electrification will lead to cost savings and yield beneficial health outcomes. We know strategically and equitably designed programs to help drive … this transition is critical.”
That perspective, embraced by Gov. Murphy, has proven controversial in the past. The DEP in December dropped a plan to prohibit the installation of fossil fuel-fired commercial boilers amid vigorous opposition from business groups, who say electric boilers are vastly more expensive to install. (See NJ Backs off Ban on Commercial-size Fossil Fuel Boilers.) But Murphy in February signed executive orders establishing a goal to install electric heating and cooling equipment in 400,000 homes and 20,000 commercial properties by 2030.
Speaking after the Newark meeting, Boland said the state has not determined the priorities, but that building electrification is one competing priority among several. The state’s RGGI spending is divided among the BPU and DEP, each of which is allocated 20%, and the Economic Development Authority (EDA), which spends 60% of the funds. State officials said part of their effort to accelerate the spending has been to smooth the coordination and decision making among the three agencies.
Together they have crafted five main priorities for guiding RGGI investments: to strengthen the grid and promote “healthy homes”; stimulate “clean and equitable” transportation; “strengthen” the state’s forests; promote carbon capture in coastal areas; and reduce the use of “high warming refrigerants.”
Improving Efficiency
The BPU also thinks the state should put greater emphasis on the agency’s pilot “whole house” program, in which properties in low-income areas of the state capital, Trenton, are evaluated for health and safety hazards and efficiency, and remediated where necessary, Boland said.
“We’re looking to utilize funding in this strategic round to really bring that program to scale statewide,” she said. “We’re looking to build a strong portfolio of electrification and energy efficiency programs that leverage the federal incentives that are now available and drive down the cost of building [decarbonization] efforts.”
Peg Hanna, DEP assistant director of air monitoring and mobile sources, said the agency wants to continue investing RGGI money on EV projects, such as fleets of electric municipal school buses and garbage trucks, and to help put EV chargers in multi-unit dwellings, where residents have difficulty installing their own chargers. (See NJ RGGI Spending Focuses on Transportation.)
“We also know that the statistics show a lot of our ride hailing drivers live in multi-unit dwellings,” she said. “So providing charging hubs for those residents will also enable ride hailing to become electric.”
In a similar vein, the DEP is looking to pursue more programs such as the Go Trenton pilot program, still under development. The pilot will use RGGI funds to address the likelihood that EVs will struggle to take hold in the city because of low incomes and the fact that 30% of households don’t have a car, while 21% of residents report using car-sharing to get to work. Go Trenton would provide EV options such as a car-sharing, ridesharing and shuttle services.
During last week’s hearing, an audience member questioned whether RGGI funds could be used to help residents in environmental justice areas who can’t afford to buy an EV to repair their internal combustion engine vehicle.
Hanna said the issue clearly needs to be addressed, given that the state won’t replace all of its 6 million ICE vehicles in the near future but needs to minimize emissions from those cars.
“Making sure that the existing fleet is well-maintained is a core focus of our statewide inspection and maintenance program,” she said. “Are there ways to identify high emitters and to make sure the vehicles are repaired more quickly? Sure. We would need our friends at motor vehicle commission to be in on that discussion with us. But that’s something that we have looked at in the past — doing things like remote sensing in high traffic corridors to try to identify the highest emitters and get them pulled in for an inspection.”
The state also is working on adopting California vehicle rules to “ratchet down on the emissions from new internal combustion engines that can be sold and registered in the state,” she said.
Combating Super Pollutants
The third hearing on Thursday focused on “buildings, [the] grid and refrigerants,” highlighting potential projects that weren’t funded by RGGI money in the first phase.
For the EDA, key candidates for RGGI expenditures include improving grid resiliency to reduce electrical outages in overburdened communities and financing for “beneficial electrification, renewable energy distributed energy resources or energy efficiency projects in commercial buildings,” said Marta Cabral, senior project officer for clean energy programs at the EDA. The money could also be used to finance improvements that reduce emissions from commercial and industrial buildings, she said.
A DEP official said RGGI funds could additionally be used to reduce the use of refrigerants in low-income communities.
Hydrofluorocarbons account for 6% of the state’s greenhouse gas emissions and are “considered a climate super pollutant,” said Ky Asral, bureau chief of the DEP’s Bureau of Sustainability. That means that any reduction in their use would have a big impact, but businesses in low-income areas may balk at installing more expensive ultra-low commercial refrigeration system chillers, he said, suggesting that incentives funded by the RGGI program could get the job done.
“Funding the incremental cost from the installation of new refrigeration systems to ultra-low systems will accelerate the adoption of these systems and have immediate impact on reducing the global warming pollutants from this sector,” he said. “Creating similar incentives in overburdened communities for retrofitting or replacing high [global warming potential] refrigeration systems or chillers will keep much needed commercial facilities like supermarkets in neighborhoods that may otherwise not be able to afford the transition on their own.”
Stakeholders Endorse Manual Revisions for Real-time Values
VALLEY FORGE, Pa. — The PJM Market Implementation Committee overwhelmingly voted to endorse manual revisions to put limits on when generators can submit real-time values.
The revisions would only permit real-time values to be used for physical unit limitations or circumstances outside the generation owner’s control. Documentation of those factors would be required to be submitted to PJM and the Independent Market Monitor within three days. If real-time values are improperly submitted, PJM’s Lauren Strella Wahba said the RTO would have the ability to reject them after the fact and the option to refer the seller to FERC.
Real-time values are meant to be a temporary way for generators to provide PJM its operating capabilities when it cannot satisfy its unit-specific parameter limits or approved parameter-limited exceptions. The RTO has found that the values have been used to override parameter limits or exceptions in some instances, Wahba told the MIC, while in other circumstances dispatchers would only become aware of a deviation from operating parameters when they called upon a unit.
FERC rejected a previous proposal to codify real-time values in the tariff, stating in a May 2021 order that submissions would not have been based on actual physical or operational constraints. The commission also stated that PJM’s status quo governing documents could contain market power issues (EL21-78).
Several stakeholders questioned why PJM sought endorsement of new manual language rather than embarking directly on making tariff revisions. PJM’s Chen Lu said real-time values currently exist in the manuals without a requirement for physical constraints and by making manual revisions now, the changes can be implemented while stakeholders work toward a FERC filing on tariff revisions.
PJM proposed initiating a quick-fix process to address synchronized reserve deployment times exceeding PJM’s 10-minute internal standard since it implemented an overhaul of the reserve market on Oct. 1, 2022. Nonperformance rates have also increased to around 49% during the eight reserve deployments since the implementation, excluding those during the December 2022 winter storm.
The quick-fix process allows for a problem statement and issue charge to be endorsed concurrently with a proposed solution. Under the proposed manual revisions, PJM would be able to extend the second step of the operating reserve demand curve (ORDC) process by taking nonperforming reserve resources into account, allow the addition of on- and off-peak periods, and require that the extended values be posted as they’re changed.
PJM’s Phil D’Antonio said the RTO believes that the issue lies in market participant training, rather than in the pricing of reserves, and ongoing outreach to generators will yield progress. Glen Boyle, also of PJM, said that because penalties are based on synchronized reserve revenues earned and clearing prices are low, penalties are also low at this time.
Monitor Joe Bowring said he believes the issue is not appropriate for a quick-fix solution, as there is no demonstrated reliability issue that would be addressed by the proposed change.
He noted that PJM’s proposal would nearly quintuple the second step of the ORDC, from 190 MW to 890 MW, without any quantitative support for that significant a change, which he argued would trigger shortage prices more often and increase the price of synchronized reserves. Bowring also pointed out that the Oct. 1, 2022, change in the reserve market design increased the supply of synchronized reserves and included a must-offer requirement. He argued reserve prices since Oct. 1 have not been too low but have appropriately reflected the balance of supply and demand.
Under the applicable NERC standards, only one spinning event has exceeded the limit, and that is under investigation, Bowring said. He agreed with PJM that individual unit response times have been a problem and that both the Monitor and PJM are contacting individual unit owners to investigate the reasons for the poor performance. Bowring also stated that PJM’s rules for not paying resource owners for nonperformance were too weak and contributed to the performance issues.
Stakeholders Fine-tune Design Components on Local Considerations for Net CONE
Stakeholders continued the identification of design components to include in the drafting of proposals on whether and how to include regional factors impacting the net cost of new entry (CONE), such as environmental regulations or taxes. The MIC also discussed interests and design components during the February and March meetings, with the next phase being the creation of packages. (See “Discussion on Local Considerations for Net CONE,” PJM MIC Briefs: March 8, 2023.)
James Wilson, a consultant for five state consumer advocates, recommended two design components: a transition mechanism when net CONE is updated, potentially capping any increase at 20% during years between Quadrennial Reviews; and consideration of changes to the variable resource requirement (VRR) capacity demand curve shape — the latter of which he acknowledged had previously been ruled out of scope, which he suggested could ultimately result in any proposal to just change net CONE rules being rejected by FERC.
Stakeholders discussed whether CONE values and the reference resource should be reviewed whenever an impact, particularly signed legislation, is identified, including in between Quadrennial Reviews.
The discussion also looked at whether the creation of a new CONE area should result in the original region parameters being recalculated to account for the different footprint, particularly if the reference resource was based in the excised area.
Discussion on Co-located Load Packages
Several proposals to define how configurations in which load is directly connected to generators fit into PJM’s rules continued to be discussed by stakeholders.
Much of the discussion was centered on whether generators co-located with load that does not have a direct interconnection to the transmission grid should be required to relinquish a portion of their capacity interconnection rights (CIRs) equal to the energy consumed by the load, as they currently are, or if they should be permitted to retain that capacity, as well as whether interconnection and ancillary services charges should be assessed. (See “Proposals on Rules for Generation with Co-located Load Presented,” PJM MIC Briefs: March 8, 2023.)
Exelon’s Sharon Midgley said the company’s proposal would allow generators to retain their CIRs, but the facility would be classified as a load-serving entity for the co-located load and all applicable LSE charges and credits would be applied to it. She noted the package currently only focuses on capacity resources, but it will be expanded in the future to consider energy-only generation, given the interest expressed by other PJM members as well.
“Our primary interest is having more clarity in PJM’s rules,” she said.
A proposal from the Advanced Energy Management Alliance would codify all status quo rules and practices, with the addition of creating penalties for the host generator if the co-located load is not curtailed when the generator is dispatched.
Two proposals from the Monitor and a joint package from Constellation Energy and Brookfield Renewable remain largely unchanged since the MIC showed less than 20% support in a November poll. Following the poll, Bowring — whose package largely codifies existing practices and adds administrative requirements and charges — suggested discontinuing the discussion, but stakeholders felt that clarified rules are needed.
The Constellation-Brookfield proposal would allow generators to retain their full CIRs without making either the generation or the load subject to ancillary service charges, under the argument that the load does not benefit from grid services. Former Constellation Director of Wholesale Market Development Jason Barker stated that the arrangement the company envisioned under the rules would be a nuclear facility supplying power for highly interruptible load, such as hydrogen electrolyzers. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)
Bowring argued that PJM should be required to assess the impact of diverting a significant amount of low-cost energy off the grid to meet new load added to the grid behind the generators. He also said that emissions would increase as a result because nuclear energy would be dedicated to the new loads while existing load would be met by the emitting resources at the top of the supply stack. A related result would be an increase in energy market prices that the Monitor had previously estimated as exceeding a billion dollars, Bowring said.
“Nuclear plants were never built to provide energy for a few hours per year. The promise to provide energy from the resources for a few peak hours a year is not consistent with the obligation of capacity resources.”
First Read on Smooth Supply Curve Quick Fix
PJM presented a proposal to initiate a quick fix process to clarify that the informational smoothed supply curves PJM publishes after Base Residual Auctions will not be created for Incremental Auctions (IAs). PJM’s Skyler Marzewski told the committee that PJM cannot create smoothed supply curves for IAs because of the lack of demand curves in those auctions and the risk that they could be used to expose market sensitive data.
INCLINE VILLAGE, Nev. — FERC Commissioners Allison Clements and Mark Christie offered their thoughts on Western market formation to a large gathering of state regulators and stakeholders at last week’s meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB).
Christie urged caution on joining an RTO, and Clements said “bigger is better” when it comes to organized markets. But both said the West will have to make its own decisions on market options.
Those options now include the Western Power Pool’s Western Resource Adequacy Program (WRAP), SPP’s planned RTO West and its Markets+ day-ahead offering, and CAISO’s extended day-ahead market for its real-time Western Energy Imbalance Market (WEIM). A legislative effort is underway that could eventually allow CAISO to become a multistate RTO. (See related story, Western Day-Ahead Markets Debated at CREPC-WIRAB.)
Clements compared the situation to a “dating process,” a metaphor she said she had borrowed from others at the meeting. And like other speakers, she noted the difference between pre-pandemic circumstances in the West and the current push toward Western regionalization.
“You really have made great progress in the last two and a half years,” she said. “Before COVID, everyone was just kind of looking around and checking each other out, and, wow, we come back from COVID and things have gotten serious.”
“I want to be clear that FERC’s job is not to be the parents to choose for you,” she said. “We’re not going to choose between the banker and the lawyer. We’re not going to choose between the banjo player and the marketer. Right? You are going to make a decision on your own.”
Clements pointed to the $3.4 billion in cumulative benefits obtained by participants in CAISO’s WEIM as evidence of the value of market development. The market allows participants to trade inexpensive renewable resources and to optimize dispatch across portions of 11 Western states and one Canadian province.
“The benefits of the EIM have really kind of shut the door on the question of whether or not increased market optimization works,” Clements said. “It feels like that conversation is done. Markets designed well save customers money. That’s the bottom line.”
She also praised the progress on WRAP, a first-of-its kind effort to coordinate resource adequacy across much of the Western Interconnection. FERC approved the program’s tariff in February. (See FERC Approves Western Resource Adequacy Program.)
Decisions about whether to join WRAP, the proposed day-ahead markets or to engage in interregional transmission planning could have long-term consequences and must be considered carefully, Clements said.
“The idea that you would choose one partner for resource adequacy and one partner for the day-ahead market and another partner maybe down the line for transmission system planning creates a lot of inefficiency and leaves a lot of savings on the table,” she said.
“You know, to my mind, it’s always the case that bigger is better,” she said. “The broader the interconnected nature of the system, the more ability you have to ensure reliability in extreme weather because the extreme weather won’t cover the whole system.”
A state-led market study in 2021 estimated that a West-wide RTO would save $833 million per year in production costs by 2030, Clements noted.
RTOs have seams agreements with each other and the ability to dispatch across those seams, and they can develop transmission while avoiding unnecessary costs and redundancies, she said.
“There are a lot of benefits that come with the full-scale development of an RTO, and there are issues to deal with as well,” she said. “I won’t pretend it’s just a rosy walk in the park.”
Seams agreements between RTOs can be especially difficult, requiring “intensive coordination,” she said.
“So, as regulators, you want to be at the table very early to think about how that coordination is going to get set up,” Clements said. “It’s not the kind of thing you want to leave and punt down the road and just see how it goes for a while.”
“Those are the questions I’m asking myself, as I see you all asking yourselves and engaging in these conversations around ‘what and where do we go from here?’” Clements said. “I will say I’m really impressed by where you are. And I look forward to continuing to watch you all and support you all trying to figure out your next steps.”
‘Lowest Rates in America’
In a separate session, FERC Commissioner Mark Christie weighed in on the question of whether Western states should join an RTO.
“You in the West will decide for yourselves what you want to do,” said Christie, who noted the range of options between doing nothing and joining “a full-scale RTO with all the bells and whistles.”
The West could come up with a unique construct that’s not being used elsewhere in the U.S., Christie said. Market choices, including real-time and potentially day-ahead market choices, could be meshed with a resource adequacy program such as WRAP, which Christie lauded as being creative, simple and voluntary.
“What could be more simple than having load-serving entities mutually pledge to reach certain resource requirements and to make available their excess resources when another participant needs it?” he said. “And to help each other in a reasonable way and on a voluntary basis.”
Another aspect of the RTO decision is what a state utility commission would relinquish in choosing to go with an RTO.
“If you want to give up your transmission planning, you’ve got to ask yourself, what am I giving up?” said Christie, who served 17 years on the Virginia State Corporation Commission before joining FERC in 2021. “Well, you’re giving up the ability … to control how assets are going to be deployed and how much money is going to be spent and how the costs are going to be allocated.”
“Maybe you want to do that,” he added. “Maybe that works for you. My point is, don’t accept unskeptically the benefits of any construct.”
Putting customers first should be the driving interest for state and federal regulators, Christie said. He pointed to three Western states — Utah, Idaho and Wyoming — that had the lowest electric rates in the nation as of the morning of his presentation.
“If the promise of an RTO is [that] it’s going to save us all this money, and we’re sitting here in these three states and we have the lowest rates in America, the question would be, ‘Seriously? … It’s going to save us money? How?’”
The Treasury Department has released an updated list of electric vehicles that qualify for all or part of the Inflation Reduction Act’s tax credits, providing mixed news for U.S. and foreign automakers and prospective buyers.
Under the guidelines for meeting the IRA’s domestic content provisions, released last month, U.S. automakers fared well, with most of their models on the revised list, but some qualifying for only half the credit. The guidelines for 2023 models require that 40% of critical minerals in an EV’s battery and 50% of other battery components be sourced from the U.S. or from a country with which the U.S. has a free trade agreement. (See Fewer EVs May Get IRA Tax Credit Under New Domestic Content Rules.)
To qualify for the full $7,500, EVs must also meet the IRA’s limits on manufacturer’s suggested retail price (MSRP), and final assembly of the car must be in North America. The MSRP limits are $55,000 for a passenger EV and $80,000 for SUVs and light-duty pickup trucks.
A previous list, issued at the end of 2022 did not factor in the domestic content requirements, allowing more than 20 EVs and plug-in hybrid electric vehicles (PHEVs) to qualify for tax credits.
All Tesla’s Model 3 and Model Y vehicles qualified for the full $7,500 tax credit on that list, but now the standard, rear-wheel drive Model 3 — with a range of 272 miles and a $42,000 MSRP — only qualifies for $3,750, signaling that its battery does not meet the domestic content requirements for the full credit. The topline Performance Model 3 is still eligible for the full credit.
Similarly, Ford’s F-150 Lightning electric pickup qualifies for $7,500, but the automaker’s popular Mustang Mach-e SUV is only eligible for $3,750.
All European and Asian models previously on the list were cut, including the Nissan Leaf, Volkswagen’s ID.4 and BMW’s 330e plug-in hybrid vehicle.
GM has the most models qualifying for the full $7,500 tax credit, with its Cadillac Lyriq and Chevy Bolt, Blazer, Equinox and Silverado still on the list, the result of its investments in domestic supply chains, the company said in a statement released Monday.
“Over the next 10 years GM will offer a broad selection of qualifying vehicles across numerous segments and price points, which will bolster our EV transformation as well as the U.S. production and adoption that these incentives were designed to support,” the company said.
Ford, which holds the No. 2 spot in the U.S. EV market — after industry leader Tesla — released its own list of models qualifying for tax credits earlier this month. Like GM, the company is promoting its plans for continued supply chain growth and delivering more EV models in the coming years.
Challenging but Achievable
Sen. Joe Manchin (D-W. Va.) wrote the domestic content provisions into the IRA to support the buildout of a home-grown EV supply chain and to cut U.S. automakers’ dependence on China for the critical minerals and other components in EV batteries. The law required the Treasury Department to issue guidelines for the EV tax credit by the end of 2022, but the agency only released partial guidelines, delaying rules on the domestic content provisions until March. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
Manchin made an unsuccessful attempt to force implementation of the domestic content provisions with a bill he introduced in January, and he was not satisfied with the domestic content guidelines Treasury issued March 31. But he has not taken any further action. (See Transparent, Traceable Supply Chains Key to EV Domestic Content Rules.)
But as gas prices again edge up, the Biden administration is framing the slimmed-down list as still providing U.S. consumers with a good range of choices for purchasing an EV with the full or partial tax credit, while also supporting ongoing growth of domestic supply chains. Getting both halves of the credit may be challenging, but it is achievable, according to an administration official speaking on background.
The Treasury guidelines are clear, workable and having the intended effect, the official said. According to a preliminary administration analysis, close to 65% of EV sales in the first three months of 2023 met the IRA’s requirements on vehicle price and final assembly, qualifying them for at least the $3,750 credit, the official said.
Further, 90% of those vehicles also met the IRA’s domestic content requirements, the official said.
Other administration officials have been keen to point to the $45 billion in private sector investment in EV and battery supply chains that has been announced since President Joe Biden signed the IRA in August, For example, Korean automaker Hyundai is building a factory in Georgia expected to go into production in 2025, with an estimated production of 300,000 EVs a year.
Similarly, Japan’s Nissan announced a $500 million investment to transform a Mississippi plant for EV production.
EV Sales Continue to Grow
The big question is whether and to what extent the reduction in EV models eligible for the IRA tax credits might slow EV adoption and put a brake on Biden’s goal of EVs becoming 50% of all new passenger vehicle sold in the U.S. by 2030.
Phil Jones, CEO of the Alliance for Transportation Electrification, is expecting a “hiccup” in the EV market as automakers adjust to the domestic content guidelines and focus on domestic supply chains. “There will be some slowdowns for certain vehicles and certain manufacturers, obviously, because consumers are price-sensitive,” Jones said in a recent interview with NetZero Insider.
“But I don’t think it’s going to be significant,” Jones said. “There’s so much pent-up demand for these vehicles out there, and the major issues, in my view … it’s chips; it’s semiconductors; it’s components of an automobile other than the battery.”
U.S. EV sales seem to support that view. EV registrations in the U.S. in 2022 topped more than 750,000, a 57% jump from 2021, according to data from Experian cited in insideevs. Tesla accounted for 64% of sales, followed by Ford and Chevy. EVs accounted for 7.1% of all new vehicle sales in January, according to Experian, with Tesla once again in the lead with sales of more than 46,000.
PJM asked FERC on Friday to initiate settlement judge procedures in its dispute with generators over nonperformance penalties for the December 2022 winter storm.
The RTO asked the commission to establish a “global settlement procedure” for the eight complaints filed by generators (EL23-53 through EL23-60) and “for any similar complaints that may be filed.”
PJM officials told stakeholders last week they had assessed more than $1.8 billion in performance penalties on generators that underperformed during the Christmas weekend storm dubbed Winter Storm Elliott. (See related story, PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)
The RTO told FERC it properly implemented its emergency procedures and that the nonperformance charges follow its tariff and are just and reasonable.
“At the same time, however, PJM recognizes the potential benefits of a prompt resolution, to the extent possible, of the disputed assessment of these charges,” it said. “These disputes, considering the complaint, rehearing and appeal processes, could hang over the PJM market for years, affecting market participants’ conduct in ways that may be irreparable and not always desirable. The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market. Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”
PJM noted that several of the complainants have also requested settlement procedures or alternative dispute resolution.
“A global proceeding would best provide, to the extent possible, a measure of principled consistency in any settlement outcomes of these multiple complaints,” it added. “To that end, PJM seeks a single overarching settlement process, led and coordinated by the commission’s administrative law judge(s), for all of these complaints.”
Staff, Stakeholders See Resource Adequacy as Key Issue
SPP staff and stakeholders spent much of last week’s virtual Markets and Operations Policy Committee meeting discussing resource adequacy and the various initiatives the grid operator has rolled out to address the issue.
“Resource adequacy is a critical area for us,” SPP’s Casey Cathey said. “The regional fuel mix is consistently changing. The state of the future grid is extremely important. Loads are changing; pretty much everything’s changing that we know of in our industry, even HR.”
As director of grid asset utilization, Cathey runs a department responsible for planning a reliable and efficient bulk electric transmission system, with an eye on economically preparing SPP for the future grid. His staff facilitates generation interconnection and transmission service functions and operates resource adequacy across both the Western and Eastern interconnections.
Cathey’s department is not alone.
“Everything we’re doing related to resource adequacy is critical, which is why we have a number of different groups that are focusing on various aspects of resource adequacy,” COO Lanny Nickell said.
SPP’s Supply Adequacy Working Group (SAWG) handles immediate resource adequacy issues and the technical aspects of various studies. The Improved Resource Availability Task Force was formed after the February 2021 winter storm and is working on fuel assurance and resource planning and availability recommendations identified in the RTO’s review of the storm. (See SPP Board of Directors/Members Committee Briefs: July 26-27.)
The grid operator has also created the Resource and Energy Adequacy Leadership (REAL) Team under state regulators’ Regional State Committee. Chaired by Texas Public Utility Commissioner Will McAdams, the REAL Team has been tasked with the more strategic aspects of resource adequacy by assessing SPP’s current construct and anticipated challenges from resource mix changes, extreme weather effects, increased demand and evolving consumer behaviors.
Staff and stakeholders will be busy in the near term. SPP’s annual tasks include winter and summer season deliverability studies and, this year, a loss-of-load expectation study to help determine the planning reserve margin for summer. The study will address weather-forecast uncertainty by using 40 historical weather years dating back to 1980. It will also determine a winter resource requirement and PRM and an unforced capacity PRM.
Staff and the REAL Team are both looking at whether an expected unserved energy (EUE) standard needs to be developed. Then there’s the SAWG and Operating Reliability Working Group’s joint review of the planned and maintenance outage policy and a slew of other work.
Cathey noted SPP and the industry have traditionally followed the one-day-in-10-years LOLE standard, a legacy from a time when generation fleets primarily comprised thermal resources. He said the industry may be leaning toward a combined standard that combines LOLE with EUE and loss-of-load-hours.
“One thing that is missing in our LOLE study is forecasting climate change. There’s not a forecast or prediction or aspect to our LOLE study today, so that’s another area that we’d like to continue to explore,” Cathey said. “We have an urgency for resource adequacy, not the least of which is that resource adequacy is now one of our top corporate risks and also industry-wide. Everyone’s trying to figure out the potential policy changes.”
Nickell assured stakeholders that they will continue to have a voice in the resource adequacy work.
“I just want to deal with the impression that this is all happening behind the scenes and behind closed doors, and it’s just staff collaborating on this stuff,” he said. “That’s absolutely not true. We have been working with stakeholders along the way. … They will all have an opportunity to provide input.”
Responding to FERC’s Rejection
One of the REAL Team’s first actions has been to direct the SAWG to modify and “harmonize” two revision requests so they focus on equitable and appropriate treatment of resources in response to FERC’s recent rejection of SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds.
The commission agreed in March with renewable energy developers’ arguments that it had erred with last year’s order accepting the RTO’s proposed tariff revisions to accredit wind and solar resources based on historical performance using an effective load-carrying capacity (ELCC) methodology (ER22-379). (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)
“This was a surprise to SPP and SPP staff and members,” Cathey said, noting the ELCC was expected to be in place this summer.
The SAWG is working to separate the ELCC and performance-based accreditation into two separate RRs, with the ELCC request expected to reflect FERC guidance. The RRs have been targeted for final presentation to the board and RSC in October.
Cathey said the accreditation methodology changes for all resources should be filed together as a policy change and their implementation’s timing be consistent across all resource types. He said seasonal net peak demand should be defined in the tariff and modifications considered for ELCC allocation methodology.
FERC said in its filing that it expects staff to provide “sufficient detail in its tariff, consistent with the directives of this order, to allow the commission to act in a subsequent order without the need for additional record development.”
“We all know, especially since we passed the performance-based accreditation policy last summer, that we were working to become more equitable in our accreditation process across all fuel types,” Cathey said. “However, from a legal perspective, that was not in front of [FERC] in that docket, and so it’s certainly a lessons-learned for us.”
2024 ITP Scope Revisions OK’d
The MOPC approved a pair of Economic Studies Working Group recommendations to the 2024 Integrated Transmission Planning 10-Year Assessment’s scope that are more reflective of current grid conditions.
The first revision would include a winter weather analysis because of more frequent extreme conditions, such as the February 2021 and December 2022 storms. The MOPC and the Strategic Planning Committee both directed the ESWG to study extreme winter weather conditions.
The second increases the amount of assumed amounts of renewable capacity in the scope’s two futures, based on the amount of renewable interconnection requests in the queue. Both measures passed overwhelmingly, 80% and 93%, respectively.
Increased renewable energy assumptions in the 2024 ITP’s scope | SPP
The ESWG suggests building two distinct winter weather power-flow scenarios: one focused on operational conditions to better understand reliability issues that took place in December, and a generic model based on a set of historical winter regional stressors such as fuel availability, wind output, and transmission and generation outages.
“At the very least for December 2022 … we are going to have some outages baked in to be able to study what exactly happened in Winter Storm Elliot,” said ESWG Chair Derek Brown, of Evergy.
Brown said it could take as much as $600,000 for additional staff time to keep the 2024 ITP on schedule.
The ESWG also proposes to increase its assumptions for renewables added to the grid in the futures’ year 5 and year 10 scenarios. The studies will assume year 10 highs of 19.1 GW for solar in the reference case and 24.1 GW in the emerging technologies case; 54.9 GW and 59.1 GW for wind; and 5.7 GW and 9.6 GW for battery storage.
GI Backlog Tracking for 2025 Completion
SPP remains on track to clear its generator interconnection queue’s backlog by 2025 despite 599 active requests, Cathey said. The queue’s six cluster studies are all green thanks to the grid operator’s two-year-old, three-phase approach to processing generator interconnection requests in place since 2022 and its backlog mitigation plan.
The mitigation efforts began in 2022 with 898 GI requests for 171.5 GW of generation in the queue. As of Sunday, the requests are down to 593 for 118.1 GW of capacity.
“It’s mostly around restudies and ensuring that we’re not causing too much churn to the GI customers and making sure that we get through the backlog as each cluster of DISIS [definitive interconnection system impact studies] is captured,” Cathey said. “So far, it still appears to be effective.”
Even with the backlog, SPP has added almost 28 GW of capacity to the system since 2016 and executed 144 interconnection agreements. Complicating matters going forward is that a little over 41% of the queue’s requests (48.3 GW) are for solar. Wind (29.9 GW) and energy storage (21.8 GW) — all of it four-hour, lithium-ion batteries, Cathey said — account for much of the rest. Developers have 21 requests for 3.5 GW of thermal capacity in the queue.
“We’re trying to thread that needle in terms of where our fuel mix is going five, 10, 15 years in the future, coupled with our load profiles,” Cathey said. “We definitely need to work on those particular policies because even if they’re all approved, as massive as 119 GW are, it’s more than twice our peak load.”
Tx Service RR Remanded
The MOPC remanded a revision request back to the Transmission Working Group after Dogwood Energy’s Rob Janssen pulled it off the consent agenda for further discussion and vetting in the stakeholder process.
Dogwood abstained from the Regional Tariff Working Group’s vote on RR534, which is intended to clarify and correct tariff language that limits transmission service to the amount of interconnection service.
Janssen said 95% of RR534 is “perfectly fine,” but the inclusion of point-to-point service along with network service runs counter to FERC Order 888’s language that doesn’t allow limitations on parties purchasing transmission service in the absence of anticompetitive practices.
“While you do try to include both point-to-point transmission service and network service in this set of restrictions, my concern is that you actually increase the probability of gaming, because now you’re allowing a third party to buy point-to-point transmission service and effectively block a load-serving entity that might have a deal with a generator for being able to get transmission service for any deal that they put in place,” Janssen said. “That could result in a very significant problem for some parties as SPP’s grid gets more resource-constrained and parties are fighting for access to generating resources.”
The consent agenda, approved unanimously, included seven other RRs that are effective immediately and one, RR530, that requires the Board of Directors’ approval:
RR530: identifies consistent criteria for when it is acceptable to implement a transmission reconfiguration and outlines responsibilities for the reliability coordinator and transmission operator.
RR532: removes section 4.5.9.21 (Real-Time Joint Operating Agreement Amount) and adds the variable RtJoaHrlyAmt in the definitions section of 4.5.12 (Revenue Neutrality Uplift Distribution Amount) among other cleanup to revenue neutrality uplift language.
RR533: adds language to clarify how resources will be settled with operational tools downstream from the real-time balancing market and that cleared quantities are updated when a price correction is needed for the day-ahead market.
RR535: corrects the protocols for uncertainty products by clarifying summation for reserve zone additions, settlement variables and if/else replacements.
RR538: ensures the protocols and tariff clearly describe when emergency limits will be used and how market participants can know if the emergency limits are used.
RR540: ensures RR382 (Multi-day Minimum Run Time) is accurately implemented by revising governing language for day-ahead and reliability unit commitment make-whole payments.
RR541: clarifies that the credit customer, not the market participant, is the highest level for exposure tracking.
RR544: modifies the Transmission Owner Selection Process Task Force’s changes to the competitive transmission selection process to include cost caps and guarantees in competitive upgrades.
