NYISO stakeholders on Monday voted to recommend that the ISO’s Class Year 2021 (CY21) study results and cost allocations move to the Operating Committee for a vote next week.
Nearly 120 stakeholders attended Monday’s Transmission Planning Advisory Subcommittee meeting, where NYISO shared the list of upgrades required to reliably interconnect the 57 projects included in the CY21 study, at a cost of up to $900 million.
NYISO Manager of Facility Studies Wenjin Yan shared that 54 projects were requesting both energy resource interconnection service and capacity resource interconnection service (CRIS), while three members were CRIS only.
Decision Process and Timeline
With the upgrades and cost allocations for the CY21 projects identified, the ISO will now seek OC approval for the class year study reports, which include the allocations for CY21 system upgrade facilities (SUF) and system deliverability upgrades (SDU).
The OC’s approval of the CY21 study report will trigger the start of the initial decision period, during which class year developers will have 30 calendar days to accept or reject their cost allocations for SUFs and SDUs, and deliverable megawatts, if available, by providing NYISO either an acceptance or non-acceptance notice.
Developers who reject their cost allocations during this initial period will trigger additional decision rounds in which the ISO will issue within 14 calendar days a revised CY21 that removes projects that rejected their cost allocation, whereupon the remaining developers will have an additional seven calendar days to provide their acceptance or rejection to the revised CY21 cost allocations.
If additional rejections occur in subsequent rounds, the rejected projects are removed from the CY21 and the ISO will issue another revised CY21, and this iterative process will continue until all remaining CY21 members accept their respective cost allocations.
Once the remaining CY21 projects have accepted their cost allocations, developers will have five business days to pay cash or post security for the full cost allocation amount, and any developers who intend to post security are encouraged to reach out to applicable transmission owners to ensure the type of security that they intend to post meets the applicable transmission owners’ security arrangement requirements.
NYISO pointed out that developers who fail to notify the ISO by a stated deadline will be deemed as submitting a non-acceptance notice and removed from the class year.
Due to projects that reject their cost allocations in one round, the remainder of the CY21 members may see their CY21 cost allocations and any deliverable megawatts revised based on the updated study results.
NYISO also shared rules and procedural elements of this decision process, noting how developers that have additional SDU studies may accept their SUF project cost allocations, but separately accept or reject their SDU costs.
Developers with additional SDU studies not yet completed before the start of the CY21 initial decision period are given the ability to accept their SUF costs at this time and proceed with the additional SDU studies until they are completed or they can wait until the additional SDU studies are completed and, at that time, accept or reject the SUF and SDUs.
The ISO shared anticipated CY21 calendar breakdown, noting that the CY23 study could start as early as Jan. 3, 2023, with one decision round, or Feb. 13, 2023, should the CY21 study enter three decision rounds; however, CY21 can proceed with more than three decision rounds.
In response to questions about the timeline and whether the process could be sped up, Yan responded that “there is no reason we are going to hold up the results” if things could move faster than anticipated as the ISO “will use all their efforts to meet class year and tariff schedules.”
CY21 is considered complete once the class year report has been completed and all remaining developers have accepted and paid — or posted — security for their respective cost allocations.
Next Steps and Voting
Attending stakeholders recommended that the CY21 final results and cost allocations proceed to the OC for approval, though one objection was submitted by Empire Offshore Wind LLC, which represents two CY21 projects: Q958 (EI Oceanside 1) and Q959 (EI Oceanside 2)
The final report will be presented for approval at the next OC on Oct. 24. If approved, developers will have 30 calendar days to decide whether to accept their respective CY21 cost allocations.
If all 57 CY21 members accept their cost allocations, and no further decision rounds are required, then the ISO anticipates CY21 will end on Dec. 2, with the Class Year 2023 (CY23) study expected to start on Jan. 3, 2023.
MISO remains committed to beefing up and making information from its generation retirement studies more public as it outlined a number of study changes it plans to soon file with FERC.
The grid operator told stakeholders Wednesday it plans to impose a yearlong notice requirement on retiring generation before it begins retirement studies under Attachment Y of its tariff. It also plans to conduct the studies on a quarterly basis, share with stakeholders the megawatt value of retirement requests, and discourage reliance on load shed as a valid mitigation option when voltage and thermal violations are uncovered in its steady state analyses. (See MISO Bolstering Generation Retirement Studies Amid Capacity Shortage.)
“I know it’s a major change, but this will help us perform better studies. We believe there may be a ramp up in retirements, and this will help us study them,” Sydney Yeadon, with MISO’s resource utilization team, told stakeholders during a Planning Advisory Committee meeting.
Currently, generators intending to retire must notify the RTO six months ahead of time and studies are conducted as the notices are received. Staff says the changes are needed given the increase in retirement notices.
MISO says it will need four quarterly study periods worth of notice, rather than 52 weeks, from generation that is being retired or suspended.
MISO will define first-quarter retirement studies as beginning the first business day of March through the last business day of May; the second quarter as beginning the first business day of June through the last business day of August; the third quarter as beginning the first business day of September through the last business day of November; and the fourth quarter as beginning the first business day of December through the last business day of February.
The new study process will allow one quarterly study period after FERC approval for generator owners to prepare to use the new system.
Stakeholders asked whether the grid operator will study alternatives to keeping aging or uneconomic generation online under system support resource (SSR) agreements. Staff responded that it annually re-evaluates the need for SSRs after they are designated and said they view the agreements as a last resort for reliability.
DTE: Consider Old Generators for Reactive Power
DTE Energy is continuing its push to give old thermal generators new life as synchronous condensers that furnish the grid with reactive power.
During an Oct. 11 Planning Subcommittee, DTE’s Kenneth Gavin said that as dispatchable power retires and renewable integration gains traction, MISO will find a greater need for reactive power.
The utility says that existing generators can be cost-effectively converted to zero-emissions synchronous condensers after they suspend operations through MISO’s Attachment Y retirement process. It says that such conversions “can supply clean reactive power to the grid that maximizes performance and maintains customer affordability.”
Sustainable FERC Project’s Lauren Azar said the sooner MISO and members begin addressing grid technologies to support a majority renewable mix, “the better off we’ll all be.”
WPPI Energy’s Steve Leovy said it’s an opportune time for the RTO to signal a need for synchronous condensers because several thermal generators are announcing or weighing retirements.
Currently, retiring generators in the MISO footprint that are converted into synchronous condensers aren’t eligible for compensation under the tariffs Schedule 2, which outlines compensation for reactive supply and voltage control. The grid operator’s retirement process would take away a converting plant’s interconnection rights.
MISO says it will easily navigate normal winter conditions with its own firm supply but acknowledges that a worst-case winter storm in January could exhaust its emergency reserves.
During a winter readiness workshop Thursday, staff estimated they will have between 112 GW and 116 GW of capacity available to meet a projected 102 GW demand peak in January and 97-GW peaks in December and February. The forecast assumes average outage rates that have historically reached 29 GW.
The RTO’s all-time winter demand peak of 109 GW was set in January 2017.
Resource Adequacy engineer Eric Rodriguez said MISO “will be long as far as firm resources are concerned” if it experiences a normal number of outages and typical winter weather.
But the grid operator said “high-risk, low-probability events,” such as an artic blast, intense winter storms and fuel supply issues, “could impact available power” and challenge reliable operations.
According to Adam Simkowski, MISO’s principal meteorological risk analyst, MISO South should experience above normal temperatures while MISO Midwest should see near to slightly below normal temperatures. The grid operator noted that the National Oceanic and Atmospheric Administration is modeling a dynamic winter storm pattern for the Great Lakes states and said the area is at risk for blizzards and wind turbine icing.
“We could see a pretty active precipitation pattern this winter,” Simkowski said.
MISO is monitoring the small potential for a stratospheric warming event “which could destabilize the polar vortex” and unleash frigid weather that could dip into MISO South, he said.
“Overall, the ingredients for this to happen this winter don’t seem extremely likely,” Simkowski said, although he said the footprint could encounter “five- to 10-day shots” of cold weather.
Staff doesn’t foresee emergencies outside of a perfect storm of variables during the January peak. They said a scenario with unusually high demand of 109 GW and low available generation of only 95 GW could use up its 9.3 GW of expected emergency supply and force MISO to rely on imports from its neighbors to avert load shedding.
“Operating the power system is extremely complex, and adverse weather conditions can test the resiliency of the electric grid,” Jessica Lucas, executive director of system operations, said in a press release. “We have a responsibility to ensure 42 million customers have reliable power, which is why we need to work collaboratively with our partner utilities as we head into winter.”
“The system is evolving and will continue to evolve toward a more complex, less predictable future for the region,” added Anna Foglesong, director of strategy and policy coordination.
The Department of Energy on Wednesday awarded 20 companies $2.8 billion to supply minerals critical to battery production and bolster domestic manufacture of batteries for electric vehicles and the grid.
The grants are the first round of $7 billion in DOE funding for batteries from last year’s $1.2 trillion Bipartisan Infrastructure Law, which included $62 billion for energy programs. The awardees will build or expand facilities in 12 states to manufacture battery components, including from recycled materials, and extract and process battery materials such as lithium and graphite, DOE said in a news release.
“This is truly a remarkable time for manufacturing in America, as President Biden’s agenda and historic investments supercharge the private sector to ensure our clean energy future is American-made,” Energy Secretary Jennifer Granholm said in the statement. “Producing advanced batteries and components here at home will accelerate the transition away from fossil fuels to meet the strong demand for electric vehicles.”
Sales of plug-in EVs have tripled since Biden took office, but the U.S. remains too dependent on other nations for critical minerals needed to produce EV batteries, mainly lithium, cobalt, nickel and graphite, DOE said.
“China controls the supply chains for many of these key inputs,” it said.
The grants are intended to alter that imbalance. All are matched or exceeded by company investments “to leverage a total of more than $9 billion,” according to DOE.
The largest award of $316 million went to Ascend Elements to establish industrial-scale separation of cathode materials from spent lithium-ion batteries and produce “precursor cathode active materials and metal salts to support domestic production of cathode active material (CAM),” DOE said in a fact sheet on the project. CAM can then be used in new lithium-ion batteries for EVs and energy storage systems, it said.
A new plant in Hopkinsville, Ky., will supply enough materials for 250,000 EVs annually, according to DOE. Ascend received another $164 million to design and construct the CAM plant.
With a $115 million DOE grant, Talon Nickel plans to construct a battery minerals processing facility in central North Dakota to process nickel ore for battery production. The company has an agreement with Tesla to supply 75,000 metric tons of nickel in concentrate along with copper, cobalt and iron in nickel and copper concentrates for “multiple battery chemistries,” DOE said.
“This process improves yield and metal byproduct utilization relative to legacy processing of nickel ores,” it said.
Talon CEO Henri van Rooyen said in a statement Wednesday that the “national urgency and the target date for nickel and iron production set within our Tesla-Talon supply agreement required an innovative approach to bring a new domestic source of battery minerals into production during a period of global battery-grade nickel deficits. Today’s announcement is a clear recognition that production of domestic nickel and other battery minerals is a national priority.”
In McMinn County, Tenn., Piedmont Lithium will use a $142 million grant to help build its $600 million Tennessee Lithium project, “which aims to expand the U.S. supply of lithium hydroxide by 30,000 metric tons per year,” the company said in a news release. “Lithium hydroxide is a key component of high energy density, long-range, EV batteries,” it said.
“We are pleased that the DOE has chosen to support our Tennessee Lithium project, and we are committed to being responsible stewards of these grant funds,” Piedmont COO Patrick Brindle said in the statement. “This funding will enable us to accelerate detailed engineering and place orders for long-lead items.”
Construction at the Tennessee Lithium project is expected to start next year, with production beginning in 2025, the company said.
‘Reliable’ and ‘Sustainable’ Supply Chain
Other projects funded include the first large-scale lithium electrolyte salt production facility in the U.S.; an “electrode binder facility capable of supplying 45% of the anticipated domestic demand for binders for EV batteries in 2030”; the nation’s first commercial-scale silicon oxide facilities, which will produce materials for an estimated 600,000 EV batteries annually; and the first lithium iron phosphate cathode facility in the U.S., DOE said.
In total, Wednesday’s first-phase funding will help supply enough battery-grade lithium for “2 million EVs per year, enough graphite for 1.2 million EVs annually and enough nickel for 400,000 EVs,” DOE said. The grants will promote creation of 8,000 jobs including 5,000 permanent jobs, many of them in or near disadvantage communities, it said.
The Biden administration wants electric vehicles to make up half of all new vehicle sales by 2030 and to transition to a net-zero emissions economy by 2050, the department noted.
Toward that end, the Biden administration announced Wednesday it was launching the American Battery Material Initiative, a “new whole-of-government effort to secure a reliable and sustainable supply of the critical minerals that power everything from electric vehicles to homes to defense systems,” the White House said in a fact sheet. “The American Battery Materials Initiative will be led by a White House steering committee and coordinated by the Department of Energy with support from the Department of the Interior.”
“The Initiative will work through the Partnership for Global Infrastructure and Investment, and leverage ongoing work by the Department of State, to work with partners and allies to strengthen critical mineral supply chains globally, and it will leverage and maximize ongoing efforts throughout the U.S. government to meet resource requirements and bolster energy security,” it said.
Carbon capture and storage is having a banner year, with 30 commercial CCS facilities now in operation worldwide capable of storing more than 42 million tons of carbon dioxide per year. Add in a pipeline of 164 projects in various stages of development, and the potential stored capacity jumps to almost 244 million tons per year — a 46% jump over 2021 — according to the 2022 Status Report from the Global CCS Institute.
“After so many challenges and so many false starts … the momentum is palpable,” said Brad Crabtree, assistant secretary of the Department of Energy’s Office of Fossil Energy and Carbon Management.
But speaking at a webinar on the report Monday, Jarad Daniels, the institute’s CEO, said optimism about new momentum in the industry must be tempered by the need for unprecedented growth. “Global efforts to reduce emissions, including investment in CCS, are still grossly inadequate overall,” he said. “Government policy must be met with private capital to unlock the full potential of CCS and limit global warming to 1.5 degrees.”
Hitting that target will mean increasing carbon storage capacity more than 100-fold by 2050, said Guloren Turan, GCCSI’s general manager for advocacy and communications.
“The science shows that reaching our sheer climate goals is practically impossible without [CCS],” Daniels said. “CCS is a mature, well-understood technology that is increasingly commercially competitive across the full value chain from capture to storage.”
The report highlights major industry developments, with the expansion of the 45Q tax credit in the Inflation Reduction Act at the top of the list. Daniels said the new law’s $85/ton credit for CCS and up to $180/ton for direct air capture (DAC) could increase deployment 13-fold in the U.S.
Denmark’s €5 billion investment in CCS has also signaled a growing market in Europe, with the Orca DAC plant in Iceland now sequestering about 4,000 tons of CO2 per year. The plant uses a process called mineralization, which turns the injected gas into stone in about two years.
CCS plants worldwide now number 30, with 164 projects at various stages in the development pipeline. | GCCSI
Climeworks, the company behind the plant, recently broke ground on an even larger direct air capture facility in Iceland, which could sequester up to 36,000 tons per year, according to the company.
China has also opened its first CCS plant, with the capacity to capture 1 million tons per year, which is being used for enhanced oil recovery (EOR), according to the report. A second plant, which will capture carbon from coal-fired generation, is under construction.
Despite such progress, the industry faces a challenge in winning over the sizeable number of CCS skeptics, said U.K. and U.S. energy officials speaking at the event. In the U.S. and elsewhere, environmental and other community groups have criticized the technology as a too-expensive strategy for extending fossil fuel generation.
“Not everyone supports carbon capture as the route to net zero,” said Alex Milward, director of carbon capture utilization and storage at the U.K. Department for Business, Energy and Industrial Strategy. “It’s important for us all to work together to bring everyone along on this journey as well as we can.
“There’s more we all need to do together on international standards and modularization and product standards and transport standards, and then we [need] to get the optimal balance between where world CO2 is emitted and where we can cost-effectively capture and store it,” Milward said.
“We need to get implementation right,” agreed DOE’s Crabtree. “There’s a lot of misunderstanding about what [CCS] technologies can and cannot do, but there are also real legitimate concerns about how these investments will benefit in real tangible ways communities, economically and environmentally. That’s something we really have to focus on going forward.”
Turning Point
A turning point for CCS, besides the IRA, was its recognition by organizations such as the U.N. Intergovernmental Panel on Climate Change and the International Energy Agency as critical to the 1.5-degree global climate goal.
In line with that institutional validation, a core driver for market growth is “the demand for greenhouse gas emission reductions in line with net-zero commitments from governments and businesses, together with rising expectations from civil society,” Turan said.
Other factors include the need to decarbonize “products that are critical to human economic development,” such as steel, cement and chemicals, she said.
Early development has been focused on EOR, the injection of CO2 to produce more oil from low-producing wells, which accounts for 21 of the 30 facilities currently in operation. Turan expects the project pipeline will be more focused on other forms of sequestration.
The U.S. currently leads the world both in operating CCS facilities and in projects in development, according to the GCCSI report, with the IRA and $12 billion for direct air capture hubs in the Infrastructure Investment and Jobs Act, focusing on development and investment.
DOE issued a notice of intent for the funding in May, and according to the agency website, an application opening date is expected by year-end.
In addition, the report notes other key policy advances, with the Pipeline and Hazardous Materials Administration releasing new guidelines on CO2 pipeline safety and the Bureau of Land Management issuing guidance on CO2 storage on public lands.
“One of the exciting things for us, it’s not just the scale of these resources [in the IRA and IIJA], it’s also for the first time, we’ve really expanded research and development to include large-scale commercial demonstration, and that’s a major policy change in the United States. It’s long overdue and needed to really ramp up deployment of carbon management technologies across the economy.”
Other key funding in the IIJA includes $2.5 billion for “the development of dedicated regional geologic storage sites” and $2.1 billion for “carbon dioxide transportation infrastructure finance,” Crabtree said. The two projects will work in tandem, he said, so that “we can finally get beyond this historic chicken-and-egg challenge where you develop a carbon capture project, but how do you get the transport done, who develops the storage site?”
The goal, he said, is to build out a CCS “ecosystem in an integrated way on a regional basis, importantly to reduce costs and ultimately so we can bring carbon management to climate scale.”
Speakers at NERC’s annual GridSecCon security conference on Wednesday urged their colleagues to get involved in the Electricity Information Sharing and Analysis Center’s (E-ISAC) biennial GridEx security exercise, with one panelist calling the event a “perfect opportunity” to test emergency operations plans in a highly realistic setting.
Like last year’s event, GridSecCon 2022 was held online because of lingering concerns over the COVID-19 pandemic. (See GridSecCon Panelists Share Cyber Supply Chain Fears.) NERC, the E-ISAC and ReliabilityFirst hosted this year’s conference.
The ERO holds GridEx every two years. Each exercise consists of two parts: a two-day distributed play in which participants across the country work a core scenario developed by the E-ISAC and customized by each organization, and an executive tabletop hosted for leadership of various organizations, including investor- and publicly owned utilities, government entities, and grid operators, as well as representatives from other industries.
Last year’s GridEx VI saw participation in the distributed play portion of the exercise decline for the first time since the event was first held in 2011, which organizers attributed partly to the pandemic and partly to changes in how participants were counted. (See NERC: GridEx Lessons Already In Use.) NERC confirmed earlier this year that planning is already underway for next year’s GridEx VII, which is scheduled for Nov. 14-15, 2023.
Clockwise from top left: Jesse Sythe, E-ISAC; Blake Stave, Xcel Energy; Doug McCracken, Eversource Energy; Adrienne Lotto, APPA. | NERC
This year’s GridSecCon featured two separate panels focused on the security exercise. The first focused on recommendations from GridEx VI, while the second dealt with preparations for GridEx VII and the threats that it will need to consider.
“One of the neat things about GridEx is its amazing flexibility,” Peter Grandgeorge, state national security and resilience programs adviser at Berkshire Hathaway Energy, said in the first session. “And this is part of why I think it’s so successful across the board, and it’s why we’re here today talking about it, because this exercise keeps building … both in the sheer amount of folks involved, but also in depth.”
Grandgeorge and his fellow panelist Lance LaBreck, CAISO’s business continuity manager, noted how the exercise had grown since their organizations began to participate. Grandgeorge reminisced about “sitting around a table [with] about 50 folks” the first time BHE participated in the distributed play in 2013, a number that had grown to 600 by GridEx VI.
LaBreck said one of the most satisfying elements of the evolution of GridEx over the years is its expansion to include stakeholders beyond the electricity industry itself, with input now welcomed from government bodies and other infrastructure sectors like natural gas and telecommunications. He said exercises like this are an opportunity to build relationships with these players so that a utility’s emergency personnel are not meeting them for the first time during a crisis.
“The key part I try to bring up again and again, focused specifically to the electricity subsector, is [that] we are all interconnected … what’s upstream and what’s downstream of us,” LaBreck said. “And if we don’t leverage this training opportunity … at every level we can within the organization, it’s a missed opportunity. There is no other place where you have the ability to bring in your incident command, your cyber and physical security components, [and] your operators to work together internally [and also] to interface with your state emergency management agency [and] your local county … to leverage that relationship.”
In the second panel, Jesse Sythe, the E-ISAC’s GridEx program manager, said the organization’s intent with the exercise is to foster a “train-like-you-fight, fight-like-you-train mentality.” Adrienne Lotto, senior vice president of grid security at the American Public Power Association, said utilities should take advantage of the training opportunity and not be afraid of exposing weaknesses in their defenses.
“I guarantee … you will find gaps and lessons learned. But that’s OK,” Lotto said. “It’s all part of the continuous process to improve, and I think there’s always value to be driven from the exercise.”
Clean energy and public consumer advocates questioned Wednesday whether MISO planners are sufficiently exploring alternatives to the projects transmission owners submit to staff.
Piqued by a batch of expedited substation projects in MISO South for the 2022 planning cycle, they asked for proof that the grid operator is identifying or studying alternative projects. They expressed hope during a Planning Advisory Committee that staff find larger regional projects that could satisfy several needs rather than blindly accepting TOs’ project plans. (See MISO’s 2022 Tx Planning Cycle Exceeds $4B.)
Several stakeholders said TOs don’t make enough project specifications public to allow meaningfully proposed project alternatives. “More detail needs to be given to stakeholders ahead of time,” Southern Renewable Energy Association Executive Director Simon Mahan said.
He suggested that MISO planners might also lack the capabilities to study project alternatives.
“As a stakeholder, I don’t know what to do,” Mahan said. “I think you all are doing the best you can … but $70 million is a lot to rush through. I don’t know if MISO has the tools to future-proof the system. I’m just worried how many more times this is going to happen in the future. I’m just really worried about this.”
This summer, Cleco applied to include a 230-kV and an 138-kV substation, each costing $15 million, for expedited treatment. Entergy requested approval to install two additional 230-kV breakers into an existing substation near the Louisiana-Texas border; to construct a 230-kV substation; and a $32.6 million, 115-kV substation in northern Mississippi. The utilities said the projects were necessary because of load growth in their territories.
MISO recommended all the projects for late inclusion in its 2022 Transmission Expansion Plan.
Clean Grid Alliance’s Natalie McIntire said her organization has raised the issue with MISO several times. She said she believes that Order 1000 obligates staff to offer and analyze project alternatives.
“Whenever we ask about this, MISO assures us it studies alternatives. But we don’t in the stakeholder process see alternatives. … This is an issue of costs for consumers,” McIntire said.
She said it seems that MISO “does a lot of hand waving” in only reassuring stakeholders that they study alternatives, but don’t back that up with evidence. The RTO is best positioned to examine alternatives with its “top-down” view of the system, McIntire said.
“We continue to make these comments, and I feel like it’s never quite resolved,” she said.
Jeanna Furnish, MISO’s director of expansion planning, said “there are situations in which” MISO comes up with alternative projects, with those alternatives sometimes presented in subregional planning meetings.
“So does every single project get an alternative? That’s probably not true,” she said.
Furnish said MISO will “think through” whether it has the tools to adequately study alternatives and how it might be more transparent in discussing the alternatives.
She also said grid operators stand to be affected by FERC’s notice of proposed rulemaking on more comprehensive transmission planning. Furnish appeared before the commission’s technical conference on transmission planning earlier in the month. She said then it isn’t feasible for grid operators to consider alternatives to every TO-proposed project. (See States Urge More Transparency on Tx Planning, Independent Monitors.)
Cleco Energy’s Chris Thibodeaux said the utility’s expedited projects will bring jobs to Louisiana and are requested by industrial customers who need transmission-level service.
“I’m not sure how the Environmental Sector really has a say in that,” he said.
Jeff Cook, with the Office of Consumer Advocate, said a public consideration of alternatives can help stakeholders more easily accept expensive projects.
LS Power’s Brenda Prokop added that an evaluation of alternatives could help determine whether the RTO could rely on larger projects to take care of various smaller needs.
Mahan agreed that MISO could help members figure out whether larger projects would save money and give stakeholders more confidence in the planning process.
The California Energy Commission approved a $31.3 million grant Wednesday for a long-duration storage project that will pair vanadium-flow and zinc hybrid cathode batteries with carport solar panels on tribal land in San Diego County.
The 60 MWh microgrid project is the first recipient of a grant under the state’s new Long-Duration Energy Storage Program (LDES), funded with $140 million in the state’s recently enacted 2022/23 budget.
Long-duration storage is a priority in California, where the grid is increasingly reliant on variable renewable generation, especially solar, requiring longer storage discharge times to compensate for cloudy weather and extended interruptions from equipment failure, forest fires and extreme heat.
Approximately 3,600 MW of four-hour lithium-ion batteries have been installed in the past three years, but those batteries have limits, Erik Stokes, deputy director of the CEC’s Energy Research and Development Division, said.
Invinity Systems makes vanadium flow batteries being used in the 60 MWh project in San Diego County. | Invinity
“Currently, we’re relying on one technology for our energy storage needs in lithium-ion,” Stokes said. “Lithium-ion is a great technology. It’s really enabled us to achieve a lot of our clean energy progress, but it’s not a silver bullet. There’s been a lot of well publicized concerns about supply chain and safety issues with lithium-ion technology.”
The batteries are vulnerable to overheating and fires, and worldwide competition for lithium is straining supply. So, the state is seeking non-lithium resources able to discharge energy to the grid for at least eight hours and up to 100 hours.
Priority for LDES is being given to technologies on the verge of commercialization or positioned for widespread deployment within the next five to 10 years.
The project components approved Wednesday fit that bill because they have a successful history of field demonstrations and have attracted significant private capital to scale up manufacturing, the CEC said.
The zinc batteries, manufactured by EOS Energy Enterprises, do not use rare-earth minerals such as lithium, reducing risk in the supply chain, and they can operate at much hotter and colder temperatures than lithium-ion batteries, the commission said. The vanadium flow batteries, made by Invinity Energy Systems, have proven safe and stable and can perform for 25 years or more, the CEC said.
The project will be installed at the Viejas Band of Kumeyaay Indians Reservation and casino near the town of Alpine, California.
More LDES projects are set to follow. The CEC said it expects to provide $50 million to $180 million in total funding for long-duration storage next year through LDES grants and its Electric Program Investment Charge (EPIC) funding, which supports earlier-stage demonstration projects.
CAISO began a stakeholder process Monday to explore the benefits of greater regional cooperation and a Western RTO, as California lawmakers had requested in Assembly Concurrent Resolution 188, passed in August.
ACR 188 asked CAISO to report to the legislature by February on recent studies of the “impacts of expanded regional cooperation on California” and to identify “key issues that will most effectively advance the state’s energy and environmental goals, including any available studies that reflect the impact of regionalization on transmission costs and reliability for California ratepayers.” (See California Legislature Asks CAISO to Report on Regionalization.)
Despite its limited goals, many saw the resolution as potentially restarting discussion of a Western RTO involving CAISO. Several prior attempts from 2016-18 failed because lawmakers were unwilling to expand CAISO’s one-state governance to other states.
Monday’s meeting was a brief introductory session that laid out CAISO’s plans to produce the report in the next four months in partnership with the National Renewable Energy Laboratory (NREL), which it commissioned to author the study. NREL is expected to draft the report by November, followed by stakeholder comments and calls in December.
Monday’s meeting materials cited 30 relevant studies since 2011 as a starting point. They included a study conducted by CAISO in 2016 under Senate Bill 350, which found that a “multi-state regional electric market and grid overseen by the ISO would provide significant environmental and economic benefits to California and the West,” the ISO said.
Another study published last year found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, financed by the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
A subsequent study released in July by Advanced Energy Economy looked at regional economic effects. It concluded an 11-state Western RTO could generate roughly $19 billion to $79 billion in additional gross regional product by 2030 and could help create 159,000 to 657,000 permanent jobs. (See Study Tallies Economy-wide Benefits of Western RTO.)
CAISO and NREL asked participants Monday to send comments listing additional studies they should consider and those they should not consider, both with supporting comments.
SPP told stakeholders last week that it has chosen a hybrid approach to improve its transmission- and congestion-hedging markets, focusing first on equitably allocating congestion rights instruments and then increasing the pool of awards available.
The proposal marks a change in direction from the initial focus on counterflow optimization. Stakeholders were unable to coalesce around the market mechanism despite three years of effort.
The SPP Board of Directors in April directed staff to survey members, the regulatory stakeholder groups and the RTO’s Market Monitoring Unit (MMU), gather feedback, and bring a final recommendation to the board’s October meeting. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
Staff will bring a proposal to the board later this month, but they will also ask that a vote be delayed until the directors meet again in January. That will give the board and state regulators an opportunity to provide the policy direction that will go into developing tariff changes. It will also give staff more time to build stakeholder support for the proposal and gather additional feedback.
“I know the board values input from the members, but we feel that this is taking a look at the entire picture and not just focusing on one thing,” COO Lanny Nickell told the Markets and Operations Policy Committee Oct. 10. “We feel pretty confident and pretty good on the direction where we’re going.”
Nickell complimented staff for their recent work “to get some movement on resolving the concerns and issues around the congestion-hedging process.” Congestion-hedging supervisor Micha Bailey said staff talked with stakeholders who provided input to gain a deeper understanding of their concerns.
“We kept hearing some of the same themes … Fair, transparent, equitable, needs to provide a hedge. And as we looked at those and as we were hearing the same common themes, we wondered, ‘What can staff propose?’” Bailey said. “What can we propose that’s going to help SPP today and also in the future, recognizing that generation is changing.”
Bailey said “hybrid” was the new buzzword, replacing counterflow optimization. That market mechanism, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency. (See SPP Continues its Counterflow Optimization Work.)
The hybrid proposal will increase the number of hedges available as the Holistic Integrated Tariff Team intended when it approved a package of 21 improvements to the SPP grid in 2019, Bailey said.
“We’re going to increase equity and fairness within the congestion-hedging process,” Bailey said. “We’re focusing on bringing those who are getting nothing up right. When you introduce equity, some entities [receiving hedges] … have to give up some to allow other entities to come in. We need to focus on a short-term solution that that will help entities that are getting nothing get something.”
He compared the current process to a buffet line, where excess auction revenue is distributed to participants, who already have hedges, in what amounts to a load-ratio share.
“You’re double dipping … at the end of the year, you’re getting something on top of what you want,” Bailey said. “In the buffet line analogy, which we’ve heard time and time again, you’re going two to three times in the buffet line. Those sitting with empty plates at the end of the year, they’re the ones who should be getting the ARR excess revenue.”
Staff’s recommendations include:
Resetting long-term congestion rights (LTCR) awards every 10 years to give market participants more opportunities to gain the hedges.
Modifying the LTCR’s second round of nomination capacity from 100% to a more equitable incremental percentage up 100%.
Changing the auction revenue rights (ARRs) process’ annual first round nomination capacity calculation to more fairly allocate ARRs.
Revising the ARRs’ first round nomination capacity from 50% to an incremental percentage up to 50%.
Distributing excess auction revenues.
SPP also plans to update its load and generator modeling to better align them with transmission service that is studied, review the planning process’ firm transmission assumptions, and provide further stakeholder education.
“We need to involve the upstream applications from congestion hedging because congestion hedging starts with firm transmission service,” Bailey said.
While stakeholders generally expressed support for the proposal, American Electric Power’s Richard Ross, who chairs the Market Working Group that put a lot of time and effort into resolving the issue, offered a counterpoint.
“I don’t hold out much hope for the stakeholders suddenly going, ‘Oh yeah. This is great.’ But, you know, we’ll see,” he said, offering his own praise for staff’s work.
MMU Executive Director Keith Collins said the hybrid proposal addresses the monitor’s concerns and is a good package.
“There’s no silver bullet in this process. The approach that Micha is outlining is like a scattershot approach … but it applies that basic set of points that Micha raised of how we improve the equity so that we can improve affordability,” Collins said. “We reduce the effects of the buffet line. You want people to go through the line and if you can do that at least a couple of times, you’ll allow folks to be able to get more if you’re at the back of the line.”
Members Address Resource Adequacy
MOPC approved five revision requests (RRs) related to resource adequacy and a planning reserve requirement (PRM) that the board and state regulators recently raised from 12% to 15% for the summer season, effective next year. (See SPP Board, Regulators Side with Staff over Reserve Margin.)
The committee had to first reconcile competing versions of a revision request (RR515) that lays out the process by which load-responsible entities (LREs) may qualify for and receive exemptions of the deficiency payments assessed to those that have not met the tariff’s resource adequacy requirement, if they have met the applicable criteria.
Members eventually sided with the version brought forward by the Supply Adequacy Working Group (SAWG), which allows a three-year exemption from a deficiency payment and adds triggers if the PRM was increased the year before. To qualify, LRES must demonstrate they had adequate capacity to meet the resource adequacy requirement based on the prior effective PRM and show enough capacity to meet the upcoming season’s forecasted load and a prior effective PRM.
Under SAWG’s version, LREs meeting the PRM, must demonstrate that as of April 5 of the current year, sufficient capacity for purchase has not been identified on bulletin board or demonstrate a contracted obligation to purchase capacity from a generator/developer or demonstrate it has a pending request for interim, surplus or replacement generator interconnection service that is of sufficient size.
The Cost Allocation Working Group, comprised of regulatory staff and which reports to the Regional State Committee, offered the same language, with the exception of using “and” instead of “or” before “demonstrate it has a pending request …”
The motion to endorse RR515 cleared the two-thirds threshold at 72.5%.
Casey Cathey, SPP’s director of system planning, said staff has already begun developing the principles for deficiency payment exemptions.
“[The exemption] needs to be realistic and must support reliability improvements,” he said. “We need to ensure the policy meets the proper incentive for the reserve margin. When it’s increased, we need to make sure we’re still sending the right signal for reliability purposes. We want to create a positive policy that FERC would agree to and approve.”
A bulletin board for informational purposes only will be developed so LREs and generation owners can view and post requests to buy or offers to sell power. All information on the board will be confidential, with only the MMU having the rights to review the data.
SPP bases its reserve margin requirement on a probabilistic loss-of-load expectation (LOLE) study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year).
Stakeholders also approved RR508, which allows LREs to use deliverable capacity to meet their winter season obligation as well. SPP said with more LREs seeing increased loads in the winter season and some becoming winter peaking, it became apparent that the LREs should be able to use the same method to meet their winter obligations.
MOPC also endorsed three other RRs:
RR513: Removes barriers to requesting surplus interconnection service by permitting expansion of existing substations to a location near enough to be considered part of the existing substation. Equipment additions required at the interconnection substation classified as network upgrades would not invalidate the request and would further permit added or modified “system protection equipment” at a remote substation.
RR516: Implements the planning reserve margin’s increase from 12% to 15%.
RR517: Creates a business practice documenting SPP’s consideration of a long-term service reservation as evidence that interim interconnection service or interconnection service subject to limited operations associated with a long-term service reservation causes no adverse thermal or voltage impacts to the transmission system. It also documents that the generating facility can continue to operate, provided there are no adverse short-circuit or stability impacts.
RRs 508 and 513 passed together unanimously and RR517 passed with 93% approval. RR516 barely passed at 67.9% approval, although it simply adds the 15% PRM to the tariff. AEP opposed the proposal during the SAWG vote, saying imposing an immediate 25% increase to the LRE reserve margin, given SPP’s generator interconnection queue backlog and other challenges faced by LREs, “sets a dangerous precedent and represent a poor implementation of capacity rules changes.”
Members Endorse 2022 ITP
MOPC approved a pair of working groups’ recommendation to endorse the 2022 Integrated Transmission Plan and its assessment report. The 2022 assessment report documented the 2022 plan as being complete.
The Economic Studies (ESWG) and Transmission (TWG) working groups said the reliability-only portfolio is smaller than previous ITP plans, thanks to the $3.4 billion in new transmission projects being placed in service between 2015 and 2019. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.
During the re-baselining process, staff worked with the ESWG and TWG on a comprehensive review of the ITP’s governing documents to find efficiencies and improvements to help meet future assessment deadlines. The work resulted in four to six weeks of time savings.
SPP staff is currently juggling three other planning studies: the 20-year long-term assessment and the 2022 and 2024 ITPs. The 20-year assessment is the only study that is still behind, and that is only by one month. Staff said they will have to reduce scope to meet its April 2023 deadline.
Cathey complimented the ESWG for developing 2024 ITP futures that reflect industry trends in arriving at realistic renewable energy projections.
The stakeholder group’s base case foresees solar capacity growing from 7.1 GW to 14 GW between years five and 10 and wind increasing from 43.8 GW to 49.9 GW. Its emerging technologies future has greater projects of 11 GW to 22 GW and 48.2 GW to 54.9 GW, respectively. The ESWG expects storage to grow to as much as 8.8 GW in 10 years, based on a percentage of solar capacity.
“For a number of ITPs, we feel like we’ve gotten better at hitting the future. That said, the last few cycles, we’ve been hitting 10-year numbers within two years,” Cathey said. “We believe, especially given the Inflation Reduction Act and everything that’s going on in the industry, that this is probably the first one that really is taking a leap. We’re kind of all on board that this is a better prediction of what we’re actually going to see in the next five to 10 years.”
The ESWG evaluated more than 35 projections, using input from SPP’s GI queue, the U.S. Energy Information Administration’s annual energy outlook, and extrapolated 2022 ITP input from its members and the Market Monitoring Unit to arrive at its numbers.
The group plans to bring the final 2024 ITP scope document to MOPC in January for its approval.
Cathey also said the long-term assessment, due in the spring, should inform more of the assumptions that will be made in the 2025 ITP and in the consolidated planning process.
Increasing BTM, DR Resources’ Visibility
MOPC approved a pair of Operating Reliability Working Group (ORWG) revision requests designed to give SPP’s balancing authority visibility into controllable, dispatchable, non-registered behind-the-meter (BTM) and demand response data, referred to as “cats and dogs” by some stakeholders.
The ORWG said RR520 improves the BA’s ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected load-responsible entities (LREs). Under RR512, LREs will submit used and unused capacity on BTM resources that have qualified as accredited capacity that can be used to respond to emergency conditions.
The first change passed with 84.4% approval and 10 abstentions. RR512 passed unanimously, also with 10 abstentions.
The RTO said its tariff exempts certain generations of small size from full market registration. Because some entities don’t have the proper technology to meet market registration data requirements, SPP will allow data submission through its managed file transfer system but plans to also use its application programming interface before next February’s implementation deadline.
“[Being] registered is key, whether through the market or modeled in [the energy management system], but it is not a requirement for all units that are BTM,” SPP’s Yasser Bahbaz, director of markets development, told stakeholders. “If these resources are not registered, then we are not requiring or receiving telemetered information … Your BTM units may be modeled in the reliability model but not registered. In this case, we still need to know about the info requested in these RRs.
“Knowing that capacity that’s available is really important to SPP,” he said.
“We need SPP’s real-time visibility into what’s out there,” Nebraska Public Power District’s Ron Gunderson, the ORWG’s acting chair, said.
The changes are a result of the 2021 winter storm, which required SPP to rely on energy transfers from MISO to meet demand.
The MMU registered several concerns with the changes, saying BTM generation and demand response are not adequate for the grid operator to objectively apply its performance-based accreditation but would likely represent a small reliability risk. It disagreed with the grid operator’s legal determination that adding the data requirements to the operating criteria results in enforceability and recommended better definition of various terms.
GI Backlog Down to 405 Requests
Staff told MOPC that they have reduced the number of active requests in the GI queue down to 405 as of September, a 37.8% reduction since their backlog mitigation process began in January with 651 requests. SPP has eliminated 76 active requests since its last update to members in April. (See “Staff Reducing Interconnection Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022).
“We’re happy with the progress we’re making,” the RTO’s Juliano Freitas said.
Renewables dominate SPP’s current generation-interconnection queue. | SPP
More than 200 requests have been withdrawn, leaving 222 in progress and another 183 waiting to be processed. The grid operator has executed 33 GI agreements, with four more pending.
But SPP is still in a hole, though not as deep. Staff said they have received and validated another 82 GI requests totaling 17.7 GW of capacity since April. That leaves the current queue at 487 requests totaling almost 96 GW of capacity. Solar requests (210, 45.1 GW) account for the bulk of the new requests.
Freitas said the grid operator doesn’t plan to close the current cluster until its finishes the backlog mitigation plan, still on schedule by the end of 2024. He said SPP is forecasting that it could install more than 50 GW of capacity by 2028.
“We have to keep our eyes on [the current cluster], because we don’t think it’s feasible to study a cluster with 100 megawatts in it,” he said.
NASEB Gas-electric Forum Convened
Charles Yeung, SPP’s executive director of interregional affairs, encouraged members to engage themselves in a gas-electric harmonization forum recently begun by the North American Energy Standards Board.
The forum was convened in August at the request of FERC and NERC. The organizations want NAESB to address a recommendation from their 2021 joint report on the year’s winter storm that calls for improving the reliability of the natural gas infrastructure system in support of the bulk power system. The recommendation focuses on gas-electric information sharing regarding system performance, gas infrastructure reliability during cold weather, and generators’ ability to obtain fuel during extreme cold weather.
“Obviously, SPP alone cannot deal with those issues,” Yeung said, noting many of the items date back to a similar cold-weather event in 2011. “Some of these issues have been brought up before, but the perception of them has changed with the disaster in Texas.”
The forum is tasked with delivering a report that includes concrete actions to increase gas infrastructure reliability, detailed plans to implement the recommendations, and the entities responsible for deploying the changes. The group met for the first time in August and will continue to convene monthly into early 2023.
Among those involved in the forum are former FERC Chair Pat Wood and Department of Energy veterans Susan Tierney and Robert Gee, who, like Wood, also chaired the Texas utility commission.
MOPC Chair Buffington ‘Honored’
AEP’s Ross, who hands out to staff and stakeholders eponymous “Gold Star” awards, complete with certificates of authenticity, unveiled a new “Richard Ross Boot Award” during the meeting.
Ross, jokingly saying he was “booted off” a recent stakeholder conversation, promised to send the first Boot Award to Evergy’s Denise Buffington, who is cycling off the committee as its chair, for her leadership the past two years.
Buffington warned members her term does not expire until Dec. 31. ITC Holdings’ Alan Myers, MOPC’s vice chair, will succeed Buffington next year.
Gold Star awards are also due for SPP’s Bailey, Drew Gilvray and Nikki Roberts in recognition of their work to improve the congestion-hedging process, Ross said. He will bring the awards and certificates to an upcoming meeting.
12 Revision Requests Pass
MOPC unanimously approved a consent agenda with 12 RRs, although nine members abstained:
RR492: Provides clarity on the risks, timing and treatment of generator-interconnection requests’ financial securities refunds, cost allocation comparisons and withdrawn opportunities. It also adds a definition to distinguish “equally-queued” versus “lower-queued” priority of GI requests.
RR497: Adds further definition to the Project Cost Working Group’s oversight for applicable projects that are funded through direct assignment of cost.
RR498: Allows the ESWG to determine whether SPP’s additional incremental generation capacity recommendations should be included in the ITP’s economic model.
RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
RR500: Clarifies and documents a more efficient and detailed process for submitting late data submittals in the ITP, including a new submittal form to help staff assess impacts.
RR503: Modifies language in the market mitigation sections of the protocols and tariff by removing references to dispatch and “settlement purposes” and replacing them with clarifying language to specify the solution will be used for determining locational margin prices and marginal clearing prices (MCPs).
RR504: Addresses potential inefficiencies in the regulation mileage compensation design by revising the mileage factor calculation and setting the mileage MCP to the resource projected to provide the last mile based on the mileage factor.
RR507: Updates the list of transmission services grandfathered agreements.
RR510: Revises SPP’s competitive transmission process with changes to the request for proposal’s scoring methodology and deposits and cost calculations sections and adds an additional table to the confidential information treatment section.
RR511: Changes the tariff by updating the IEP public report deadline from 14 to 21 calendar days.
RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to be $1,500.
RR518: Corrects a calculation error in the protocols related to when regulation is not cleared in the real-time balancing market.
