NYISO’s Operating Committee on Jan. 18 approved the final locational minimum installed capacity requirements (LCRs) for the 2024/25 capability year.
The LCRs represent the minimum amount of capacity that New York load-serving entities must maintain within each of three downstate “localities” with transmission constraints. They are expressed as the percentage of the peak load forecast: 81.7% for New York City (Zone J), 105.3% for the rest of Long Island (Zone K) and 81% for the Lower Hudson Valley, including the city (zones G to J).
As detailed by the ISO’s LCR Study, the figures were calculated using the 22% installed reserve margin (IRM) approved by the New York State Reliability Council late last year, and transmission security limits (TSL) floors, which, respectively, establish the required reserve capacity and minimum transmission limits necessary for reliable operations.
Because the figures had already been presented to stakeholders, the OC’s vote proceeded without significant discussion. (See “Final LCR Results,” NYISO Finds No Need for New Capacity Zones.)
NYISO will now publish the final LCR values online, along with the 2024/25 locality bulk power transmission capability report, which documents the transmission capability inputs required to establish the TSLs for each locality.
December Operations
Aaron Markham, NYISO vice president of operations, told the OC that “December was quite a mild month, with no real cold snaps,” which resulted in “a pretty low peak load” of 21,001 MW and a minimum load of 13,136 MW.
In his December operations presentation, Markham noted that New York had added 215 MW of land-based wind and 20 MW of front-of-the-meter solar resources since the previous month’s report. (See NYCA Surpasses 5,000 MW of Installed BTM Solar.)
Markham last mentioned that New York is “in the midst of its first cold snap of 2024.” This led to a peak load Jan. 17 of 22,754 MW, which was about 94% of the baseline forecast of 24,200 MW for the winter season. However, he added that “transmission and generator performance has been very good” during this period.
OLYMPIA, Wash. — A Washington lawmaker has introduced a bill to authorize a study to gauge the ecological impacts of offshore wind projects along the state’s coastline.
House Bill 2341 by Rep. Larry Springer (D) calls on the University of Washington School of Oceanography to study how the installation of OSW turbines would affect the fish, invertebrates, mammals and plant life that constitute the marine ecosystem near the coast. The report would be due to the governor’s office and Legislature by June 30, 2026.
West Coast OSW development efforts currently focus on the waters off California and Oregon. And while there are no active government efforts targeting the Pacific Ocean off Washington’s coast, the U.S. Bureau of Ocean Energy Management has received two unsolicited proposals for the area.
In October, Gov. Jay Inslee (D) announced the beginning of a public-private partnership to develop an OSW industry in Washington, even to support out-of-state projects. The effort will have state agencies, ports, manufacturers and business associations meet to identify supply chain issues and map out approaches and goals for such a venture. (See Wash. Looks to Become Supplier to West Coast OSW Efforts.)
“The issue for me is that we simply get it right,” Springer said during a Jan. 19 hearing on his bill before the Washington House Agriculture and Natural Resources Committee.
The proposed study would look at whether offshore turbines attract or repel fish and marine life. It would also study the effects of construction and operations on water cloudiness, noisiness, vibrations, thermal patterns and electromagnetic fields.
It also would examine how turbines affect upwelling, which occurs when winds blow parallel to a coastline. The effect pushes surface waters offshore and brings up colder water from the deep to replace the surface water that was pushed away. The deeper water is rich in nutrients that encourage the growth of plants such as phytoplankton, a key part of the ocean’s food chain. Fish concentrate where upwelling occurs.
Committee member Rep. Debra Lekanoff (D) wondered how turbines would interact with oil tankers along the coast.
Four people testified in favor of Springer’s bill at the hearing. No one opposed. It.
“Whales do whale stuff. Crabs do crab stuff. The tuna — it just all explores. … Does it matter if we develop closer to the shore or farther from the shore?” former Democratic state Rep. Brian Blake said.
“We need science so we can develop a no-harm solution,” said Dale Beasley, speaking on behalf of the Coalition of Coastal Fisheries and the Columbia River Crab Fisherman’s Association.
Eric ffitch, executive director of the Washington Public Ports Association, also spoke in support of the bill.
Stephanie Harrington, associate dean for administration for the University of Washington’s College of the Environment, which contains the oceanography school, said her department is willing and able to tackle the study.
WASHINGTON — Electric vehicles dominate the lower level of the Washington Auto Show, being held this week at the Walter E. Washington Convention Center, with Volvo showing off its EX90 SUV, Polestar displaying its $97,000 model 3 (zero to 60 in 4.6 seconds) and Hyundai offering test drives of its IONIQ 5 on an indoor track.
But those carmakers are chasing an illusion, U.S. Reps. Mike Kelly (R-Pa.) and Roger Williams (R-Texas) said during a panel discussion at the auto show’s Public Policy Day on Jan. 18.
“We see a situation where the manufacturer and the government are trying to shove these EV vehicles down people’s throats. They don’t want it,” said Williams, whose daughter now runs the dealership started by his father in 1939. “It’s a phony economy.”
Kelly agreed. “I don’t need people with more degrees than a thermometer to tell me what my market is. I’m there every day with them,” said Kelly, owner of Mike Kelly Automotive in Butler, Pa. “We should never force a market on anybody. If it’s market-ready, you don’t need to subsidize it.”
Williams and Kelly sparred with Reps. Debbie Dingell (D-Mich.) and Marcy Kaptur (D-Ohio) during the panel, with the Democrats defending the Biden administration’s goal of making EVs 50% of new car sales by 2030. In later appearances, White House National Climate Adviser Ali Zaidi and senior officials from the departments of Energy and Transportation also defended the administration’s policies.
“We are competing in the global marketplace. China is subsidizing their products every single day. And we cannot let them win,” Dingell insisted. “We have to invest in R&D. We are competing with other countries where the government makes the investment.”
EV Subsidies, Performance Criticized
Williams said EVs should be judged on their own merits, without subsidies.
“I’m not against EV vehicles, but I’m for competition. And we don’t have that right now,” he said.
Williams criticized EVs’ cold-weather performance and said they are particularly ill suited for a state as large as Texas. “When you go from Weatherford, Texas, to Midland, Texas, and you’re pulling a two-horse trailer or pulling a jet ski and a boat, [with] the EV vehicle you’re never going to make it. You’ll have a gasoline[-powered] truck come and get you and pull you back where you started from.
“I can live with a hybrid,” he added. “It’s kind of a real thing; we sell many in Texas. But … you can’t compare to an EV vehicle, because that’s a product that is not going to exist in a few years.”
Affordability
Kelly said the government’s EV push is evidence that Washington is out of touch with Main Street Americans. He recalled a customer visiting his dealership seeking to trade in a Chevy Volt. “It needed a new battery. The car was worth $11,000. The replacement battery was $10,000,” he said.
Deputy Energy Secretary David Turk acknowledged, “The affordability story is something that’s not breaking through as much.”
But he said federal research and development spending has helped reduce the cost of batteries by 90%, with a further 42% reduction expected by 2030.
“It’s incredibly exciting to see the [Chevrolet] Bolt under $20,000 [after the $7,500 federal rebate],” he said. “It’s incredibly exciting to see a variety of new models that are very cost-competitive, especially when you factor in the fueling; the fact that it only costs you $15 [to charge a battery] versus $46 [for a tank of gas].”
No Role for Mass Transit?
The panelists also clashed over the role of mass transit and how the U.S. compares with Europe on EV penetration and mass transit.
“This country, what made it great to begin with was our ability to go from point A to point B, and to get there by ourselves with just private transportation,” Kelly said. “Why the hell would we follow anybody from Europe and the path that they’re on when they rely on us for their very existence?”
“I don’t want to drive everywhere,” Kaptur responded. “I want … to have transportation options. We are very behind as a country in terms of road transportation, truck transportation and rail transportation. … We can’t live in 1950. We have to [prepare for] 2050. … We need a transportation revolution.”
Dingell said it’s the government’s role to lead the way on safety and environmental improvements.
“[Car] companies didn’t want CAFE [Corporate Average Fuel Economy] standards. Every consumer wants a more fuel-efficient car. … We didn’t want emission standards, and now everybody wants a cleaner environment. We didn’t want to wear safety belts; they’re saving lives. So sometimes when you’re doing what’s right, you’ve got to help educate.”
Charger Rollout, Reliability
The federal government’s charger buildout and reliability problems with existing chargers provided another flashpoint.
“I can tell you what a [public charging] station will look like. It’ll have graffiti all over it after a week and won’t be working. It will be broken,” Williams said.
Zaidi and Gabe Klein, executive director of the Joint Office of Energy and Transportation, said the U.S. has increased the number of public chargers to almost 170,000 from 73,000 in 2019. At the current installation pace, Zaidi said, the U.S. could reach its 2030 goal of 500,000 chargers three or four years early.
“We’re starting to see some improvement in the J.D. Power [reliability] numbers,” Turk said. “Just a couple of percent improvement over the last few months.”
“I feel like this coming year, we’re going to see a dramatic increase … in charging, reliability and availability,” said Deputy Transportation Secretary Polly Trottenberg, who joined Klein and Turk on a panel after the House members.
The Department of Transportation has created more than 40 new programs and awarded money to more than 40,000 projects over the last two years, Trottenberg said. “2024 is the year of project delivery,” she said. “Now our goal — and the EV charging projects are in that bucket — we have to make sure we get those projects up and running.”
Industrial Policy and the ‘Chicken-and-egg’ Dilemma
Turk defended federal subsidies as a response to the “chicken-and-egg” dilemma.
“In order to get the cost down, you need to get the scale. In order to get the scale, you need to bring the cost down. So what we’ve seen in country after country that’s made success in EV transitions is you’ve got to have some … intentional investment and do it in a very targeted way to get to scale that then brings the cost down.”
Zaidi said funding from the Inflation Reduction Act, Infrastructure Investment and Jobs Act and CHIPS and Science Act of 2022 has used billions in private investment, including more than 40 factories with a combined capacity of 1 million chargers a year. “So that’s the transformational scale I think that we have unleashed,” he said. “And this isn’t some sort of pie-in-the-sky concept. We’re seeing steel go in the ground.”
“The future of automotives is electric plug-in hybrid, battery electric, hydrogen electric,” Zaidi continued. “The president’s policies have made the United States the [No. 1] destination for private investment to write the next chapter of automotive history here with our workers.”
Turk said federal funding has used $157 billion of private investment for EVs and batteries, with 340 new or expanded facilities producing 136,000 direct jobs. “That’s a remarkable amount of funding, even in an economy as big as our economy.”
“I grew up in a steel mill community in which the jobs just went away,” Turk continued. “If you want to … just sit there and watch all those jobs go to China, that’s one approach. The other approach is you use the tax incentives, you use the grants, you use the loans, you have an industrial strategy and you play offense. And that’s what we’re doing right now.”
Joseph Pittel, vice president of legal and public affairs for Samsung SDI, said tax credits from the IRA were “a critical component” of his company’s decision to invest $9 billion in the U.S., including two battery factories in Kokomo, Ind., and an expanded battery factory in Auburn Hills, Mich.
“That’s money we put on the table that would not be on the table, but for the policy,” he said during a panel on supply chain issues.
AM Radio
Toward the end of the House members’ discussion, Dingell offered the Republicans “something every one of us agrees on. And this is AM radio. … I want it in my car.”
The cowboy boot-wearing Williams agreed. “It’s the only one that plays my kind of music,” he said.
The Treasury Department and the IRS on Jan. 19 released guidance on tax incentives from the Inflation Reduction Act meant to offset the cost of installing electric vehicle charging stations and other alternative refueling stations.
The IRA “has unleashed an investment and manufacturing boom in the United States unlike any we’ve seen in decades, with companies from around the world choosing to do business in America and electric vehicle sales surpassing 1 million for the first time in 2023,” Deputy Treasury Secretary Wally Adeyemo said in prepared remarks. “Additional clarity around the law’s incentive to build new charging infrastructure in communities that need it most will help drive continued progress in 2024.”
The Alternative Fuel Vehicle Refueling Property Credit offsets 30% of the cost of a qualified alternative refueling property placed into service by the taxpayer; both individuals and businesses are eligible. The credit caps out at $1,000 for personal property and $100,000 for business property.
Taxpayers can also claim the credit through “elective pay,” meaning that governments and other tax-exempt organizations making investments in infrastructure can benefit.
The credit was expanded, but the IRA also limited it to either low-income census tracts or those that are not in urban areas.
Treasury’s notice announced an intent to propose regulations to define eligible census credits, with low-income tracts following the definition it proposed for the new markets tax credit and nonurban tracts, where at least 10% of the census blocks are outside of urban areas. The Department of Energy released a mapping tool to help taxpayers find out if their census tracts are eligible.
DOE also made two major funding announcements for clean cars last week: $131 million for the battery supply chain and innovation in plug-in cars and $46 million to improve charger reliability and for workforce development.
The biggest chunk of the $131 million is going to the United States Advanced Battery Consortium of Southfield, Mich., which is getting $60 million for advanced research and development. The research will be aimed at enhanced performance and using more common, domestic materials for batteries.
The other $71 million is being spread across 27 projects aimed at lowering battery costs, improving public transportation, increasing range and advancing EV charging systems.
DOE, the Department of Transportation and the Joint Office of Energy and Transportation are putting up the $46 million, which is going to be split by 30 projects in 16 states and D.C. The projects are meant to improve chargers, support equitable access to clean transportation and grow the clean energy workforce.
The projects support clean transit and school bus deployment, enhance charger resilience to hurricanes and wildfires, and accelerate workforce development through pre-apprenticeship programs.
DOT and DOE also announced $150 million to 24 grant recipients to upgrade almost 4,500 public charging stations, which comes from the Infrastructure Investment and Jobs Act.
The NYISO Business Issues Committee on Jan. 17 voted to recommend that the Management Committee approve proposedtariff revisions that would provide all fast-start resources with their physical schedules for the day-ahead market (DAM) to avoid scheduling them below their minimum generation levels.
The changes stem from FERC orders requiring NYISO to modify how it reflects and prices fast-start resources in its energy markets for more accurate representation of their contributions. (See FERC Orders Fast-start Rules for PJM, NYISO.) Although NYISO implemented the required changes, it realized that they inadvertently extended DAM eligibility to some units that are now receiving ideal schedules below their minimum generation level, potentially causing operational inefficiencies or market imbalances. (See “Enhanced Fast-Start Pricing,” NYISO OKs Changes on Hybrid, Fast Start Resources, TCCs.)
In the DAM, the “ideal schedule” refers to a planned dispatch based on model or system predictions, whereas the physical schedule represents units’ actual operational outputs, reflecting real-time electricity production.
Andres Flores, NYISO market design specialist, explained to the BIC that fast-start resources are divided into fixed-block and non-fixed-block units. Fixed-block units currently receive their physical schedules, but non-fixed block units are given their ideal schedule, which allows a unit’s minimum operating limit to be relaxed to zero.
This led to a problem where some non-fixed-block units in the DAM are given ideal schedules that may result in them being scheduled below their minimum generation level. Allowing these units to receive their physical schedule in the DAM would ensure their minimum generation levels are respected.
In response to questions, NYISO said that the proposed changes would not affect the FERC-required pricing logic adjustments already in place, nor would they require major software updates.
Assuming approval from the MC, the revisions are expected to be filed with FERC in March.
December Market Operations
Nicole Bouchez, NYISO’s senior principal economist, presented the December market operations report to the BIC, highlighting how the month’s average locational-based marginal price (LBMP) was $33.67/MWh, lower than November’s $34.90/MWh and significantly below December 2022’s $110.17/MWh. (See “November Market Operations,” NYISO BIC Stakeholders OK Modeling, Market Design.)
Bouchez also noted that December’s natural gas prices also decreased, falling from $2.21/MMBtu in November to $2.11/MMBtu. That also marked an 83.7% year-over-year decrease in natural gas prices.
She attributed the declines to the significant drop in natural gas prices, adding how this is “not surprising, given how warm our December was.”
Backers of an effort to create the framework for an independent Western RTO know how much money they’ll need to get things off the ground this year. Now they’re seeking funders to help foot the bills.
“We have a budget estimate of about $570,000 to get us through the next several months,” Jim Shetler, general manager of the Balancing Authority of Northern California, said during a Jan. 19 virtual meeting of the West-Wide Governance Pathways Initiative (WWGPI).
Shetler is co-chair of the initiative’s Priority Admin Work Group, part of the Launch Committee tasked with establishing the entity.
Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, said donations will help cover costs for the legal analysis the group will perform over the next few weeks, project management and the creation of a nominating committee to select the entity’s board of directors.
Staks encouraged meeting participants to contact their Pathways Initiative sector representative to arrange donations and said she was “feeling very positive” about the diverse set of commitments the group has received so far.
“I know for us an area of information that’s important is the disclosure of funding and who is funding — and the amounts,” Puget Sound Energy’s Jessica Zahnow said. “I really appreciate what you shared today about the bridge funding for the $570,000, and it sounds like that’s expected to kind of bridge for a period of months. But disclosures around that [are] really helpful as we see who’s engaged.”
Staks also told stakeholders the Pathways Initiative on Jan. 18 submitted its application to the Department of Energy to obtain $400,000 in annual funding over the next two years through an agency Funding Opportunity Announcement.
“This was the full application for the stakeholder engagement framework project proposed in the concept paper last fall,” Staks told RTO Insider in an email. (See Western RTO Group Seeking $800K in DOE Funding.)
That paper explained the need for the grants and described how they would be used, including to support “leadership, staffing, virtual meetings and administrative support”; facilitate four in-person meetings per year; and provide funding for 50 people to attend those quarterly gatherings.
Speaking for the Launch Committee’s Functions and Scope Work Group, Evelyn Kahl, director of policy for Cal-CCA, told meeting participants that, after reviewing 16 law firms, the committee selected Perkins Coie to perform legal analysis for the effort.
The firm will first tackle what changes to California law would be needed to shift parts of CAISO’s governance to either the Western Energy Imbalance Market or a new regional organization. That analysis will factor in the range of Pathways Initiative governance options the committee shared with stakeholders at its meeting last month. (See Western RTO Initiative Outlines Governance Options.)
“Central” to the analysis, Kahl said, is California Public Utilities Commission Code Section 345.5 and state Corporations Code 5210, which oblige CAISO to “manage” the state’s electricity market.
“We’ll be assessing what ‘management’ means under these statutes, and in approaching the question, we’ll be looking at various aspects of governance, like the level of authority that’s granted to the WEIM, or regional organization, and whether it’s joint, primary or sole jurisdiction relative to the CAISO,” Kahl said.
“There’s a general sense that there may be changes that we can make without a change in California law to move the needle toward independent governance, but that somewhere along the spectrum, we’re going to be required to make a change to California law. So, we’re trying to figure out where is that and what kind of changes will be required,” she said.
Staks told RTO Insider the committee hopes to complete the legal analysis within the next couple of months.
“The analysis will help the Launch Committee identify the preferred structure, functions and scope of the new regional organization, including the legislative and legal steps and timing necessary to get there,” she said.
Asked whether the committee hopes to finish in time to influence the current California legislative session, Staks said the group “does not engage in any lobbying efforts in California or any other state.”
Getting It Right
During the Jan. 19 meeting, Lauren Tenney Dennison, director of market policy and grid strategy with the Public Power Council, asked whether the Launch Committee still expected to stand up an independent entity by late spring, in line with an earlier schedule.
Staks said the group still is trying to “nail down” the timeline and will not hit that target.
“I think we want to make sure we get the legal analysis done, and that is really going to help us make a more concrete decision and timeline that is associated with where we ultimately want to go with this,” Staks said.
Group members “are really committed to doing this as thoroughly and with as much input to increase our likelihood of success,” Staks said. “So, the timeline as we originally thought has shifted, but I think that’s OK.”
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Members Committee meeting Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
The Markets and Reliability Committee also is scheduled to meet from 9 to 9:40 a.m. ET, but its agenda does not contain any endorsements or voting items. RTO Insider will cover the discussions and votes.
Members Committee
Consent Agenda
The committee will be asked to endorse as part of its consent agenda:
B. tariff and Operating Agreement revisions to implement PJM’s proposed overhaul of its regulation market. The new design would use a single price signal and rely on two products representing a resource’s ability to adjust its output up or down. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.)
Texas Gov. Greg Abbott on Jan. 19 appointed Thomas Gleeson, the Public Utility Commission’s executive director and a 15-year staffer, to chair the PUC in a term that expires Sept. 1, 2029.
Gleeson replaces Kathleen Jackson, who has served as the PUC’s interim chair since June. The appointment also brings the commission to four members, one short of capacity.
In a statement supplied by the PUC, Gleeson said he was “deeply honored” by the appointment and that his three years as the commission’s executive director had prepared him for the moment.
“I know full well the magnitude of the responsibility being placed upon me,” Gleeson said. “The [PUC’s] work touches every Texan by ensuring reliable, affordable and accessible electric, water and telecom service. I look forward to working with my fellow commissioners and the extraordinary [PUC] team … to continue strengthening utility services critical to the daily lives of all Texans.”
“Thomas Gleeson’s longtime service at PUC and wealth of knowledge make him the ideal choice for chair of the commission,” Abbott said in a statement.
Texas lawmakers overhauled the PUC after the disastrous and deadly winter storm in 2021, raising the commission’s membership from three to five and serving staggered, six-year terms. Prior to that, the commissioners reached quorum under the state’s open meeting laws when in one-on-one discussions with each other.
A veteran of 15 years on the commission staff, Gleeson was named the commission’s executive director in December 2020. He previously served as the commission’s COO, as its director of finance and administration, and as a fiscal project manager. Gleeson also was a legislative analyst for the Texas Senate and a budget analyst for the Legislative Budget Board.
He holds a bachelor’s degree in business administration from Southwestern University and a master’s in public administration from The Bush School of Government and Public Service at Texas A&M University.
Gleeson’s appointment still must be confirmed when the Senate next meets in a special session or during the 2025 Legislature.
Potomac Keeps IMM Contract
The PUC also said Jan. 19 it has finalized a four-year, multimillion-dollar contract with Potomac Economics to serve as ERCOT’s Independent Market Monitor through 2027.
The contract, signed Dec. 28, is not to exceed $22.5 million, with Potomac responsible for any overage.
According to its language, Potomac must hire a director and staff to carry out day-to-day monitoring functions. However, Potomac has agreed to use its “best efforts” to avoid any staffing changes and also to remove any IMM staff the PUC “finds unacceptable for reasons related to their experience, qualifications or performance of services in the [PUC’s] sole discretion.”
The commission must vote during an open meeting to request Potomac to remove the IMM director.
Carrie Bivens resigned as the IMM’s executive director in November. ERCOT pushed back against several of the IMM’s reports last year that indicated the grid operator’s heavy use of ancillary services created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion through November. (See Bivens Resigns as ERCOT’s Market Monitor.)
ERCOT’s staff plans to revisit its use of ancillary services and report back to stakeholders in April.
David Patton told RTO Insider he expects to announce a director in the very near future. “The search is well underway,” he said. “The IMM team is doing a great job as we search for a new director.”
Potomac has held the ERCOT contract since 2007. It also monitors the ISO-NE, MISO and NYISO markets.
CARMEL, Ind. — MISO said it has landed on a final design in its quest to move to a sweeping capacity accreditation that will better measure generators’ availability based on predetermined risky hours.
That’s despite stakeholders’ calls for MISO to push back a FERC filing until later in 2024.
MISO last week said it will file by March to employ a direct loss of load approach to accreditation by the 2028/29 planning year, when capacity credits will be determined by a combination of individual past performance and a resource-class average performance during risky hours for different types of generation. Most MISO resources will see their capacity values shrink under the new method. (See MISO Defers Unpopular Capacity Accreditation Filing, Remains Committed to Design.)
At a Jan. 17 Resource Adequacy Subcommittee meeting, MISO’s Neil Shah said the RTO began discussions on accreditation two years ago, right after it rolled out its first attempt at availability-based seasonal accreditation for thermal resources only.
Since RASC meetings in 2023, MISO has modified its proposal to include an expanded set of hours beyond loss of load hours that it will draw on to gauge generator availability for accreditation. Those will include low-margin hours where the reserve margin comes within 3% or less of load. The inclusion of more hours is meant to cut down on volatile accreditations year over year. Nevertheless, the loss of load hours will carry more weight in establishing capacity credits.
MISO’s FERC filing will leave some unfinished business with stakeholders: The RTO won’t define resource classes in the filing or how it will divvy up its planning reserve margin requirement into obligations among load-serving entities.
“MISO’s plan is to not define specific resource classes in its tariff. The idea is we will include criteria on how to define resource classes, and we will work with you all in the coming months to flesh out details,” Shah told stakeholders.
Shah said MISO’s final definition for resources classes will be contained in business practice manuals only.
MISO likewise will hold off on detailing exactly how it will allocate its planning reserve margin requirement (PRMR) to load-serving entities, leaving that to a later, separate filing. MISO previously said its direct loss of load accreditation could change how MISO allocates its PRMR among its load-serving entities. Today, MISO metes out its PRMR on a load-ratio share.
A new allocation would depend in part on how MISO ultimately defines resource classes. Shah said there’s no need for MISO to include the PRMR allocation in filing, as it originally proposed.
Sustainable FERC Project’s Natalie McIntire said she worried MISO’s resource class definitions would be too vague at the time of filing for stakeholders to be confident in how their resources would be classified and therefore accredited.
Shah said working out how resources would be grouped is a matter of technical details.
“The details are what stakeholders are going to judge for whether we can support this proposal,” McIntire countered.
WPPI Energy’s Steve Leovy agreed that MISO’s proposed tariff language to group resources by similar technologies and operating characteristics is “extremely slim.”
Minnesota Power’s Tom Butz said MISO seemed in a rush to file the accreditation, while Entergy’s Wyatt Ellertson asked MISO to allow a few more months to get stakeholders more comfortable with the proposal.
“I’m hearing honest requests from stakeholders. These are not delay tactics,” Ellertson said.
“I’m hoping that by now we’ve made the case as to why capacity accreditation is an important step to mitigate, especially in the resource transition,” Executive Director of Market and Grid Strategy Zak Joundi said.
Joundi said utilities appear to be in the midst of integrated resource planning and charting future portfolios. He said it’s valuable for market participants to be able to make investment decisions with a clear view of future accreditation values.
“That’s what the rush is all about,” Joundi said.
But MidAmerican Energy’s Dehn Stevens said the accreditation’s implementation date in the 2028/29 time frame seems to set LSEs up for “failure” because they won’t be able to get new resources lined up in time in MISO’s generator interconnection queue. Stevens said a date closer to 2030 is more appropriate and would allow LSEs time to prepare different types of resources if necessary to meet summer requirements in five years.
Shah said though some LSEs “will be in a bind” and should plan better, the accreditation would give valuable investment signals to utilities. He said though stakeholders might want a later implementation, the 2028/29 target date strikes the right “balance” between MISO, utilities and the energy transition.
Joundi agreed a three-year transition will give companies time to adjust investments.
Alliant Energy’s Jamie Niccolls said MISO could find itself in a “real weird situation” if FERC were to approve the PRMR allocation method based on the new accreditation but not the accreditation filing itself.
Shah said MISO will make sure FERC approved the accreditation process before it proposes a PRMR allocation to LSEs.
Shah also said MISO will tackle how to manage data transparency in the new accreditation process, devising measures to share data and modeling with utilities in the coming months.
Staff and stakeholders will continue to discuss the accreditation plan leading up to MISO’s filing.
FERC didn’t completely buy into MISO’s package of stricter rules to lighten its gridlocked interconnection queue, rejecting the RTO’s proposed annual megawatt cap on project submittals.
The commission last week denied MISO’s proposal to use a formula to calculate an annual megawatt cap on the generation projects it will accept into its generator interconnection queue (ER24-340). MISO intended for the cap to help solve its project backlog and prevent annual surges of project entrants.
However, FERC signaled it might be open to a cap with different design elements. The commission said it couldn’t greenlight MISO’s cap because of concerns over a section of the cap’s formula, proposed exemptions to the cap and MISO’s lack of attention on resource adequacy when designing the cap.
“MISO has provided evidence that a cap in some form could be beneficial,” FERC said.
FERC OK’d other provisions on queue entry and exit that MISO submitted to reduce the size of its generator interconnection queue. In addition to its request to place an annual megawatt limit on project proposals, MISO proposed to double entrance and staged fees; institute automatic and escalating penalty charges; and require developers to confirm they’re able to obtain land for projects. (See MISO Relaxes Proposal on Stricter Queue Ruleset; MISO’s More Stringent Interconnection Queue Rules Go Before FERC.) FERC said the trio of new rules “will help improve the readiness and quality of interconnection requests” and can go into effect Jan. 22.
FERC said MISO demonstrated that its current queue requirements “are not stringent enough to deter interconnection customers from submitting speculative interconnection requests into the queue, nor strong enough to prompt unready projects to exit the queue at the earliest opportunity, as underscored by the volume of submitted interconnection requests and withdrawals that MISO has experienced in recent queue cycles.”
Though MISO proved it has a problem on its hands, FERC said the megawatt cap proposal is faulty because it allowed an unlimited number of exemptions to the cap.
MISO wanted to allow developers to exceed the cap when projects are intended for load-serving obligations, have a power purchase agreement, are an approved generator replacement facility or are requesting to convert their unguaranteed level of interconnection service to firm service.
“Although MISO’s initial proposed formula includes a 5% margin to account for exemptions (which would have the effect of decreasing the cap value to be established), MISO proposes no limit on the exemptions that may enter a queue cycle beyond the established cap,” FERC explained.
FERC said it was concerned the exemptions on certain projects could create “priority access” to MISO’s queue and violate the commission’s open access requirements for generator interconnections.
FERC also said the formula MISO planned to use to calculate the cap for each of its study regions annually was a headscratcher. It said MISO’s formula inexplicably called for calculating load remaining to be served after existing generation and higher-queued generation proposals are dispatched at the lowest possible megawatt output while remaining online. FERC said the minimum output levels don’t mimic actual or expected system conditions, and it’s unclear why MISO would use them in its cap formula.
MISO intended the megawatt cap formula to be based on its ability to develop a reasonable dispatch for studying interconnection requests based on the existing system and considering regional and subregional peak loads.
Finally, FERC said MISO needed to factor its own future resource adequacy needs into the cap’s design, especially with capacity shortfalls on the horizon.
FERC said it agreed with National Grid and Steelhead that a cap must strike a “balance between limiting the volume of requests to a level that can be processed efficiently and avoiding unnecessary barriers to entry that will delay the development of the generation capacity needed to meet growing supply shortages within the MISO region.”
However, Commissioner Mark Christie said he supported the controversial cap in a partial dissent to the order.
“Faced with a tsunami of interconnection requests from generation developers — many speculative, and which will never be built — MISO seeks to ameliorate its interconnection studies process in the near term with a cap on applications,” Christie wrote. “A cap is admittedly a blunt instrument, but it is also a logical one if the goal is to enable MISO to focus its undeniably limited resources to maintain an orderly and efficient interconnection process.”
Christie said FERC’s concern that the exemption provision would be so heavily used that it would dilute the cap was pure speculation. He also said cap exemptions for generation projects necessary to serve load are appropriate because they keep resource adequacy decisions in the hands of states.
