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December 24, 2024

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Panel Provides Update on Energy Storage in Mass.

Battery storage remains largely reliant on state programs and subsidies to be viable in Massachusetts but increasingly could stand on its own as renewable resources proliferate, a panel of energy storage experts said during a webinar May 30. 

“As we further decarbonize our grid, these products become ever more important,” said Tom Ferguson, energy storage programs manager at the Massachusetts Executive Office of Energy and Environmental Affairs. 

Ferguson noted that battery storage’s ability to balance the grid will become more valuable with more intermittent resources on the system. He emphasized that long-duration storage pairs particularly well with offshore wind, which could help drive the business case for long-duration technologies. 

While credits associated with Massachusetts’ Clean Peak Energy Standard (CPS) make up a major portion of the revenue for new storage resources today, “over time, the hope is that the need for incentives will decrease,” Ferguson said. 

He cited a December 2023 report commissioned by the state that found storage likely will be “a cost-effective element of mid- and long-term resource portfolios” but needs increased state support in the near term to scale up quickly enough to meet the state’s goals. 

“Additional state programs will be required, as will dedicated efforts to reduce existing financial, technological, supply chain and operational barriers to deployment,” the report found. 

Responding to a question about Massachusetts’ progress toward its goal of deploying 1,000 MW of storage by the end of 2025, Ferguson said the state currently has “a little over 500 MW. … We’re hoping we’ll hit that target.” 

Chris Sherman, senior vice president at Cogentrix Energy, discussed the company’s ongoing efforts to replace the West Springfield Station, which retired in 2022, with battery storage. 

The first phase of the project consists of a 45-MW battery facility with a projected in-service date of mid-2025, while the company is “in the process of designing Phase 2, which will likely be an additional 105 MW,” Sherman said. 

“The clean peak standard is the basis for the project,” Sherman said, noting that it accounts for about 40% of the project’s projected revenue. 

Looming changes to how ISO-NE accredits resources in its Forward Capacity Market likely will further reduce the revenues available to battery storage from the wholesale markets, Sherman added. 

An ISO-NE analysis from early May indicated the in-development accreditation changes could result in a $58 million reduction in total capacity market revenues for storage resources. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

The changes are intended to better align capacity procurements with actual reliability benefits. Sherman said they amount to “a fairly significant derate,” adding that “we would need to have that [capacity market revenue] made up somewhere … [but] it was probably the least amount of our revenue; it was never a great revenue source.” 

Todd Olinsky-Paul, senior project director at the Clean Energy States Alliance, said the new accreditation framework likely will “push battery storage toward longer-duration resources.” 

Jason Viadero, director of engineering and generation assets at Massachusetts Municipal Wholesale Electric Co. (MMWEC), said the company has deployed storage to minimize its peak and save customers money without substantial support from state programs. Massachusetts’ municipal utilities are not subject to the CPS. 

“This is one specific use case that completely stands on its own economically,” Viadero said. “These systems are able to pay for themselves throughout the life of the system.” 

Growing electricity demand will make peak shaving increasingly important, Viadero said, highlighting the significant differences in ISO-NE’s cost projections for a 57-GW peak load system and 51 GW. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

Viadero said MMWEC is working to deploy “upwards of 50 MW” of energy storage in 2024 and 2025, with a greater focus on longer-duration storage going forward. 

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Calif. Officials ‘Cautiously Optimistic’ on Summer Reliability

California energy officials are “cautiously optimistic” about maintaining grid reliability this summer, with the state benefiting from above-normal snowpack and precipitation coupled with expectations for cooler temperatures in coastal regions.  

That was the assessment of multiple presenters speaking during a summer reliability workshop hosted by the California Energy Commission on May 29. 

But climate change is making it increasingly hard to ensure reliable grid conditions, and planners must remain vigilant to avoid outages such as those in 2020, CEC Vice Chair Siva Gunda said during the workshop. “In 2020, we had two [rolling] outages on Aug. 14 and Aug. 15 — something we hadn’t seen at that point in 20 years — and it has been a primary focus in California to ensure electric reliability as we move forward.”  

Maintaining reliability requires a host of responses to keep up with decarbonization efforts and a warming climate, including having flexible and dispatchable resources, especially during the critical sunset hours when solar rolls off the system, said David Erne, CEC deputy director of resource planning, reliability and emergency response. But this summer is looking better than last, he said.  

Weather Patterns

Zeroing in on weather conditions, Amber Motley, director of short-term forecasting at CAISO, highlighted that the central Sierra Nevada had above-normal snow water equivalent this winter, although California was at 67% of its snowpack average as of May 20, said Jeff Fuentes, deputy chief of fire intelligence at Cal Fire.  

But the Pacific Northwest “did not have as good of a snow year,” Motley said, resulting in abnormally dry to moderate drought conditions in many portions of Oregon and Washington.   

This summer also should mark a transition away from El Niño, which is associated with warmer sea surface temperatures in the Pacific Ocean and hotter, dryer conditions in the northern U.S., to La Niña, marked by colder sea temperatures, drought and warmer conditions in the South and heavy rains in the Pacific Northwest.  

“For the Desert Southwest, this is really critical,” Motley said. “Because of the position of … where the heat is focused to be, it’s expected they don’t get as much monsoon moisture, which leads to less precipitation, but also leads to less cooling for them in the evening hours. The key piece as we head into summer is really watching the position of that [heat] ridge.” 

Another factor to watch, Motley said, is above-normal sea surface temperatures in the Atlantic, leading to forecasts that hurricane season will be more extreme — which impacts conditions in the West.  

“That’s going to be critical to watch because if you have big hurricanes, when we get into the August and July time period, they will move up into the gulf, and they kind of act like a traffic jam to the atmosphere. So, that could allow a ridge to stay parked over the West and not move for a number of days.”  

Taking all these pieces into account, forecasters anticipate above-average temperatures in the Desert Southwest, interior California and Rockies regions and a low probability of above-normal temperatures in California’s coastal regions.  

California fire risk is low to normal, Fuentes said, but “normal” typically means one to two large fires in each of the state’s service areas in June, three in July and six in August. Additionally, the Pacific Northwest will see normal risk of significant fires until July, when areas of Central and Southeast Oregon may shift to above-average potential for wildfire.  

Reliability

Changing weather patterns aren’t the only significant challenge to ensuring reliability. Expedited resource builds coupled with delays and resource retirements also are having an impact, said Branden Sudduth, WECC vice president of reliability planning and performance analysis.  

“Over the last two-year cycle when we developed our reports, we saw about 5,000 MW worth of generation retirements being delayed,” Sudduth said. “A lot of states in the West are focused on making sure they have adequate energy, adequate resources over the next couple of years. But we just want to make sure that people are alert and aware that those retirements are still going to happen in the future, and we just need to keep our foot on the gas pedal when it comes to making sure that we get new resources developed, built and online.”  

Sudduth provided an overview of NERC’s 2024 Summer Reliability Assessment, which evaluates June through September. This year’s assessment showed that while all areas of North America have adequate resources for normal summer demand, British Columbia, California, Mexico and the Southwestern U.S. have an elevated risk of insufficient operating reserves and loss of load under “extreme conditions,” defined as demand meeting or exceeding the 90th percentile threshold of the region’s demand curve. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

The “good news,” Sudduth noted, is that no regions were identified as “high risk,” indicated as having insufficient operating reserves under expected conditions, for the upcoming summer.  

Focusing on the elevated risk identified for California and Mexico, the highest chance for load loss was the period ending at 7 p.m., though that totaled less than one hour. In the Southwest, the concern lay in the potential for a heat wave to increase the region’s probability of being unable to meet its operating reserve requirements.  

A broader reliability concern identified by WECC is the industry’s ability to keep up with the pace of development.  

“From January 2023 to June 2023, the Western Interconnection added around 14 GW of new generation capacity. Currently, we’re planned to add just over 17 GW” by summer, Sudduth said. “As we look at things such as supply chain delays and … we know there are workforce shortage issues, that’s really one of the challenges we face is can we build enough generation quick enough to meet our plans, and I assume that will continue to be one of our challenges in future years as the pace of generation builds [continues] to increase.” 

Christine Root, integrated resource planning and compliance supervisor at the California Public Utilities Commission, emphasized the rapid pace of resource development, with 18,500 MW of clean energy nameplate capacity coming online from 2020 to 2024, 5,700 MW of that last year — “the highest amount of clean energy on record for a given year thus far.”  

Ensuring reliability is dependent on long-term forward planning and procuring the volume of resources needed to support the evolving grid, Root added. The CPUC adopted a preferred system plan in February 2024, which estimates 55 GW coming online by 2035, 32 GW of which is expected to be solar.  

Though grid planners and forecasters presented a generally positive outlook for summer 2024, they continued to emphasize the importance of being cautious and vigilant.  

“Maintaining reliability is paramount and underscored by what we’re all collectively facing with the climate crisis,” said Christine Hironaka, senior adviser for energy for the office of Gov. Gavin Newsom.  

She noted that extreme heat events like the one in September 2022 are likely “to increase in frequency and intensity as time goes on.”  

“I think the good news is, last year … the grid did not have any major emergencies and I think the topline for me is we remain cautiously optimistic for this summer’s outlook,” she said.  

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Texas RE Sees Challenges in Resource Mix, Physical Security

Staff at the Texas Reliability Entity said in a webinar that the regional entity’s upcoming Reliability Performance and Regional Risk Assessment should show most performance metrics are “trending in the right direction,” although work still is needed in some areas. 

Texas RE produces the assessment each year as a supplement to NERC’s State of Reliability report, reviewing the performance of the state’s grid over the previous year. Both reports normally are released in June. Speaking at the RE’s regular “Talk with Texas RE” event May 30, Director of Reliability Services David Penney said the assessment has performed a valuable role since the RE started releasing it 10 years ago.

“We’re one of the few regional entities that puts a report like this together, that looks at both the regional performance from a reliability perspective, as well as a regional risk assessment to look at the risks that we face as a region,” Penney said. “We tried to tailor this report [to] … a target audience [of] industry stakeholders, industry executives, as well as policymakers, to [share] the key risks that we [see] as a region, as opposed to what you may see from other industries or other [regional] entities.” 

Penney observed that of the seven reliability performance metrics the RE tracks, more than half either were improving or stable in 2023 compared to the previous year. These include resource adequacy — where reserve margins show sufficient resource capacity, and Texas RE has observed “a very positive trend” in winterization since the February 2021 winter storm — transmission performance, and protection system performance, where the misoperation rate decreased in 2023 and remains below NERC’s overall misoperation rate. 

However, the RE did note several areas where monitoring is needed, such as resource performance, which analyzes generator outage rates, primary frequency response and balancing contingency events to measure generation performance. Penney noted that while the RE has seen improvement in PFR performance, there also has been a long-term increase in equivalent forced outage rate, indicating times when generators have experienced forced outages when the units were needed to meet load.

Texas RE also identified issues in grid transformation, which measures the developing challenges associated with the shift to renewable resources. Penney said the report will discuss the need to monitor the drop in solar performance in evening hours and how it impacts reliability, as well as the decrease in system inertia levels that may leave the grid open to disruption.

Along with these issues, Penney discussed the physical security risks to electric equipment, which have risen across most categories in recent years. For example, the RE counted 15 gunshot incidents involving power stations in 2023, up from three the year before. A similar increase was reported in theft incidents, while the number of intrusion events rose from 18 to 20. Penney said the number of physical security events has continued to rise this year, indicating “this is a risk that’s definitely not going away.” 

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SPP Monitor Collins Joins ERCOT as VP of Market Ops

ERCOT said May 29 that it has hired Keith Collins, SPP vice president of market monitoring, as its new vice president of market operations, effective June 17. 

Collins will replace Kenan Ögelman, who retired as vice president of commercial operations in April. He will be responsible for ERCOT’s market analysis, performance and design, reporting to COO Woody Rickerson. (See “Ögelman Extends ERCOT Service,” ERCOT Technical Advisory Committee Briefs: March 27, 2024.) 

Collins brings more than two decades of experience in market operations and 25 years of experience in the electric power industry. He joined SPP in June 2017, serving under MMU Executive Director Alan McQueen during a brief transition period before taking over. Previously, he was CAISO’s manager of monitoring and reporting and a branch chief for FERC. Collins also worked with NYISO on market performance. 

“I look forward to the challenges and opportunities of working with stakeholders, regulators, legislators and [ERCOT’s Independent Market Monitor] to continue to develop and improve on one of the premier electricity markets,” Collins told RTO Insider. “I am confident that my background and experiences have prepared me for success in this role.” 

“With the Texas energy market rapidly evolving, ERCOT is focused on continuing to make improvements to market performance,” ERCOT CEO Pablo Vegas said in a news release. “A key component will be to review the current market design and behavior to drive positive market outcomes.” 

Collins has a master’s in public policy from George Mason University and a bachelor’s in economics and government studies from Bowdoin College. He also attended the Advanced Management Program at the Massachusetts Institute of Technology Sloan School of Management. 

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SPP’s REAL Team Moves Package of Policies

SPP’s resource adequacy stakeholder group has moved several policies that indicate the team’s work is “coming home” after months of presentations and discussions. 

“I know we’ve spent at least six, seven months on this now, so this is coming to a head and very important for the region,” Casey Cathey, SPP’s newly minted engineering vice president, said during a conference call with members of the Resource and Energy Adequacy Leadership (REAL) Team on May 24. 

The team plans to bring several policy issues and tariff changes to the July and August governance meetings, where SPP’s Board of Directors and its Regional State Committee hold the key votes. 

The REAL Team endorsed policies that set the base planning reserve margins (PRMs) at 36% and 16% for the winter and summer seasons, respectively, effective with summer 2026 and winter 2026/27; and extend the sufficiency valuation curve’s applicability so it applies to the three planning seasons beginning in 2026. 

Cathey said staff will circle back to the June REAL meeting with proposed tariff revisions that codify the policies. 

The team also approved a fuel assurance revision request (RR621) and agreed to evaluate and update the tariff’s cost of new entry, effective summer 2028. RR621 would add an “after-the-fact” application of fuel assurance based on historical performance, rather than imposing prescriptive requirements; it would be additive to the approved performance-based accreditation (PBA) methodology and meet the RSC’s directive to develop a policy incorporating PBA weighting based on critical system periods. 

In a separate motion, REAL directed the Supply Adequacy Working Group (SAWG) to evaluate and recommend summer 2029 and winter 2029/30 PRMs for the September REAL meeting. 

The team also agreed to staff’s request for support in developing potential use cases for the value of lost load in resource adequacy and transmission planning studies using a “willingness-to-pay” calculation. As the use cases are developed, the calculation will be evaluated and updated as appropriate. 

SPP is using willingness to pay for 30-minute, one-hour, two-hour and eight-hour outages, based on a recent study conducted by The Brattle Group for ERCOT. Its initial work has shown the weighted average of various commercial-and-industrial and residential sectors ranging from $35,863 for a half-hour outage to $220,592 for an eight-hour outage. 

ERCOT is using an interim VOLL of $25,000, and MISO is using $35,000 to create its operating reserve demand curve and a market VOLL (price cap and administrative price during load shed) of $10,000 to reflect a price that aligns with load that should be incented to shed. 

“The work done here kind of lays the framework for us to move forward,” Cathey said. 

REAL rejected an alternative reserve-retention proposal, submitted by American Electric Power, for cases in which load-responsible entities are not able to secure excess reserves. The proposal would have set accredited capacity (ACAP) requirements for 2026 using a 36% base PRM; LREs that voluntarily agreed to retain or sell excess reserves within the region would have their ACAP reduced to effectively meet a 33% base PRM. 

“This AEP proposal does step forward into the future, not just perpetuate this piecemeal reserve margin-setting process that we have before us,” AEP’s Richard Ross said. 

Golden Spread Electric Cooperative’s Mike Wise, supporting SPP’s proposed PRM changes, pointed out AEP’s suggestion had not been vetted through the LREs. 

“I do like [AEP’s] glide slope concept that he’s got,” Wise said. “The concern I have over Richard’s proposal is that it needs further work.” There would be “consequences intended and unintended that need to be really vetted and thought about.” 

Staff withdrew from REAL’s consideration an initial proposal for optional voluntary load-mitigation agreements between the RTO and LREs. An agreement would satisfy LREs’ deficiency for a transitional period during the summer and winter seasons. During a Level 3 energy emergency alert, the SPP would instruct voluntary load reductions pro rata among LREs with the agreements; additional load mitigation would be pro rata across LREs. 

“I hate this,” Ross said. “What about NERC penalties? I feel like this puts us in a situation where we are planning the system to not have adequate reserves. I fear that puts SPP in the position where they don’t have a good answer, and I don’t like NERC penalties.” 

“This is counter to what we’re trying to accomplish, right? Having resources out there that we can count on when we need them instead of not having a resource and somebody banking on shedding load,” Oklahoma Municipal Power Authority’s David Osburn said. “We could in essence be creating almost like a free rider that the rest of us are spending a lot of money getting resources available when we need them.” 

“The bottom line is if this idea is not well formed, if it’s not fully baked, maybe now’s not the time to act on it,” Cathey said.  

Looking ahead, Cathey promised more discussion on PRM stabilization policies at the next REAL meeting June 13 in Little Rock, Ark. He said the focus will be on accurate forecasting and stronger assumptions, with more frequent studies ensuring SPP is sending moderate signal changes and smoothing out capacity requirements over time. 

Staff will work with the SAWG to develop a plan for a plan, he said. 

“We haven’t spent a lot of time at the REAL on this,” Cathey said. “This is sort of a strategic and recommended approach for the REAL to work with the SAWG and really have the SAWG come up with some longer-term solution.” 

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MISO IMM Knocks LRTP Benefit Calculations; RTO Poised to Add More Projects

MISO’s Independent Market Monitor continues to cast doubt on the theoretical benefits estimates of the second long-range transmission projects as the RTO intends to add more projects to the already $17 billion to $23 billion portfolio.  

During a May 29 stakeholder workshop, IMM David Patton said MISO risks “substantially overstating” the benefits of its proposed, second long-range transmission plan (LRTP) portfolio. 

“We think transmission investment is extremely important, but it’s also expensive. So, it’s important that the transmission investment be economic. … Overinvesting in transmission has adverse effects on the market,” Patton told stakeholders at the workshop.  

MISO has not yet finalized the benefits it will use in the business case for the second LRTP portfolio, but it has signaled it will value decarbonization, reduced risks from extreme weather and the avoided costs of otherwise-necessary new capacity in addition to other, more traditional benefits. (See MISO to Present Final, $20B 2nd LRTP Portfolio in September.) 

Patton said MISO is on track to confer outsized benefits on its second LRTP portfolio because it doesn’t consider how the market would influence generation additions without the LRTP projects. He said it’s “not valid” for MISO to presume it will need more capacity in aggregate if it doesn’t build the second portfolio.  

Patton recommended MISO “eliminate altogether or fundamentally change” its proposed LRTP benefit derived from the avoided costs of adding capacity that otherwise would be necessary without the lines.  

“There is little basis to assume that transmission will affect MISO’s capacity requirements,” he said.  

Patton said absent major transmission, markets will facilitate the construction of generation to meet reserve requirements in areas where it’s more easily deliverable to load. He also said MISO isn’t optimizing its hypothetical generation siting in its transmission planning and that MISO’s zonal capacity needs would shift depending on whether LRTP lines are built. He said it’s worth MISO’s time to explore an alternative siting of future resources and simulate market responses without a second LRTP portfolio.  

“We can’t ignore those changes,” he said.  

For instance, Patton said MISO should factor in plans to restart Michigan’s Palisades Nuclear Plant in its modeling.  

“I just can’t see us not adjusting in the benefits analysis for those sorts of known” developments, Patton said. 

Patton also said MISO underestimates how additions of storage assets can mitigate some transmission congestion and chip away at the perceived congestion savings of LRTP lines.  

“Storage is really, really good at alleviating congestion due to transitory peaks,” he said.  

He also said MISO shouldn’t consider placing its own value on decarbonization because it’s already “baked into” the government’s production tax credits.  

“I really don’t think it’s MISO’s place to speculate on what the value of carbon is,” he said.  

Patton also said it’s not appropriate to calculate potential voltage problems without LRTP lines using the cost of load shed. He said no RTO resorts to load shedding when faced with voltage issues. MISO would be better served by calculating the cost of equipment to correct voltage issues, he said.  

Finally, Patton took issue with MISO attempting to quantify transmission’s role in reducing extreme weather risks to the grid, calling it “one of the most uncertain and speculative benefits.” He said MISO should use a lower, more realistic probability of extreme weather events occurring in the footprint.  

Sustainable FERC Project Attorney Lauren Azar countered that unlike transmission built on 10- to 15-year timelines, markets stimulate only near-term investments.  

Azar said if MISO followed Patton’s recommendations, it would be ignoring FERC’s recent Order 1920 to engage in long-term, scenario-based transmission planning.  

“I challenge your fundamental assumption that markets are the best driver of new lines,” Azar said. “I would caution MISO to follow your advice.”  

Azar said avoiding congestion is just one benefit of new transmission infrastructure, not the primary aim.   

Patton insisted he isn’t advocating for anything beyond appropriate customer costs for transmission expansion.  

Patton for months also has criticized MISO’s second transmission planning future as unrealistic. (See MISO Shelves IMM’s Transmission Planning Recommendation in State of the Market Report.) The second LRTP portfolio is based on that 20-year scenario, which predicts that by 2042, MISO will manage 466 GW of installed capacity, have a 145-GW peak load that occurs in January rather than July and have overseen 103 GW in generation retirements. It also expects its fleet will emit 96% less carbon pollution than it did in 2005.   

MISO Undeterred, Plans More LRTP Projects

Meanwhile, MISO likely will fill in its second LRTP portfolio with more projects than it originally proposed in its draft plan.  

MISO’s Jeanna Furnish said MISO has been evaluating alternatives and additional projects to its indicative map of transmission solutions under the second LRTP portfolio. She said MISO is poised to make seven additions of 765- or 345-kV projects in the Dakotas, Minnesota, Michigan, Indiana and Iowa and replace an original 765-kV project in Missouri and Iowa with segments of 345-kV line in the St. Louis metropolitan area.   

Furnish said MISO tested 47 of nearly 100 project alternatives suggested by stakeholders. MISO turned to stakeholders for more ideas after it revealed its draft plan in March.  

“The feedback we got is that we need to take a bigger step,” Executive Director of Transmission Planning Laura Rauch said. “It’s that guidance that helped us look at a bigger Tranche 2 portfolio than we originally envisioned.” 

American Transmission Co.’s Tom Dagenais thanked MISO for taking suggestions and being open to expanding the portfolio.  

Furnish said while “initial ideas were good,” MISO sought to improve the reliability and economic performance of the second LRTP portfolio. MISO said its lone replacement proposal for lower-voltage projects in St. Louis would provide congestion relief while increasing interstate transfers. It also said it could revisit the possibility of a continuous 765-kV line spanning Missouri and Iowa in the future.  

MISO planners didn’t address Patton’s critiques during the workshop.  

Later, in an emailed statement to RTO Insider, MISO said it “appreciates Dr. Patton’s report and will continue working on LRTP solutions through our stakeholder process.” The RTO did not say whether it plans to address Patton’s recommendation to axe certain benefit metrics.  

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Smaller Projects Expected from Maiden MISO-PJM Joint Tx Study

CARMEL, Ind. — MISO has told stakeholders not to expect sweeping, greenfield projects as a result of its new transfer capability study with PJM.  

Speaking at a May 29 Planning Advisory Committee meeting, MISO Director of Expansion Planning Jeanna Furnish said MISO and PJM anticipate sharing more details around possible projects in the first half of 2025. However, the projects probably won’t be staggering in scale. 

MISO Director of Economic and Policy Planning Christina Drake said MISO and PJM’s transfer capability study first must entail an engineering analysis before the RTOs begin future work on a new project type or adding a new cost allocation method to the MISO-PJM joint operating agreement.  

After prodding from state regulators and consumer groups, MISO and PJM in early May announced they would embark on a new type of interregional planning study. (See MISO, PJM Agree to Perform New Type of Joint Transmission Study.)  

Drake said MISO and PJM might create a new project type to expand interregional transfer capabilities.  

But she said MISO and PJM first need to “explore the edges” of their joint modeling. She said the first study will center on near-term construction, not the more complex, interregional projects that require greenfield development. The first study probably will aid “future work on project type and cost allocation,” Drake said.  

Drake said it’s likely MISO and PJM will identify project needs even though the study was described as “informational” by the RTOs.  

“Informational does not imply that we’re just going to post results and not bring anything forward,” Drake said.  

Invenergy’s Arash Ghodsian asked whether MISO and PJM’s study also will focus on interconnection upgrade needs on the seam that have been showing up for years in the RTOs’ interconnection queues.  

Drake said the focus of the study is strictly interregional transfers, not enabling more generator hookups, as is the case with MISO and SPP’s Joint Targeted Interconnection Queue study. Drake also said it’s unlikely MISO and PJM will develop a major, multivalue style project stemming from the initial study.  

Nevertheless, Ghodsian said the study is “long due” and Invenergy looks forward to the effort.  

Drake said MISO is meeting with PJM regularly on the nascent study.  

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Electric School Buses Get $900M Boost from EPA

EPA Administrator Michael Regan was in Jackson, Miss., on May 29 to take a ride on one of the city’s 25 electric school buses, funded with grants from the Infrastructure Investment and Jobs Act.  

He also announced another $900 million in IIJA awards that could put 3,400 more clean school buses on the road in 532 school districts across the U.S.  

The bipartisan 2021 law provided EPA with $5 billion for its clean school bus program, and with the latest announcement, EPA has awarded more than $2.7 billion of that total, which will allow about 8,500 diesel buses to be replaced, Regan said.  

The awards are going to 47 states, the District of Columbia and Puerto Rico. No school districts in Alaska, Hawaii or Nevada applied for funds, according to a senior administration official speaking on background. 

School districts in low-income, disadvantaged, rural and tribal communities have been a top priority, making up about 45% of awardees and receiving 67% of the funds, according to an EPA announcement. Most but not all of the new buses will be electric ―92% ― with the remainder running on propane, which has significantly lower emissions than diesel. 

“The majority of the communities that are receiving these school buses are communities that look like this one,” Regan said, speaking at Jackson’s Henry J. Kirksey Middle School on the last day of classes. “They are black and brown communities; they are tribal communities; they are communities that have been disproportionately impacted by pollution for far too long. … 

“We all know that traditional school buses rely on engines that emit toxic pollutants in the air, putting the health and wellbeing of every single student in jeopardy,” he said. The IIJA funds are aimed at “reimagining what it’s like for children to ride to and from school each and every day.” 

Jackson is a case in point — and a strategic choice for the announcement as a state capital that already has experienced significant impacts of climate change. The city has survived two 30-year floods in the past four years, along with occasional blasts of subfreezing weather, with temperatures even colder than Anchorage, Alaska, according to Mayor Chokwe Antar Lumumba (D).  

Echoing Regan, Lumumba stressed the environmental justice message behind the city’s new buses, combining concern for children and “the way in which they commute from their homes to their learning environments,” and for the community at large as it seeks to “eradicate the challenges of climate change.” 

Getting Diesel off the Road

The May 29 announcement represents the third round of IIJA funding for clean school buses, and the program has been one of the Biden administration’s more successful initiatives, in terms of getting dollars out to communities and getting diesel buses off the road.  

The program’s focus on the risks diesel emissions pose to children’s health and the benefits of electric school buses has made it less controversial than other transportation electrification initiatives, such as EPA’s recent rules on cutting carbon dioxide emissions from light-, medium- and heavy-duty vehicles. 

The administration official said each round of funding for the clean bus program has been oversubscribed. 

But the program hit some bumps early on as school districts faced a steep learning curve on working with utilities to get chargers for their new buses connected to local distribution systems.  

At this point, program materials provide a template for school districts that include early communication with their local utilities to discuss if any grid upgrades will be needed and what they might cost. EPA is working with the Joint Office of Energy and Transportation, which can offer school districts technical assistance, the administration official said.  

EPA also now allows IIJA funds to be used for chargers and some of the equipment needed for interconnection and does not set specific limits on the portion of federal dollars that can be spent on charging infrastructure.  

Ben Prochazka, executive director of the Electrification Coalition, pointed to the potential use of electric school buses as grid resources “to provide backup power to communities during emergencies with vehicle-to-grid technology,” making them “a win-win-win for kids, schools and communities.” 

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Stakeholders Scold NYISO on Messaging Ahead of Summer

NYISO stakeholders on May 29 scolded the ISO for using the wrong figure in a press release on its summer capacity assessment, saying it suggested capacity margins would be tighter this summer than expected. 

Aaron Markham, NYISO vice president of operations, was presenting the ISO’s assessment, which had been presented to the Operating Committee on May 16, to the Management Committee. (See NYISO Reports Adequate Capacity for Summer, but Heat Waves a Concern.) The ISO said there is enough capacity to serve peak load this summer under its baseline forecast, but it made a point of noting that margins continue to shrink and that a prolonged heat wave could lead to emergency operations. 

NYISO expects to have about 40.7 GW of total capacity (34.9 GW after expected derates) to serve an expected peak load of about 31.5 GW. The day after the presentation to the OC, however, the ISO issued a press release reporting a “forecasted peak demand conditions of 33,301 MW.” 

That figure is actually the ISO’s predicted peak load under its 90/10 forecast, an extreme weather scenario it expects has only a 10% chance of happening. 

“I think it was a bit misleading to do that, as opposed to describing our baseline forecast and the conditions that you would expect,” said Howard Fromer of PSEG Power. “It kind of suggested that things are much worse than our market is intended to support. … If we think 90/10 is our reality, we need to have a conversation about how we’re setting our markets.” 

He noted that the sentence following the figure reads, “In 2023, summer peak demand reached 30,206 MW.” 

“It suggests that there’s a year-over-year increase of over 3,000 MW in spite of everything New York state is doing,” such as energy efficiency and behind-the-meter solar, Fromer said. 

The Times Union reported the 90/10 figure as the expected peak load and quoted Gavin Donohue, president of the Independent Power Producers of New York, as saying, “This has been a concern for quite some time, and now it is a red light concern.” T&D World’s report on the assessment was headlined “NYISO Warns of Potential Summer Power Shortages Despite Adequate Supplies Under Normal Conditions,” also reporting the 90/10 figure. 

“I very much support the concern about NYISO’s press release,” said Christopher Casey, utility regulatory director for the Natural Resources Defense Council. “I’ve been raising my own concerns with NYISO’s press releases for almost a year now, and I think NYISO is increasingly giving a confusing message to the public. Having the release focused on the 90/10 criteria … is pretty misleading.” 

Marc Montalvo of Daymark Energy Advisors said NERC’s 2024 Summer Reliability Assessment, released May 15, found “the New York region being essentially normal, sufficient; no expectations for issues or insufficient operating reserves,” while CAISO, ERCOT, MISO and ISO-NE face an “elevated” risk of insufficient operating reserves in above-normal conditions. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

“But this [NYISO’s assessment] looks like, under high-load conditions, that you might have an expectation of operating reserve shortages. So I’m trying to reconcile these two presentations,” Montalvo said. “If there’s one set of information that suggests a certain type of [condition or concern], and ostensibly measuring the same thing, and it looks like it’s telling a different story, it can be a bit confusing.” 

“We provide the NERC assessment with data in the format that they want it,” Markham said. “Here we try to take a little bit more conservative view of what conditions might look like in New York. … There can be various ways of accounting for forced outages of generation and how you calculate that number. … Here we use the average over five years.” 

‘Contributing to the Problem’

While NERC did say NYISO is expected to have sufficient reserves, it noted that a probabilistic assessment by the Northeast Power Coordinating Council found the ISO “could experience resource shortages during high-demand conditions and require limited use of operating procedures for mitigation.” However, even under the highest peak load scenarios, NPCC estimated a “small” cumulative loss-of-load expectation of 1.6 days for the season. 

Casey expressed confusion about “why [NYISO is] deciding that [data] should be presented and discussed differently to a stakeholder and New York public audience versus when you’re reporting to” FERC and NERC. 

“I think the ISO is in some respects … contributing to the problem here,” said Mark Younger, president of Hudson Energy Economics. “The summer assessment is not an evaluation of whether the ISO is likely to be unable to meet its loads. The summer assessment is an evaluation of whether the ISO can operate its system and remain under normal operating parameters for the whole thing. That is a long distance from where we are at risk of failing to meet load. … The ability to use [emergency operating procedures] is probably something the general public and reporters would not at all understand.” 

Robert Fernandez, NYISO general counsel and chief compliance officer, said he appreciated the feedback, but “I reject categorically any implication that there was an intention to mislead the public or anyone else here. That is simply not the case. … We can talk about clarifying [the presentation], but … you guys know us better than that.” 

“I don’t think you intended to, Rob; I’m not suggesting that at all,” Fromer replied. “But the casual reader is going to look at this press release and say, ‘Wow, our load went up 3,000 MW from last summer!’” 

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NYPA Unveils Expanded Grid Simulation Lab

ALBANY, N.Y. — The New York Power Authority has expanded its transmission laboratory with extensive new digital twin capabilities, allowing it to model and test the impact of new technologies on the grid. 

The Advanced Grid Innovation Laboratory for Energy (AGILe) is expected to be an important tool for the public and private sectors alike as New York decarbonizes its grid, identifying the demands that will be placed on existing infrastructure and ways to minimize that impact. 

How best to use these new technologies and match them to the grid are critical details of the energy transition. Stakeholders can base their planning on data provided by AGILe, NYPA said at a ceremony unveiling the facility May 29. 

NYPA founded AGILe in 2017 at its downstate headquarters and has gradually expanded its capabilities since. 

New York Power Authority President Justin Driscoll | © RTO Insider LLC

Albany was chosen as the site for the physical expansion of the lab because of the concentration of key stakeholders: The headquarters of NYISO, the Department of Public Service and the New York State Energy Research and Development Authority are all near, as are multiple colleges. The new lab space itself is within NY CREATES, a $15 billion high-tech research hub. 

“AGILe is more than just a technical facility; it’s a hub that is designed for collaboration of national and global stakeholders to evaluate and solve grid-related challenges,” NYPA President Justin Driscoll said before a ribbon-cutting ceremony. 

NYSERDA President Doreen Harris said AGILe and its ability to model real-time, real-world results will help the state work toward the statutory goals in its clean energy transition. 

“Where we sit today, so many of the models we use are static,” she said. 

As one of the lead agencies in the state’s energy transition, NYSERDA has a direct stake in expanding this modeling capacity. It will provide $9 million for advanced technology research facilitated by data from AGILe. 

Jessica Waldorf, chief of staff and policy implementation for the DPS, said AGILe will be a key part of the department’s efforts to expand and improve transmission, including through the Coordinated Grid Planning Process implemented in 2023.

“AGILe will help confront the challenges of balancing system reliability with clean energy development and cutting-edge technologies,” NYISO President Richard Dewey said in a statement. “NYISO is excited to work with NYPA in this regard, and having a grid ‘digital twin’ in our backyard will only make our collaboration that much closer.” 

Learning Process

The new space is a 10,000-square-foot office and control room powered by a data center drawing 400 kW of power and cooled with a 40-ton air conditioner. 

It is the first facility of its kind, NYPA said, able to use digital twins of devices and wires to see how they will interact. 

AGILe can model cyberattacks and responses, draw on an archive of the effects of actual weather events, and run a post mortem on past failures of components or systems. Engineers can wheel actual components into the lab to record and analyze their performance, or they can work from existing performance data. 

Importantly for the decarbonization of the grid, AGILe can model the effects of inverter-based resources and grid-enhancing technologies. It starts with the best possible model of the existing grid functioning perfectly and the best possible model of the effects of changes on anything from a 13-kV local line to a 765-kV backbone line. 

AGILe Director Hossein Hooshyar said, as an example, that a wind farm developer could bring a control panel into the lab and simulate operation to see how it would affect the grid and find a way to avoid affecting the grid negatively. 

Hossein Hooshyar, director of the New York Power Authority’s AGILe Lab | © RTO Insider LLC

“That’s the beauty of it,” Driscoll said. “You create what ‘perfect’ looks like … and then test aberrations or changes in circumstances that you might face … dynamic line ratings, advanced power controls, advanced conductoring — we could test that out before deploying it in the field.” 

Standing amid banks of supercomputers and speaking over the cooling system’s hum, Reza Pourramezan, senior power systems engineer, explained AGILe’s capabilities. 

“By receiving real-time measurements and data from sensors, as well as weather forecasts and load forecasts and market information, I can incorporate all this input into our simulations — that makes it even more realistic,” he said. Training, asset management, field support and collaborative decision-making also are enhanced with this digital twin approach. 

Senior power systems engineer Rahul Kadavil said the simultaneous rise of intermittent renewables, societal increase in power demand and growing weather-related threats to transmission created a need for the capabilities of AGILe. 

“It will revolutionize the way we manage our energy infrastructure,” he said, standing before a wall of screens in the control room that provide a visual display of all the factors acting on the New York grid in increments of milliseconds. 

Kadavil had Driscoll press the prominent red button in the middle of the room, triggering a simulated large grid disturbance, complete with flickering room lights, and an appropriate simulated response by the grid management. 

The readouts for load and frequency spiked up and down briefly, then flattened back out. 

“We have married real-time simulators with the immersive power of visualization to create that tactile feedback,” Kadavil said. 

NYSERDA’s Harris said AGILe’s capabilities will speed the adoption of new technologies because utilities and other customers will be more confident about something that has been tested. 

“This simulation allows us to understand the impacts [in advance] as opposed to physically deploying it in the field,” she said. 

Ali Mohammed, NYPA senior director of digital innovation and transformation, said the lengthy evolution that led to the debut of the new lab created a unique tool for the energy transition. 

“The digital twin asset is pretty much new in the industry,” he said. “No one has ever built a grid-level digital twin. Asset-level, yes, but not at the grid level.” 

AGILe’s research partners will include Electric Power Research Institute, NYISO, NYSERDA, the Long Island Power Authority and investor-owned utilities. Potential clients include vendors, innovators, universities and grid operators from around the world. 

Fees will vary by project details and by client, Mohammed said.