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.
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.”
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.
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.
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.
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.”
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.”
“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!’”
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.
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.
“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.
The Biden administration on May 28 launched an effort to work with 21 states to help roll out advanced grid technologies.
The states participating in the Federal-State Modern Grid Deployment Initiative all have Democratic governors, who have committed to support the adoption of advanced grid solutions that expand capacity and add new capabilities to existing and new transmission and distribution lines.
The White House also held a summit on modernizing the grid with industry, regulators and other stakeholders focusing on advanced conductors, dynamic line ratings (DLR) and other grid-enhancing technologies (GETs).
“We think this is the lowest-hanging fruit of being able to get additional capacity on the grid and for the least amount of money,” Energy Secretary Jennifer Granholm said at the White House summit. “So, there’s no reason not to love grid-enhancing technologies.”
The Department of Energy is working to help utilities get comfortable with the technologies by testing advanced reconductoring at Idaho National Laboratory, with the Electric Power Research Institute and at the Georgia Institute of Technology.
The agency also recently released one of its “liftoff” reports on GETs, which said the technologies by themselves could meet the projected demand growth over the next decade, Granholm said. (See DOE Report Highlights Benefits of Advanced Technologies.)
Alongside the announcement, the U.S. Climate Alliance — a group of 24 states that includes the 21 in the initiative — said it would offer policy, technical and analytical assistance to help participating members carry out their commitments.
The states in the initiative agreed to deploy innovative grid technologies to bolster the capacity of the electric grid and more effectively meet demand, maximize the benefits of new and existing transmission infrastructure, increase the grid’s resilience to the growing impacts of climate change, and better protect consumers from volatility in energy prices.
FERC’s recently issued Order 1920 included a requirement that transmission planners evaluate their use in regional plans. In a recent interview on the order, Johannes Pfeifenberger, a principal at The Brattle Group, said GETs could be a key part of controlling transmission costs.
“And then you can create another third by sort of upgrading existing lines to higher voltages and things like that,” Pfeifenberger said. “And then the last third of doubling our transmission capability, then you’d have to build new lines. But we cannot afford to ignore the lower cost.”
LineVision CEO Hudson Gilmer said in an interview that dividing the grid buildout into thirds makes sense, though he thinks the monitors his firm sells to enable DLR are so affordable they could be used on new transmission lines to maximize those investments.
The firm has worked on dozens of projects in the U.S. and around the world, with two major domestic efforts being with AES utilities in Ohio and Indiana and National Grid in upstate New York, Gilmer said before the White House event.
LineVision is developing other projects, and Gilmer explained why he sees growth for the industry.
“The biggest thing that gives me optimism is the experience of the utilities [that] have deployed these technologies,” he said. “And they’re not one and done. They’re not stopping there. They’re saying, ‘We’re seeing amazing results here, and we want to roll this out more and more widely.’”
Dominion Energy’s Virginia Power utility is on pace to double its demand in the next 15 years, driven in large part by the rapid expansion of data centers in Data Center Alley about 30 miles west of the White House, said Matthew Gardner, the company’s vice president of electric transmission. He said that’s just half the challenge because the utility also sees its supply transition along with the most active interconnection queues in PJM.
“In addition to capacity, we look at the promise of GETs to provide … capability and flexibility as well,” Gardner said. “So that’s where GETs come into play.”
‘Absolutely Essential’
Dominion has run a number DLR pilots over the past decade, some of which have shown that some of its operational assumptions were too conservative because it found more capacity than expected. But the opposite has occurred in other cases, with some assumptions being too loose and requiring a reduction of flows on lines. In general, Dominion has seen the technology either open up or lower line capacities by 10 to 12%, Gardner said.
“DLRs are key to maximizing grid capabilities, especially those in situations where we’re taking outages for constructing grid upgrades,” Gardner said. “So, I like to think of DLR as being like flex lanes on the interstate that sometimes allow for additional traffic flows.”
GETs are poised to keep growing in Virginia because of recent legislation passed by both Democratic-controlled legislative chambers and signed by Gov. Glenn Younkin (R), said state Del. Phil Hernandez (D) at the White House summit.
“So really all this bill does … it says that anytime that a utility submits an IRP as part of their long-term energy planning, they have to do a comprehensive assessment of the potential application of grid-enhancing technologies,” Hernandez said. “So that is a first step for us.”
GETs have avoided the politicization accompanying transmission issues, as seen on Capitol Hill or in the dissent and concurrence related to FERC Order 1920, or with a bill passing unanimously out of the Utah Senate, though it ultimately did not clear the lower chamber this past session, said state Sen. Nate Blouin (D). The legislation was similar to what Hernandez helped push through in Virginia.
The conservative “Eagle Forum” usually does not get involved in energy issues, and Blouin said it has opposed many of his proposals in the past.
“One of their representatives got up to speak on my bill,” Blouin said. “And I was just thinking, ‘Oh, shoot, what’s he going to say about this one,’ and actually, it was a really positive comment. They were … very interested in the potential grid security and resilience-type aspects.”
The tool is resource-agnostic, which is important for states like Utah where the climate issues are not top of mind, but it still can help meet growing demand and provide resilience against issues like wildfires, he added.
But GETs can help in states with very different policies, such as California, where climate laws require the industry to bring on about 8,000 MW of renewable resources per year on average, but reliably and cost effectively, said CAISO CEO Elliot Mainzer.
GETs are in a place like where storage was just a few years ago — ready to take off, Mainzer added. California has 10 GW of storage now, while GETs are starting to be included in some of its regionally planned transmission projects.
“The way that our grid is operating today is transitioning so quickly,” he said. “Any of you that operate in the West, just the patterns of flows that we’re seeing, the type of generation on the grid — having this sophisticated portfolio of tools that can manage flows and manage this next generation of resources and do it honestly, reliably and as affordably as possible is absolutely essential.”
ERO officials urged state policymakers in a webinar to work with their utilities and regional entities to understand the reliability challenges and opportunities presented by the transition to renewable energy resources.
The May 29 webinar was hosted by Midwest Reliability Organization CEO Sara Patrick, with participation by NERC, ReliabilityFirst and SERC Reliability, with the goal of giving state regulators a clearer picture of how grid reliability has been affected by the deployment of inverter-based resources (IBRs) such as wind, solar and battery facilities.
Howard Gugel, NERC’s vice president of regulatory oversight, emphasized that “education is key” and recommended the regulatory community learn “as much as [they] can about these resources, how they’re going to be interconnected and integrated … and how your state policy can help influence” the reliability impact to end users.
Gugel pointed out that summer peak demand in North America increased by 3% between 2012 and 2022, according to NERC’s analysis, while peak capacity decreased by 4%. In addition, wind, solar and batteries grew as a share of generation from 2.9% in 2012 to 9% in 2022, while the share comprising coal and oil shrank from 34.2% to 22%.
The growth of IBRs and retirement of traditional generation has significant implications for reliability, Gugel explained. During a “wind drought” last year in ERCOT, SPP and MISO, installed wind generation with a total capacity of 60 GW generated only 300 MW at some points, he said. With demand likely to continue growing, especially in areas where transportation and heating are transitioning quickly to electricity, Gugel said policymakers need to understand the implications of renewable energy mandates.
“At this point, we’re retiring generation faster than we’re putting it on. And there’s going to be a point at which there’s not going to be excess energy available there,” Gugel said. “And so we’ve [all] got to work together to ensure that we’re getting adequate capacity and energy installed in the system to meet the needs of our customers and to keep those lights on at all times.”
The task is not as simple as replacing retired baseload generation with equivalent solar or wind capacity, Gugel added, presenting a simple example of 100 MW of baseload. Assuming the sun shines for eight hours, to replace this generation, a utility must provide 100 MW of solar capacity, 400 MW of batteries to discharge at the same rate during the night and an additional 200 MW of solar just to charge the batteries for eight hours.
Gugel reiterated that NERC is doing its part to address IBR-related reliability concerns, citing the ERO’s work on developing registration criteria for the new resources and reliability standards to address their performance concerns. (See NERC Says IBR Work Proceeding as Planned.) Other presenters pointed out that IBRs also can be assets for reliability, noting their responsiveness compared to traditional generation.
Asked by Patrick about the cost of complying with the new standards, Gugel acknowledged states must recognize this potential burden but should not let it stop them from implementing the policies to safeguard the grid for the future.
“There’s going to be a cost for compliance with any type of regulation [that] will be rolled into [electric] rates,” Gugel said. “I don’t expect that to be substantial, but I’m not going to sit here and say that it’s not going to cost anything. But frankly, all existing generation has a cost for compliance. … So there will be somewhat of a cost for this, but it’s small, based on the reliability benefit that we’re going to receive from it.”
A recent study from the U.S. Department of Energy finds that managed charging ― that is, shifting the time electric vehicles charge to off-peak hours ― could be critical to controlling the costs of building charging networks and local electric distribution systems needed to power them.
By 2032, those rules could put an extra 3.9 million plug-in EVs of all classes on the road in those states ― bringing the cross-state total to 20 million EVs ― along with 2.3 million additional EV chargers. But, the study finds, managed charging could halve the number of new substations needed and cut additional grid investments by $700 million.
The study provides even more granular figures, based on a unique “bottom-up” methodology developed by Kevala, a grid analysis firm, which partnered with the National Renewable Energy Laboratory and the Lawrence Berkeley National Laboratory on the project. Drilling down to the parcel level, researchers were able to model the kinds of chargers that might be installed on individual feeders between 2027 and 2032.
Again, managed charging could cut the number of extra feeder lines needed ― to carry power from substations to end users ― from 125 to 75, and the number of additional service transformers needed from 30,000 to 21,000.
As defined in the study, managed charging not only shifts the time when charging occurs, but also minimizes its speed “such that the session is completed just prior to [an EV’s] departure from that location.”
The study also notes that managed charging programs are best suited to home and commercial depot locations, where EVs are parked on a regular schedule and therefore “are considered most likely to have margins for adjusting charging speed without negatively impacting vehicle availability.”
The resulting reductions in peak demand could be significant. Rather than demand spiking in the late afternoon or early evening, when EV owners arrive home and plug in their cars to recharge, managed charging could keep demand curves relatively flat, with some variation throughout day.
While the study is limited only to the effects of EV power demand and managed charging on distribution systems, the flexibility provided could have even broader system benefits when combined with other distributed energy resources on a feeder, said Troy Hodges, a data science manager with Kevala.
“One last benefit of doing this at the parcel level is not only do we know which vehicles are on those feeders, but we also have … simulated the non-EV loads on the feeders,” Hodges said during a May 22 webinar on the report. “So, from there, we can start modeling a managed charging technique that is more responsive to the dynamic needs of particular equipment on the grid.”
In one model scenario incorporating non-EV loads, the study found “further distribution cost savings, particularly on high-EV-penetration feeders,” Hodges said. In one example in California, managed charging incorporating non-EV loads cut peak demand by an additional 25%, he said.
Flattening the duck: The DOE study also looks at the impact of managed charging on California’s famous duck curve. | DOE
“It really drove home the value on these high-penetration EV residential areas or commercial areas with fleet depots,” Hodges said. “This type of more advanced, active control approach could really have a big impact.”
First Time, Every Time
Distribution grid planning has emerged as a vital part of EV charger installation, with lack of capacity on local systems slowing the deployment of chargers along the nation’s highways. Funded with $5 billion from the Infrastructure Investment and Jobs Act, the National Electric Vehicle Infrastructure (NEVI) program was created to help build out a network of 500,000 direct current (DC) fast chargers on major routes by 2030, but to date has installed eight stations with a total of 33 charging ports in six states.
In its most recent NEVI update, the Joint Office of Energy and Transportation estimated the U.S. now has more than 183,000 public charging ports, but fewer than a quarter of those — 41,065 — are DC fast chargers. In addition, 9,472 public chargers, both Level 2 (L2) and DC fast chargers, are classified as “temporarily unavailable” — that is, not working.
Depending on the EV and capacity of the chargers (NEVI-funded chargers must be at least 150 kW), DC fast chargers can recharge a battery to 80% capacity in 20 to 60 minutes. Typically used for home or workplace charging, L2 chargers can take several hours to repower an EV.
The Multi-state Study is one of several DOE initiatives aimed at overcoming barriers to more rapid expansion of charging networks, efforts that have become increasingly urgent as the November election looms and growth in EV sales has slowed. According to Kelley Blue Book, Americans bought 268,909 EVs in the first three months of 2024, up a modest 2.6% over the first quarter of 2023, when EVs scored a 46.4% jump over the first quarter of 2022.
Along with price, consumers’ concerns about EVs’ range and charger speed and availability are the most commonly cited brakes on the wider adoption of electric vehicles, Kelley said.
DOE and the Joint Office launched the National Charging Experience (ChargeX) Consortium in August 2023 to help consumers get over those bumps. A public-private initiative, the consortium is focused on ensuring “that any driver of any EV can charge on any charger and have it work the first time, every time,” said ChargeX Director John Smart.
The group includes industry stakeholders, along with consumer advocates, academics and state government officials, who collaborate on “complex issues … that no single company can solve on their own,” Smart said during a May 23 webinar providing a progress report on the group’s efforts.
“To truly understand the customer experience, we need more metrics … that are used and measured uniformly across the industry, so that everyone’s speaking the same language, so that we’re properly measuring and therefore improving the customer experience,” Smart said.
Top priorities include developing minimum standards ― or key performance indicators (KPIs) ― that will provide the benchmarks needed to make charging more predictable and reliable.
Breaking down the KPIs
Frank Marotta Jr., assistant manager for charging network reliability at General Motors, detailed how the consortium breaks down a customer’s experience at a charger into discrete elements, each with its own KPI.
“How effective are the mapping tools drivers can be using to locate the station? How effective are they at actually getting the vehicle right up to the plug?” Marotta said.
“We have waiting probability, which is basically the probability that at least one port might be available to deliver energy when the EV arrives,” he said. “And under starting to charge, we have two KPIs … one that is meant to measure the effort required to actually start the charging session and then … the time required to actually get that session initiated.”
Another priority is communication between EVs and chargers, and chargers and the cloud, Smart said. “What is needed to allow the industry to scale, and specifically as more makes and models of chargers come to market and more makes and models of electric vehicles, how do we ensure that they all work together going forward?”
The answers will include better sharing of diagnostic data between stakeholders and improving interoperability “to efficiently verify that every charger works with every vehicle,” Smart said.
Market growth and the resulting need for interoperability and better grid planning are coming. While only a handful of NEVI projects are online now, the Joint Office has reported that 36 states have at least issued their first solicitation for chargers, and 23 have made conditional awards or agreements for more than 550 charging stations, each with four or more ports.
U.S. public EV charging ports by month | Joint Office of Energy and Transportation
The Joint Office’s checklist for state planners includes early communication with utilities to prepare for the interconnection of NEVI-funded stations.
Also, consumer range anxiety could begin to taper off, with DOE reporting that 19 EV models that were on the market in 2023 could travel 300 miles or more on a charge, up 35% from 14 such models in 2022.
While noting that “everything about EVs is controversial,” Kelley expects market growth to continue, driven by the increase in available models and some price reductions. The slowdown could be a sign that EVs are becoming mainstream in some parts of the country, Kelley said. “Segment growth typically slows as volume increases.”
