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.”
Rural electric cooperatives face challenges different from investor-owned utilities as they pursue clean energy goals, the leader of Tri-State Generation and Transmission Association said.
Tri-State CEO Duane Highley was the featured speaker in a May 28 webinar hosted by the American Clean Power Association. He pointed out that the customers served by cooperatives often are spread farther apart than IOUs’ customers and that the communities that cooperatives serve often have high rates of poverty.
Tri-State CEO Duane Highley | American Clean Power
But one of the biggest differences is coal, which is in the crosshairs of most decarbonization scenarios. The Power Plant and Industrial Fuel Use Act of 1978 had the effect of steering cooperatives toward coal-burning plants at a time when they were rapidly expanding generation capacity, Highley said. As a result, they are more reliant on coal than other power industry sectors.
“And now as we make a transition, it’s especially challenging because to reduce carbon emissions, we’re retiring coal, which for us is the majority,” he said. “So when you talk about, ‘Oh, just shut down your coal plant,’ what if that’s over half of your capacity in one plant?”
Forty-one of Tri-State’s 44 members are electric distribution cooperatives and public power districts. They serve more than 1 million customers across nearly 200,000 square miles in Wyoming, Colorado, Nebraska and New Mexico.
ACP CEO Jason Grumet asked Highley how Tri-State is managing its transition from coal to renewables.
Tri-State’s board and its member-owners were supportive of the move, Highley replied, as long as the result was reliable and affordable.
“So that’s what we’re doing, and we’re doing it at what I’d call light speed for a utility,” he said. “We … are building hundreds and hundreds of megawatts of wind and solar. And people who said ‘you can’t do that and keep the lights on’ are wrong. We’re able to do this and prove reliability at an accelerated level.”
To meet reliability needs, Tri-State is overbuilding renewables and looking forward to long-duration energy storage technology maturing, he said. And it is retaining fossil backup.
“We’re going to keep a lot of gas and oil generation around because we have to have it for reliability,” he said.
Tri-State’s proposed resource plan calls for a new combined cycle gas-burning plant with carbon capture and sequestration capacity retrofitted later.
Highley is excited about the potential of small modular reactors as well, again as a backstop for reliability. But he thinks they are at least a decade away and that cooperatives cannot be first adopters; someone else must take the risk of proving the concept.
Tri-State also needs to be in an RTO, to transfer power between regions and balance out spikes or lulls in intermittent power generation, Highley said.
“And that’s why we’ve been so much an advocate for promoting the western expansion of the Southwest Power Pool. And we believe it’ll be starting up the first quarter of 2026 in our area,” he said.
Along with the challenges unique to cooperatives, Highley laid out some that are common across the power industry: rapid growth of demand and constraints on transmission to meet that demand.
“There’s definitely growth coming, and it is exceeding what we had been previously forecasting,” he said, citing electric vehicles and overall electrification as the primary causes, along with data centers that can consume a gigawatt apiece.
“There’s just not a utility that I know of in the West that has a gigawatt of surplus capacity that they say, ‘Hey, I’m not using it right now. Would you like to hook up?’” Highley said.
“Plus the transmission question,” he added. “There are very few areas on the grid where you can drop hundreds of megawatts of load without making some significant transmission investments. And what we’ve seen in the past is it can take anywhere from five to 15 years to get a new transmission line built.”
Highley gave a nod to the state and federal policymakers who set decarbonization goals but don’t have to do the actual work of meeting them.
“We can make lots of growth. We just can’t make maybe as much as fast as people would like to see [in] some instances.”
The United States is a step closer to its first potential floating offshore wind farm.
The Bureau of Ocean Energy Management said May 28 it has completed its environmental assessment of the state of Maine’s request for a lease area where it could place a research array. It found the lease and the site assessment work that would be done on it would have no significant impact on the environment.
BOEM offered the state a research lease May 24. Maine must accept or reject BOEM’s offer or request modifications within 30 days.
Gov. Janet Mills (D) responded in a prepared statement May 28 that the lease offer is a “major milestone” for the state in its efforts to site offshore wind and that her administration looks forward to reviewing it.
Floating wind turbines are a relatively new technology only now beginning to be installed on a larger scale. The technology is still being developed and tested, and at this point it is more expensive and complicated than the fixed-bottom turbine technology that has come into widespread use worldwide over the past three decades.
For years, Maine has sought to be a leader in floating wind in the United States — as a way to extract emissions-free electricity from its lengthy but deep coastal waters and to build a new industry. (See Maine Finalizes Offshore Wind Roadmap.)
The University of Maine has been researching the concept and execution for more than a decade, and generated electricity with a downscaled turbine it set afloat in 2013/14.
In October 2021, Maine requested the research lease that has now been offered.
It would allow the state to place up to 12 turbines with a combined rating of up to 144 MW on up to 9,728 acres within a 34,596-acre research lease area 28 nautical miles southeast of Portland.
BOEM’s final environmental assessment determined the likely impacts of the research array would be negligible or negligible to minor.
In its news release, BOEM Director Elizabeth Klein said: “Floating wind technology can make offshore wind a reality in the Gulf of Maine. BOEM will continue to work in partnership with the state of Maine as we move forward to facilitate the responsible development of offshore wind in this region, as well as the deployment of floating offshore wind technology nationwide.”
In her press release, Mills said: “Offshore wind offers our state a tremendous opportunity to harness abundant clean energy in our own backyard, to create good-paying jobs and drive economic development, and to reduce our over-reliance on fossil fuels and fight climate change.”
As it advances Maine’s research lease request, BOEM simultaneously is setting the stage for commercial offshore wind development in the Gulf of Maine.
In April, it proposed an auction for eight lease areas totaling nearly 1 million acres and holding a potential 15 GW of capacity. Six of the eight commercial areas would be well south of the research area, closer to the outer arm of Cape Cod than to Maine. (See Wind Energy Lease Areas Designated in Gulf of Maine, Oregon.)
New Jersey Gov. Phil Murphy has directed the state Board of Public Utilities (BPU) to advance the opening of its fifth offshore wind solicitation by 15 months as the state scrambles to recover the time lost when Danish developer Ørsted abandoned two of the state’s first three projects.
Murphy (D) said advancing the solicitation from the third quarter of 2026 to the second quarter of 2025 “builds upon the momentum of the state’s growing offshore wind industry” as it strives to reach its goal of installing 11 GW of OSW capacity by 2040.
The May 28 announcement comes as concern about the effectiveness and public benefit of wind generation continues to surface at public hearings. It emerged at legislative budget hearings on the finances of the BPU and at a permit hearing for the state’s now-leading OSW project — Atlantic Shores — held May 14 by the state Department of Environmental Protection (DEP).
$125M Payment
The state has pushed ahead undeterred since October, when Ørsted abandoned two of the state’s first three OSW projects, Ocean Wind 1 and 2. The BPU awarded two new projects in January at the conclusion of its third solicitation. And within weeks of Ørsted’s withdrawal, Murphy directed the BPU to speed up the normal two-year cycle between solicitations and prepare for the fourth solicitation, which opened in April and will close July 10. (See New Jersey Opens 4th Offshore Wind Solicitation.)
Murphy said in a release announcing the accelerated timeline for the fifth solicitation that Ørsted has agreed to pay the state $125 million in a settlement to “release claims against each other arising out of or related to the Ocean Wind Projects.”
The developer has agreed to put $200 million into an escrow fund New Jersey could spend on other wind-related projects. The law also required the developer to post a performance security of $100 million for the completion of the project, which would be forfeited if the project failed to reach commercial operation. Lawmakers set up the provision to strengthen the requirements on Ørsted in return for the state allowing the developer to receive federal tax credits awarded to support OSW projects. The credits otherwise would otherwise have gone to help state ratepayers. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)
Gov. Phil Murphy (D) | Gov. Phil Murphy
Murphy also said the state would “pause” its planned second solicitation for offshore infrastructure projects using the State Agreement Approach (SAA), which would allow coordinated offshore wind transmission planning with regional grid operator PJM.
The BPU completed its first SAA process in October 2022, awarding $1.07 billion for transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid. BPU officials said it would save ratepayers hundreds of millions of dollars, but the solicitation award covered only upgrades to the landside portion of the transmission. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The BPU planned the second SAA to solicit coordinated transmission alternatives for the offshore portion of the transmission lines. But FERC on May 13 released Order 1920, the long-awaited final rule on long-term regional transmission planning and cost allocation. The order is of particular relevance to PJM’s ongoing interconnection queue reform process, Murphy said.
His release said he paused the SAA process to give BPU staff the “opportunity to fully evaluate the implications of the new FERC rule and participate in PJM’s process to ensure the best outcome to meet New Jersey’s transmission needs at the least cost to ratepayers.”
Efficiency Questioned
If all goes to plan, OSW projects now in the pipeline would account for about half — 5.25 GW — of New Jersey’s 11-GW goal. Aside from the 1,510-MW Atlantic Shores project, the state in January approved the 1,341-MW Attentive Energy Two project and the Leading Light project, with two phases of 1,200 MW each.
The state’s wind projects have faced opposition from the commercial fishing industry and tourism-related businesses. That skepticism was present at the May 14 hearing of the Senate Budget and Appropriations Committee, at which Republican senators pushed back on the BPU’s aggressive drive to line up wind projects. They questioned whether the state should launch an initiative in which it has little experience, for which the technology is new, and for which the eventual cost to ratepayers is unknown.
As he opened the hearing for lawmakers’ questions of BPU officials, Chairman Sen. Paul Sarlo (D), called the OSW projects “very controversial, as you know, politically charged” and queried whether the BPU is concerned the projects “may run the risk of not coming to fruition.”
Sen. Douglas J. Steinhardt (R), assessing the program’s recent history, was more direct.
“With so much uncertainty surrounding projects that are currently already underway, or were already underway and suspended, do you believe it is appropriate to open a new round of solicitation for future projects?” he asked BPU President Christine Guhl-Sadovy, referring to the fourth solicitation.
Given the rising costs, isn’t it “a bit sort of a quixotic quest and a tilt at windmills, no pun intended there,” he asked.
Great Opportunity
Guhl-Sadovy brushed aside his concerns.
“Offshore wind is really a once-in-a-lifetime opportunity to bring not only clean energy to New Jersey, but [also] billions of dollars in economic benefits, tens of thousands of jobs across the state, primarily in South Jersey,” Guhl-Sadovy said.
Sitting next to Guhl-Sadovy, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which has funded much of the state’s OSW infrastructure investment, faced questions about the agency’s determination to position the state as an East Coast leader in offshore wind, quickly building an industry from scratch.
“If this is a once-in-a-lifetime opportunity, it’s also a once-in-a-lifetime opportunity to get this correct, or catastrophically incorrect, in my opinion,” Steinhardt said.
Sullivan acknowledged the risks of offshore wind. “Anytime we’ve got a new capital-intensive, regulatorily complex industry, you’re going to see fits and starts.” But the state must “focus on the competitive dynamics here, because other states want this leadership position.”
At a May 15 hearing of the Assembly Budget Committee, Assemblyman Gerry Scharfenburger (R) said he’s concerned the state is transitioning from fossil fuels in favor of solar and wind energy, whose “intermittent” characteristics would create “economic and environmental problems down the road.” He questioned the Murphy administration’s “prioritization of wind turbines over, say, nuclear energy.”
“I have no affinity for fossil fuels,” he said, adding that “I would put goose droppings in my car if it would make it run … We just have to look for the best alternative that is viable, is fiscally doable and is going to be there. It can’t be intermittent.”
Guhl-Sadovy said there was no preference against nuclear, which would account for 40% of the state’s electricity generation in state clean energy plans. She said the BPU believes in the sector economics.
“As we look at the clean energy that we’re investing in … we are going to see an economic development come to the state of New Jersey,” she said.
Nuclear or not
The role of nuclear energy also surfaced at the DEP’s May 14 hearing seeking public input on the Atlantic Shores project. The agency is assessing the developer’s request for waterfront development, coastal wetlands and other offshore environmental permits, as well as onshore permits for a transmission cable to run to the Cardiff substation in Egg Harbor Township.
Dennis DeForest, a member of Save the East Coast, a New Jersey group that opposes offshore wind, said the projects would damage the marine environment, disrupt neighborhoods when cables are run through them and hurt tourism. He added that voters never had a chance to vote on the issue.
“There’s really no reason for us to use this unreliable energy,” he said. “There’s other ways to create energy, clean green energy, right, through nuclear, with small nuclear reactors.”
Henry Waldron, a resident of Brigantine, one of the communities closest to the proposed OSW development, said the state already is too reliant on electricity produced by burning fossil fuels, and much of the power is imported from other states. He said his hometown — a barrier island near Atlantic City — already is affected by rising sea levels and damage to the beaches.
“New Jersey is already in a deficit for electricity,” he said, foreseeing brownouts by the middle of this decade.
“People talk small modular reactors,” which could be ready by 2040, but “big nukes” would take much longer, he said. “I don’t see anybody who’s yelling against wind offering their communities for more nuclear reactors. And a nuclear reactor would take 12 years (to build).”
NV Energy will commit to joining CAISO’s Extended Day-Ahead Market (EDAM), sources have told RTO Insider, a move that will end months of speculation among Western electricity sector stakeholders about whether the Nevada utility would choose EDAM over SPP’s Markets+.
The utility plans to make its intent public May 31 when it files an integrated resource plan with the Public Utilities Commission of Nevada, multiple sources closely involved with market developments in the West said.
NV Energy did not respond to a request for comment on the matter, a topic of increasing interest in the region, with multiple sources recently telling RTO Insider that the utility has been revealing its decision in favor of EDAM in private meetings. An NV Energy executive offered the clearest public signal yet on the utility’s leaning during a May 22 joint session of the CAISO Board of Governors and Western Energy Imbalance Market (WEIM) Governing Body. (See Is NV Energy Leaning to CAISO’s EDAM?)
The selection still must be approved by the PUCN. A 2021 Nevada law requires the utility to join an RTO by 2030, with the decision subject to approval by the commission, which has been hosting workshops exploring the two day-ahead market options in the West as part of its RTO proceeding. (See Nevada RTO Proceeding Examines EDAM, Markets+ Design.)
At one of those workshops, the Brattle Group presented data showing NV Energy stood to gain $62 million to $149 million in annual economic benefits from joining the EDAM, while it stood to lose as much as $100 million from withdrawing from CAISO’s Western Energy Imbalance Market (WEIM). The results of joining Markets+ ranged from a loss of $17 million compared with the status quo to a benefit of $16 million. (See Nev. RTO Effort Turns Focus to NV Energy Day-ahead Studies.)
Big Win for EDAM
NV Energy’s decision spells a major victory for the EDAM in its ongoing competition for members with SPP’s Markets+ day-ahead offering.
The utility serves the majority of Nevada’s electricity users and is the balancing authority for the state. Its control area occupies a central position in the WEIM, functioning as the primary wheel-through point for energy transfers between the WEIM’s California participants — including the ISO — and PacifiCorp’s sprawling balancing authority area in the inland West.
PacifiCorp in April became the first entity to agree to sign an implementation agreement for the EDAM, sealing its participation in the market. (See PacifiCorp Fully Commits to CAISO’s EDAM.)
NV Energy’s membership in EDAM also would be consequential for Markets+ because the utility’s BAA sits between the territories of the entities that have shown the most interest in joining the SPP-run market, including the Bonneville Power Administration and Puget Sound Energy in the Northwest, and Arizona Public Service, Salt River Project and Tucson Electric Power in the Desert Southwest. The inclusion of Nevada’s transmission network in EDAM would limit the ability of those entities to transfer energy among each other in a geographically divided Markets+.
The decision also is significant for the West-Wide Governance Pathways Initiative. Backers of that effort in April issued a proposal to make stepwise changes to the governance of the WEIM/EDAM, with the objective of eventually putting the market under the authority of an independent “regional organization” after seeking changes to California law related to CAISO. (See Pathways Initiative to Act Fast on ‘Stepwise’ Governance Plan.)
But step 1 in that proposal entails elevating the “joint” authority the WEIM’s Governing Body currently shares with CAISO’s Board of Governors over WEIM matters to “primary” authority. Under the plan, the ISO would pursue that change with FERC only after the EDAM secures implementation agreements with a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO BAA annual load in 2022. With commitments from PacifiCorp, Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric, NV Energy has been cited by Pathways supporters as the entity needed to trigger that move.
NV Energy’s filing with the PUCN on May 31 will coincide with a monthly meeting of the Pathways Initiative’s Launch Committee, at which the committee is expected to vote on adopting step 1 of the governance proposal.
