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November 8, 2024

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WPP Shares First Stats from Western RA Program

The Western Power Pool discussed the results of its first regionwide analysis of the Western Resource Adequacy Program (WRAP) with stakeholders Tuesday, including a look at the changing resource mix through 2027 and the need for higher planning reserve margins in the Desert Southwest.

“We are going to be an inch deep and a mile wide, so you should think about this as a survey or 101 overview of the metrics,” Ryan Roy, WPP director of technology, modeling and analytics, said while introducing the webinar.

“We’re going to talk a little bit about the loads and resources in the WRAP footprint,” Roy said. “We’re going to provide an overview of the installations and nameplate [capacity] for wind and solar, give you a feel for the number of units and number of plants that are out there.”

The WPP also provided an overview of the qualified capacity contributions (QCC) and effective load-carrying capability (ELCC) values for each resource class and of planning reserve margin values by region and month.

“This is relatively new for the Western Power Pool,” Roy said. “We’re working our best to ensure that the data is accurate, informative and timely. We’ve made a strong commitment to transparency. So, this is our first opportunity to talk about the broader regional results that we’re seeing in our modeling.”

Among the results:   

For the Northwest, from 2023/24 through 2026/27, additional hydroelectric output will compensate for the retirement of most remaining coal plants, which will make up 2.07% of the resource mix in 2023 but .06% a few years later.

The Southwest, with a much different supply stack, will add solar and short-term battery storage from 2023 to 2027. The region will see a reduction in coal generation but still retain coal as a sizable portion of its resource mix, going from 24% in 2023/24 to 17% in 2026/27.

“The Northwest has planned resource retirements that can impact the capacity available to meet that one event day in a 10-year loss-of-load expectation, and the Southwest [will see a] significant increase in [solar and battery] resources.” Roy said. “They have very aggressive plan-to-build targets.”

An assessment of resource classes showed the WRAP footprint has a total of 146 wind plants with a nameplate capacity of 12,688 MW and 267 solar plants with 11,162 MW of capacity.

Peak loads in the Northwest top out at 41,502 MW during winter and in the Southwest at 37,434 in summer.

Planning reserve margins in the Northwest will not alter significantly in the four-year period covered in the analysis, but the Southwest will need to increase its PRM values to compensate for the infusion of variable solar resources, WRAP said. PRMs in the Southwest, for instance, will need to increase from 20% in November 2023 to 32% in November 2026, a slide in the presentation showed.  

The webinar also included a detailed discussion of the ELCC and QCC of various resource classes by region and month. 

‘Above the Line’

The presentation was a milestone for WRAP, the first broad-ranging resource adequacy program in the West.

WPP, formerly the Northwest Power Pool, started work on the effort two years ago amid concerns that Northwest utilities were increasingly and unknowingly drawing on the same shrinking pool of reliability resources.

Interest in the effort spread quickly to other areas of the West, and in a move that signified its expanding reach across the Western Interconnection, the Northwest Power Pool rebranded itself as the Western Power Pool earlier this year.

The program now has 26 participants from British Columbia to Arizona and east to South Dakota, including major players such as Arizona Public Service, the Bonneville Power Administration and PacifiCorp. CAISO, however, is not involved.

NWPP-Wrap-(NWPP)-FI.jpgWPP’s WRAP program has 26 participants covering much of the Western Interconnection. | NWPP

WPP and SPP plan to launch a “nonbinding” iteration of WRAP soon, one that lacks enforcement and penalties, and a binding phase in 2024, in which participants will be held accountable for failing to meet their expected resource contributions.  

WPP’s board approved a tariff for WRAP last month and is hoping for FERC approval by the end of the year.

SPP, which WPP chose last year as a program operator, provided the modeling and metrics discussed Tuesday.

“Current WRAP participants are completing the non-binding Winter 2022-2023 and Summer 2023 forward-showing submittals using the just-released metrics as a guide to meet program requirements,” WPP said in a news release. “Participants will turn in workbooks to SPP for evaluation and feedback. WPP and SPP intend to release aggregate performance information from these non-binding submittals once complete.” 

Stakeholder comments in Tuesday’s webinar included a question from Fred Heutte, senior policy associate at the Northwest Energy Coalition, asking organizers why they had not summarized data by participant, showing those that have or lack sufficient qualifying capacity, and whether participants will have access to that data going forward.

“Who’s above the line?” Huette said. “Who’s not, for example?”

Rebecca Sexton, WPP director of reliability, responded that public release of the data could impact purchase negotiations between parties.

“There’s just too much sensitivity about that,” Sexton said. “You can imagine that if someone is being shown to the region as slightly deficient, that that just opens a whole can of worms with respect to how their conversations with folks go who might have some capacity they are willing to sell them.

“So, that sensitivity is one we want to be really aware of. We don’t want to have a negative impact on their participation in any market, bilateral now, certainly, or bilateral in the future as well, as we think about this forward procurement, so we will not be sharing that information.”

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FERC Reluctantly Proposes Cybersecurity Incentives

FERC reluctantly issued a Notice of Proposed Rulemaking on Thursday to consider a 200-basis-point incentive for utilities that make voluntary cybersecurity investments, an initiative directed by Congress in last year’s Infrastructure Investment and Jobs Act (RM22-19).

Expenses and capital investments in advanced cybersecurity technology that “materially improve” a utility’s cybersecurity posture and are not already mandated by NERC’s Critical Infrastructure Protection (CIP) reliability standards, or local, state or federal law, would be eligible for the incentives. Also included would be expenses for participating in cybersecurity threat information-sharing programs.

‘FERC Candy’

Chairman Richard Glick and Commissioner Mark Christie said they were reluctantly supporting the NOPR because of Congress’ directive.

Glick said NERC’s mandatory reliability standards have “proven to be a pretty effective approach,” although he acknowledged that it can take too long to respond to emerging threats by amending the CIP standards.

“I think that, if it is important that utilities make investments, or if it’s important that utilities participate in these information-sharing groups, we need to explore whether we need to utilize our mandatory reliability standards approach to get there,” Glick said. “And that that was my preferred option.”

He cited the commission’s 2019 technical conference on cybersecurity incentives, where he said numerous utilities said they had not encountered problems recovering their costs from FERC or state regulators. (See Mixed Reaction for ‘Resilience Incentives’.)

“I’m not totally sure the incentives approach is the way to go, given the significance of these types of investments,” he said.

The NOPR proposes that utilities choose between a return on equity (ROE) adder of 200 basis points or deferred cost recovery, allowing it to add the unamortized portion of the expenses to its rate base.

The commission acknowledged that a 200-basis-point adder exceeds the ROE incentives for transmission facilities. But it said that “given the relatively small cost of cybersecurity investments compared to conventional transmission projects, a higher ROE may be necessary to affect the expenditure decisions of utilities, without unduly burdening ratepayers.”

“Two hundred basis points — that is a lot,” said Christie. “As you know, the ROE already is supposed to represent the market cost of equity capital, and now you’re going to give them 200 basis points on top of that for doing what they ought to do anyway? I mean, there’s a reason why these adders over the years have come to be known as ‘FERC  candy.’ They’re really sweet for those who get it, but not to consumers who have to pay for it. Pretty sour for consumers. …

“I acknowledge the statute says create an incentive,” he added. “One might make the case that the rate treatment itself is a pretty good incentive.”

Commissioner James Danly said that because of the time it takes to enact new mandatory reliability rules, “of all of the challenges that NERC faces, maybe cybersecurity is the one for which NERC is the least apposite.”

Willie Phillips (FERC) FI.jpgFERC Commissioner Willie Phillips | FERC

“So the question becomes, if that is an inapposite  tool — and I would argue that it probably at least partially is — is the provision of FERC candy the proper way to incentivize the rapid immediate response that I think is the policy that is being driven at here? And the fact of the matter is, I do not know. We have to see what the comments are.”

Commissioner Willie Phillips, a former NERC assistant general counsel, said the CIP standards are “a great foundation. The problem is, as everyone has pointed out, they just take too long. …

“We absolutely need to make sure that our utilities don’t do the bare minimum, but that they’re reaching for the sky,” he continued. “What we don’t want to do … is look back years from now, in the wake of some catastrophic, successful cyberattack, and say, ‘If only we had done a little bit more.’”

Prequalified Expenditures

FERC proposed creating a prequalified list of cybersecurity expenditures eligible for incentives with a rebuttable presumption of eligibility. It said it would initially include on the list expenses related to participation in the Department of Energy’s Cybersecurity Risk Information Sharing Program and those for internal network security monitoring, which it said “may better position an entity to detect malicious activity that has circumvented perimeter controls.”

Incentives would generally last as long as the underlying assets are depreciated, with a maximum of five years. Technologies that “may be innovative and/or above and beyond industry standards at one time … may subsequently become conventional, mandatory or even antiquated and therefore may be less deserving of an incentive over time,” the commission said.

The commission also asked for comment on whether cyber incentives should be through performance-based rates. “In particular, we seek comment on whether any widely accepted metrics for cybersecurity performance could lend themselves to be benchmarks needed for performance-based rates, or whether new appropriate metrics could be developed,” it said.

As a result of the NOPR, the commission voted to terminate a previous cybersecurity incentives proposal it opened in December 2020 (RM21-3). (See Industry Warns of Hidden Dangers in Cyber Incentives.)

Comments on the new NOPR will be due 30 days after publication in the Federal Register, with reply comments due 15 days after that.

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Bottlenecks, Cybersecurity, EJ Top of Mind for FERC’s Phillips

NEW YORK — Geopolitics, tackling energy bottlenecks and increasing consideration for environmental justice are novel forces that FERC is now contending with, Commissioner Willie Phillips told an Institute for Policy Integrity conference on Tuesday.

Phillips said the U.S. is “in the middle of an energy transition,” driven by a shifting global energy landscape caused by the war in Ukraine, rising inflation and supply chain issues, all while the Biden administration advances “landmark legislation.”

The past few months have been a “historic period,” and the U.S. is now at a “turning point” where the nation must decide if “we’re ready to make decisions … that help empower the clean energy transition” and address growing crises.

Growing Crises 

The energy crises in Europe and the U.S. represent the first serious challenges in the “net-zero clean energy transition period.”

With Europe confronting staggering increases in energy prices, Phillips pointed to the impact on areas in the U.S., such as New England, where the natural gas-dependent electric sector confronts resource adequacy challenges and high fuel costs as LNG is increasingly exported to the European Union to cover shortfalls in Russian supplies. Phillips said that in recently visiting the region he found that stakeholders were “really hoping for a mild winter.”

Willie Phillips (Institute for Policy Integrity) Content.jpgFERC Commissioner Willie Phillips | Institute for Policy Integrity

Furthermore, other contemporary problems, such as cybersecurity, aging infrastructure, a global pandemic and rapidly advancing technologies, are challenging FERC to remain committed to its duties.

Phillips pointed out, however, that FERC is “addressing all of these issues.”

FERC has responded to the crises “head-on,” Phillips said, and recent legislation, such as the Inflation Reduction Act and last year’s Infrastructure Investment and Jobs Act, has given FERC the ability to help accelerate electric vehicle and renewable deployment, better respond to climate impacts and invest more in disadvantaged communities, while still prioritizing the agency’s guiding principles to provide reliable, affordable and sustainable energy.

Phillips likened those three principles to the “three legs of a stool” that are critical to FERC’s “overall operation.”

FERC’s Challenges 

Phillips explained that FERC’s top challenge will be solving transmission and interconnection reform because the buildout of needed infrastructure for clean resources will be “costly and it’s going to take time.”

FERC is accelerating transmission processes and tackling generator interconnection queue backlogs by encouraging RTOs and ISOs to take a more long-term view that considers state public policy goals and looks “at the reality on the ground,” he said

Interconnection queues have been a “bottleneck” that prevents the U.S. “from unleashing the full potential all of the renewable resources” that currently wait in queue.

FERC is “uncorking” this problem and has proposed “moving away from a serial approach to a cluster approach,” where projects are reviewed not on “a first-come, first-served basis, but a first-ready, first-served basis.”

The next challenge is cybersecurity, which has become increasingly important after Russia’s invasion of Ukraine.

According to Phillips, FERC is using a “two-pronged approach” to ensure grid cybersecurity: mandatory reliability standards and constant stakeholder collaboration. This ensures critical systems are secure and the U.S. avoids another hack like that which shut down the Colonial Pipeline last year.

Environmental Justice

The last challenge is the rising importance of environmental justice (EJ) and the increasing need to consider the environmental and economic impacts that the energy transition is having on disadvantaged communities.

Phillips, who previously served as chair of the D.C. Public Service Commission and was unanimously confirmed by the Senate last November, shared how his rural Alabama background gave him insight into the looming challenges that come with providing reliable energy to disadvantaged communities.

He said is glad that EJ is getting “more and more attention” because his own firsthand experience has shown the positive impact that government regulations can have on homeowners and landowners.

Phillips said that providing clean, sustainable, affordable and reliable energy to disadvantaged communities is always “top of mind,” and he asked industry stakeholders to focus on EJ. He explained that he is paying attention to businesses’ commitments to workforce development, board diversity and entry-level representation, as these have been shown to increase profit and innovation in those communities.

Phillips emphasized that transparency, financial disclosures and targeted communications around decision-making processes will help cultivate environmental justice.

Jeremiah Baumann (Institute for Policy Integrity) Content.jpgJeremiah Baumann, DOE | Institute for Policy Integrity

Additionally, he called on people to “comment, comment, comment” and put their concerns on the record because it helps the commission “sharpen its considerations” and better understand “where pockets of public interest lie.”

EJ concerns were echoed by other speakers, such as Jeremiah Baumann, chief of staff to the undersecretary for infrastructure at the U.S. Department of Energy.

Baumann stated in his panel that the Biden administration “has made commitments that center on key communities, particularly environmental justice communities disproportionately impacted from pollution and those that are liable to be left behind in the clean energy transition, such as timber or coal communities.”

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Texas Lawmakers to Vet ERCOT Market Redesign

The head of Texas’ Public Utility Commission told state lawmakers last week they will get a chance to vet ERCOT’s market redesign early next year before it becomes operational.

During a joint hearing on Sept. 13 before the Texas House of Representatives’ State Affairs and Energy Resources committees, PUC Chair Peter Lake said he intends to publicly present the proposed market design in November. That will give stakeholders, who are expecting the proposal to drop after the Nov. 8 mid-term elections, just enough time to comment before the holiday season’s quiet period.

State Rep. Phil King (R) pressed Lake on whether lawmakers would have a chance to pass judgement on the market design when the 88th Texas Legislature begins Jan. 10. He said his biggest concern is the uncertainty investors see in the market’s future design.

“We’re trying to get people to invest in the market. I think it’s critically important before anything gets implemented that the legislature have a role in affirming that because, otherwise, you’re not going to have certainty for the industry going forward,” King told Lake. “At the end of the day, there just needs to be a marriage between what the PUC comes up with and what the legislature wants. And if there’s not, we’re just going to create a lot of confusion.”

“We would be grateful for that affirmation when it gets to that point,” Lake said. “We’ll always be mindful of how damaging uncertainty in the investor marketplace can be. It’s taken us a long time to get to this point. I want to start putting steel on the ground as soon as possible.”

“Many legislative members would rather these kinds of major policy changes not be made at the agency, asserting that is their domain,” tweeted Austin-based energy consultant Doug Lewin.

Lake said the commission has already received the first component of a consulting firm’s review of the proposed design. He said the commissioners “synthesized” that report and have sent it back to the consultants to “iterate and continue narrowing the filter … to drive towards a final market product.”

“We’ll present a final product to you all that is as ready as possible to be plugged into ERCOT,” Lake said.

The Phase II proposal has sometimes been described as a “capacity-light” market with a load-side reliability mechanism and a backstop reliability service. (See PUC Forges Ahead with ERCOT Market Redesign.)

Coincidentally, E3 Consulting, which is reviewing the PUC’s proposal, also developed the load-side reliability obligation mechanism that may be the central part of the market design. E3’s proposal introduces a formal reliability standard for load-serving entities and a mechanism to ensure sufficient resources to meet this standard.

“It seems to make sense that the companies that get paid for providing power should do it reliably, and so that’s what we’re working through now,” Lake said, noting the commission unanimously approved the Phase II design last December.

Brad-Jones-2022-04-19-(RTO-Insider-LLC)-FI.jpgERCOT CEO Brad Jones | © RTO Insider LLC

“The blueprint … is designed so that we can go through the different iterations with these consultants to capture the features of each concept and integrate those into a hybrid while discarding the flaws,” he said.

Speaking on the same panel with Lake, ERCOT’s Brad Jones — interim CEO “at least for the next 17 days and five hours,” he said when introduced — defended his proposal to add a gas desk to the grid operator’s control room. Jones has been publicly promoting the idea of ERCOT operators monitoring gas availability and restrictions for gas-fired power plants as early as January.

“There’s not a great deal of transparency around the operations of our natural gas system. That information doesn’t usually flow to us,” Jones said in January during an education session for the Board of Directors. (See ERCOT Preps for 2nd Cold Snap of Year.)

‘They Want it to Stay Private’

Gas industry representatives pushed back during the hearing against the desk and a similar proposal for a gas market monitor.

“As an agency, we don’t understand what a gas desk and a market monitor is because we are in a free market in the state,” said Christi Craddick, who sits on the intrastate gas-regulating Railroad Commission. “I’m not clear what a gas desk or an independent market monitor is, [or] how that would resolve or make the electricity grid even more reliable. That’s not clear to me.”

Rep. Tom Craddick (R) from gas-rich West Texas, who is also Christi Craddick’s father, said he does not want a gas desk proposed until the legislature can opine on it.

“I believe it’s a policy change,” he told Jones. “My constituents don’t like the idea. They don’t want to give you all that information. They want it to stay private.”

“There’s been a lot of confusion around this and hopefully, we can begin to resolve some of that confusion,” Jones said, explaining that the desk would have nothing to do with trading gas commodities.

“It’s just an accident of the words that we use when we first began discussing this concept,” he said. “It only makes sense as gas is a significant contributor to over half of our generation fleet. This is purely operational information. Is a [pipeline] operating? Is a compressor station out? Is there maintenance been done?”

Jones stressed the information would be voluntarily provided by gas operators.

“There’s a lot of people who are not willing to give you that information or wanting it out,” Rep. Craddick said. “So how are you going to have them give it to you?”

“That’s where I’m facing opportunity. Most people know that I’m a very positive person, and I’m just positive enough to believe we can make this work,” Jones responded. “If we can get down to the fact that it’s really just operational information that is necessary for ERCOT to operate the system. I’m still very hopeful that we can get to that place where the gas companies will recognize moderate amounts of information … it’s purely for improving reliability

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Will Hydrogen Fuel Cell Vehicles Beat out Battery Electric?

ARLINGTON, Va. — Sunline Transit in Southern California’s Coachella Valley — home to Palm Springs and the Coachella music festival — got its first hydrogen fuel cell bus in 2006.

Today, the regional transit agency runs 21 hydrogen buses and recently received funding for 10 more, according to Lauren Skiver, CEO and general manager.

The agency also has several battery electric vehicles and plans to add more, but Skiver said as the 82-bus fleet transitions from compressed natural gas, most of its buses will run on hydrogen, produced by the agency’s own electrolyzer.

“It doesn’t make sense to go all battery electric,” Skiver told a packed hall at Infocast’s Hydrogen Hubs Summit last week.

“We get about 150 miles per charge on our battery electric buses; we get 350 miles on a full fill of hydrogen,” she said, noting that a growing number of transit agencies in California “have put the flag down for hydrogen.”

The California Fuel Cell Partnership reports 66 fuel cell buses currently on the road in the state, with more than 100 in the pipeline. The state also has 54 hydrogen fueling stations.

Skiver was one of six speakers on a panel on the potential market for green hydrogen in long-haul transportation, and the opportunities and challenges of competing with the fast-growing market for electric vehicles. Transportation is one of the applications for green hydrogen that the U.S. Department of Energy has specified for the demonstration hydrogen hubs to be funded with $8 billion from the Infrastructure Investment and Jobs Act (IIJA).

The market could also benefit from the $3/kg production tax credit for green hydrogen contained in the Inflation Reduction Act (IRA). (See Summit Attendees Hail IRA’s Hydrogen Tax Credit as ‘Game Changer.’)

James Kast, hydrogen infrastructure manager for Toyota Motors North America, reeled off a list of clean hydrogen’s selling points, from better air quality for rural and remote communities that experience high levels of pollution from diesel trucks to the ease and flexibility of switching to hydrogen.

Toyota’s hydrogen fuel-cell sedan, the Mirai, has been available in the U.S. since 2020 but has had only minimal sales ― 499 in 2020 and 2,629 in 2021, according to figures from CarFigures.com. The company’s fuel cell drive train is also being used in Class 8 trucks ― 18-wheel semis ― at the ports of Los Angeles and Long Beach.

“You can produce hydrogen from so many different methods; you can even move it around with a lot of different methods,” Kast said. “So now you have this very fuel-flexible energy carrier that you can still put in an existing truck stop and have a similar fuel dispenser and still fuel a bunch of trucks back-to-back 10 to 20 minutes at a time.

“That really resonates with people who say, ‘Well, what’s our other solution?’ Make a massive battery charging farm for all of your trucks,” he said.

But Kast said the $8 billion in hub funding from the IIJA “doesn’t solve all our problems. It’s a start, but really these aren’t [an] enabler for all the other investment to achieve all the things we’re talking about” at the conference.

Still, developing the hubs could allow the industry “to get some synergies to enable cost reduction because there are a lot of vehicles, like trucks and other things, that take a lot of [hydrogen] demand,” he said.

Echoing Kast, Shawn Yadon, president of commercial markets at Hyzon Motors, also stressed the parallels between traditional fossil-fueled trucks and hydrogen as a key issue for market development. Based in Rochester, Hyzon is selling hydrogen fuel cell semis, commercial coaches and garbage trucks in the U.S. and global markets.

“You’re going to have fleets who are saying, ‘Look, I need [fueling] behind the fence — on site,” Yadon said. “Every element and every touchpoint that fleets are used to today with their traditional fueling are going to be asks and requirements down the road. Starting from the hydrogen hub and production all the way through distribution, down to the actual user, all of those elements, all of those touch points are going to have to be covered, and different costs, obviously go with those different methods.”

‘Laser-focused’ on California

Nikola Corp. already has its electric semi, the Tre BEV, on the road, helped by incentives such as California’s Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), according to Erik Mason, the company’s global head of energy supply and trading.

Nikola’s hydrogen fuel cell semi is due out in 2024, and the company will again be “laser-focused” on the California market, Mason said. He was, however, more cautious in looking at the impact of the IRA’s $3/kg production tax credit and the DOE’s Hydrogen Earthshot, which is targeting a $1/kg price for green hydrogen over the next decade. “What does the $1/kg mean? What point of the value chain is that?” he said. “Is that $1/kg dispensed into a truck? That’s very different than $1/kg produced at the [hub]. … You produce hydrogen at ambient temperature at the hub; now you’ve got to compress it or liquefy it to get it into a station. You’ve got to transport it; you’ve got to build the station. There’s cost of capital.”

The price of green hydrogen produced by electrolysis has recently soared, with industry analysts citing prices between $10 and more than $16/kg.

Siting clean hydrogen fueling stations could also run into the same roadblocks as EV chargers ― the lack of critical infrastructure, Mason said.

“Five years ago, when we started envisioning how we would solve this, we were going to build 700 stations across the U.S., all with on-site electrolysis,” he said. “But when you get down to reality, most locations where you want those stations don’t have the electrical infrastructure, and you’re going have to pay transportation [and] distribution costs and all these things that just make the electricity costs way too much.”

The company is now planning for a “hub and spoke” model for its hydrogen charging stations, he said, with hubs located at sites with the necessary existing infrastructure, he said.

Unified Voice

Regulation remains another, significant roadblock as state regulators and policy makers lag the speed of technology adoption.

“The standards organizations are not keeping up,” said Rich Mihelic, director of emerging technologies for the North American Council for Freight Efficiency (NACFE), “So there is a lot of learning for this industry to get through. A lot of operational issues are out there.”

A key example, he said, are state regulations that prohibit trucks carrying hydrogen as a commercial product to go through some tunnels. Maryland does not allow trucks carrying hydrogen in its long harbor tunnels.

New Jersey also bans self-service gas stations, and Oregon still limits self-service to standalone gas stations in counties with fewer than 40,000 residents.

“Is that going to apply to hydrogen?” Mihelic said. “You have union contracts where the phrase ‘hydrogen fueling’ has never been used.”

Yadon said the industry is going to have to take on the education of state and local officials.

“It’s about refreshing some of these statutes or regulations that just really didn’t foresee hydrogen to be a player,” he said. “We just have to get people … to understand why these things need to be refreshed and what makes sense and what doesn’t make sense. But all of these barriers need to be tackled one by one … and that’s going to take coalition efforts.”

Skiver also called for the industry to speak with a more unified voice. “We have to stop arguing with ourselves about what the benefits [of hydrogen] are,” she said. “If you look at electrification [advocates], they’re not arguing with themselves about cost, about applications, about manufacture. They are just on [Capitol Hill], in the offices, talking about the benefits of electrification.

“We’re still arguing about pathways to cost parity. We still talk about that more than anything else,” Skiver said. “We really have to start getting a unified voice out there with our elected officials.”

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Oregon DEQ Foresees Economic, Equity Benefits from ACC II

Oregon’s adoption of California’s Advanced Clean Cars II (ACC II) rules could cost automakers up to $3 billion to comply with the regulations but provide the Pacific Northwest state about $5.8 billion in economic benefits by 2040, according to the Oregon Department of Environmental Quality (DEQ).

The new rules would also support the state’s efforts to improve racial equity by reducing pollution along transportation corridors that often run through low-income areas home to a disproportionate number of people of color, the department says.

The assessments were included in the DEQ’s draft fiscal and racial equity impact statements, a requirement of its process to review and adopt the ACC II rules.

The California Air Resources Board (CARB) last month approved ACC II to replace the Golden State’s existing vehicle emissions standards, starting with model year 2026. The new rules ban the sale of new gasoline-powered cars in California in 2035 and include a stricter low-emission vehicle (LEV) component for any such cars sold before then. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

Oregon is one of 17 states that follow California’s strict tailpipe emissions standards rather than the U.S. EPA’s looser ones. The DEQ has been moving quickly to adopt ACC II by 2026. (See Oregon Moving Quickly to Adopt Advanced Clean Cars II Rules.)

In developing the ACC II fiscal impact statement, the DEQ relied heavily on research already performed by CARB to ascertain the financial effects of the new rules, Rachel Sakata, senior air quality planner, said Tuesday during an online meeting of the state’s ACC II Advisory Committee. The meeting was intended to gather feedback from the committee and the public on the potential impact of the rules — especially on small businesses — before the DEQ issues a notice of proposed rulemaking next week.

Sakata said the $3 billion in impacts to automakers represents Oregon’s estimated share of the costs the companies will take on to convert their production to zero-emission vehicles and LEVs and market them to consumers. The DEQ’s figure is based on CARB’s finding that the impact of adopting the rules for California alone would cost car manufacturers $30 billion.

“The costs associated with this proposed rulemaking are going to be costs incurred by the manufacturers to produce and deliver certain percentages of zero-emission vehicles for each model year” for Oregon, starting with a 35% ZEV requirement for 2026, Sakata said.

The DEQ draft impact statement points out that cost to comply in Oregon could actually be less than $3 billion because of the economies of scale resulting from compliance in California.

“I think Ford alone has committed to investing $50 billion before 2026 on our EV plan, and I know where that’s just Ford; the other companies are in similar spots,” said Advisory Committee member Steve Henderson, director of vehicle regulatory strategy and planning at Ford. “So there’s a tremendous amount of investment being targeted for this, and that’s a good thing; that’s going to make this happen — but it’s a lot more than $3 billion.”

“You’re thinking nationwide, right?” Sakata asked.

“These are the costs of development; these aren’t the costs of selling,” Henderson replied. “I’m not in a position to say what our costs of selling the EVs will be compared to the [internal combustion engine cars], but that’s the amount that we’re investing so that we can produce these vehicles.”

Sakata said the DEQ acknowledged that the new rules will incur direct costs for 17 auto manufacturers, but she also noted that California is already seeing declining costs for EV batteries.

“We recognize that the costs to manufacturers will be high per vehicle, particularly in the early years of this regulation, but are expected to decrease over time by 2035,” she said.

Health Benefits

The fiscal impact statement assumes no direct costs to consumers from adopting ACC II but notes the potential for indirect costs in the form of higher prices for EVs and the need to install home chargers. Still, those costs should be outweighed by $675 million in indirect net benefits resulting from the expected lower overall cost of ownership for EVs, largely from lower maintenance costs and reduced fuel expenses, the DEQ found.

But the department foresees a much larger pool of net benefits — more than $5 billion — based on savings stemming from the reduced emissions of greenhouse gases and other pollutants. Based on its own estimates and those of the Northeast States for Coordinated Air Use Management (NESCAUM), the DEQ expects the ACC II rule will reduce Oregon’s GHG emissions by 48 to 54.1 MMT per year by 2040.

“A recent analysis conducted by DEQ for the [Oregon Clean Fuels Program] Expansion 2022 Rulemaking indicates that transitioning to lower-carbon transportation fuels through 2035 provides significant health benefits to Oregonians, in the range of $90 million per year of avoided health costs. Much of this can be attributed to reduction in particulate emissions due to electrification,” the impact statement says.

The DEQ cited pollution reduction as a major benefit in its impact statement on racial equity, which state law requires must be a primary consideration in all new regulations.

“The pollution and public health impacts from on-road vehicle emissions are significant in many overburdened and underserved communities. Communities that are adjacent to or near transportation facilities and corridors are disproportionately impacted by those emissions and are traditionally lower-income and have a higher percentage of Black, indigenous and other peoples of color residents,” the statement says.

Sakata said the state understands that the relatively higher costs for EVs can be a barrier to ownership for lower-income residents, but she reiterated the lower long-term costs associated with the vehicles. She also pointed out that ACC II rules contain provisions intended to ensure that EVs be transitioned to the used car market and assure that automakers provide vehicles that are durable, offer a minimum driving range, provide sufficient warranties for batteries and other parts and allow for DC fast charging.

“Because, you know, for those who may not have access to home charging, they’re going to be more reliant on public fast charging, and so ensuring that there’s that capability for the vehicles will help overall,” Sakata said.

Advisory Committee member Victoria Paykar, transportation policy manager at Climate Solutions, said that low-income areas and communities of color have lower access to EV charging infrastructure. Paykar encouraged the DEQ to partner with the state’s Department of Transportation to ensure that charging stations with competitive rates and services be made available in those communities.

Impacts on Mom and Pop

The DEQ has less insight into the financial impact of the ACC II rules on businesses outside the auto industry. Sakata said the rule change would likely represent one of the “largest growth opportunities” for electric utilities, while EV infrastructure provides should also benefit. Traditional auto parts suppliers will probably lose some business, while suppliers of batteries and other EV parts would see increased sales.

Sakata noted that the estimated 1,800 small automobile repair shops across Oregon could see “negative fiscal impact” from the transition to EVs, given their smaller number of moving parts compared with gas-powered cars.

“So, this trend overall suggests that the number of businesses providing these services may decrease along with a reduced demand over time. However, there will still be gasoline vehicles on the road for well past the regulation time frame,” Sakata said.

Committee member Glenn Choe, a regulatory affairs specialist at Toyota, asked if the DEQ had modeled the economic impact of the rules on smaller “mom-and-pop” gas stations.

“Because what we could anticipate is that the smaller gas stations go away, and the larger gas stations like the ones from Costco or the grocery stores take over, that there is some loss of pricing power for consumers, given the fact that larger entities could have a greater influence on gasoline or fuel availability and also pricing,” Choe said.

“We have not done any specific modeling for the mom-and-pop businesses; that was a little harder for us to sort of be able to quantify,” Sakata said.

Speaking during the public comment period of the meeting, Michelle Detwiler, executive director of the Renewable Hydrogen Alliance, pointed to the apparent interchangeability of the terms “ZEV” and “EV” during the meeting. She said her organization would continue to “beat this drum” around the fact that California intended that all ZEV technologies be given equal emphasis under the ACC II rules — including fuel cell vehicles.

“I also wanted to mention that all of the health benefits in particular that will accrue to disadvantaged [and] overburdened communities from the adoption of EVs will also accrue to those communities from fuel cell electric vehicles,” Detwiler said.

Sakata said the DEQ plans to hold two more public meetings on the ACC II rules in mid-October, after issuing its proposed rulemaking next week. The department will seek approval for the final rule from Oregon’s Environmental Quality Commission in December.

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US Climate Alliance Marks First Five Years

The U.S. Climate Alliance, created in response to former President Donald Trump’s decision to withdraw from the Paris Agreement on climate change, noted its fifth anniversary this week, celebrating its achievements and partnership with the Biden administration while soberly acknowledging the increasing impact of climate-related disasters.

Founded by California, New York and Washington state, the Alliance now numbers 23 states and Puerto Rico, representing 58% of the U.S. gross domestic product, 54% of its population and 41% of net greenhouse gas emissions.

The Alliance’s annual report, released this week, said its members reduced their net GHG emissions by 24% between 2005 and 2020, keeping them on track for meeting the Paris goals: at least a 26% cut in GHG emissions from 2005 levels by 2025, at least a 50% cut by 2030 and net-zero emissions by 2050.

‘Dozens of New Laws’

Alliance members initiated “more than 40 high-impact actions” last year, the report said, including “dozens of new laws to adopt more aggressive emissions-reduction requirements and targets, reduce the climate impact of vehicles and buildings, and create governing bodies to guide state resilience and environmental justice actions and establish priorities. Members also have developed regulations to codify and operationalize their participation in carbon markets, EV sales mandates, and methane reductions from the oil and gas sector.”

Greenhouse gas emissions (US Climate Alliance) Content.jpgThe U.S. Climate Alliance — 23 states and Puerto Rico — reduced their net greenhouse gas emissions by 24% between 2005 and 2020. | U.S. Climate Alliance

 

The report also touted the impacts of the state’s actions:

  • Nearly half of the electricity generated in Alliance states is from zero-carbon resources, compared to about one-third in the rest of the country. Non-Alliance states are more than twice as reliant on coal power as Alliance members.
  • Alliance members generate half of the levels of criteria pollutants per capita of non-Alliance states, on average.
  • As of 2020, utility energy efficiency programs in Alliance states saved 1.5 MWh of electricity per capita over the lifetime of their programs, compared to 0.65 MWh per capita in the rest of the U.S.
  • Alliance members employ more than 40% more workers in renewable energy and energy efficiency than non-Alliance states.

The report also cited the growth of electric vehicle sales, with pure EVs accounting for 5.6% of vehicle sales in the second quarter of 2022, more than double the previous year. It also noted that solar and wind power account for nearly two-thirds of electric generation capacity expected to come online in 2022, with battery storage representing another 11%.

Friends in Washington

Created to fill a void in federal policy, the Alliance now has an ally in the White House. It praised the Biden administration for adopting more stringent corporate average fuel economy (CAFE) standards, reinstating California’s authority to implement its own GHG emissions rules for cars and light-duty trucks, and its support for offshore wind. It also celebrated the administration’s recent legislative wins.

“With the passage of the Infrastructure Investment and Jobs Act and Inflation Reduction Act, states now have a major role to play in implementing and delivering the new and expanded programs and funding in a way that maximizes their climate benefits,” it said. The bills are the largest climate investments in U.S. history, with the IRA providing $369 billion in funding for climate and energy programs and $4 billion for Western drought resilience.

But the Alliance also noted U.S. experienced 20 “billion-dollar” extreme weather and climate-related events in 2021 totaling $145 billion, with another in the first half of 2022.

“One in three Americans report that an extreme weather event has personally affected them over the past two years,” it said, citing a Gallup poll. “And, as of June 2022, nearly every region of the continental United States had experienced some form of extreme weather including extreme heat, violent thunderstorms, wildfires, prolonged droughts and flooding.”

It also cited the Supreme Court’s ruling in June limiting EPA’s authority to curb GHG emissions from power plants. (See Supreme Court Rejects EPA Generation Shifting.)

“This moment has hardened the resolve of Alliance governors to continue moving forward with bold state climate action in 2023 and beyond,” it said. “States will continue playing a critical role in achieving the nation’s climate goals by  maximizing the climate benefits from new and expanded federal programs, thanks to recent congressional action, while continuing to advance bold climate action beyond the federal floor.”

Climate Week Announcements

The Alliance released its report during Climate Week in New York City, where New York Gov. Kathy Hochul and New Jersey Gov. Phil Murphy gave a joint press conference Wednesday. The governors spoke in front of more than 1,400 solar panels recently installed on the roof of the Javits Convention Center, the largest rooftop solar farm in Manhattan.

Hochul, one of three co-chairs of the Alliance, used the conference to announce an executive order committing to 100% renewable energy in state operations by 2030. All light-duty nonemergency vehicle fleets will be zero-emission vehicles by 2035, and all medium- and heavy-duty vehicle fleets will be ZEVs by 2040. She also said state agencies and authorities, which hold $50 billion in investments, will reach net zero in their portfolios by 2040.

Phil Murphy (Gov Kathy Hochul) Content.jpgNew Jersey Gov. Phil Murphy | Gov. Kathy Hochul

“I’m not going to tell the private sector what to do if we’re not prepared to make those same decisions internally,” she said. “We are going to transition to 100% renewable energy in all state operations by the year 2030. I’m making that pivot right now. We’re going to get that done.”

She also announced the state’s sixth competitive renewable energy solicitation, calling for 2,000 MW in large-scale projects.

And she made a pitch for her proposed $4.2 billion environmental bond issuance, which will be subject to a referendum in November, saying it would be “a game-changing investment in our infrastructure for our clean energy future.”

A major component of several Alliance members’ decarbonization strategies is offshore wind, with East Coast governors committing to almost 40 GW in procurements. That total increased with Murphy’s announcement Wednesday that he was boosting New Jersey’s target from 7,500 MW by 2035 to 11,000 by 2040.

“This is an aggressive target, but an achievable one when we combine the offshore wind plan currently in place and moving forward [and] the opportunities of the recently auctioned portions [of] the New York Bight, and the technological advancements that are making turbines more and more efficient, almost literally by the day,” Murphy said.

New York’s current OSW target is 9,000 MW by 2035.

While both states hope their OSW investments will produce economic development, Murphy insisted they were not in competition.

“I like to think of this as a cross-country meet. It’s not about the individual times; it’s about the team score. And while we’re still running for personal bests … we don’t win unless we each pull each other along so that the team wins,” he said.

Elections Loom

The Alliance expressed confidence that its progress will continue after the November elections, saying it was “committed to working across party lines with all governors willing to advance tangible climate solutions.”

Hochul is one of 36 governors who will face voters this fall, including 18 of the 23 states in the alliance. Twenty of the seats are currently held by Republicans and 16 by Democrats. (Murphy was narrowly re-elected last year.)

The Cook Political Report projects eight races, including New York, as solid Democratic and six leaning or likely Democrat, all of them members of the Alliance. Two of those states are currently headed by Republican moderates: Maryland’s Larry Hogan, who is term limited, and Massachusetts’ Charlie Baker, who is not seeking re-election.

Cook projects 12 solid Republican and five leaning/likely for the GOP, with only one — Vermont — a member of the Alliance.

That leaves five “toss up” races, including Alliance states Nevada, Oregon and Wisconsin and non-members Arizona and Kansas.

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MISO, SPP Hunt for Small Interregional Tx Projects

MISO and SPP said Tuesday they have tentatively settled on qualifying criteria and will begin developing a first set of smaller interregional transmission projects.

The RTOs are using their new targeted market efficiency projects (TMEPs) process, incorporating many of their standards from those used on the MISO-PJM seam.

The grid operators proposed to the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) that TMEPs:

  • cost $20 million or less;
  • must not be greenfield projects;
  • be in service by the third summer peak after their approval; and
  • completely cover their installed capital cost through avoided congestion within four years of service.

Their staffs plan to screen for possible TMEPs when a market-to-market (M2M) flowgate has amassed $1 million or more in congestion costs over a two-year period. The two have catalogued seven permanent flowgates that have racked up between $10 and $43 million worth of congestion. (See MISO, SPP Identify Hotspots for Smaller Interregional Tx Projects.)

The RTOs aren’t considering projects that have a pending transmission solution under their joint targeted interconnection queue study or MISO’s long-range transmission planning process. That knocks the RTOs’ most chronically congested flowgate — Neosho-Riverton on the Kansas-Missouri border — out of the running for a TMEP solution.

SPP’s Neil Robertson said the grid operators sought a cost-effective, low-risk approach to find projects that will resolve constraints rather than letting them continue to accrue congestion costs.

Multiple stakeholders said MISO and SPP should reconsider the $20 million cost threshold because of frail supply chains and escalating materials costs.

“We’re certainly sensitive to those arguments that a $20 million cost cap is quickly becoming antiquated,” Robertson said, adding that the RTOs will further examine the cost ceiling.

Robertson said a cost cap and three-year construction limit ensure that TMEPs don’t overlap with other interregional planning processes or “mask” opportunities for larger, more comprehensive projects.  

He said that while beneficial greenfield projects could meet the other TMEP criteria, the RTOs think it “extremely unlikely” given the current challenges with obtaining siting approval for new transmission.

Other stakeholders advised the grid operators to be more flexible in their criteria because they have yet to approve an interregional project.

“Transmission planning is in a transitory state for much of the country,” Robertson said, explaining that FERC is developing transmission planning criteria and grid operators are currently expanding planning practices.

“We feel like this, most of all, is an appropriate first step to take,” he said.  

Data Limitations on First TMEP Recs 

The first set of TMEP recommendations will be restricted by SPP’s current congestion data limitations, as the RTO doesn’t model MISO constraints in its day-ahead market calculations. The initial TMEPs will only consider SPP M2M constraints because those are the only constraints that have a complete set of historical data, Robertson said.  

Robertson said that by next June, SPP plans to incorporate MISO constraints, likely giving the RTOs a better understanding of congestion by the second batch of TMEPs.

MISO Independent Market Monitor David Patton has criticized SPP’s failure to model MISO’s constraints in its day-ahead market, saying it makes some uneconomic generation units appear economic in the SPP market. (See MISO Says System Volatility Here to Stay.)

Robertson said he while wouldn’t delve into “longstanding market mechanics,” SPP is currently investigating how it can consider its neighbor’s constraints.

The grid operators hope to present viable TMEP candidates to stakeholders during an Oct. 28 IPSAC meeting.

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Midwest Governors Form Clean Hydrogen Coalition

Seven Midwest governors on Monday announced the creation of the Midwestern Hydrogen Coalition to accelerate clean hydrogen’s production and use.

Dubbed the M-H2 Coalition, the group includes Illinois, Indiana, Kentucky, Michigan, Minnesota, Ohio and Wisconsin. Their governors signed a memorandum of understanding that seeks to establish a “robust clean hydrogen market, supply chain and workforce ecosystem in the Midwest.”

The participating governors said the Midwest has the potential to be a clean hydrogen market because it’s already flush with an ammonia distribution network, pipelines and agricultural nurse tanks, thanks to the region’s manufacturing and agricultural background.

The coalition said it will use a “coordinated multistate, multisector approach to developing a robust and sustainable hydrogen economy across the Midwest, informed by industry, academic and community engagement.” It plans to create a taskforce of senior leadership from each participating state and collaborate with corporations, universities and nonprofit organizations to best determine how to remove barriers and develop a Midwest workforce and market for clean hydrogen.

The M-H2 Coalition said it will pursue funding through applications for hydrogen hub designation under the federal Bipartisan Infrastructure Law. The legislation appropriated $8 billion to the U.S. Department of Energy to create regional clean hydrogen hubs, or networks of production, consumers and connective infrastructure. The DOE is expected to open a application period for the hubs this fall.

“We don’t have to choose between clean energy and clean air and creating good paying jobs and a strong economy — we can do both,” Wisconsin Governor Tony Evers said in a press release.

“Kentucky’s robust infrastructure, strong chemical and manufacturing base, along with our leadership in the automotive and logistics sectors position us as a natural location for economic development in hydrogen,” Kentucky Governor Andy Beshear said. “We are looking forward to working with our Midwest and local industry partners to build a hydrogen economy in Kentucky.”

Ohio Governor Mike DeWine said the “partnership will be the start of a new era of energy production that will create jobs and grow our economy.” He said the coalition is “just the beginning of our support for a clean hydrogen market.”

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Pa. Steps up EV Incentives as Federal NEVI Funding Arrives

The Pennsylvania Department of Environmental Protection (DEP) has awarded incentives of $5.4 million for electric vehicle purchases and the installation of 54 direct current fast chargers (DCFCs) as the state plans how to spend another $25.4 million in federal funds allocated last week to get more EV chargers on its key highways.

Pennsylvania was among the first 35 states to have its EV charger plan approved for funding under the National Electric Vehicle Initiative (NEVI) program, funded by the Infrastructure Investment and Jobs Act (IIJA).

With $2 million in state funds available for purchase incentives, the DEP has increased the maximum rebate available under the Alternative Fuel Vehicle Rebate Program (AFV) from $750 to $3,000. The department expects the latest tranch of funds to put an additional 1,000 EVs on the road in a strategy that it says is aimed at working-class households.

It also announced on Sept. 8 that it has awarded $3.4 million from the state’s share of the Volkswagen settlement to fund the installation of fast chargers in 16 high-traffic locations under the state’s Driving PA Forward DC Fast Charging Grants program. DCFCs, which can charge a battery electric vehicle to 80% in 20 to 60 minutes, will be installed on several corridors across the state, with charging stations available only every 50 miles.

“DEP continues to work strategically to support Pennsylvanians’ growing interest in zero-emission electric vehicles,” acting Secretary Ramez Ziadeh said in announcing the awards. “By reducing nitrogen oxide, carbon monoxide, particulate matter, carbon dioxide and other pollutants from the transportation sector, we make the air quality healthier in our communities, while helping to slow down climate change and its impacts.”

The department’s shift toward offering greater support for lower-income EV buyers follow its 2020-2021 report on the AFV program released in May showing that of 995 grants awarded that year just 21 residents were eligible for an extra incentive of $1,000.

Under the new rules, buyers whose household income is below 400% of the federal poverty level are eligible for a $2,000 incentive, and those with incomes of 200% of the poverty level would be eligible for an additional $1,000. That means, for example, that a family of two with a household income of $69,000 is eligible for a $2,000 rebate, but a family of two with a household income of $35,000 would be eligible for a $3,000 rebate, the DEP says.

Reinventing Transportation

Pennsylvania announced on Sept. 14 that under its NEVI plan, it will receive $25.4 million from the Biden administration’s initial tranche of $171 million to provide 80% of the cost of an EV charging infrastructure project.

NEVI funds are aimed at ensuring that alternative fuel corridors (AFCs) have a charging station every 50 miles or less and a charging station within 1 mile of an exit or a highway intersection. Pennsylvania’s NEVI submission said most of the 2,000 miles of the state’s AFCs had gaps of more than 50 miles between charging stations.

The federal funds will give the state the “the opportunity to reinvent transportation in a way that is smarter, cleaner, safer, more equitable and more efficient than ever before,” said Yassmin Gramian, secretary of the Pennsylvania Department of Transportation. “And we are ready to put them to good use.”

The number of EVs registered in the state, about 31,000, is nearly triple that of three years ago, according to the DEP. But that is still a minor share of the overall vehicle population. The state’s NEVI report said that the 23,500 registered EVs in 2021 accounted for less than 1% of the 10.3 million vehicles registered in the state.

The NEVI report, which was submitted in July, said that the state had about 2,300 Level 2 chargers in 1,100 locations  and 560 DCFCs in 130 locations. However, about 65% of those ports are Tesla chargers, which can’t be used by other vehicles. And the Federal Highway Administration estimates that only about two-thirds of the fast-charger stations are available to the public, the report said.

Convenience Charging Sites

Boosting the number and availability of public chargers is key to overcoming range anxiety and increasing the number of EVs on the road.

Seeking to improve the accessibility of charging infrastructure, the Driving PA Forward program has now funded the installation of 106 DCFC plugs in 34 locations, among them the recently announced projects. The program will fund up to 65% of a charger installation project, depending on the location, to a maximum of $250,000 in four types of locations: high-transportation areas, EV interstate corridors that are being developed in Pennsylvania, destination locations and community hubs.

The latest grant awards predominantly funded installations at convenience stores, such as Wawa, Sheetz, Coen Markets and KwikFill, as well as allocating $500,000 for the installation of eight chargers at two plazas on Interstate 76 westbound and eastbound in the Somerset County area, just outside of Pittsburgh.

The AFV program has since 2011 awarded more than $15 million in incentives to more than 10,000 Pennsylvanians, primarily for battery or plug-in hybrid EVs, according to DEP spokeswoman Deborah Klenotic.

The program funds the purchase of vehicles priced $50,000 or less, including pre-owned and dealer demonstration vehicles. Aside from the rebates of up to $3,000 for a battery EV, the program awards $1,500 for a plug-in hybrid and $500 for a compressed natural gas vehicle, propane-fueled vehicle or an electric motorcycle.

In the 2020-2021 funding year, with the incentive at $750 plus $1,000 for low-income residents, the program approved 995 rebates worth $674,750, according to the DEP’s annual report. Of these, about 63% were battery EVs and 36% were plug-in hybrid electric vehicles.

Tesla Model 3s accounted for the largest group of incentives, with 22%, followed by Chevrolet Bolt, with 14%. The third largest, the Chrysler Pacifica, had 10%.