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April 13, 2026

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Ann Arbor Voters May Consider Clean Energy Tax

Ann Arbor voters, some of the most politically progressive in Michigan, could decide this November to increase their property taxes to fund the city’s plan to move to renewable power sources and eliminate its carbon emissions by 2030.

Mayor Christopher Taylor unveiled what he calls the Community Climate Action Millage plan to City Council members this week. The proposal, which would have to be approved by council for the November ballot, would impose an additional 1 mill on the city’s residences and businesses for 20 years.

The tax would raise as much as $150 million over the life of the levy, including an estimated $6.5 million in the first year. A house valued at $100,000 would likely see its annual tax rise by $100 should the plan be approved. Ann Arbor levies nearly 17 mills for city operations alone; with county and school taxes, homeowners pay taxes based on more than 47 total mills.

If adopted, it would be the first such tax in Michigan. 

Full details on the proposal have not been released, and it seemed to have caught some people by surprise. A spokesperson for the Ann Arbor-Ypsilanti Regional Chamber said the group had not seen any details on the plan and would have no comment at this point.

“Achieving carbon neutrality is a moral imperative,” Taylor said in introducing the proposal. “And we need to do everything that we can [to] do our part.”

Ann Arbor, home of the University of Michigan, adopted its A2Zero plan in 2019. It calls for all its power to come from renewable sources by 2030 with programs to aid lower income residents to upgrade appliances and add home electric generation.

Councilmember Jen Eyer told NetZero Insider the plan was “not passed to sit on a shelf; the intent was to put it in action. To do so requires funding.”  She said because Michigan has failed to adequately help fund local governments, there is no money in Ann Arbor’s budget to put the plan into operation.

The tax would not cover all the costs to implement the energy plan, she said. The city will also pursue grants and other funding options to cover the full costs of implementation.

Nick Dodge of the Michigan League of Conservation Voters praised the proposal. “Ann Arbor is demonstrating leadership on tackling climate change, which is the challenge of our lifetime,” he said. “Investments made today to mitigate climate change will pay off in dividends in the future.”  

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MISO, SPP Solicit Ideas on Allocating Joint Tx Costs

While MISO and SPP continue to search for joint transmission projects that might ease crammed interconnection queues, they’re opening the floor to stakeholder suggestions on allocating the projects’ costs.

The RTOs surprised some stakeholders during a Wednesday teleconference by not coming equipped with a draft cost-sharing plan for seams projects that might result from their ongoing joint targeted interconnection queue study. The grid operators are trying to identify interregional transmission projects that could lighten their interconnection queues.

As part of the study, MISO and SPP late last month zeroed in on two expensive project clusters that would eliminate most flowgate congestion. The $424 million and $728 million options traverse South Dakota, Minnesota and Missouri. (See MISO, SPP Name Projects to Help Queue Troubles.)

SPP Vice President of Engineering Antoine Lucas said the novel study is an opportunity to wipe out “common barriers” to generation projects along the MISO-SPP seams. He also said the RTOs don’t yet have a detailed proposal on how new transmission construction will be funded.

“We’re not here today to discuss design-level ideas on cost allocation,” Neil Robertson, SPP’s interregional relations senior engineer, said.

Robertson said MISO and SPP could devise other benefit metrics beyond adjusted production costs, such as increased voltage support, accomplished renewable goals, heightened reliability beyond constraint relief, and greater interregional transfer capability.

“The transfer capability is a critical component of maintaining reliability,” LS Power’s Pat Hayes said. “I think the benefits are clearly measurable.”

Apex Clean Energy’s Richard Seide said he was disappointed the RTOs didn’t bring possible cost allocation proposals to the table.

David Kelley, SPP’s director of seams and tariff services, said MISO’s and SPP’s existing FERC-approved cost allocations haven’t yet yielded any project construction on the seams.

“What we are looking for are stakeholders to come with their cost allocation ideas in a manner that would be acceptable to both generation and load,” Kelley said. “We’re not going to drive the discussion and tell you how projects are going to be allocated.”

“What we’d really like is to develop a proposal … with the interests of those who will be sharing the costs,” Lucas added.

Other stakeholders said the cost allocation discussion failed to address that the RTOs are still accepting project suggestions to ease their three most congested 345-kV flowgates on the Kansas-Missouri border near Kansas City. The three constraints are not addressed in the two project clusters.

MISO and SPP asked stakeholders to submit written ideas on cost allocation approaches.

“Any idea that can be thrown into the mix would be helpful,” Robertson said.

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Long-delayed Solar Project Breaks Ground in Central Washington

Construction began last Friday on a 15 MW solar farm on the eastern slopes of the Cascade Mountains in central Washington, the third utility-scale project in a state on the verge of a solar boom.

Gov. Jay Inslee greenlit the $25 million Columbia Solar project in 2018, but the developer, Seattle-based TUUSSO Energy, has taken nearly three years to begin building the solar farm, which will spread across three 5-megawatt sites in the Kittitas Valley.

The valley is one of the sunniest areas in the state, the Washington Energy Facility Site Evaluation Council (EFSEC) said.

TUUSSO has begun work on a 5-megawatt site near Ellensburg and will follow up in a few weeks with two similar sites in the same vicinity. All the land is agricultural or pastureland.

The three sites will be completed by the end of the year or early 2022, TUUSSO CEO Owen Hurd told NetZero Insider. TUUSSO will also operate the sites, which will deliver power to Puget Sound Energy.

Founded in 2008, TUUSSO Energy has developed five solar farms totaling 145 MW in California, Arizona, Georgia and Maryland

On June 15, the EFSEC approved the Initial Site Restoration Plan for the project. That plan requires the developer to return the sites to their original conditions if and when the solar panel farms are closed and removed.

In 2017, TUUSSO Energy applied for a site certification agreement from EFSEC to build and operate the facility. EFSEC determined the project would have limited impacts on the environment with mitigation measures. Gov. Inslee, based on EFSEC’s recommendation, approved construction in October 2018.

However, EFSEC withdrew that approval because TUUSSO had not paid all of the permitting fees due to the state. EFSEC reviewed its permission in November 2019 when TUUSSO paid what it owed the state plus an extra $50,000 — an amount totaling $273,378. At that time, construction was supposed to begin in early 2020.

The project was originally designed to consist of five 5 MW solar farms scattered around Ellensburg. But power lines in the area did not have the capacity to handle more than 15 extra megawatts, so the five sites were trimmed to three, Hurd said.

The project was supposed to be finished in 2018, but was then delayed to 2020 because of financing problems, Hurd said, declining to elaborate. Those same financing problems led to TUUSSO owing more than $200,000 in permitting fees to EFSEC.

“We’re very excited to get this built out,” Hurd said.

More than 20 solar projects have been proposed for Washington, nearly all of which would be located east of the Cascades.

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Fuel Cell Semis Get Road Test at Port of Los Angeles

Ten hydrogen fuel cell electric semi-trucks are beginning a yearlong test of their effectiveness at the Port of Los Angeles.

The 10 semis, manufactured by Kenworth in Renton, Wash., are being tested along with about 30 similar battery-operated trucks to see how their performance compares with traditional diesel trucks, port officials told NetZero Insider. The test run is scheduled to end in May 2022.

The test will examine how well the hydrogen-fueled and battery-powered semis pull loads and manage inclines and declines, with drivers also provide feedback on general handling, said Jacob Goldberg, the port’s project manager for the test. The port also wants to determine whether the fuel cell trucks can travel the promised 350 miles before refueling.

Goldberg and Christopher Cannon, the port’s director of environmental management, are also seeking real-world financial comparisons on the costs of operating all three types of vehicles, especially pertaining to fuel.

They said the purchase price for a new diesel semi is $110,000 to $120,000, roughly $350,000 for a battery-powered semi and an estimated $1 million for a hydrogen-fueled semi. The battery-powered and hydrogen-fueled trucks will be used only for short hauls lasting less than a day and not for multiday long hauls.

The tests are being financed by part of a $41 million Zero and Near-Zero Emissions Freight Facilities grant awarded by the California Air Resources Board, with the port as the prime applicant. The grant is part of California Climate Investments, a state initiative funded by billions of cap-and-trade dollars, according to a written statement from PACCAR, the company that owns Kenworth, which manufactured the hydrogen-fueled trucks. PACCAR is based in the Seattle suburb of Bellevue.

One apparent advantage of using a hydrogen truck over a battery truck is that the latter takes hours to recharge while the former can be refueled as fast as a conventional diesel truck, Goldberg and Cannon said. The port is doing the final safety checks for two on-site hydrogen refueling stations and expects to have another station running soon about 70 miles from the port.

Four years ago, the port set a goal of producing net-zero carbon emissions from its short-haul trucks by 2035.

“The problem is that the technology to reach those goals is still emerging,” Cannon said.

The port currently has about 18,000 long-haul and short-haul semi-trucks listed on its registry to use the port. Of that amount, 11,000 to 12,000 enter or leave the port at least once a week.

The fuel cell trucks are Kenworth T680s built with Toyota hydrogen fuel cell electric powertrains, with water being the only emissions, according to PACCAR. The trucks went through initial tests at a PACCAR facility in Mount Vernon, Wash.

In the written statement, Kenworth General Manager Kevin Baney said: “The Kenworth T680 on-highway flagship offers superior fuel efficiency, performance and comfort, and serves as an excellent foundation to develop the hydrogen fuel cell electric powertrain.”

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Rhode Island’s TCI-P Bill Stalls at End of Legislative Session

Rhode Island has joined Connecticut in failing to enact enabling legislation for the Transportation and Climate Initiative Program (TCI-P), which both states pledged last year to implement.

A bill that would have authorized TCI-P deployment in Rhode Island did not make it through the state legislature before its session ended last week.

The Rhode Island Senate passed the Transportation Emissions and Mobile (TEAM) Community Act (S 0872A) on June 22, but a companion bill (H 6310) did not pass out of the House Finance Committee.

A planned special session later this year, however, offers another opportunity for the House of Representatives to pass the bill.

While the legislature is planning to come back into session this year, no date has been announced, Daniel Trafford, a spokesperson for the General Assembly, told NetZero Insider. It is likely that the special session would be held after the summer, he said.

The state’s legislative leadership also has not indicated which bills will be taken up, he said, adding that “it is certainly a possibility,” that the TEAM Community Act could be on the list.

The nonprofit Acadia Center is urging House leaders to prioritize and pass the act in the anticipated fall session, Hank Webster, Rhode Island director and staff attorney, told NetZero Insider.

“Rhode Island legislators passed the milestone Act on Climate earlier this year, setting critical greenhouse gas emissions reductions into law,” Webster said. “Transportation is the state’s largest contributor of greenhouse gas and air pollution causing asthma, cardiovascular disease and premature deaths. That’s why [Gov. Dan] McKee’s administration and the Senate are backing the regional and bipartisan TCI Program as one measure that helps our state invest in cleaner mobility for everyone.”

Rhode Island joined Massachusetts, Connecticut and D.C. in signing a memorandum of understanding in December to implement the program, which aims to cut emissions from transportation 26% over 10 years.

Connecticut’s legislature was unable to pass its authorizing legislation (Governor’s Bill 884) this spring. (See TCI-P Faces Uncertain Future in Connecticut.)

The fate of Connecticut’s legislation had an impact in Rhode Island, Paul Craney, spokesperson for the nonprofit Massachusetts Fiscal Alliance, said in a statement Friday.

“While gasoline is surpassing $3/gallon and inflation is devaluing wages, TCI is about to make matters worse for working people and low-income families in order to subsidize electric cars for the affluent,” he said.

Modeling has shown TCI-P could increasing retail gas prices in participating jurisdictions by 5 cents/gallon in 2023. Initial emissions reporting is set to begin in 2022 under the model rule that TCI released in June, with first auctions and compliance requirements starting in 2023.

“At some point, the regional approach to TCI is going to lose whatever credibility it has left when it’s just Massachusetts entering into the agreement next year,” Craney said.

Massachusetts does not require legislative approval to implement the program. In D.C., the Department of Energy and Environment and Department of Transportation are working with district leadership to establish a local program that implements TCI-P next year.

As written, the TEAM Community Act would create the foundation for a cap-and-invest program based on the TCI model rule.

Under the state’s program, the Rhode Island Department of Environmental Management (DEM) would establish the necessary regulations for limiting and reducing carbon emissions from transportation fuel supplied by as yet undefined regulated entities.

DEM would conduct auctions to sell carbon emission allowances, which the regulated entities could purchase and trade in a possible multijurisdictional market. Those entities would surrender allowances equivalent to the carbon emissions that result from the fuel they supply in the state.

Auction proceeds would support TCI-P goals of promoting clean transportation and improving mobility for residents, with no less than 35% to benefit “overburdened and underserved communities.” DEM also would establish an equity and environmental justice advisory board to ensure those communities have a say in how the state invests program proceeds.

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FERC, E-ISAC Report Details Reach of SolarWinds Compromise

Electric utilities must step up their cybersecurity best practices or risk further software supply chain security breaches like last year’s SolarWinds hack, according to a report released this week by FERC and the Electricity Information Sharing and Analysis Center (E-ISAC).

The SolarWinds and Related Supply Chain Compromise paper summarizes both the original hack of SolarWinds’ Orion network management software — along with vulnerabilities later discovered in other common industry tools such as Microsoft 365 and Exchange, and computer services provider Pulse Connect Secure — and recommended mitigation measures. FERC and the E-ISAC aimed the white paper at electric industry stakeholders but suggested that “members of other critical infrastructure sectors may also find [it] of interest.”

Security vendor FireEye first reported the breach of the Orion platform in December 2020, and “nearly 18,000 SolarWinds Customers” were initially thought to have been compromised. (SolarWinds now claims “the actual number of customers who were hacked … to be fewer than 100.”) Victims identified in the first days after discovery included the Department of Energy and FERC itself. (See FERC Pushes Cybersecurity Incentives.)

In April, the U.S. formally accused Russia’s Foreign Intelligence Service (SVR) of perpetrating the attack as part of a “broad-scope cyber espionage campaign that exploited [Orion] and other information technology infrastructures.”

The report’s account of the hackers’ operation aligns with other reporting: after SVR gained access to the SolarWinds production environment, it subverted the company’s update process to push malicious code to customers that enabled the hackers to gain remote access to their systems. At the same time, the attackers were able to leverage their access to SolarWinds’ servers to “gain network privileges” on the company’s Microsoft 365 and Azure Cloud environments.

According to a timeline of the attack compiled by SolarWinds in January, the malicious code — nicknamed “Sunburst” by analysts — was compiled and deployed in February 2020, but the company’s CEO admitted in May that the attackers “were doing very early [reconnaissance] activities in January of 2019.”

Shortly after FireEye announced its discovery of the malicious software, the E-ISAC published an all-points bulletin on the breach; the following week NERC issued a private Level 2 alert. The E-ISAC and Electricity Subsector Coordinating Council have since held “a series of restricted webinars to provide additional insights to electric utilities with key vendors involved in the response.”

Orion the Foundation for Further Attacks

Along with the Orion hack, the report provides more detail on other recent, related supply chain attacks. In the Pulse Connect Secure event, attackers used “Supernova” — a small piece of malicious code implanted through flaws in the Orion software — to gain access to the company’s virtual private network (VPN) servers. In addition, Microsoft recently reported a “wide-scale malicious email campaign” in which “Nobelium,” Microsoft’s name for the SolarWinds hackers, posed as a U.S.-based development organization to “distribute malicious URLs to a wide variety of organizations and industry verticals.”

Microsoft also revealed earlier this year that Hafnium, a group of hackers believed to be sponsored by China, has been using multiple weaknesses in the company’s products to attack on-premise versions of Microsoft Exchange Server at target companies that “may have allowed remote, unauthorized access, arbitrary write-to-file paths, and potential exfiltration of data on vulnerable Exchange servers.”

While this last breach does not appear to be linked to the SolarWinds compromise, it bolsters the report’s conclusion that “geopolitical competitors” are trying to use cyberattacks against critical infrastructure “to advance their interests.” The authors “strongly recommend” a number of steps, including:

      • looking for indicators of compromise (IOC) noted by the Cybersecurity and Infrastructure Security Agency (CISA). This should be done even if utilities do not use SolarWinds products because the attackers may have been able to move laterally through the systems of affected vendors or other companies;
      • requiring key vendors to report their use of SolarWinds and — whether they do or not — if they have checked for the IOCs or other warning signs;
      • if still using patched SolarWinds software, implementing the mitigation measures recommended in CISA’s previous emergency directives; and
      • considering participating in the Cyber Mutual Assistance Program with peer utilities “to ensure a collective response during a cyber threat.”

“In the coming months the E-ISAC anticipates supplementing its current information sharing with new CRISP capabilities, enhanced cross-border sharing, and collaboration with the U.S. Department of Energy’s office of Cybersecurity, Energy Security and Emergency Response,” the report says. “Likewise, FERC staff stands ready to assist in the dissemination of actionable information that supports the electric industry in proactively responding to cyberattacks and other cyber vulnerabilities.”

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NY Utilities, ESCOs Offer Tweaks to CCA Rules

Investor-owned utilities and energy service companies (ESCOs) in New York picked apart state recommendations on community choice aggregation (CCA) made in an April white paper, supporting some and rejecting others (14-M-0224).

The Department of Public Service staff paper made recommendations to resolve program challenges, remove barriers to data access and better incorporate distributed energy resources into CCA programs.

The Municipal Electric and Gas Alliance (MEGA), an ESCO serving upstate New York, said it supports program standardization and uniformity in elements of the CCA program rates but disapproves of the recommendation to adopt a 5% cap on commodity product offerings.

“The fundamental calculation of the ‘price to compare’ is flawed, [and] to use a baseless price construct and impose a 5% cap is nonsensical. More importantly, it is disconcerting that staff is considering imposing an artificial limit to a free and competitive supply market,” MEGA said.

DPS staff recommendations include standardizing CCA program filing requirements; streamlining the filing process; modifying existing requirements; and adopting additional requirements.

NRG Energy said it generally agrees with the department’s proposal to develop a uniform filing structure, but not with the recommendation that all program participants be enrolled in the same rate, regardless of when they join the CCA, unless they voluntarily choose a different option.

“NRG prefers the ability to enroll new participants on a different rate due to seasonality and price risk … [and] does not necessarily agree with the proposal surrounding the price to compare,” the company said.

“First, the price to compare in New York is not a fair apple-to-apples comparison. Utilities adjust and true up their rates after the fact, making it impossible for ESCOs to compete with the rate,” NRG said. “As a result, including the price to compare on a customer’s bill will be misleading and not an accurate summation of the value they are receiving from participating in the CCA program.”

Make-work Complaints

The state’s IOUs said they support standardizing guidelines, processes and procedures for CCA programs; “however, some staff recommendations are infeasible and cannot be cost-effectively implemented at this time. Others require additional collaboration to develop necessary program rules and details, especially as it relates to integrating community distributed generation (CDG) on an opt-out basis.”

The IOUs recommended, to ensure consistency, using the quarterly 12-month trailing average price to define the price to compare for the CCA market. But they requested further discussion among stakeholders regarding the public-facing display of such information “to determine whether using the current 12-month trailing prices is sufficient, how to best present residential and nonresidential service classification information most clearly, and what effect displaying the price has on the different programs.”

The utilities also opposed the recommendation that during a CCA program opt-out period, the utility be required to maintain a record of every customer that contacts them to opt out or to have an ESCO enrollment block placed on their account for the purpose of CCA program opt-out.

“There are little to no benefits in requiring” utilities to track customers in such a way, and this additional tracking and reporting is “needless” because enrollment in the CCA will not happen if the customer has requested a block on their account during the opt-out period, the IOUs said.

Additionally, the utilities urged the Public Service Commission to address conceptual design elements before either extending the ability to combine opt-out CDG with CCA or allowing opt-out CDG-only programs.

The IOUs said design elements that need to be considered include compensation that reflects reduced developer costs of the opt-out CDG model; potential inequities among municipalities; utility data considerations; customer protections; and implementation and administration changes for opt-out CDG.

MEGA said that “pairing CCA programs with opt-out CDG savings provides a powerful tool given the challenges with procuring affordable 100% green electric supply for CCA communities. By pairing the programs, communities that are hesitant to potentially increase resident electric bills with 100% green supply can access a guaranteed savings program through opt-out CDG.”

If New York state is invested in incentivizing and growing CCA programs, the two programs should remain paired, MEGA said, noting it “does not support standalone opt-out CDG but recommends that these programs operate in tandem to enable greater renewables access and affordability.”

The IOUs cautioned that creating a set of blanket requirements for as yet undefined new offerings may not be achievable considering the potential number of permutations that could arise, instead recommending the commission establish “an ongoing framework under which it will consider authorization of new CCA programmatic offerings.”

Consumer Protections

NRG also urged the commission to make further improvements to the filing process. The system does not currently work with many of the newer browsers that corporations are using, and older browsers do not always work with corporate firewalls and other protections.

The company made specific requests regarding both the aggregated dataset and the customer-specific contact information set.

“Sometimes the rules may seem appropriate on paper; however, when actually implementing the program, they are not practical in nature,” NRG said.

The aggregated dataset should provide the customer’s bill cycle and period codes, rate class and NYISO ICAP tags and zones, as these fields are necessary for ESCOs to accurately price customers and prepare a bid. The bill cycle and period codes are the most important pieces of information for timing purposes, NRG said.

In addition, NRG said it does not believe that municipalities are authorized to impose gross receipts tax (GRT) on customers taking service under CCA programs.

“Any suggestion that NRG and other ESCOs should increase their charges to CCA customers and then make payments to such municipalities ‘in lieu of’ GRT would violate Rule 28 of the commission’s CCA rules, which expressly provides that ‘municipalities may not collect funds from customer payments to cover lost sales tax revenues,’” NRG said.

The Coalition for Community Solar Access (CCSA) said it supports the commission’s requirements to always provide savings, to not include a credit check, and to ensure necessary outreach and education.

Regarding an April petition from software company Ampion for PSC approval of a program similar to a traditional CCA that supplies only a CDG product — one not integrated with other CCA products — the solar coalition encouraged the commission “to review the petition from the same lens it has reviewed this matter: ensuring the customer choice, customer engagement, consumer protection and customer benefits are at the center of all consideration.”

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GM Invests Big in California ‘Near Zero’ Lithium Project

General Motors (NYSE: GM) will invest millions of dollars in Controlled Thermal Resources’ lithium production project at the Salton Sea in Southern California, the automaker said Friday.

The investment will give GM first rights to lithium produced in the first stage of CTR’s Hell’s Kitchen lithium and power project. The project involves extracting lithium from geothermal brine.

CTR expects to start delivering lithium from its Hell’s Kitchen project starting in 2024.

The collaboration will give GM a U.S.-based source of lithium as the company accelerates its rollout of electric vehicles. Lithium is a key material used in EV batteries, but most lithium used in lithium-ion batteries is mined and processed outside the U.S.

The lithium from Controlled Thermal Resources will be produced with a “near zero” carbon footprint, CTR said. The extraction process uses renewable power and steam, and the geothermal brine is returned to the deep geothermal reservoir when the process is finished.

“GM has shown great initiative and a real forward-thinking strategy by securing and localizing a lithium supply chain while also considering the most effective methods to minimize environmental impacts,” Rod Colwell, CTR’s chief executive officer, said in a news release.

GM described its investment as the first multi-million-dollar investment in CTR’s Hell’s Kitchen project. A GM spokesman declined to say the exact amount of the investment. The deal includes an option for a multi-year partnership. It does not make GM a shareholder in CTR, the spokesman said.

“By securing and localizing the lithium supply chain in the U.S., we’re helping ensure our ability to make powerful, affordable, high-mileage EVs while also helping to mitigate environmental impact and bring more low-cost lithium to the market as a whole,” Doug Parks, GM executive vice president for global product development, purchasing and supply chain, said in a news release.

Geothermal, Lithium Resources

The Salton Sea Geothermal Field in California’s Imperial County is described as the largest known geothermal resource in the world. The Salton Sea is also a rich source of lithium, with the potential to satisfy 40% of global demand for the element, according to some estimates.

In addition to CTR, other companies are taking an interest in the area’s resources, including Berkshire Hathaway Energy. (See California Lithium Extraction Plans Advance.)

Some officials envision the area becoming a “Lithium Valley,” playing a central role in the U.S. domestic lithium supply chain.

California Assemblyman Eduardo Garcia (D), whose district includes Imperial County, described the agreement between CTR and GM as “the first major investment in actualizing that vision.”

“After years of laying the groundwork, we are ready to move forward — pedal-to-the-metal — on our cleaner air, electric vehicle, and climate goals while utilizing these economic development opportunities to bring vital resources, improve public health and uplift overall circumstances in our region,” Garcia said in a news release.

Garcia is chairman of the Assembly Select Committee on California’s Lithium Economy.

He also sponsored Assembly Bill 1657, enacted last year, which established the Blue-Ribbon Commission on Lithium Extraction in California. The 14-member panel, commonly known as the Lithium Valley Commission, began meeting in February.

EV Acceleration

The collaboration between GM and CTR follows GM’s announcement last month that it is boosting its investment in EVs and autonomous vehicles to $35 billion from 2020 through 2025. The investment is an increase from the $20 billion the company committed in March 2020 for electric and autonomous vehicles over the same time period.

With the added investment, GM will include new electric commercial trucks in its plans for North America. In November, the company said it would deliver 30 new EVs by 2025 globally, with 20 of those available in North America.

GM has two Ultium battery-cell manufacturing plants under construction in Ohio and Tennessee and plans to build two more battery-cell plants in the U.S. by mid-decade.

Also last month, GM announced an agreement to supply its Ultium batteries, as well as its Hydrotec fuel cells, to Wabtec Corp., which is developing the world’s first completely battery-powered locomotive.

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NJ EV Incentives Target Cheaper Vehicles, Middle-income Buyers

Launching year two of an incentive program that subsidized the purchase of 7,000 electric vehicles in the first year, New Jersey outlined new rules Tuesday that focus heavily on encouraging drivers to buy lower-priced EVs, with a maximum incentive of $5,000 available only for vehicles priced $45,000 and below.

The eligibility criteria for the second year of the $30 million/year program mean that only seven vehicles for sale in the state are listed as eligible for the maximum incentive on the website of the program, and only one of them is of the popular Tesla brand. Vehicles with a manufacturer’s suggested retail price (MSRP) of more than $55,000 are not eligible for any incentive at all.

The program is part of New Jersey’s effort to get 330,000 registered light-duty EVs in the state by 2025, in line with its goal of using 100% clean energy by 2050.

In the first year of the program, Tesla vehicles accounted for 83% of the vehicle purchases that received an incentive, and the three counties that received the most incentives were the high-income Bergen, Middlesex and Monmouth. In a May 27 hearing on the second-year proposal, Cathleen Lewis, the New Jersey Board of Public Utilities’ (BPU) e-Mobility program manager, said the board in the next phase of the program wanted to make the incentives “more accessible to middle-income families.”

BPU President Joseph Fiordaliso, noting that transportation generates more than 40% of the state’s greenhouse gas emissions, said the program would not only reduce pollution but also improve public health and air quality in low-income and minority communities, who are disproportionately affected.

“Making EVs more affordable will encourage EV adoption and get us closer to 100% clean energy by 2050,” he said.

The BPU said the focus on the “moderately priced” enabled the final program rules to prioritize “incentive-essential” buyers, or those that would likely not buy an EV without the incentive. The focus also would “provide greater equity as New Jersey electrifies its transportation options,” the document said.

Impact of Threshold Cutoffs 

Jim Appleton, president of the New Jersey Coalition of Automotive Retailers, a trade association that represents about 500 car and truck dealers, said the BPU made the “right call” in setting the threshold for the maximum incentive at $45,000 and the cutoff at $55,000. But, he said, the BPU “missed an opportunity to introduce more people to EVs” by setting the incentives for plug-in hybrid electric vehicles (PHEVs) so low. The BPU said it concluded that the PHEV incentives should be at the same rate as the other incentives.

“I know there is a vigorous debate in the EV world about the potential to cannibalize EV sales with a more generous incentive on PHEVs. And I understand that concern,” he said. But he added that “many buyers need the flexibility that PHEVs offer, and it is a powerful jumping off point for many consumers” who later will go on to by EVs. The impact of the low incentive can be seen in the fact that PHEVs — with an average incentive of $625 — accounted for only 3% of the incentives awarded in the first year of the program, he said.

He added that the 10-year program should be accelerated to “frontload” the funding so that a large number of incentives spark a wave of EV buys that would encourage other drivers to take the step.

Range of Incentives

The rules for the second year of the program were largely similar to those set out in the BPU’s straw proposal, released May 18, despite a vigorous analysis at a public hearing on May 27, which included several speakers who urged the BPU to raise the threshold for receiving the maximum incentive above $45,000. They argued that the low threshold would shut out too many vehicles from eligibility for an incentive. (See Drivers, Stakeholders Question NJ’s Proposed EV Incentive Rules.)

Stanislav Jaracz, president of the Central Jersey Electric Auto Association, suggested at the hearing that incentives be smaller to enable the BPU to give more of them and go further toward reaching 330,000-vehicle goal. He repeated that concern upon seeing the final rules.

“If they run out of the $30 million budget too soon, my words will prove correct,” he told NetZero insider in an email.

The second year of the program, as in the first, awards a $25 incentive for each mile of range that a vehicle can drive solely powered by electricity. That incentive is capped at $5,000 for vehicles with an MSRP of $45,000 and $2,000 for vehicles priced above $45,000 but below $55,000.

The program uses the same $25/mile criteria for PHEVs, which have a much more modest range, and so are eligible for smaller incentives. The range of the 16 eligible vehicles listed on the program website is between 17 and 47 miles, with incentives between $425 and $1,175.

The program for the first time also will enable EV purchasers to obtain the incentive at the dealership — the point of sale — instead of applying for it after purchase.

Data on the Charge Up New Jersey website shows that in the first year of the program, Tesla Model 3 vehicles, which were eligible for an incentive of $5,000, accounted for about 35% of the vehicles sold. Tesla’s Model Y accounted for 39%.

But while the Model 3 — which sells for $39,990, according to the company website — is eligible for the maximum incentive in the second year program, the Model Y — which sells for $52,990 — is only eligible for a $2,000 incentive.

To be eligible for an incentive, a vehicle must be purchased in New Jersey, rather than out of state. Twelve vehicles meet the criteria for an incentive, including seven that are eligible for an incentive that is below the maximum.

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Hawaii PUC Approves EDRP Plan for Oahu

Hawaii’s Public Utilities Commission last week approved Hawaiian Electric Company’s (HECO) plan to create an emergency demand response program (EDRP) to help cover the expected energy shortfall caused by the shutdown of Oahu’s coal-fired AES Hawaii Power Plant in September 2022.

Order 37853 approved the EDRP in the form of a scheduled dispatch program (SDP) that would encourage HECO customers to install solar PV and batteries at their homes in order to make up to 50 MW of DR available to the utility during Oahu’s peak energy usage hours of 5 p.m. to 9 p.m. The program also will be open to customers with existing DER resources. (See Hawaii PUC Approves DR Stopgap to Address Coal Plant Closure.)

At a June 28 conference to discuss the program, Yoh Kawanami, HECO co-director of customer energy resources, said, “Plenty of DER resources are out there. If we can put a battery on it and move that generation towards the peak [of the system’s energy use], we can resolve a lot of things.”

The PUC approved a $34 million budget for the program, which HECO will recover through a demand-side management (DSM) surcharge. The surcharge will add an average of $1.37 to customers’ monthly bills over the next three years, the utility estimates. HECO had sought $35 million for the program.

Customers participating in the program will be paid after a verification process that could take up to 90 days to allow HECO to confirm the performance of the equipment during peak hours. Although the PUC had targeted a 30-day verification, Kawanami said the process was being extended because “anyone who lends their system” can be eligible for benefits and that different DER systems may lengthen the verification process.

SDP payments will be considered income by the state, requiring customers to fill out a 1099 tax form to be submitted to the IRS.

HECO will start accepting applications for the SDP on Aug. 1.

Last week’s order also approved an addendum to Oahu’s fast demand response program, increasing authorized participation by 2.657 MW for a total of 7 MW by the end of 2022. HECO hopes to draw more participants to the undersubscribed program through an incentive of $250/kW.

“I know that opening the door [to the EDRP] is scary to a lot of people, but I’m a lot more scared that, come next fall, if we don’t have enough of these measures in place, we’re going to have a much different discussion,” PUC Chair James Griffin said during the June 28 conference.