New Hampshire legislators are considering a bill that would require the state’s vehicle fleet to be emissions-free by 2042 (SB 131-FN).
Gov. Chris Sununu vetoed a similar bill in 2019, citing concerns about the costs of electric vehicles at the time. But Sen. David Watters (D), sponsor of the bill, is optimistic about its chances for passage this year because of the declining costs of EV ownership.
“The state could save tens or hundreds of millions of dollars on maintenance costs because the cost of [EV] operation, let alone fuel costs, is so much lower than standard vehicles,” Watters said during a New Hampshire Senate Transportation Committee hearing Tuesday.
Under the bill all new light-duty trucks and passenger vehicles leased or purchased by the state would be required to be emissions-free by 2026. In addition, new trucks and other vehicles exceeding 10,000 pounds would need to be emissions-free by 2032. There is room in the bill for consideration of alternatives when existing zero-emission vehicle technologies do not align with the vehicle need, such as for police cruisers or snowplows, Watters said.
The most recent New Hampshire state vehicle bid covering the 2021 model year demonstrated the competitive cost of new EVs, Rebecca Ohler, administrator of the Technical Services Bureau in the New Hampshire Department of Environmental Services’ Air Resources Division, said in her hearing testimony.
In the bid’s four-door, five-passenger sedan category, the vehicle with the lowest operating cost over its lifetime was the all-electric Chevrolet Bolt, she said. The Bolt, she added, cost about $500 less than the second lowest vehicle and “thousands of dollars less than most of the other vehicles within the category.”
If the bill is passed without amendments, state agencies would be required to create a vehicle transition plan by mid-2022. Watters noted that the bill does not require agencies to take any cars or trucks out of service until they have reached the end of normal operations.
Charging Infrastructure
The bill also includes language that expands on an existing plan to spend funds from the 2016 Volkswagen diesel emissions settlement on DC fast-charging infrastructure development throughout the state.
Ohler said that she expects the Department of Environmental Services to issue a request for proposals soon for the buildout of that fast-charging network.
The bill would allocate a portion of the settlement funds to a rebate program for municipalities that build charging infrastructure. It also would authorize utilities to include make-ready programs under a systems benefits charge to pay for network upgrades that support charging facility installation.
Madeleine Mineau, executive director of Clean Energy NH, asked the committee to consider including review and approval standards for make-ready investments that utilities seek to recover.
“I want to make sure that, like all other utility investments that are recovered from their customers, that those are prudent investments and in the benefit of their customers,” Mineau said in her testimony.
Watters said that the bill includes a surcharge for EV owners to support charging infrastructure expansion costs after VW settlement funds are exhausted.
To address EV charging station rate design, the bill provides a series of guidelines for utilities. It says that “appropriate” rate design features include:
rates that account for seasonality cost drivers on the electric system;
load management offerings;
time-of-use rates, when metered separately from other loads; and
demand charges for high-demand equipment.
Mineau said that Clean Energy NH disagrees that demand charges are appropriate for fast charging rates.
“We actually think that it’s a very significant disincentive to building out the DC fast-charging network,” she said.
Magness drew political heat following the system’s near collapse last month that led to long-term power outages and misery for millions of Texans. (See Texas Lawmakers Dig into Power Outages.)
The board voted 6-1 to invoke the termination notice in Magness’ contract. He will continue in his role for 60 days, working with state leaders and regulators on potential reforms to ERCOT, the grid operator said.
The ERCOT board fired CEO Bill Magness (left), shown here during a media briefing following the February winter storm alongside Dan Woodfin, senior director of system operations. | ERCOT
The board also directed ERCOT to engage with a search firm “as soon as reasonably possible” to find a new CEO. A transition plan will be discussed during future board meetings.
Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas and representing the commercial consumer segment, voted against the motion.
Magness, who was not present, and Lori Cobos, CEO of the Office of Public Utility Counsel, both abstained from the vote.
“I would have preferred to have more time to evaluate this important matter … to evaluate my concerns,” Cobos said.
ERCOT General Counsel Chad Seely conducted the board meeting in the absence of a chair and vice chair, who were among the four independent directors who resigned Feb. 23. (See ERCOT Chair, 4 Directors to Resign.)
Magness joined ERCOT in 2010 after 14 previous years in the electric industry and served as its general counsel. He was appointed CEO in January 2016 and made more than $876,000 in salary and other compensation in 2019.
ERCOT’s board, ideally composed of 16 members, is now down to 10, including Magness. Two of the seven members who have resigned are currently being replaced by acting directors; the independent retail electric market segment’s director and alternate director are both vacant.
Arthur D’Andrea, who was appointed as chairman of the Public Utility Commission on Wednesday, sits on the board as a non-voting member. His predecessor, DeAnn Walker, stepped down Monday. (See PUCT’s Walker Steps Down from Commission.)
A new report from the National Academies of Sciences, Engineering and Medicine (NASEM) recommends an expanded role for federal leadership in transmission planning.
Efforts to predict what the grid of the future will look like have a poor track record, according to a new report from NASEM. So rather than even try, the report on grid evolution takes a hard look at the current state of the U.S. energy transition and offers recommendations “to support whatever ways the power system evolves” so that it remains “simultaneously safe and secure, clean and sustainable, affordable and equitable, and reliable and resilient.”
Following the election of President Biden, the U.S. energy sector has been rife with reports and recommendations on how to accelerate the U.S. electric grid’s progress toward all those adjectives — including another study from NASEM released earlier in February. (See Report: ‘Social Contract’ Needed for Decarbonization’.)
What distinguishes the current report from the pack is its embrace of uncertainty and focus on the likely drivers of change, ranging from the development of grid-edge, distributed technologies, to impacts on jobs and social equity, to “shifts in the locus of electricity-relevant innovation” outside the U.S. The study was originally requested by Congress in 2018, and the committee of experts that wrote its more than 40 recommendations also included specific action items assigned to Congress and other federal and state agencies and policymakers.
The NASEM report lays out several possible scenarios, ranging from an incrementally changed current system (S1) to a highly decentralized system (S4) with no macro transmission grid. | NASEM
Speaking during a Feb. 25 webinar to launch the report, committee member Karen Palmer, a researcher at Resources for the Future, said, “We have to recognize that which pathway we end up taking is going to depend on what customers want, what climate policies are adopted, what happens with economics, including market design, and also what happens with technology development.”
“The system is on the cusp of a fundamental transformation,” added Carnegie Mellon University professor Granger Morgan, who chaired the study committee. “Many of these transformations are not under industry control. How these transformations manifest will be different in different parts of the country. An environment that promotes technical, economic and regulatory innovation is essential.”
For example, referring to the recent power outages in Texas, Morgan pointed to a recommendation that the departments of Energy and Homeland Security “jointly establish … a visioning process [for] systematically imagining and assessing plausible large-area, long-duration grid outages.”
National Transmission Policy
Granger and other committee members kept the webinar focused on some of the report’s key recommendations, such as an expanded role for federal leadership in grid planning.
“First, we would encourage Congress to enact a national transmission policy that would rely on a high-voltage transmission system to support energy diversity, energy security and the nation’s equitable transition to a low-carbon economy,” said Susan Tierney, a senior consultant with the Analysis Group.
FERC should be authorized to direct transmission companies and operators to plan for a system that is not only efficient, reliable and resilient, but extends to areas of the country with high-quality renewable resources, Tierney said. The commission should also take over DOE’s role in designating new “national interest electric transmission corridors” and approving new lines in those corridors, she said.
Charting the US Innovation System
“It’s fashionable to say that we have the technologies now that we need” to decarbonize the grid, said David Victor, a professor of international relations at the University of California, San Diego. “That’s simply incorrect.”
The fractured landscape of the U.S. energy transmission, with states and utilities setting various decarbonization goals. | World Resources Institute
Victor’s first recommendation is “to improve awareness and capacity; to take the pulse of how the U.S. innovation system actually works because there is such a big role for innovations coming from outside” both the electric power industry and the U.S. “Lots of different policy instruments have an impact.”
He also calls for tighter collaboration between DOE and DHS “around managing the tension between the benefits of globalization and natural security.” At the same time, NASEM echoes other recent reports in its call for an increase in funding for research and development in the face of a loss of U.S. leadership in innovation and global competition.
A broad range of government, industry and research stakeholders should work together to identify the “breakaway” technologies of the future and “develop and fund a research agenda that creates fast-moving programs that help to de-risk such solutions from technology, market and regulatory perspectives,” the report says.
The Need for Better Tools
Not knowing exactly how the grid will evolve “will require a major change in the way we approach the whole idea of tools,” Washington State University professor Anjan Bose said. “We are looking at a major change in the architecture happening to the grid, and not happening uniformly across the country. The only way we’ll be able handle all of this is if we do enough fundamental study of how these things all operate together.”
With the system changing rapidly, “it will be very important that the skill sets of our regulators are very high, that they have a lot of tools available to enable their modeling, simulation [and] analytics,” said Reiko Kerr, senior assistant general manager of power systems at the Los Angeles Department of Water and Power. “The dynamic availability of information [is needed] to understand the decisions and be able to build in flexibility so that you can also course correct and not make decisions that would require years to unwind or fix.”
Charging an electric vehicle with a Level 2 charger uses almost as much power as an air conditioner. | Pecan Street
Terry Boston, former CEO of PJM, underlined the importance of advanced planning tools as more sectors of the U.S. economy are powered by electricity. “We’re talking about the electrification of fertilizer in the chemistry industry; we’re talking about the electrification of cement and even steel,” Boston said. “My greatest fear is we’re going to under-forecast the loads. How do we get to resource adequacy in a world where decarbonization means electrification of almost everything?”
Dartmouth College professor Elizabeth Wilson said that beyond better tools, a paradigm shift in how we think about energy will be needed. “This combination of critical infrastructure and fundamental changes to our system require that we engage in new ways,” Wilson said.
“What this report does really well is highlight the importance of energy for society, energy for vulnerable communities, and really mapping a path forward for how energy in the future needs to be integrated into our core societal decisions,” she said.
The U.S House of Representatives’ principal oversight committee on Wednesday joined the roster of agencies investigating ERCOT following last month’s severe winter storm that plunged more than 4 million Texans into darkness for several days and left 14 million without water.
The Committee on Oversight and Reform’s Subcommittee on Environment sent a letter to ERCOT CEO Bill Magness requesting information and documents regarding the grid operator’s “lack of preparation” for and response to the storm and its “preparedness for future storms.”
The subcommittee said it is concerned “that the loss of electric reliability and the resulting human suffering, deaths and economic costs, will happen again unless ERCOT and the state of Texas confront the predicted increase in extreme weather events with adequate preparation and appropriate infrastructure.”
The powerful U.S. House Oversight committee has begun its investigation into ERCOT’s response to the severe February winter storm. | Raul654, CC-BY-SA-3.0-migrated via Wikimedia Commons
The storm and the ensuing blackouts could wind up causing as much as $90 billion in damage.
“Extreme winter weather events in Texas have occurred repeatedly over decades and ERCOT has been unprepared for them,” subcommittee Chair Ro Khanna (D) wrote in the letter.
ERCOT is already under investigation by its regulator, the Public Utility Commission of Texas and the state attorney general’s office. FERC and NERC have also opened a joint inquiry into the grid’s operational issues during the event, as they did after cold weather in 2011 that resulted in a similar round of rolling blackouts.
Khanna promised an investigation last month, telling CNN, “We will get to the bottom of this.”
“This was an anticipatable problem,” he said. “Ten years ago they had the same issue. Why did they not weatherize their equipment? Why did they not take appropriate regulatory action?”
As Magness told state legislators during more than 10 hours of testimony last month, ERCOT collects weatherization plans and emergency operations plans from generators but does not have enforcement authority over their weatherization practices. Sub-freezing temperatures and ice knocked out more than 52 GW of the ISO’s generation at one point, or nearly half of its installed capacity. (See Texas Lawmakers Dig into Power Outages.)
On Monday, the ISO said it had received multiple inquiries from resource entities on how they should submit their updated plans, as required by the grid operator’s protocols.
The subcommittee asked for all documents relating to preparations for an extreme winter weather event dating back to 2010, including:
details on every generator that failed;
all communications between ERCOT and the PUC, Texas Gov. Greg Abbott and any other state or federal staff referring to causes for outages and/or preparations for future extreme weather events;
all documents relating to decisions on the rolling blackouts; and
all documents on the 1989 and 2011 outages.
The materials are due March 17.
In a statement, ERCOT said, “We received the letter and will be providing responses.”
The Oversight committee has broad authority to investigate “any matter” at “any time” under House rules. The environmental subcommittee’s jurisdiction includes global climate change, public health and regulatory affairs.
PUC Proceeds Without its Chair
In its first open meeting since Chair DeAnn Walker’s resignation Monday, the PUC voted to direct ERCOT to claw back ancillary services (AS) payments from generators for service that went undelivered during the outages.
Carrie Bivens, executive director of the ISO’s Independent Market Monitor, filed a letter with the commission Monday noting a number of instances where AS, contracted in advance, was not provided in real-time because of the forced outages or reduced available capacity.
Bivens recommended that ERCOT invoke a “failure to provide” settlement treatment for AS not provided in real-time during the Feb. 14-19 operating days, thus producing “market outcomes and settlements consistent with underlying market principles.” She also recommended repricing the Feb. 15-20 operating days’ day-ahead AS clearing prices and capping them at the system-wide offer cap of $9,000/MWh.
PUC Commissioners Shelly Botkin (left) and Arthur D’Andrea discuss clawing back ancillary service costs. | Public Utility Commission of Texas
Commissioners Arthur D’Andrea and Shelly Botkin saved the latter discussion for their next open meeting on Friday.
The PUC also terminated the use of the low system-wide offer cap, which was replaced by the system-wide offer cap on Feb. 16 because it was preventing generators from reaching the $9,000/MWh scarcity price. It additionally directed Oncor Electric Delivery, CenterPoint Energy, Houston Electric, AEP Texas and Texas-New Mexico Power to waive the 5% late fee for invoices due from retail electric providers from Feb. 22 through March 3 (51812).
D’Andrea, who has seniority over Botkin, led the 15-minute meeting in Walker’s absence and opened the proceeding by acknowledging the former chair’s “dedicated and tireless service to this agency.”
“She was the hardest-working and the most detail-oriented person I’ve ever met,” D’Andrea said. “I’ll miss having her around.”
D’Andrea and Walker both worked on Abbott’s staff before he appointed them to the commission. Botkin was with ERCOT before being appointed to the PUC.
Texas Legislators Seek More Changes
State legislators continue to file bills to reform the Texas grid and prevent widespread outages in the future.
Rep. Will Metcalf (R) filed a measure (HB2522) to require that the independent organization certified to manage the grid have a 15-person board comprised of only Texas residents. The governor, lieutenant governor and Texas House speaker would each pick five of the members.
Other bills would remove the PUC chair from the board (HB2529); require members to represent different geographic regions of the state (HB2544); certify the Railroad Commission, which regulates the state’s oil and gas industry, as the grid manager (HB2562); and require the PUC to annually perform a financial and compliance audit of ERCOT and then publicly share the results with lawmakers (HB2586).
WECC stakeholders expressed their displeasure Tuesday with a revised proposal to revamp its committee structure and appoint a new Committee Review Body (CRB) to oversee its working committees and report to the board.
The regional entity for the Western Interconnection is holding workshops this month to discuss a third version of its plan to streamline its committee structure and create the CRB, pronounced “CARB.”
Offering a “gut reaction” to the CRB proposal, Lorissa Jones-Cardoza, transmission reliability program manager at the Bonneville Power Administration and a member of WECC’s Member Advisory Committee (MAC), said, “We don’t feel that it’s appropriate that the CRB be the only venue to the board.”
She recommended that other standing committees, including the MAC, should have “individual voices to the board, not have everything funneled to the CRB. It feels like an extra layer and a removal of that direct conversation and feedback that the various working groups get from the board.”
Fred Heutte, Northwest Energy Coalition senior policy associate and member of the MAC, said, “I have mixed feelings about the CRB — defining what its scope is, what its authority is and the usual issues of who’s on it and [its voting role and procedures]. I’m not a big fan — at this point — of the idea.”
WECC needs to balance the “self-determination” of its expert stakeholder committees — “the ability to develop and progress along the path of their approach in considering issues and input and doing assessment” — with the “need for coordination across different groups,” Heutte said.
“What’s the right amount of top-down coordination or direction versus the ability of the different bodies to do their thing and yet have a cohesive result that brings good results back up the chain to whatever level of reporting and outputs that we’re looking for?” he said.
Victoria Ravenscroft, WECC senior policy and external affairs manager and the moderator of Tuesday’s session, asked stakeholders to identify good aspects of the CRB. She was met with dead silence. “Uh, oh, that’s not good,” Ravenscroft said.
So far, the efforts of WECC’s Stakeholder Engagement Task Force (SETF) have faced resistance.
An initial straw proposal in October prompted numerous stakeholder concerns and resulted in a heavily revised proposal in November, followed by Version 3 in February.
The latest revised straw proposal offered a new take on how committees would be configured after the shakeup, which WECC hopes to implement in September.
It includes a plan to combine two major oversight groups, the Operating (OC) and Market Interface (MIC) committees, into a new Reliability Risk Committee (RRC), which would report to the CRB along with the existing Reliability Assessment Committee (RAC). The prior plan called for retiring the OC, MIC and RAC.
It maintains Version 2’s proposal to establish the CRB to “ensure [WECC’s working] committees are delivering relevant and timely work products to the appropriate audiences.” (See WECC Overhauls, Expands Stakeholder Committee Plan.)
The CRB would consist of representatives from WECC management, the RAC, RRC, MAC and others, according to the newest plan. It will report to the board, oversee the RAC and RRC, review and manage WECC’s stakeholder committee structure, and “identify the need for, and when necessary, initiate work to meet WECC’s strategic objectives,” the plan states.
The SETF is scheduled to deliver a final proposal to the board between June and August.
Massachusetts residents want the state’s grid to be clean by 2050, but they are also opposed to the infrastructure projects that will support that energy transition, Matthew Nelson, chair of the Massachusetts Department of Public Utilities, said Wednesday.
“I don’t think there’s a really great understanding about what it’s going to take to actually build out an electric grid that’s going to support electrifying the transportation sector, electrifying the heating sector and moving the clean energy from one point to another,” Nelson said at the Northeast Energy and Commerce Association’s Renewable Energy Conference.
The energy industry at large needs to invest in educating the public about the infrastructure necessary to accommodate clean energy, he added.
To eliminate carbon emissions in the state by 2050, Massachusetts needs to electrify major sectors that have large energy consumption rates, such as transportation and housing, which together account for 74% of the state’s emissions. The conversion of those sectors will place major strains on the existing electric infrastructure. New electrical substations and transmission lines, as well as upgrades to existing substations and transmission lines, will be needed to increase the state’s capacity for supplying clean sources of energy to buildings, homes and vehicles.
Nelson’s comments about infrastructure challenges for electrification echo the struggle between state regulators and the East Boston community over a recently approved substation project.
Massachusetts’ cumulative installed solar capacity of 2,572 MW as of December 2019 exceeded the state’s target of installing 1,600 MW of solar in 2020 by 972 MW. | Massachusetts Department of Energy Resources
The Massachusetts Energy Facilities Siting Board approved the substation despite the concerns of members of the state-designated Environmental Justice Community. (See Follow-up: Controversial East Boston Substation Approved.)
Community members argued that East Boston is already overburdened by infrastructure and air pollution that contribute to the disproportionate number of people with asthma or COVID-19.
But Nelson said that the energy industry needs to help the public understand that infrastructure will increase the grid’s capacity and ability to electrify industries that are currently emitting harmful gases. New electrical infrastructure will “make the air cleaner and improve the health and quality of life of all the people that live in Massachusetts,” Nelson said.
Opponents of the substation also claimed that the increase in demand for clean energy could be met with solar panels and battery storage, which would cost ratepayers less than the proposed substation.
The state surpassed its goal of installing 1,600 MW of solar power by 2020 by 972 MW, but the widespread distribution of renewable energy requires upgrades to substations and “sophisticated planning” to ensure it is efficient, reliable and resilient, Nelson said.
“We are hearing loud and clear from the public they want clean energy and more reliability, and I think we can achieve both of those things, and that will require there to be a lot more electric infrastructure,” he said.
Eversource Energy and Ørsted’s joint offshore wind development venture signed a long-term agreement Friday with the city of New London, Conn., to facilitate the modernization efforts at State Pier to support turbine staging and assembly.
The Host Community Agreement between the city and developers guarantees at least $5.25 million for New London in payments over seven years during the construction of the Revolution Wind, South Fork Wind and Sunrise Wind projects, according to a press release from Connecticut Gov. Ned Lamont. If Eversource/Ørsted wins OSW procurement bids from Connecticut, the city could receive up to an additional $1.5 million per year, retroactive to year three of the deal.
Heavy seas engulf the Block Island Wind Farm off the coast of Rhode Island. | NREL
The agreement was more than a year in the making and built on a $157 million public-private Harbor Development Agreement announced in February 2020 between Connecticut and Eversource/Ørsted, which is expected to pay about half of the project’s price tag plus millions in rent during its 10-year lease. The three OSW projects represent more than 1,700 MW, including 304 MW procured by Connecticut through Revolution Wind. Connecticut has called for its electricity supply to be 100% decarbonized by 2040. (See IRP Details Conn.’s Paths to Carbon-free Future.)
The State Pier site actually consists of two piers that will be conjoined under the HDA. According to the Connecticut Port Authority’s website, “the facility will accommodate a broad range of cargo types” after the OSW developers’ lease agreement is up. The infrastructure upgrades will increase the pier’s capacity to accommodate heavy-lift cargo and maintain its freight rail link. Construction is expected to be completed by August 2022. The wind developers and operator Gateway Terminal will also help the state market the port’s use during times when turbine construction is not occurring.
If Eversource/Ørsted continues operations at State Pier beyond the initial 10 years under the HDA, the HCA provides an option to negotiate additional payments. As for the completion of the wind projects, Eversource said during its year-end earnings call on Feb. 17 that South Fork Wind has an in-service date of 2023. All the review process steps for the project have either been met on or ahead of schedule since the U.S. Bureau of Ocean Energy Management established its revised plan last summer. Both Revolution and Sunrise are “unlikely to achieve” the end of 2023 in-service dates. (See Eversource Reports Profit Increase, Carbon Decrease.)
The Eversource/Ørsted’s joint offshore wind projects (Revolution Wind, South Fork Wind and Sunrise Wind) are highlighted in blue and are a key part of a new agreement between the companies and the city of New London, Conn. | Ørsted
New London Mayor Michael Passero said in a statement that under full implementation of the agreement, with additional payments from the port authority and Gateway, the city is expected to take in more than $1 million yearly for the initial seven-year time frame.
“The city has worked tirelessly to reach an agreement that benefits the taxpayers of New London as the host city for the State Pier’s use for offshore wind development,” Passero said. “It is exciting for the city to partner with the state on its commitment to increasing clean, renewable energy for Connecticut residents, and we look forward to economic growth opportunities for New London and the region as the offshore wind industry continues to grow.”
Previously, the city received payments in lieu of taxes from the Department of Transportation when it owned State Pier. U.S. Rep. Joe Courtney (D-Conn.), whose district includes the city, said the agreement between it and the developers “is a long overdue restructuring of payments to New London that is much fairer to the taxpayers of the city.”
“Today’s agreement makes Connecticut’s role as a leader in the offshore wind industry official, with New London now poised to become the premier commercial East Coast hub for this sector and our state set to become a leader in the transition to renewable energy and the fight against climate change,” Lamont said. “This project represents exactly what I have wanted to see at the local level since I came into office: local investment, job growth, development, and a focus on providing for a better environment and future for our state.”
For decades, rural Scott County, Va., has been transporting thousands of students daily in diesel-powered school buses. Drivers shift the rumbling yellow vehicles into low gear to climb the Blue Ridge Mountains, expelling plumes of carbon dioxide, a cause of climate change, and particulate matter, which can cause respiratory ailments.
On Saturday, the General Assembly approved legislation introduced by Del. Mark L. Keam (D) (HB 2118) offering school districts grants to replace pollution-belching buses with nonpolluting — but more expensive — electric ones. Separately, the legislature rejected a proposal by Dominion Energy to authorize $400 million in spending to purchase 1,500 electric buses.
But some rural school district transportation directors say replacing diesel buses with electric ones is unrealistic, citing a laundry list of potential problems, including battery life, charging station challenges and cost.
“Electric buses simply would not be workable in this area,” said Tim Edwards, director of transportation for Scott County Schools. “Scott County’s terrain is too hilly, mountainous.”
Some rural school districts say electric buses are not practical for them. | Dominion Energy
Ben Truett, head of transportation for Alleghany County Schools, agreed that electric buses “would work in cities, because of their flat terrain, but not in the mountain areas” of Virginia. “The batteries do not have enough range or power.”
A spokesman for Gov. Ralph Northam did not respond Wednesday when asked whether he plans to sign Keam’s bill.
Keam says his legislation, which would allow school districts to seek competitive grants from a new state fund, offset by federal and private sector philanthropic contributions, would provide major health benefits. In Virginia, he said, nearly 130,000 children suffer from asthma, which leads to many missed school days. With approximately 17,000 school buses transporting more than 1 million students, electric buses would improve their health, he said. Studies have estimated that average exposure to particulate matter inside diesel buses is three to six times greater than ambient levels.
Battery electric buses’ fuel and maintenance costs are about 60% lower than conventional diesel vehicles, but they cost two to three times as much. | Dominion Energy
However, Keam has acknowledged that electric school buses aren’t ideal for rural districts. “My bill really wouldn’t be helpful” to those areas, he said. “Virginia needs a plan on where we put charging stations” before encouraging rural areas to apply for the competitive grant, he said.
Erik Bigelow, senior engineering consultant at the Center for Transportation and the Environment, agrees that current batteries are suitable for flat land but don’t have the power or range in rural areas. Improved battery technologies could give buses the range needed to run rural routes, but that could be years away, he said.
Hydrogen fuel cell buses could offer longer range but require expensive fueling infrastructure.
Battery electric buses’ fuel and maintenance costs are about 60% lower than conventional diesel vehicles, but the increased purchase cost — a premium of about $200,000 per vehicle — have limited deployments to date. Alternative procurement strategies could accelerate the transition, however. The school district in Montgomery County, Md., last month approved a contract to lease 326 school buses over the next four years — the largest single procurement of electric school buses in North America — without increasing the district’s costs. (See related story, Schools’ ‘Budget Neutral’ Bus Deal Could Accelerate BEB Growth.)
Infrastructure
But reducing upfront costs does nothing to address range anxiety.
The leading electric bus maker, High Point, N.C.-based Thomas Built Buses, averages 134 miles on a fully charged 220-kWh battery. Some bus routes in Alleghany and Scott counties are more than 100 miles round trip, the directors said. Given the power needed to climb steep hills, they doubt a fully charged battery would last an entire trip. Both counties run buses that get about 360 miles to a 100-gallon tank, with most requiring a top off several times a week.
The lack of charging stations also concerns the transportation directors, especially Edwards. Scott County has only five buses returning to a central depot each school day; the remaining 41 stay at the drivers’ homes.
While HB 2118 provides funding for charging stations, Edwards asked for clarification: “Does that mean each driver would have a charging station at their home?” If buses were rerouted to a central location, it would double the amount of time and miles drivers are on the road, costing the cash-strapped district money it can ill afford.
Additionally, Edwards questions whether the county has the infrastructure to operate charging stations. The district still has schools using coal furnaces for heat, because some parts of the county’s electric infrastructure is 60 to 70 years old, said Edwards, the district’s former maintenance director. “Homes running air conditioning in the summer and electric heat in the winter couldn’t power buses without problems,” Edwards said.
Proponents of vehicle-to-grid technology say school districts could charge their buses when prices are low at night and profit from selling power during the day when prices are higher. But Truett worries the school district could fall prey to powerful electric utilities. “I don’t see a mutual benefit here,” he said. “It’s not 50/50.”
Even with grants, the rural districts fear they would struggle to keep electric buses on the road. While the maintenance is cheaper, nobody in their garages has the know-how to repair one, the directors said.
Truett, a self-described environmentalist, wants the district to carry students in environmentally friendly electric buses, but even if they were practical, the $400,000 price tag per bus is beyond the district’s budget.
Alleghany County, where one in five people live in poverty, has a fleet of 56 buses. “We are talking tens of millions of dollars to replace our fleet,” Truett said. “This district doesn’t have that kind of money. And I sure hope the state doesn’t make electric buses an unfunded mandate.”
Edwards echoed that sentiment. “It’s Cadillac versus Ford,” he said. “Even if we won a Cadillac, it requires upkeep, costly upkeep. It requires special tools and knowledge, things we don’t have here.”
If the state requires school districts to purchase electric school buses, Scott County, with an 18% poverty rate, would also be “in a world of hurt,” Edwards said.
Dominion Bus Plan Rejected
Rayhan Daudani, a spokesperson for Dominion, Virginia’s largest electric provider, says battery-powered buses are a “win-win” for schools and the power grid. “The buses use less fluids [and] require no oil changes,” he said.
The power company announced in August 2019 it would pursue what it called the nation’s largest electric school bus deployment, beginning with a $13.5 million pilot to provide 50 electric buses to school districts. The first recipients are some of Virginia’s largest school systems: Alexandria, Arlington, Norfolk and Richmond. The first buses were delivered in October.
Dominion Energy’s proposal to spend $400 million to purchase 1,500 electric school buses was rejected by Virginia lawmakers. | Dominion Energy
Dominion said it hoped to replace all 13,000 diesel buses in its service territory. (See Dominion Sees Green in Electrification.) But legislation that would have allowed the utility to purchase 1,500 buses at a cost of $400 million was rejected by the House of Delegates on Feb. 27, the last day of the legislative session (SB 1830). The bill failed even after the program was reduced to 1,250 and then 1,000 buses, according to a report by the Virginia Mercury. Other amendments would have required that one-quarter of the buses go to districts serving low-income students and given the State Corporation Commission authority to determine whether the program was “in the public interest.”
Dominion would have paid the increased cost of the buses and owned the batteries, while school districts would own the buses. The State Corporation Commission reportedly estimated the cost — excluding charging infrastructure — at $345 million, including $108 million in profit. Dominion would have offset the cost by raising residential customers bills by $12 annually.
Observers said some of the opposition to the bill came from resentment over Dominion’s efforts to block legislation that would have restored state regulators’ power to conduct rate reviews, legislation that the Senate Commerce and Labor Committee killed Feb. 15.
Maryland’s largest school district last month approved a contract to lease 326 electric school buses over the next four years — the largest single procurement of electric school buses in North America and one that would double the number of battery electric school buses in the U.S.
But the real significance of the deal may be not its size — Montgomery County in suburban D.C. runs the 14th largest district in the U.S. — but its contract structure.
Battery electric buses’ fuel and maintenance costs are about 60% lower than conventional diesel vehicles, and they emit no carbon dioxide or particulate matter, which can contribute to asthma and other respiratory diseases. But sticker shock — BEBs cost two to three times as much as diesels — has limited most districts to one or two buses, based on available grant funding.
The contract Montgomery County Public Schools approved with Highland Electric Transportation is “budget neutral” — meaning the school district will pay no more than it would have to acquire traditional diesel vehicles. Highland will pay for the buses and recoup its investment through decreasing vehicle prices, less expensive fuel and maintenance savings. It also will be able to sell power from idled bus batteries to the grid when prices are high.
“As far as MCPS and the vendor know, this is the first budget-neutral, non-grant-dependent, school bus fleet electrification plan available,” schools Superintendent Jack R. Smith told the county’s Board of Education in seeking approval of the four-year $168.7 million contract. “This is the leading edge of the trend that is expected to sweep through the school bus industry.”
Nat Kreamer, CEO of Advanced Energy Economy, said the innovative contract could help meet President Biden’s pledge to electrify the nation’s 500,000 school buses within a decade.
“This leadership step taken by Montgomery County Public Schools shows that it’s possible today to electrify transportation at scale. Comprehensive solutions like Highland Electric’s can leverage private capital, meet the needs of fleet operators and serve communities now without burdening ratepayers or taxpayers.”
“Like solar, where the upfront technology costs are ‘sticker-shock’ high, but the value created for customers over time is substantial, selling EV as a service makes it affordable for customers to make the switch,” said Kreamer, co-founder of SunRun. “I believe Highland’s business model can accelerate the adoption of electric vehicles in the same way SunRun did for residential solar.”
He added: “These school buses do double duty, providing pollution-free transportation for schoolchildren and grid services that benefit all electric customers, while also being available as mobile backup for communities affected by power outages.”
Creating a Stir
Montgomery County intends to replace all of its more than 1,400 diesel buses by 2035.
The district will receive 25 Daimler Thomas Built buses with Proterra batteries for fall 2021, 61 in fall 2022 and about 120 — representing one-twelfth of its fleet — in each of the two years thereafter.
The district’s contract includes use of the buses, all charging infrastructure, charge management and electricity. Separately, it will be responsible for vehicle liability insurance, tags and any damage to vehicles.
“Budget neutrality depends on achieving all of the savings associated with not using the equivalent number of diesel buses,” Smith said. “As some of the diesel infrastructure is scaled back, there may be some modest cost in the early years, which will be offset in later years as the whole fleet is electrified.”
“It’s created quite a stir,” Todd Watkins, the district’s director of transportation, said of reaction to the contract. “If [the contract model accelerates BEB deployment] we’re certainly happy to play that role.”
The contract calls for Highland Electric to provide charging infrastructure at all five of the district’s bus depots, beginning this summer with one near Bethesda — less than a mile from a Pepco switching yard — which will need no power upgrades.
“In one [depot] we need a new loop, I’m told. In others, we just need some transformers. It varies across the different depot locations,” he said in an interview with NetZero Insider. For the first depot, “there was nothing else that Pepco had to do.”
Highland Electric agreed to allow the district’s staff to perform maintenance on the new buses and reimburse the district for the costs, “so we don’t all of a sudden lay off a bunch of our fleet maintenance employees,” Watkins said.
Watkins said the district’s routes average under 100 miles per day, with the longest about 130 miles. The depots will be equipped with Level 3 DC fast chargers, “so we know if we need to boost them in the middle of the day, we can do that.”
Watkins said he attended meetings where the three major American school bus manufacturers predicted that within 10 years, all orders for new school buses will be for electric versions.
But, even if the cost concerns are addressed, the limited range of the batteries and lack of charging infrastructure will make it a difficult sell in some districts. (See related story, Rural Va. Schools Skeptical on Electric Buses.)
With Washington’s first hydrogen production facility slated to be built in his district, a state legislator has introduced a bill to create tax exemptions for hydrogen fuel cell electric vehicles.
The bill (SB 5000) by state Sen. Brad Hawkins (R) to apply a partial sales tax exemption to hydrogen FCEVs appears to be sailing through the Senate with overwhelming bipartisan support. Three committees have recommended passage, and the bill faces a full Senate floor vote any day. If passed, the bill would go to the House of Representatives. Opposition in Olympia has been almost nonexistent.
The production of hydrogen is carbon-free when the fuel is sourced from water and the process is powered by emissions-free resources. Exhaust from a hydrogen FCEV is a trickle of water from the tailpipe and a wisp of steam.
Washington’s Senate Bill 5000 would provide a partial sales tax exemption for hydrogen fuel cell electric vehicles sold in the state. | Toyota
Hawkins’ bill would set up an eight-year pilot program in which the 6.8% state sales tax on cars would be cut in half for the first 650 hydrogen FCEVs sold in Washington. Prices for the cars range from $34,000 to $58,000, according to manufacturers’ figures. After eight years, the exemption would be reevaluated. The exemptions would apply only to new vehicles.
Hawkins is not aware of any hydrogen FCEVs being sold so far in Washington. However, a Kenworth manufacturing plant in the Seattle suburb of Renton has built a handful of fuel cell semi-trucks earmarked for use in California with hydrogen cells from Toyota Mirai cars. A legislative memo said Washington has almost 64,000 conventional electric vehicles.
Hawkins represents a legislative district in central Washington crossed by the Columbia River, which supports an extensive network of hydroelectric dams. His district includes the Douglas County Public Utility District, owner and operator of the 840-MW Wells Dam.
The PUD plans to use electricity and water from that dam to power a proposed plant to create hydrogen from reservoir water. That project’s origin comes from a 2019 Hawkins bill signed into law that allows Washington PUDs to manufacture and distribute hydrogen.
Construction of that $20 million hydrogen plant is scheduled to begin this spring and be finished by November, Douglas County PUD official Gary Ivory told the House Transportation Committee on Feb. 18. The plant is expected to produce two tons of hydrogen a day. “We hope to expand the plant if there is an adequate demand,” he said.
In an interview, Hawkins said: “It is really a big opportunity.”
Hawkins envisions central Washington with its many dams becoming a center of producing hydrogen fuel cells for cars. He said that electric vehicles are slowly becoming more numerous and noted that a hydrogen fuel cell can be refueled in a few minutes, while using an electric charging station can take hours to fully recharge a standard electric vehicle.
Washington does not have any hydrogen fuel cell stations. Hawkins described the co-dependency of hydrogen FCEVs and fueling stations as a “what-came-first-the-chicken-or-the-egg” situation. He said that one hydrogen fueling station is planned for southwestern Washington. Hawkins hopes the Washington legislature’s biennial transportation-funding package — to be tackled later this session — will include two hydrogen stations for his legislative district.
He argued that his agriculture-heavy district — which is the nation’s leading grower of apples — is well suited to combine hydrogen fuel stations with hydrogen-fueled trucks serving the area’s farms.
“North-central Washington is as well positioned as any region in the United States to lead the use of hydrogen” in vehicles, Hawkins said.
