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November 16, 2024

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New Jersey Tees up Funding, Guidebook to Boost EV Charger Installations

New Jersey plans to boost the number of EV chargers in the state with $4 million in funding from the Volkswagen settlement and a new guidebook to help municipalities efficiently move proposed charging stations through the permitting process.

The money — part of the state’s share of the carmaker’s settlement for false reporting of vehicle emissions — will go to the New Jersey Department of Environmental Protection’s (DEP) It Pay$ to Plug In program for a second round of grants that will add conveniently located charging sites to the 636 public chargers already installed and in operation across the state.

The DEP will start accepting applications on Monday for awards that can be used to install Level 1, Level 2 or DC fast chargers. The deadline for applications is May 14.

The state’s new, 28-page guidebook, “Charge Up Your Town: Best Management Practices to Ensure Your Town is EV Ready,” is intended speed up those installations by helping towns and cities evaluate EV charger projects and expedite their permitting. The book was put together by the DEP, the New Jersey Board of Public Utilities (BPU), the New Jersey Department of Community Affairs and stakeholders, including two independent transportation agencies.

“With this guide, we are equipping towns with a roadmap to help develop cost-effective EV charging infrastructure,” said Lt. Governor Sheila Y. Oliver, in a Tuesday release announcing the guidebook’s publication. “Taking these steps is part of our administration’s larger strategy to help the state meet its climate goals.”

The DEP expects the Plug In program to award between 20 and 53 grants that will cover the cost of installing and maintaining Level 1 and 2 chargers and DC fast charger projects. Eligible locations include public areas, multi-unit dwellings and private sites, such as workplaces, with a maximum grant of $200,000 per location.

Gov. Phil Murphy has committed $10.8 million, or about 15 percent of the state’s share of funds from the Volkswagen settlement to the installation of electric charging stations. The first round of It Pay$ to Plug In awarded $3.2 million in grants to install 535 chargers with 842 ports in four counties and more than 40 municipalities. Funded projects — not all of which may be complete and in operation yet — are located at public sites, multi-family housing and workplaces.

The manual includes sections detailing different types of chargers and what they are used for, how to reduce the time and effort needed to ensure charging stations meet zoning, construction and building permit requirements, and the varied fee structures charging stations can use to generate revenue.

The introduction to the guide states that it is “intended to help municipal staff and their communities understand the context for the statewide EV ordinance, and the considerations relevant to municipalities as they take steps to support the state goals of increasing access to electric vehicle charging infrastructure.”

EV Charger Targets

Charger availability is key to Murphy’s goal of converting the state to 100% clean energy by 2050, and dramatically cutting emissions from the transportation sector, which generates 43% of the state’s greenhouse gas emissions.

The state wants 330,000 passenger and light-duty EVs on the road by 2025. The targets for chargers are at least 400 DC fast chargers at 200 or more locations and at least 1,000 Level 2 chargers — those with a 240-V electricity source — by December 2025.

In addition, a state law passed in 2020, S2252, sets a deadline of December 2025 for having at least 100 charging sites in community locations, such as such as a town centers, commercial areas, retail centers and multi-unit dwellings.

A network of chargers spread evenly across the state would help to assuage the concerns of prospective EV drivers who might be reluctant to buy battery-powered cars due to concerns that the batteries might run out with no charger nearby.

That need for “geographic distribution” across the state means that the location of a proposed site will play a big part in whether a proposed DC fast charger site will get second-round funding, Andrea Friedman, supervisor in the DEP’s electric vehicle program told a recent online seminar held to explain the program to potential applicants.

“We want them to be convenient, and we want them to be visible in communities,” she said. “We want to give people the confidence to go out and buy electric vehicles because they know there will be chargers nearby.”

Time is of the essence, she said.

“We’re looking for projects that are shovel-ready,” she said. “What that means to us is that you will be able to begin the process as soon as the DEP makes the award. If you’re planning a project that can’t be installed for two or three years, that won’t work for this grant program.”

State Charger Incentives

The It Pay$ to Plug In program is the latest of a raft of state and federal initiatives designed to boost the availability of chargers in New Jersey.

The federal Joint Office of Energy and Transportation rolled out the first round of state funding for EV charging from the bipartisan Infrastructure Investment and Jobs Act in February, with New Jersey slated to receive more than $15.4 million in 2022. To qualify for the funds, the state will be required to submit a plan detailing how it will use the money. (See States to Get $615 Million for EV Charging from IIJA Funds.)

In parallel, the BPU is pursuing two straw proposal processes, one to set out the rules to induce private investors to install Level 1 and Level 2 chargers around the state and another to deploy chargers for medium- and heavy-duty electric vehicles.

In September, the board also launched a $4 million incentive program to install chargers on main traffic corridors and at tourist hotspots, especially at the Jersey Shore, to attract more visitors to the state.

And in December, the BPU authorized a program to promote the installation of chargers in multifamily buildings by offering a $1,500 incentive for Level 2 chargers installed in apartment, condominium or mixed-use residential buildings. The program also will pay half of the project’s “make-ready” costs — for installing the wiring required for a charger — up to a total of $5,000.

Murphy in July signed two bills designed to make it easier to set up electric vehicle charging stations. One made the installation of electric vehicle supply equipment or a make-ready parking space a permitted use under municipal zoning laws, removing the sometimes lengthy and expensive task of getting a zoning variance to install a charger. The second bill required that any redevelopment plan approved by a municipality must include EV charging infrastructure as part of the planning for the redevelopment or rehabilitation of the area. (See NJ Cuts Permitting Obstacles for EV Charging Stations.)

Picking ‘User Friendly’ Locations

The Plug In program awards grants in two tracks, one to cover costs to purchase and maintain Level 1 chargers (120 V) with up to five ports, and the second for Level 2 chargers (240 V) with at least two charging ports. The program will offer up to $750 per Level 1 port and up to $4,000 per Level 2 port in a “first come, first served” system, the DEP’s Friedman told the online seminar.

Grant awards for DC Fast chargers, which use a 480 V source, will be made in a separate, competitive solicitation, she said. These chargers must be in a “community location,” with maximum grants of $200,000 per location, according to the program rules.

The program will not fund the expansion of existing sites because the DEP wants to stimulate the deployment of chargers across the state. Fast charger applications must include plans for at least two 50 kW chargers that are “available exclusively to the general public,” Friedman said.

On top of that, she said, “they must be user friendly.”

“That means well-lit, open 24 hours a day, seven days a week all year round,” she said. “They must accept credit cards. They can use other forms of payment, but they must accept credit cards, and they must display pricing information.”

“We’re also very interested in locations with amenities within walking distance, maximum a quarter mile,” Friedman said. “The closer, the better. We’re looking for locations with bathrooms, food, coffee, retail. And the reason is: people will be spending 20 or 30 minutes or more at these sites, and we want them to have a good charging experience and have something to do while they’re at the chargers.”

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EPA Restores California Tailpipe Standards

California and other states can again enforce tailpipe emissions rules that exceed federal regulations following EPA’s repeal Wednesday of Trump-era actions that revoked state authority to enact higher standards.     

The decision also restored California’s mandate that all new passenger vehicles sold in-state must be emissions-free by 2035.

The Trump-era actions were “decided in error and are now entirely rescinded,” EPA said in a summary of its decision. “With this action, California’s authority under the Clean Air Act to implement its own greenhouse gas emission standards and zero-emission vehicle sales mandate is restored.”

Since the 1970s, California has had waivers from the federal government to adopt its own stricter vehicle emissions rules because of “compelling and extraordinary conditions,” including Southern California smog. In 2013, the state received its latest waiver under the federal Clean Air Act to pursue the state Air Resources Board’s Advanced Clean Cars program, with tough restrictions on greenhouse gas emissions and the zero-emission vehicle mandate.

Sixteen other states and the District of Columbia enacted the California GHG rules with federal permission.

In September 2019, the Trump Administration adopted the Safer Affordable Fuel-Efficient Vehicles Rule Part One: One National Program Rule (SAFE-1). Under SAFE-1, the National Highway Traffic Safety Administration declared that state regulation of carbon dioxide emissions from new cars intruded on federal regulation of fuel-economy standards and was preempted by federal law.

EPA withdrew California’s 2013 waiver based on NHTSA’s actions and its own interpretation that the state did not need its GHG emissions standards and zero-emission vehicle mandate to address the compelling and extraordinary conditions that had prompted the waiver. Interpretations of SAFE-1 also prevented other states from adopting California’s GHG emissions standards.

On his first day in office, President Biden issued an executive order directing federal agencies to review SAFE-1 and other Trump administration rulings. EPA said it was reconsidering the previous administration’s withdrawal of California’s waiver in April 2021, as EPA Administrator Michael Regan called the withdrawal “legally dubious.”

On Wednesday, Regan said, “We proudly reaffirm California’s longstanding authority to lead in addressing pollution from cars and trucks. Our partnership with states to confront the climate crisis has never been more important. With today’s action, we reinstate an approach that for years has helped advance clean technologies and cut air pollution for people not just in California, but for the U.S. as a whole.” 

Environmental groups praised the decision, saying the cutting-edge actions of California and likeminded states had pushed automakers to produce lower-emissions vehicles nationwide.

“States have long been leaders in cleaning up tailpipe pollution, and the EPA is absolutely right to recognize this,” Luke Tonachel, director for clean vehicles and fuels at the Natural Resources Defense Council, said in a statement.

“While the previous administration tried to undermine this authority, the law clearly gives California and other states the ability to adopt standards to curb the pollution affecting the health of their citizens,” Tonachel said. “Reaffirming this legal authority will protect public health and help address the climate crisis.”

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Texas PUC Pushed on Reliability Charges

The one-year anniversary of ERCOT’s near grid collapse during last February’s disastrous winter storm was marked by a glut of reports, webinars and opinion pieces recapping what went wrong and detailing the changes made to ensure it doesn’t happen again.

Connect the Texas grid to the rest of the country, said an energy institute. Because about 61% of Texan households now use electric heat, a group of academics determined that ERCOT’s grid is more susceptible to cold weather. Another university study posited that 100% clean energy and renewable energy would prevent blackouts.

One politician said Texas fixed its problems quickly because it isn’t connected to the national grid, while another wrote that Texas is on the right track. An energy fellow at the University of Houston blamed the problems on the energy-only ERCOT market, which places all the risk on the consumer.

The truth is out there. Somewhere.

Yes, the grid has survived three cold snaps and an arctic front, but none of them was as severe as last year’s winter storm. The lights and heat stayed on, but not before raising anxiety levels among Texans still suffering from PTSD.

Alison Silverstein (Texas Tribune) Content.jpgAlison Silverstein | Texas Tribune

During one of her many recent webinar appearances, energy consultant Alison Silverstein didn’t wait for questions on the grid’s performance, asking them of herself. She said the grid is in better shape than last year with “lots more to do” but that ERCOT’s performance during these latest cold-weather events are not proof that everything is fixed. (See ERCOT Breezes Through Latest Winter Storm.)

“Absolutely no,” Silverstein said during a panel discussion last month set up by Advanced Power Alliance. Last month’s weather “was not enough of a stress test to really show that the grid is better.”

ERCOT’s regulator, the Public Utility Commission of Texas, has made several major changes, directed by the numerous power-related bills lawmakers passed last year. Power plants have been ordered to winterize, with ERCOT conducting inspections and the PUC penalizing those that have failed to comply.

The commission has also lowered the price cap from $9,000/MWh to $5,000/MWh; the previous commission set prices at the old cap for four days during last year’s storm, resulting in $45 billion in market transactions that week and several bankrupt participants. Ancillary service prices have also been limited after last year, part of several tweaks around the edges in what is called Phase 1 of the market improvements.

At the PUC’s prodding, ERCOT has been practicing a “conservative” approach to operations, calling on more reserves more quickly and increasing the number of reliability unit commitments (RUCs). London Economics said in a recent study that 96% of the RUCs last year were to maintain additional online reserves and not for resolving local issues.

“That is a good thing in terms of having more resources ready to operate, but we’re also paying a bundle to make that happen, and we haven’t had any public accounting of that those costs yet,” Silverstein said.

Partnering with the Texas Consumer Association, Silverstein filed a petition with the PUC asking it to direct ERCOT to calculate the costs spent on grid reliability. The filing says the reliability costs, along with a 36% increase in natural gas prices from April 2020 to February 2022 and new charges for securitizing generator and retail electric providers’ losses during the storm, “are being passed through higher electric bills” to the 27 million individuals the grid operator serves.

“The rough information available in the PUCT proceedings to date suggest that costs could exceed several billion dollars for past [Winter Storm] Uri costs (which will not improve future reliability) and at least another billion for recent reliability improvements,” Silverstein wrote.

During a one-on-one interview with PUC Chair Peter Lake as part of a weeklong virtual symposium, “The Winter Storm, One Year Later,” Texas Tribune CEO Evan Smith said he had been told ERCOT had spent $25 million procuring reserves during one day of the arctic front and as much as $500 million since the middle of last year.

Asked to confirm the numbers, Lake deferred to ERCOT.

“I don’t know the numbers off the top of my head, but yes, more reliability costs more … and we know we need more reliable power in Texas,” Lake said.

Doug Lewin 2022-03-02 (RTO Insider LLC) FI.jpgDoug Lewin, Stoic Energy | © RTO Insider LLC

Stoic Energy President Doug Lewin harkened back to ERCOT CEO Brad Jones’ September testimony to the state Senate Business and Commerce Committee. Asked about the RUC costs, Jones estimated that they were $40 million/month during the summer.

“That’s a lot of money for consumers to shoulder, potentially a 5 to 10% surcharge on top of already higher bills,” Lewin said. “These numbers are rough estimates. I’d love to replace them with more accurate figures, but we need transparency from ERCOT and the PUC on these costs.”

Lewin estimated $1 billion in additional reliability costs, assuming ancillary service costs have gone up two or three times from 2020’s $381.5 million bill and $50 million in monthly costs since the summer.

On Tuesday, Jones told RTO Insider that those numbers are way off. He pointed out that the $40 million was the cost during summer months for all ancillary services and said that ancillary costs were $270 million from last summer through early February.

“To put that into context, that’s less than $1 a customer per month, on average,” Jones said.

He said staff assumed 380 million MWh of energy production in ERCOT, with the average consumer using about 1 MWh/month in deriving the figure, with RUC costs being “shockingly low.”

ERCOT’s annual RUC report shows there were 3,853.1 effective RUC resource-hours in 2021, up from 220.1 in 2020. Total RUC make-whole payments were about $5.3 million last year and were covered through capacity short charges, staff said, with about $3.1 million in excess profits clawed back from generators. In 2020, those numbers were about $404,000 and $484,000, respectively. (See “RUC Usage Skyrockets,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“These actions have also moved us significantly toward a capacity market since these are mostly out-of-market capacity payments,” Lewin said. “Whatever you think about capacity markets, those decisions should be made with transparency, not by opaque regulatory changes.”

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Landfill Methane Bills Near Passage in Washington Legislature

Washington’s Senate last week voted 30-17 to approve a revised House bill to regulate methane emissions from landfills.

The amended bill (HB 1663) now goes back to the House, which passed the original 57-40 on Feb. 11. Most, but not all, legislative Republicans have opposed the measure.

“We know that methane is one of the deadliest greenhouse gases,” Sen. Liz Lovelett (D), who shepherded the bill through the Senate, said Friday.

“Methane stays in place for 10 years instead of 100 years, but it has 100 times the impact of carbon emissions,” HB 1663 sponsor Rep. Davina Duerr (D) said at a Jan. 10 hearing on the bill, which would require the capture of methane emissions from Washington’s landfills.

On Friday, Sen. Shelly Short (R) said Republicans want more incentives built into the legislation to encourage converting captured methane into energy.

At the Feb. 11 House vote, Rep. Mary Dye (R), the GOP environmental issues leader in the House, argued that it is a mistake to regulate methane in landfills before gas-capture technology is more advanced. “This bill is going into an area that we have not thoroughly vetted on their impacts to the communities. … When you put a regulation in, you stop innovation at that moment,” she contended.

In broad strokes, Duerr’s bill would require the owner or operator of an active covered landfill with 450,000 tons or more of waste in place to calculate the quantity of gas generated by the landfill. The same requirements would apply to closed landfills holding at least 750,000 tons. Washington has 24 landfills that store more than 450,000 tons of waste, according to the state’s Department of Ecology. And it has at least a couple dozen — mostly closed —that store less than 450,000 tons.

If a landfill’s emissions calculations exceed 3 million Btu per hour, the operator would have to install and operate a gas collection and control system. A collection system would also be required if methane emissions hit 500 parts per million (ppm), as determined by instantaneous surface emissions monitoring, or if an average methane concentration reaches 25 ppm based on integrated surface emissions monitoring.

The bill does not apply to landfills that handle solely hazardous wastes or only inert waste or non-decomposable wastes.

California and Oregon already have similar landfill emissions rules in place. (See Oregon Adopts Nation’s Strictest Landfill Emission’s Rules.)

Methane accounted for 10% of the nation’s greenhouse gas emissions in 2019, according to the EPA. EPA figures show that landfills account for 17% of the nation’s emitted methane, behind fuel production at 30% and livestock-related emissions at 27%. A 2021 Penn State study concluded that EPA might be underestimating the nation’s methane emissions.

Cutting Waste

The Senate on Thursday also voted 34-14 to pass another amended House bill that would cut methane emissions from the state’s landfills by reducing the waste placed into them. The tweaked legislation has also gone back to the House for approval.

The bill (HB 1799) by Rep. Joe Fitzgibbon (D), chairman of the House Environment and Energy Committee, calls for the state to reduce the volume of organic material dumped into landfills to 75% below 2015 levels by 2030. Organic material — manure, yard wastes, food wastes, wood and garden wastes — contribute to the production of methane.

The House passed the bill 52-46 mostly along party lines on Feb. 11.

HB 1799 would not apply to cities and counties with fewer than 25,000 people or those that produce less than 5,000 tons of wastes annually. Also exempted would be rural areas with a population density of less than 75 people per square mile.

The bill would require a business generating at least 8 cubic yards of organic wastes annually to have an organic materials management plan by Jan. 1, 2024, while businesses generating 4 cubic yards of such waste must implement plans by Jan. 1, 2025. The Ecology Department would be tasked with reviewing the rules in 2026 to determine if they need changes.

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Vermont Climate Council Extends Deadline to Find TCI-P Alternative

The Vermont Climate Council is planning to extend its original timeline to find a replacement for the Transportation and Climate Initiative Program in the state’s interim Climate Action Plan.

An alternative to the proposed multistate cap-and-invest program is needed to fill a 26% gap in the emission-reducing actions of the council’s interim plan, released Dec. 1. The council expected to recommend Vermont join TCI-P, but it changed course in November after Connecticut, Massachusetts and Rhode Island said they no longer planned to implement the program.

The abrupt turnaround forced the council to release its plan with a promise to further study transportation emissions-reducing options and recommend a final course of action by June.

A task group in charge of that study told the full council on Monday that it plans to extend the June deadline to November. The council did not oppose the new timeline.

“We need a little bit more time to begin to really lay out the characteristics and potential benefits and ramifications of different approaches,” said Council Member Johanna Miller, energy and climate program director for the Vermont Natural Resources Council.

“Most of our recommendations are likely going to require some legislative support,” she said.

The Vermont legislature adjourns in May, so legislators would not take up any transportation sector recommendations made in June until they reconvene in January 2023. Delaying until November, Miller said, will give the task group more time for analysis and public engagement while ensuring they give policymakers time to draft potential legislation.

Initial study by the group will focus on understanding the framework for joining the Western Climate Initiative and the possibility of creating a Vermont-only Clean Transportation Standard. (See Without TCI-P, Vt. Will Explore Joining Western Climate Initiative.)

Biomass Actions

Members of another task group in charge of finding a resolution to outstanding issues related to biomass in the climate plan said Monday that they may seek a similar deadline extension for their work.

Before adopting its interim plan, the council chose to table proposed actions on biomass for further study, with a plan to release final recommendations in June.

Biomass is a “complicated topic,” said Council Member Richard Cowart, a principal at the Regulatory Assistance Project. “It has multiple arms and legs to it, and I think it’s going to take [the task group] some time to work through the issues.”

The group has met already to identify its study scope, but the topic intersects with other climate plan segments that the council has adopted already, according to Billy Coster, co-chair of the Agriculture and Ecosystems Subcommittee and director of natural resources planning at the Vermont Agency of Natural Resources.

“Trying to understand exactly where those intersects exist and how far the council would like us to go down those paths is important,” Coster said.

Central to the task group’s work will be reconsidering the preliminary biomass actions that the subcommittee presented to the full council and that the council agreed to table. Those actions called for identifying how biomass for thermal heat generation can support the transition away from fossil-fuel heating without having a net effect on Vermont forests. They also included a prohibition on expanding or building large-scale electric generation biomass facilities in the state.

The subcommittee recommended that any policy or regulation for biomass account for all greenhouse gas emissions associated with fuel production, such as extraction and transportation, in-state or out-of-state. Vermont currently relies on an in-state, sector-based GHG inventory for tracking emissions, but a supplemental analysis of lifecycle emissions related to energy use is in the works, according to Council Member Jared Duval, executive director of the Energy Action Network.

When discussing the nuanced issues related to biomass, Duval said, council members must rely on the “latest and highest quality available science and analysis.”

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VC Firm Sees Key Role for Tech in Clean Food Systems

Investor interest is growing in the U.S. for climate-smart agriculture (CSA) systems that reduce food loss and the emissions associated with it, according to Hans Tung, managing partner at GGV Capital.

CSA enables companies to predict supply and demand so they can avoid food waste, Tung said Wednesday during a Center for Strategic and International Studies panel on food technology.

The U.S. Department of Agriculture estimates that up to 40% of the U.S. food supply is wasted, and EPA estimates that the annual greenhouse gas emissions from that waste is equal to the annual emissions of 42 coal-fired power plants.

GGV has a history of investing in climate-tech, with its smart food systems investments totaling $4 billion last year.

U.S. food-tech companies saw $16.6 billion in total funding in 2021, according to Tung. “There’s no question there will be more investments coming to this area, because there are a lot more teams that are doing good things in this space.”

In 2017, GGV invested in Bowery Farming, a company that Tung said “is extremely impressive at taking vertical farming technologies and making them commercially viable.”

Tung described Bowery as a “unicorn,” a term used in VC investing for a startup valued at more than $1 billion. The New York-based company secured $300 million in funding in May, bringing its total value to $2.3 billion, according to a press statement. The challenge, Tung said, is to make Bowery’s business model commercially viable in more places.

Bowery is the largest indoor vertical farming company in the U.S., according to Chief Marketing Officer Katie Seawell. It has two operating farms in New Jersey and one in Maryland.

“We are taking non-arable land and turning it into highly productive farmable land,” she said during the panel discussion. “We are typically refurbishing warehouses, stacking crops floor to ceiling; and we use LED light to mimic the spectrum of the sun.”

Technology is at the core of the company’s growing process, which integrates sensors, machine vision, robotics and data into operations. The company’s proprietary farming design “constantly” monitors crop needs to “unlock quality, yield and flavor in a way that … is next-level in terms of produce,” Seawell said.

Bowery’s business model focuses on building local, vertical farms that will network and scale, which Seawell says reduces food-miles and, therefore, transportation emissions. In addition, the company’s operations help address food waste by reducing the time from harvest to store to between 48 and 72 hours, which extends produce shelf life for retailers and customers, she said.

The company’s ability to use data to map demand in the marketplace will become “more precise,” Seawell said. Retailers will no longer “have a glut of produce or food,” which “reduces food waste and, ultimately, carbon emissions.”

Global Initiative

The agricultural sector needs “more tools” to lower the cost of addressing climate change, according to David Livingston, senior adviser in the Office of the U.S. Special Presidential Envoy for Climate.

“The only way to do that is by investing more in innovation,” he said during the panel discussion.

Livingston is part of the team behind the Agriculture Innovation Mission for Climate (AIM4C) officially launched in November by the U.S. and the United Arab Emirates during the U.N. Climate Change Conference in Glasgow, Scotland (COP26). The initiative launched with 33 countries and 48 nongovernmental partners to mobilize a $4 billion investment in global agriculture innovation.

AIM4C recognizes “that the agriculture sector has been neglected in climate conversations,” Livingston said. “If we’re successful with this [five-year] initiative, when you think about climate-tech, you’ll think not just about solar panels, wind farms and Teslas, but you will also think about the food-tech and ag-tech of the future.”

The initiative aims to drive more government spending to food-tech.

During AIM4C’s first ministerial meeting last month, its partners committed to doubling the original funding commitment to $8 billion before the next climate change conference (COP27) in Sharm el-Sheikh, Egypt, this fall. The initiative also announced new focus areas for public-private partnership that include methane, small farm solutions, emerging technologies and nature-based solutions.

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Mass. Net-zero Building Code Proposal Faces Barrage of Criticism

Massachusetts Gov. Charlie Baker’s administration is facing widespread criticism over its proposed net-zero building energy code, with frustrated state representatives, town officials and environmental advocates saying that it doesn’t go far enough.

Proposed updates to the current “stretch” energy code and a new specialized net-zero opt-in option that, along with the states’ base building code, would make up the options for municipalities to adopt once they’re in place, were required by the climate law passed in 2021.

“What we are proposing today would have a significant impact on both our greenhouse gas emissions as well as the cost for residents in these buildings,” said Patrick Woodcock, commissioner of the Department of Energy Resources (DOER), in announcing the straw proposal in February. But the administration’s plan has been criticized by Democrats in the state legislature. (See Mass. Legislators Call for Fossil Fuel Ban in Net-zero Building Code.)

And as DOER held a series of public hearings over the last few weeks, local elected officials piled on, too.

Central to the criticism is that the proposed specialized opt-in code, designed to be the most aggressive option municipalities can adopt, does not allow cities or towns to mandate that all new construction be fossil-fuel free.

Instead, it would require that new buildings that still use fossil fuels be “prewired” for electrification and have rooftop solar when feasible.

The opt-in code should “allow municipalities like Cambridge and Lexington and others that are ready to do so to require fossil-fuel free, all-electric net-zero buildings,” said Quinton Zondervan, a member of the Cambridge City Council.

“We’re not asking the state to impose that requirement on municipalities,” Zondervan said. “We’re asking simply for the permission to require it… in our own municipalities, using our own political processes to make those decisions and to move forward in the way we think is necessary to safeguard the climate and our future.”

Stretchcode (MA DOER) Content.jpgThe three types of building energy codes that municipalities could adopt under Massachusetts’ new proposal. | MA DOER

A commonly cited document at the hearings was the latest U.N. Intergovernmental Panel on Climate Change report, the most urgent iteration of the series yet, which calls for immediate and ambitious action to combat climate change.

In the face of the report’s urgency, critics see the Baker administration’s proposal as a half measure.

“What I’m seeing so far in the straw proposal is really weak right now, and we can’t wait for incremental, little by little movement to get there, said Alanna Nelson, an elected member of the town planning board in Marian, Mass. “We’ve been doing that for the past 10 years, but we need to move faster.”

Most of the feedback DOER received at the hearings was critical.

Even Michael Ossing, a Marlborough city councilor who said he supports the gradual, “piecemeal” approach taken by the Baker administration, acknowledged that there should be a way for municipalities to move faster.

He asked DOER to consider adding a “no new fossil-fuel energy” option to the code for communities to experiment with on a trial basis.

Five towns in Massachusetts — Acton, Arlington, Brookline, Concord and Lexington — have filed home rule petitions asking to prohibit gas and oil hookups in new buildings.

“While I ultimately think this is the end goal, the immediacy of it is what’s troubling to me,” Ossing said. “Having towns that want to participate … and be a trial balloon for lessons learned is something I think would be a fair approach and something I hope DOER would consider.”

Another of the major criticisms of the new code proposal is that it doesn’t include new requirements for renovations or additions.

“Having a renovation that has base and minimum energy code requirements put to it really just punts the energy consumption of that building for another 10 years,” said Chris Larkum, who runs a residential energy consulting company in Dartmouth, Mass. “It feels counterproductive for the intention of this code.”

The public comment process put on by the state was not immune to the frustration.

“I’m at wits end with the state, and I’m very upset about this process. And I’m upset that there aren’t more people here able to speak about this,” said Jeanne Cahill, an environmental scientist from Northboro.

DOER recently extended the deadline for written public comment to Friday, March 18.

The department will publish full code language later this spring and hold more hearings this summer.

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Lawmakers Pass Wash. Buildings Emissions Bill

The Washington Senate on Tuesday voted 28-21 along partisan lines to approve a bill designed to trim the carbon footprints of roughly 50,000 buildings in the state.

The amended Senate Bill 5722, introduced by Sen. Joe Nguyen (D), passed the House last Thursday along mostly partisan lines. It now goes to Gov. Jay Inslee for his signature. 

Nguyen’s bill calls for the state’s Department of Commerce to develop and implement standards for reducing carbon emissions from “Tier 2” buildings by Dec. 31, 2030. Tier 2 buildings include multifamily residential, non-residential, dormitory, hotel and motel areas ranging from 20,000 to 50,000 square feet. A 2019 law already addresses the carbon footprints of “Tier 1” buildings greater than 50,000 square feet, which number about 10,000 in the state.

Under SB 5722, the Commerce Department must draft standards for Tier 1 structures by Dec. 1, 2023, and inform affected building owners of new requirements by July 1, 2025. Building owners will be required to submit their compliance plans to the agency by July 1, 2027; every five years thereafter they must file updated reports detailing relevant energy management plans, operations and maintenance plans, and energy use analysis.

Building owners who fail to submit documentation of their compliance will face penalties of 30 cents per square foot, with some exceptions made for financial hardship. The bill also provides for establishment of a program to provide early adopters with base incentive payments of 85 cents/square foot — excluding parking and unconditioned spaces.

Owners complying with the requirements after 2030 will be eligible for incentives of 30 cents/square foot, to be administered by participating gas and electric utilities.

Republican opponents of SB 5722 did not say Tuesday why they voted against the bill.

However, Republicans and some business interests have previously voiced concerns about rent control measures being required for building owners to be eligible for the incentives. The final version of the bill eliminated that requirement and allows the Commerce Department to establish “enhanced” incentives for multifamily building owners “willing to commit to antidisplacement provisions.”

The Commerce Department will fine-tune the standards and submit a report to the legislature in 2029.

Buildings account for 27% of Washington’s carbon emissions, the second-largest emitter behind transportation at 45%. In 2018, Washington’s carbon emissions totaled 99.57 million metric tons (MMT). A 2008 law set emission goals of 50 MMT by 2030, 27 MMT by 2040 and 5 MMT by 2050.

Robert Mullin contributed to this article.

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House Committee Debates EVs as Response to Russia

A congressional hearing on building out a domestic supply chain for electric vehicles turned into a battleground Tuesday as Democrats and Republicans debated sharply different strategies for responding to the Russian invasion of Ukraine and the dizzying increases in gas prices Americans are facing at the pump as a result.

As President Biden announced a ban on the import of Russian oil — a move both parties support — Democrats on the House Energy and Commerce Subcommittee on Energy saw the crisis as yet another reason to move the nation toward clean energy, while Republicans wanted to double down on oil and gas production. Average gas prices across the U.S. stand at $4.25/gallon, according to AAA.

“This crisis is a stark reminder: To protect our economy over the long term, we need to become energy independent,” Biden said in his speech on the import ban. “Loosening environmental regulations or pulling back clean energy investment will not lower energy prices for families, but transforming our economy to run on electric vehicles powered by clean energy, with tax credits to help American families winterize their homes and use less energy, that will help.”

Speaking at the subcommittee hearing, Rep. Frank Pallone (D-N.J.), chair of the full committee, echoed the president, saying, “The lesson from Russia’s invasion of Ukraine is not that we need to drill more. America is already the largest oil and natural gas producer in the world, and that has not protected us from global oil shocks. … EV investments will not lower prices a ton for all consumers today, but neither will Republican efforts to force open more public lands to drilling.”

But Republicans at the hearing countered that talking about EVs amid the current crisis was irrelevant and called on Biden to quickly boost domestic oil and gas production by lifting restrictions on permitting for pipelines and for drilling on federal land. “It is time we stand up to [Russian] aggression and help our allies in Europe fight back by flooding the global market with affordable and reliable American energy,” said Rep. Fred Upton (R-Mich.), the subcommittee’s ranking member.

Committee Ranking Member Cathy McMorris Rodgers (R-Wash.) called Democrats’ support for the U.S. EV market a “command-and-control approach … central to a radical agenda to dismantle America’s tremendous energy systems,” which would ultimately play into Russian President Vladimir Putin’s hands. “We must come together and say ‘no’ to Putin … and say ‘yes’ to flipping the switch on domestic production of oil and cleaner American natural gas.”

Witnesses at the hearing also presented opposing views on the expansion of EVs and charging infrastructure.

Thomas Pyle, president of the Institute for Energy Research, said he supports energy freedom and the right of Americans to choose EVs but opposes government mandates on energy technologies and fuels. Pyle pointed to EPA’s recent update of fuel efficiency standards for light-duty vehicles to 40 mpg by 2026 as “a de facto electric vehicle mandate. To meet the standard, about 17% of vehicles sold by model year 2026 will have to be electric,” he said. (See EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026.)

He also argued that the U.S. should learn from Europe’s “rushing to green,” which had left it overly dependent on Russian oil.

“This invasion was a huge wake-up call,” Pyle said. “It took, unfortunately, this for Europe to recognize that they were moving too fast; they weren’t investing in diversification of their supplies.”

‘Massive Customer Demand’

Industry speakers, however, maintained that vehicle electrification is increasingly market- and customer-driven.

Bob Holycross, vice president for sustainability, environment and safety engineering at Ford Motor Co., said his company’s $50 billion investment in EVs over the next five years is not about “rushing to green. These are products that customers are demanding, and we need to provide that bridge for them to help with the access and affordability.”

The company recently announced it was creating distinct units for its EV and internal combustion engine businesses. In response to high demand for the F-150 Lightning, the electric version of the company’s popular pickup, Ford is doubling production of the truck at its plant in Dearborn, Mich., he said. “Massive customer demand … validates that this is the right direction to move.”

The investments by major companies like Ford and the $7.5 billion for a nationwide EV charging network in the Infrastructure Investment and Jobs Act are providing momentum for the domestic supply chain, according to Natalie King, CEO of Dunamis Energy Partners of Detroit.

Branching out from her company’s core energy efficiency contracting business, King has started an EV charger manufacturing subsidiary, Dunamis Discharge, which she described as “probably the first African-American-[owned] electric vehicle manufacturer in this country.”

The company will be producing Level 2 chargers that meet federal “Buy America” standards at its plant in Detroit beginning this summer, King said, with DC fast-chargers to follow in early 2023. She expects to create 150 jobs at the plant with “workforce development efforts [focused] on underrepresented, economically disadvantaged Detroit communities.”

In response to a question from Pallone, King also said that domestic manufacturing of EV charging hardware and software will help to ensure to system cybersecurity.

With American-made projects, “we do have the ability to secure … our network software,” King said. “If we have the control over how we create, how we engineer and how we design and how we maintain our network software through our EV infrastructure, then we now have the ability to control cyberattacks [and] hacking from outside influences, like a dominating China,” she said.

State and Regional Initiatives

State policies are also driving EV adoption and the buildout of charging infrastructure, Cassandra Powers, senior managing director at the National Association of State Energy Officials, said as she reeled off a long list of state and regional initiatives.

A Southeast Regional Electric Vehicle Information Exchange is bringing together Alabama, Arkansas, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina and Tennessee, as well as Puerto Rico and the Virgin Islands “to support  infrastructure planning, policy development and program implementation, with a focus on rural and underserved areas,” Powers said. Tennessee is also working on putting 50 DC fast-chargers on highways across the state, while Florida is also “prioritizing DC fast-charger investments along key corridors and also among evacuation routes in underserved areas,” she said.

Powers said a holistic approach is needed to ensure EV chargers are sited across urban, suburban and rural communities, as well as disadvantaged neighborhoods. “There’s also a need to coordinate impending infrastructure buildout with enhanced transmission, distribution and generation planning,” she said.

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California Faces Third Straight Drought Year

California should expect a third year of drought after two nearly rainless winter months, the state Department of Water Resources (DWR) said following its latest survey of Sierra Nevada snowpack.

Low reservoir levels will limit hydropower generation this summer, and extremely dry conditions could worsen wildfires, which burned close to 7 million acres in the past two fire seasons combined.

“With only one month left in California’s wet season and no major storms in the forecast, Californians should plan for a third year of drought conditions,” DWR Director Karla Nemeth said in a statement last week. “A significantly below-average snowpack combined with already low reservoir levels make it critical that all Californians step up and conserve water every day to help the state meet the challenges of severe drought.”

The third snow survey of the season — conducted at Phillips Station, an alpine meadow near Lake Tahoe — showed snowpack there was 68% of average for March 1. Statewide, the snowpack was 63% of average for the date, the department said.

Heavy rains throughout the state in December had raised hopes of avoiding a third consecutive dry year. The snowpack on Jan. 1 at Phillips Station was 202% of average, and statewide snowpack was 154% of average. But an absence of new precipitation combined with early season snowmelt made those figures plumet.

“As the world continues to warm, precipitation is pushing toward extremes,” Jeremy Hill, manager of DWR’s Hydrology and Flood Operations Branch, said in the statement. “Even when we see large storms producing a lot of snow early in the season, all it takes is a few dry weeks to put us below average.”

The agency said the snowpack would not be enough to fill the state’s reservoirs, which supply water for residential and agricultural use during California’s dry months and generate thousands of megawatts of electricity to help meet summer peak demand.

DWR’s State Water Project is the fourth largest power producer in California; hydroelectric generation historically supplies about 14% of peak summer capacity.

The state’s two largest hydropower-producing reservoirs were below half-full on Sunday. Lake Shasta stood at 37% of capacity and Lake Oroville at 46%. In an average year, Lake Shasta would be about twice as full by now, and Lake Oroville would have 28% more water.

The power plant at Lake Shasta, operated by the U.S. Bureau of Reclamation, has a nameplate capacity of about 700 MW, though actual production has diminished significantly over the past two years.

DWR’s 644-MW Edward C. Hyatt Powerplant at Oroville Dam has fared even worse. It shut down for the first time in its history on Aug. 5 because the lake had dropped to critically low levels. After the December storms, the plant restarted one generating unit to supply electricity to CAISO’s grid.

A two-decade drought in the Southwest has strained Colorado River supplies, with Lake Mead behind Hoover Dam and Lake Powell behind Glen Canyon Dam dropping so low that hydropower generation could cease. (See Western ‘Megadrought’ Curtails Hydropower and Western Drought Puts Hoover Dam Hydropower at Risk.)

In 2020 and 2021, California saw two of its driest years ever. Snow water content in California peaked at 60% of normal in 2021 after a similarly dry winter the year before, CAISO said. The ongoing drought reduced hydropower by 1,000 MW in 2021, the California Public Utilities Commission and California Energy Commission said last summer.

Since the rolling blackouts of summer 2020, CAISO and the CPUC have been working to install batteries to store solar power for summer evening peak hours. More than 2,000 MW of battery capacity were added by the end of 2021 with another 2,000 MW expected to come online this year, the ISO said.