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November 1, 2024

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Washington Bill Would Factor ‘Climate Resilience’ into Water Systems

The big question on a Washington bill to add “a climate resilience element” to regulating residential water systems was: What would that rule physically do?

Sen. Mark Schoesler (R) posed that question Wednesday at a public hearing on the bill held by the Washington Senate’s Environment, Energy and Technology Committee.

Introduced by Sen. Christine Rolfes (D), Senate Bill 5626 would order the Washington Department of Health to require public water systems serving 1,000 or more connections to include a “climate resilience element” as part of water system plans, beginning Jan. 1, 2024. Local governments would be required to study how climate change could affect their water systems and then take remedial measures.

The bill would allocate $10 million every two years to help with those measures. That was the part that stumped Schoesler.

“What are we going to buy for $10 million?” he asked.

Rolfes said she had not seen the committee staff’s $10 million estimate until just before the Wednesday morning hearing. “The $10 million is new to me,” she said. Meanwhile, committee staff members were also unsure about what the allocations would be used for, other than acting on potential problems identified by studies.

Committee member Sen. Liz Lovelett (D) then pointed to her hometown of Anacortes on Fidalgo Island, which is long and narrow, and juts westward like a peninsula into Puget Sound from northwestern Washington. A water channel converts the “peninsula” into an island.

Lovelett noted that rising water levels from Puget Sound had periodically flooded water lines in and around Anacortes, prompting the town to move its water lines to higher elevations. She cited that as a possible remedial action that could have used a grant from a $10 million state fund.

Five people testified in favor of Rolfes’ bill, including representatives from the Sierra Club, the Washington Public Utility Districts Association and the Climate Impacts Group at the University of Washington. No one testified against the bill.

All stressed the need for studies to pinpoint threats from flooding and wildfires, which they linked to global warming.

Amy Snover, director of the Climate Impacts Group, said a data clearinghouse is needed to help local governments find information to evaluate potential threats from flooding and wildfires. Geography and topography would be major factors in those evaluations, she said.

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BOEM to Auction Six New Lease Areas in NY Bight

Increasing its bet on offshore wind, the Biden administration announced Wednesday that it will auction six lease areas in the New York Bight on Feb. 23, enough to site at least 5.6 GW of generation.

The six leases in the Bureau of Ocean Energy Management’s (BOEM) sale notice are the most ever offered in a single auction, totaling 480,000 acres. BOEM had solicited commercial interest for 1.7 million acres in the Bight but excluded 72% of the area to reduce environmental impacts and avoid conflicts with the commercial fishing industry and other ocean users. BOEM issued its final environmental assessment on the lease areas in December. (See BOEM Issues Final Environmental Review of NY Bight.)

Interior Secretary Deb Haaland, who announced the auction in a press conference Wednesday with New York Gov. Kathy Hochul and New Jersey Gov. Phil Murphy, said the leases will include stipulations to encourage the use of union labor, building of a domestic supply chain and “planned” transmission.

The announcement of the new leases came the same day the Department of Energy issued a report identifying five strategic priorities for maximizing the value and reducing the costs of offshore wind. The Biden administration has set a goal of 30 GW of offshore wind by 2030; with states on the East Coast already committed to a pipeline of 39 GW by 2040, DOE said the country could deploy 110 GW by 2050 — equal to 6% of current demand.

Murphy said the Biden administration’s enthusiastic support for OSW was a marked change from the Trump administration. “I think the most charitable word I can use is [the Trump administration] slowed whatever progress we were making; [I] wouldn’t necessarily say they stood in the way,” Murphy said. “They started out [wanting] to drill for oil and gas offshore. … So this is just night and day.”

Supply Chain, Labor

Like state officials, the Biden administration has promoted the new generation as economic development projects.  

BOEM said it will require lessees to describe their plans for contributing to development of a domestic supply chain and will offer a 50% reduction in the “fee rate” for five years for lessees that “meaningfully and substantially” assemble or manufacture major components in the U.S. That would reduce the fee rate from 2% to 1%.

The operating fee will be based on a proxy for the wholesale market value of the power generated from each project. The proxy will assume a 40% capacity factor for the first six full years of commercial operations, with potential adjustments based on actual generation in future years. BOEM will use the simple hourly average of the spot price for NYISO’s Zone J in New York City. At a wholesale power price of $40/MWh, the annual 2% fee for a 1,028-MW facility, would be $2.9 million.

New York, which has targeted 9 GW of OSW by 2035, will base procurement of offshore wind renewable energy credits (ORECs) in part on economic benefits provided by the projects, including domestic supply chain and port infrastructure investments, benefits to disadvantaged communities and creation of jobs and workforce training programs.

New Jersey, with a goal of 7.5 GW, has approved $350 million in tax credits tied to capital investments in offshore wind-specific facilities in the state.

Officials from BOEM and the two states have created a supply chain working group that will meet quarterly to coordinate their efforts.  

“We are now going to have a very significant regional cluster between New York and New Jersey that will make it very compelling … for folks to not just install, but build the stuff here,” Murphy said.

“This opportunity we’re presented with today is absolutely transformative, not just for New York and New Jersey, but for our nation,” said Hochul.

BOEM also will require lessees to “make every reasonable effort” to sign contracts with labor unions for construction.

“We’ve been laser focused on offshore wind for several years because we think that this can be the sector that is the shining example of how the clean energy economy can create high-road, high-quality jobs,” said Liz Shuler, president of the American Federation of Labor and Congress of Industrial Organizations (AFL-CIO), who also took part in the press conference. “… I can speak from the perspective of workers in the energy industry. They’ve been skeptical of the transition, because [they] have not seen the same quality, stable careers in clean energy that they have in the industries that they’ve worked in in the past. And there hasn’t been a commitment historically to high-quality jobs in the clean energy economy. But it doesn’t have to be that way.”

Transmission Planning

BOEM’s sale notice urged strategic planning of transmission, saying the agency is considering “the use of cable corridors, regional transmission systems, meshed systems, and other mechanisms.” It said it may condition approval of construction and operations plans “on the incorporation of such methods where appropriate.”

The DOE report said “strong near-term efforts” are needed to plan transmission to incorporate OSW “without long delays or lost opportunities.

“There is a lack of sufficient onshore transmission capacity to transmit power from the strongest offshore wind resources to load centers,” DOE said. “…Creating incentives to plan and share transmission across multiple offshore wind projects, states, and transmission planning regions can encourage collaboration in infrastructure planning, cost allocation, and transmission system development that can benefit all states within and across regions.”

Sites

The sites to be leased will be 20-69 nautical miles from New York and 27 to 53 miles from New Jersey, with minimum depths of 31 to 50 meters and maximum depths of 46 to 63 meters. BOEM has established a minimum bid of $100 per acre for the leases, which the agency said could produce 5.6 GW based on 3 MW per square kilometer.

BOEM listed 25 companies eligible to bid in the auction, each of which posted a $5 million deposit. BOEM said it would limit each company to only one lease to maximize competition in future procurements and limit consolidation of the offshore wind market.

Before the auction, BOEM will hold its fifth and final meeting with the fisheries community on Jan. 19 to describe how it decided on the final lease areas.

The final sale notice reduced the area by 22% from the preliminary notice, reflecting concerns by the fishing industry, the U.S. Coast Guard, the National Marine Fisheries Service and the Department of Defense (DOD).

It excluded lease area OCS-A 0543 in response to issues raised by the fishing industry and DOD and to make room for the siting of a “fairway” proposed by the Coast Guard to accommodate traffic travelling across the NY Bight from the Delaware Bay area to east of Montauk.

It also eliminated several areas that overlap with both fishing activity and seafloor features sensitive to impacts from construction. No leases were offered within 2.5 nautical miles of the Mid-Atlantic Scallop Access Area. BOEM also removed areas to the west of OCS-A 0539 that are used by the Atlantic surf clam fishery.

DOE Priorities

In addition to calling for planned transmission, the DOE report listed four other priorities for the nation’s OSW plans:

  • Expanded federal incentives to increase demand for offshore wind energy and grow the domestic supply chain;
  • Technology innovation and adaptations to reduce costs. “New system designs are required for U.S. operating conditions, such as deep water in the Pacific, hurricanes in the Gulf of Mexico, and ice formation in the Great Lakes,” DOE said. “Accessing wind resources in deep-water areas (~60% of the U.S. offshore wind resource) will be key to reaching long-term deployment goals. The deployment of floating offshore wind platforms … will be critical to development in the Pacific, Gulf of Maine and other regions with deep waters.”
  • Increase the transparency and predictability of regulatory processes and auction new lease areas. “The number of lease areas will need to grow significantly over the next decade to meet state and federal deployment goals,” DOE said.
  • Invest in supply chain development, including customized offshore wind ports and vessels. “Building a domestic supply chain and growing the industry will require dozens of port upgrades, numerous Jones-Act compliant vessels, and new factories for component manufacturing and assembly,” DOE said.

Interest in Gulf of Mexico 

In comments posted by BOEM on Jan. 11, Ørsted and Shell New Energies U.S. (NYSE:RDS.A) expressed interest in bidding for potential OSW leases in the Gulf of Mexico.

ClearView Energy Partners said BOEM could offer leases in the Gulf as early as the first half of 2023.

“While existing energy infrastructure and supply chains in [Gulf of Mexico] coastal states may attract offshore wind project developers (indeed, commenters note that offshore wind generation could facilitate green hydrogen production), we emphasize other factors could dampen interest in comparison to the East Coast, including lower electricity prices, the lack of strong state-led decarbonization policies in the GOM area and higher risks of severe hurricanes,” ClearView said in a note to clients.

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DOE to Tackle Tx Siting, Financing, Permitting in Better Grid Initiative

The Department of Energy on Wednesday announced the launch of the Building a Better Grid (BBG) Initiative, aimed at attacking the many obstacles to building out the long-distance, high-voltage transmission network that the Biden administration sees as key to decarbonizing the U.S. electric system by 2035.

“The foundation of our climate and clean energy goals is a safe, reliable and resilient electric grid that is planned hand-in-hand with community partners and industry stakeholders,” Energy Secretary Jennifer Granholm said in a press release. Using federal dollars from the Infrastructure Investment and Jobs Act (IIJA), the initiative will “upgrade the nation’s grid, connect more Americans to clean electricity and broadband, and reliably move clean energy to where it’s needed most.”

Getting to President Biden’s goals of a decarbonized grid by 2035 and a net-zero economy by 2050 will require the grid to expand by 60% by 2030, according to DOE, and by three times its size by 2050. Large renewable projects in remote areas, as well as offshore wind, will need high-voltage transmission lines to efficiently bring power to urban demand centers.

But, according to the DOE, about 70% of the nation’s existing transmission lines and transformers are more than 25 years old. At the same time, hundreds of gigawatts of clean power projects sit in grid operators’ queues, unable to connect because of a lack of transmission capacity.

A 2021 study from the Lawrence Berkeley National Laboratory estimated that 750 GW of solar and wind and 200 GW of storage were backed up in U.S. interconnection queues at the end of 2020.

The need for grid flexibility and resilience has also been underlined by power outages caused by extreme weather or other catastrophic events, such as California’s wildfires, this summer’s extreme heat in the Northwest and the winter storm in Texas last February.

As detailed in a notice of intent released Wednesday, “DOE intends to launch a coordinated transmission deployment program to implement both IIJA and previously enacted authorities and funding.”

A transmission needs study will “identify where new or upgraded transmission facilities could relieve expected future constraints and congestion driven by [the] deployment of clean energy; … higher electric demand as a result of building and transportation electrification; and insufficient transfer capacity across regions.” Additional studies will look at viable pathways to a large-scale transmission system over the next 15 to 30 years, as well as transmission pathways for integrating offshore wind.

Provisions of the IIJA allow DOE to participate in public-private partnerships and to become an “anchor customer” for new and upgraded transmission lines, buying as much as 50% of a project’s planned capacity for a term of up to 40 years. The law also provides a $2.5 billion revolving fund to support the construction of new, replacement or upgraded high-capacity transmission lines, and another $3 billion in matching grants for grid-enhancing technologies, such as dynamic line ratings, flow control devices and network topology optimization.

The IIJA also gives DOE the authority to designate national transmission corridors in “any area experiencing or expected to experience electricity transmission capacity constraints or congestion that adversely affects consumers.” It also authorizes FERC to issue permits for the construction or upgrade of projects in such corridors. DOE intends to prioritize corridors that “overlap with or utilize existing highway, rail, utility and federal land rights of way.” It will also offer developers pre-application review of projects and coordinate with FERC on permitting.

‘Prioritize and Expedite’

The initiative was announced Wednesday by the Biden administration as part of a suite of energy initiatives.

Interior Secretary Deb Haaland kicked off the day with the announcement of next month’s auction of six offshore wind lease areas in the New York Bight, off the coasts of New York and New Jersey. The 480,000 acres in the six lease sites, the most ever offered in a single auction, could eventually generate 5.6 to 7 GW of power. The Bureau of Ocean Energy Management will hold the auction Feb. 23. (See related story, BOEM to Open Six New Lease Areas in NY Bight.)

The Interior Department also took the lead on the rollout of a new cross-agency effort to streamline reviews of wind, solar and geothermal projects on federal land. A memorandum of understanding signed by the Interior, Agriculture, Defense and Energy departments and EPA calls for the agencies to “prioritize and expedite” reviews of these projects. Interagency teams staffed with subject matter experts will help advance environmental reviews and “accelerate renewable energy decision making,” according to the MOU.

Making a Dent

All three initiatives drew praise from Democratic lawmakers and clean energy advocates, but reactions also included calls for the Senate to pass the Build Back Better Act, which includes tax credits for a range of renewable technologies and transmission.

While applauding BBG, Rep. Kathy Castor (D-Fla.), chair of the House Select Committee on the Climate Crisis, said, “I am determined to help communities lower costs with the transition to a resilient and clean energy economy, and I look forward to working with my Senate colleagues to ensure that the critical transmission investments in the Build Back Better Act reach President Biden’s desk, so he can sign them into law.” 

Gregory Wetstone, president and CEO of the American Council on Renewable Energy, said interagency efforts to streamline permitting “will ensure the American people benefit from the best solar and wind resources this country has to offer.” BBG will “unlock the potential of America’s clean energy economy by catalyzing the nationwide buildout of the long-distance, high-voltage transmission.”

Noting that China is investing 80 times more than the U.S. in transmission, Rob Gramlich, executive director of Americans for a Clean Energy Grid, said that BBG and the federal dollars in the IIJA “could make a big dent in the national transmission challenge.”

But he also cautioned that “the funding levels are nowhere near what is required for a national macrogrid. … Congress will also need to pass the Build Back Better Act with the tax credit for regionally significant transmission because there is no way to recover costs of large interstate lines presently.”

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Nevada PUC Rejects Mobile-only Payment Systems for EV Chargers

With more EV drivers using their smartphones to pay for vehicle charging, ChargePoint has asked Nevada regulators for flexibility to leave magnetic-stripe or chip credit-card readers off its public stations.

The request was made in connection with NV Energy’s $100 million EV infrastructure plan that the Public Utilities Commission of Nevada (PUCN) approved in November. (See NV Energy Gets Green Light for $100M EV Charger Plan.)

But PUCN voted 3-0 Tuesday to reject ChargePoint’s proposed changes to the charging station technical standards included in NV Energy’s plan. The plan says that stations “must accept a credit or debit card (magnetic stripe and chip card) without incurring any additional fees … in compliance with ISO 15118.”

The commission instead voted to reaffirm its Nov. 30 order approving NV Energy’s plan, but it made a grammatical change in the payment requirement. The requirement now says that charging stations “must accept a credit or debit card (magnetic stripe and chip card) without incurring any additional fees … and be in compliance with ISO 15118.”

The commission said that the technical requirements are minimum standards, and “other forms of payment may be offered and accepted in addition.”

“The commission reaffirms that more options for payment, rather than fewer options, will make it easier for customers to pay,” the order said.

In reaffirming its Nov. 30 order the commission also rejected a request from EVgo, another EV charging station provider. EVgo asked the commission to give third parties participating in NV Energy’s plan more flexibility to decide the number, type and capacity of chargers at a particular site.

EVgo also asked that the minimum power requirement for DC fast-charging stations installed as part of the plan be 100 kW, rather than 150 kW.

NV Energy’s plan, known as the Economic Recovery Transportation Electrification Plan (ERTEP), is a requirement of Senate Bill 448, a product of the legislature’s 2021 session.

The three-year plan, which starts this year, includes a network of electric vehicle charging sites throughout the state.

Paying With Smartphones

In a petition filed with PUCN last month, ChargePoint said that “real world evidence” indicates most EV drivers prefer to use a smartphone app or other mobile payment method to pay for charging.

The petition argued that requiring magnetic-stripe and chip card readers nearly doubles the lifetime cost of a Level 2 charging station, “with the predictable result that fewer charging stations will be deployed through the plan.”

Magnetic-stripe and chip readers are susceptible to fraud and are unreliable when used outdoors, the petition said.

“ChargePoint is concerned that the payment standards NV Energy has proposed drastically will limit the equipment and vendors that will be able to participate in the plan,” the petition said.

ChargePoint asked that the order be changed to require the stations to accept credit cards, but not specify the card-reader technology. Alternatively, the company suggested that charging-station hosts be allowed to ask for and receive a waiver of the magnetic-stripe and chip card reader requirement.

In a response to the petition, NV Energy said the technical requirements were a topic of “substantial debate” during proceedings leading up to the commission’s Nov. 30 order, and ChargePoint is simply rehashing those arguments.

During testimony, NV Energy officials shared concerns that EV drivers without a smartphone wouldn’t be able to use charging stations that lacked magnetic-stripe and chip readers.

Although ChargePoint said the requirements would limit the number of vendors that could participate in NV Energy’s plan, the utility responded that “the plan can be fully and effectively implemented with a limited number of … vendors willing and able to comply with the technical requirements.”

California Consistency

The Sierra Club and Nevadans for Clean Affordable Reliable Energy (NCARE) weighed in on ChargePoint’s petition, saying EV charging stations deployed as part of NV Energy’s plan should accept credit cards, debit cards and cash cards.

But NCARE questioned the need for magnetic-stripe readers, saying the technology is being phased out.

Many EV charging stations don’t directly accept credit, debit or cash cards and instead require use of a proprietary app or a call to an 800 number, NCARE representative Max Baumhefner testified in November. Prepaid debit cards are especially important to those who are “unbanked” or “underbanked,” he said.

In California, regulations require public charging stations to include a chip reader for credit, debit and cash cards, Baumhefner said, adding that Washington may soon follow suit.

“While contactless credit cards have gained market share in recent years, the debit and cash card market has not seen the adoption of contactless technology at the same rate,” Baumhefner said.

NCARE recommended that NV Energy’s plan mirror the California standards for payment at EV charging stations. Because California accounts for about half of the EV market in the U.S., makers of EV charging equipment will likely be basing designs on California standards, the group said.

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RI Asks Public: How Should We Define Net Zero by 2050?

Rhode Island’s climate council has begun the process of sorting out how it will define “net zero by 2050” for the upcoming update to the state’s 2016 Greenhouse Gas Emissions Reduction plan.

In a public session on Tuesday, the Rhode Island Executive Climate Change Coordinating Council (EC4) sought comments on which emissions to count in the plan, how to net those emissions and over what time frame to net them.

Under Rhode Island’s Act on Climate passed last year, the EC4 must submit a GHG emissions reduction plan update by January . The act sets an economy-wide, net-zero emission target for 2050.

In the current GHG inventory, the state tracks carbon dioxide, methane, nitrous oxide and fluorinated gases, summarized as CO2 equivalent and reported in million metric tons (MMT). While attendees were supportive of the four-GHG approach, there was some concern about the time frames used to calculate equivalencies.

“To combine the impacts of these very different kinds of gases, you need to come up with a way to figure out what one unit of methane means in terms of warming for the planet compared to carbon dioxide,” Timmons Roberts, Ittleson professor of environmental studies and sociology at Brown University, said during the session. That calculation, he added, depends on the time frame used.

Carbon dioxide, for example, stays in the atmosphere for hundreds of years, while methane has a short-term impact before breaking down. Their potential for warming the plant is calculated differently, depending on the time frame.

The New York Climate Action Council, in its draft scoping plan released in December, switched from a 100-year impact time frame to 20 years. For methane, Roberts said, that switch adjusts the impact from being “20 times worse than carbon dioxide per molecule to about 84 times worse.”

He suggested that Rhode Island consider the 20-year time frame for its accounting. “It looks like that’s the way the science is going,” he said.

The EC4 is considering different methods for the way it balances GHG emission from sources with sinks to find net emissions. Under the current inventory, Rhode Island takes all GHG sources and all GHG sinks, both summarized as MMTCO2e, and nets them, according to Carrie Gill, chief economic and policy analyst at the Rhode Island Office of Energy Resources.

As an alternative, she said, the accounting could net each GHG source and sink individually, then convert each GHG to MMTCO2e and add them together to find the final net measurement. A benefit of netting the GHGs separately, according to Gill, would be to target specific policies.

“If one of our policy objectives happens to be eliminating all [methane] leakage from the natural gas distribution system, then that would point us towards trying to get to a place where we can net each GHG first, because then it would meet additional policy objectives,” she said.

While attendees did not favor one accounting method over another, some suggested that netting through offsets or sinks should be a last resort, and Rhode Island should count emission sources outside of the state.

Rhode Island “should get to zero-carbon equivalent emissions” as quickly as possible, attendee Peter Trafton said. “Let’s start by 2030 and not be so focused on the arithmetic of how we add up to 2050 that we forget to get down as low as we can now.”

And while the state’s GHG inventory is consumption-based only for electricity, Roberts suggested it should be used for “everything.” That approach, however, has drawbacks.

“If we have natural gas-fired power plants, we should be including the emissions from the extraction and the transportation of that natural gas … because we know that Pennsylvania, New York and Connecticut, the states through which it’s traveling, are not counting those emissions,” Roberts said.

There’s no good way, however, to be certain of what other states are including in their own GHG inventory, he said.

The EC4 also is considering options for electricity sector accounting that changes the time frame for when emissions are released into the atmosphere.

“Our current practice aggregates these emissions based on averages over the entire year,” Gill said. Electric sector emissions change based on the fuel mix at the time that the electricity is pulled from the grid. Rhode Island, Gill said, counts them equally, whether it’s a renewables-heavy mix on a warm day or a fossil fuel-heavy mix on a cold day.

Future accounting options may allow the state to consider netting emissions over smaller time frames, but Gill said that would require some technological advances in accounting systems.

The EC4 will accept comments on how to define net zero by 2050 in the updated emissions-reduction plan through Jan. 28. In February, the council will discuss a draft of that definition during its regular meeting and release an update based on public input in March.

Another public comment session for the emissions-reduction plan in March will address the 1990 baseline against which emissions are measured.

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Washington Bill Takes Aim at Landfill Methane Emissions

A bill to regulate methane emissions from landfills drew praise and concerns during a hearing of the Washington House Environment and Energy Committee on Tuesday.

Questions surfaced about the costs and extent of House Bill 1663, introduced by Rep. Davina Duerr (D).

In its present form, the bill requires the owner or operator of a covered landfill with 450,000 tons or more of waste in place to calculate the quantity of gas generated by the landfill.

If that calculation exceeds 3 MMBtu 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 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 Emissions Rules.)

Landfills contribute to climate change with their methane emissions. “Methane stays in place for 10 years instead of 100 years, but it has 100 times the impact of carbon emissions,” Duerr said at the hearing.

Methane emissions from the state’s landfills are estimated to equal those of roughly 320,000 cars, said Martha Hankins, a manager with the Washington Department of Ecology.

“Methane is one of the most impactful greenhouse gases,” said Deepa Sivarajan, Washington policy manager with Climate Solutions. Heather Trim, executive director of Zero Waste Washington, said, “This bill is way overdue.”

Methane accounted for 10% of the nation’s emissions in 2019, according to EPA estimates. 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%.

Utilities and waste management officials voiced concerns about the unknown costs of implementing the bill and asked for more study on the subject. They also wanted a better grasp on which specific locations would have to comply with the bill’s requirements

“It is a significant unfunded mandate for municipal solid waste programs,” said Paul Jewell, policy director with the Washington State Association of Counties.

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NY Targets Bronx Neighborhood as Part of Clean Transit Program

New York Gov. Kathy Hochul on Monday announced the winners of $3.4 million in funding from the state’s Clean Transportation Prizes program for 17 projects to decarbonize trucking and busing, including five in New York City.

“As New York continues to pursue its nation-leading clean energy and climate goals, we must ensure that we are not leaving behind our traditionally underserved communities,” Hochul said in a statement. “The transportation sector is one of New York’s largest sources of pollution, and, too often, low-income New Yorkers and communities of color are forced to bear the brunt of the consequences.”

Among the projects is one by Volvo to deploy an electric garbage truck and an electric refrigerated truck in the Bronx’s Hunts Point neighborhood, as well as build a new charging hub for the area’s two dominant sectors, food and waste.

The neighborhood, across the East River from Riker’s Island, hosts the largest wholesale food hub in the U.S., nine waste transfer facilities and several large recycling yards, as well as 13,000 residents, all in the southern part of the poorest urban congressional district in the U.S.

The prize program, administered by the New York State Energy Research and Development Authority, is intended to help the state achieve its target of an 85% reduction in greenhouse gas emissions by 2050. Each of the 17 winning projects will receive an award of up to $200,000, including $100,000 for further proposal development, up to $50,000 in funding for community partners, and up to $50,000 in in-kind support from technical consultants.

They will also be eligible to compete for larger prizes in Phase Two of the program, under which the Clean Neighborhoods Challenge, for example, includes up to three $10 million awards to innovative projects that address air pollution reduction at scale in underserved communities.

The state award for the Bronx project builds on an earlier city initiative to electrify trucking at Hunts Point, which in August directed a portion of its Volkswagen diesel settlement funds to purchase five new electric Volvo trucks.

“Targeting emissions from the transportation sector, particularly in communities that have been disproportionately impacted by pollution from cars and trucks, will advance efforts to reach New York’s ambitious greenhouse gas reduction goals while protecting public health and ultimately saving lives,” Department of Environmental Conservation Commissioner Basil Seggos said.

New York is trying to reduce transportation-related pollution not only through decarbonization, but also by increasing the availability of public buses and light rail and developing greenways to make bicycling safer and easier. (See NY Using Multitude of Strategies to Clean up Transit.)

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Hearing May Settle Ameren, DOJ Clash over Coal Plant

A federal judge has scheduled a hearing next month to settle a dispute between Ameren and the Department of Justice over the closure of a St. Louis-area coal plant.

In a Monday ruling out of the U.S. District Court for the Eastern District of Missouri, Chief Judge Rodney Sippel ordered a Feb. 4 hearing over when Ameren should shutter its 1.2-GW Rush Island Energy Center. The DOJ has accused Ameren of dragging its feet on pollution mitigation (4:11 CV 77 RWS).

The hearing date gives MISO time to determine whether the plant is needed for system reliability beyond its planned 2024 retirement. The grid operator said it will decide no later than Jan. 28 whether to designate Rush Island as a system support resource that would possibly prevent it from shutting down.

The DOJ has accused Ameren of “engineering” a “drawn-out process” rather than simply closing the plant prior to 2024 or installing required sulfur dioxide controls, as directed by the Eastern District Court in 2019.

That decision appeared to conclude a decade-long battle over Rush Island, which was energized in 1976. The Sierra Club sued Ameren over the redesign and reconstruction of the plant’s Unit 1 and Unit 2 boilers in 2007 and 2010, respectively. The utility carried out the rebuilds without applying for a Clean Air Act permit, which would have required the inclusion of wet flue gas desulfurization pollution controls.

The court has singled out Rush Island as the 10th-highest source of sulfur dioxide pollution in the U.S. It currently operates without any pollution controls. It gave Ameren until 2024 to install up to $1 billion in emissions controls.

The utility said in December it would meet the court’s deadline rather than bring Rush Island into compliance. According to its 2020 integrated resource plan filed with the Missouri Public Service Commission, the plant would run through 2039.

The DOJ argued that Ameren should have been contemplating Rush Island’s closure as early as 2017, when a judge found the company liable for excessive pollution.   

“It has been more than a decade since Ameren should have installed life-saving pollution controls when it reconstructed the Rush Island plant,” the DOJ opined in a Dec. 28 filing. “It has been five years since Ameren was found liable under the Clean Air Act for failing to install those controls. And it has been two years since this Court put Ameren on a court-ordered schedule to finally come into compliance. Now, Ameren has decided it would rather just retire the Rush Island plant after all.”

Ameren could have alerted MISO to Rush Island’s retirement and study process in 2018 when the company itself “raised the specter” of retirement, the DOJ said. The utility’s expert economist said it would make better financial sense to close the plant rather than mount pollution controls.

The DOJ said Ameren has already “reaped significant financial benefits” from its illegal modifications to Rush Island and should speed up the closure rather than keep the plant pumping out dollars and toxic gas. The agency said it’s up to the courts, not Ameren, to establish a shutdown date.

“Any delay in the plant’s shutdown will come at the expense of human health and welfare,” the DOJ said.

But Ameren said the closure process is not that simple. It also insisted that its retirement decision wasn’t “definitive” until last month and pushed back against the DOJ’s insinuation of a “bad motive.”

“Rush Island cannot be hastily disconnected from the grid without careful evaluation of potential impacts on the stability and reliability of the transmission system, and resolution of any problems identified,” Ameren countered in a filing Friday.

The utility has fought for years to keep Rush Island generating electricity. Now, Ameren says the plant’s early retirement will lead to a healthier public — if MISO doesn’t conclude the plant is needed for the grid’s health.

The Sierra Club has asked that Ameren replace Rush Island’s capacity with a blend of renewable energy, energy efficiency and demand response. 

“Given the immense public health harms that Ameren Missouri chose to inflict on the region by operating Rush Island out of compliance with the Clean Air Act, [Ameren] CEO Marty Lyons and utility executives should work with the grid operator to retire the coal plant as soon as possible,” interim Sierra Club Beyond Coal Campaign director Andy Knott said in a statement last month.

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Study: EV Adoption to Cut $5.3M in Vt. Gas Taxes in 2025

The Vermont Agency of Transportation (VTrans) is estimating that the state will lose $560,000 in gas tax revenue this year from the adoption of plug-in hybrid and all-electric vehicles.

Given the state’s plans to ramp up EV adoption, gas tax revenue losses from light-duty cars could reach $5.3 million in 2025 and $80 million in 2050, Joe Segale, VTrans’ policy, planning and research bureau director, told legislators Wednesday.

“We need to make up for this lost revenue, and we need to do it in a way that doesn’t do any harm to the adoption of EVs,” Segale said during testimony before the House Transportation Committee.

Segale presented findings to the committee from a new study on the effect of EV adoption on the gas tax and possible solutions to offset revenue losses. The agency is recommending that Vermont establish an EV mileage-based user fee by 2024 that gathers odometer data during annual vehicle safety inspections.

The tax loss from Vermont’s 5,730 registered plug-in hybrid and all-electric vehicles will only account for 0.67% of the state’s total gas tax revenue this year, which Segale said is “manageable.” About one-third of those vehicles are all-electric.

Estimates from the recently released Vermont Climate Action Plan put total registered EVs at 47,500 by 2025 and 593,000 by 2050.

Vermont uses its gas tax revenue to match federal funding, so Segale said it’s critical to put sustainable alternative mechanisms in place as soon as possible. About 25% of the money raised through the gas tax comes from out-of-state drivers, he said.

The study examined the possibility of establishing a per-kilowatt-hour fee for out-of-state EV drivers at public charging stations. Data from three Vermont utilities’ charging stations showed that out-of-state drivers purchase 15 to 20% of the electricity.

Based on purchase data and an estimated 3.4-cents/kWh equivalent to the gas tax, Segale said the state would only raise $5,000 from out-of-state drivers for the year.

“That’s just not worth it at this point, but we need to figure this out,” he said, adding that the best option now is to watch the national mileage-based user fee pilot established by the federal Infrastructure Investment and Jobs Act.

The options for capturing revenue from EVs include collecting an annual flat fee or charging a fee based on miles driven, according to the study. For plug-in hybrid and all-electric vehicles, the study recommended annual flat fees of $55 and $139, respectively, based on historical average miles driven.

There are winners and losers under a flat-fee system, as nobody drives the average, Segale said. The agency, therefore, is leaning toward a mileage-based fee.

Until onboard telematics can automatically report miles driven, the state will need to establish a system for reading individual odometers.

That could happen through wireless devices installed by drivers, but Segale said the most viable option is to collect the data during annual safety inspections. Implementing that data collection process would cost the state between $1 million and $2 million and 3.5% of the annual revenue collected for ongoing operations, according to the study.

Thirteen states have active mileage-based user fee pilots, while another 13 are studying the option. Utah and Oregon have instituted mileage-based user fee programs for EVs that Segale said allow owners to pay a flat fee or pay by miles driven, with a cap at the flat rate. Both states, he added, may expand the program to all vehicles.

Virginia has also passed a law to allow mileage-based fees, but the state is still designing the system.

“There’s some uncertainty now about how much that will be pushed because there has been a change in leadership in Virginia,” Segale said.

VTrans will perform a system assessment and design study for a mileage-based program this year and seek legislative approval for the program next year. Program implementation would not begin until at least 2024, Segale said.

“The Climate Action Plan recommended waiting to establish registration fees for EVs until they reach 15% market share, and the Department of Environmental Conservation [estimated] that might happen by 2026,” Segale said.

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NEPOOL Markets Committee Briefs: Jan. 12, 2022

Retirement Bid Flexibility Proposal

The NEPOOL Markets Committee on Wednesday approved a proposal from Calpine that would make changes to the resource retirement process to allow retirement bids to be updated later in order to give generators more flexibility.

Currently, retirement bids are due in March, 11 months before the Forward Capacity Auction, a time period that Sigma Consultants’ Bill Fowler said adds “significant, unnecessary risk.” (See NE Stakeholders Propose Retirement, Financial Assurance Changes.)

The rule change would allow bids to be updated in October, by at most 25% below their initial submission. The committee approved the proposal by voice vote.

Calpine is planning to bring a second part of its proposed retirement changes — removing the “repowering rule” that requires a minimum investment to re-enter the market after retirement — to a vote in the committee next month. That change is intended to provide generators a way to mothball units and return them to service if there are significant changes in the region, Fowler said.

Financial Assurance Proposal

The committee also discussed a plan from Competitive Power Ventures to hike financial penalties for resources that fail to reach milestones prior to their delivery year and commercial operation — a timely topic as Killingly Energy Center contests a recent FERC ruling affirming ISO-NE’s decision to terminate its capacity supply obligation (ER22-355). (See FERC Accepts ISO-NE Request to Terminate Killingly CSO.)

Killingly and projects like it have “little financial incentive to withdraw a failed project,” CPV’s Joel Gordon said in a presentation, with penalties currently only assessed after resources have failed to reach their initial commercial operation date. And the only tool that the grid operator currently has to respond to such failures is termination, which Gordon called a “sledgehammer.”

When failed projects participate in capacity auctions, it harms other CSO holders through lower clearing prices and higher performance risk, and it can displace “shovel-ready” projects, Gordon argued.

CPV’s proposal would create new financial assurance requirements for projects that fail to meet certain milestones. It’s similar to a previous proposal by the New England Power Generators Association, which has raised the issue as well in recent weeks in response to Killingly. NEPGA’s Dan Dolan told RTO Insider that the group would support escalating penalties for delays.

The MC was supposed to vote on the plan Wednesday, but CPV deferred to the committee’s next meeting to try to hash out differences with ISO-NE, which said in a recent memo that the plan is not complete and needs further development to define the root cause of the conditions it describes.

GIS Revisions

The committee also voted to approve changes to NEPOOL’s Generation Information System, including:

  • metering for certain residential solar generators in the Connecticut Residential Solar Investment Program;
  • the treatment of energy storage facilities in the GIS; and
  • enhancements to the GIS to address incorrect inputs on fuel splits for dual-fuel units.