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December 27, 2025

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FERC Finds Few Errors in Co-op’s Challenge of Ameren Illinois Rates

Southwestern Electric Cooperative got a few wins last week in its challenges to Ameren Illinois’ annual formula rate updates.

FERC was not swayed by most of the co-op’s arguments against Ameren’s accounting practices behind its formula rate updates for 2020 and 2019, but it did find a few discrepancies in the 2020 rate filing (ER20-1237).

The commission ruled Thursday that Ameren inflated construction-related materials and supplies by putting them on the wrong line in its 2020 books. It ordered Ameren to recalculate its formula rate within 60 days to correct the oversight.

FERC also said Southwestern had credible concern about nearly $20,000 classified as transmission operations and maintenance under an account meant for regulatory costs. It asked Ameren to elaborate within 60 days as to whether that amount was “incurred in connection with a formal case before a regulatory body.”

Finally, the commission said that Ameren placed company-owned life insurance amounts “for officers and other employees for policies in which Ameren Illinois is the beneficiary” in the wrong accounts, overbilling wholesale transmission customers. The commission again ordered a correction within 60 days.

Southwestern has challenged Ameren’s formula rate filings for three years, often unsuccessfully. (See Challenge to Ameren Illinois Rate Rejected Again.)

Ameren Illinois Rates
Ameren employee at a substation upgrade in 2021 | Ameren Illinois

This time, Southwestern said Ameren recorded some 2020 costs relating to customer service software and net metering software in the wrong account. FERC pointed out that Southwestern couldn’t name a more appropriate account to place the expenses.

FERC also said Southwestern was mistaken in its argument “that expenses deemed non-deductible by the IRS are automatically not includable for recovery in rates.”

“The commission has no such policy, nor does Ameren Illinois’ formula rate reflect such a policy,” the agency said.

Contrary to Southwestern’s arguments, FERC said public relations costs could be included in Ameren’s general expense account and thereby included in the formula rate.

FERC also rejected an argument that Ameren is understating its excess accumulated deferred income taxes (ADIT).

Finally, the commission disagreed that Ameren was including distribution-related expenses in transmission-related expense accounts.

FERC also defended its prior ruling on Southwestern’s challenge of Ameren’s 2019 formula rate update (ER19-1276-001).

Southwestern claimed that any ADIT associated with retired plants is excess ADIT and should be returned to customers. But FERC said the co-op misunderstands ADIT and said the loan “is not kept by the utility, but instead is reversed and payable” to the IRS.

FERC continued to deny Southwestern’s request that Ameren offer more detail around its $14.8 million amortization of excess ADIT. The commission agreed with Ameren that the utility’s software system isn’t sophisticated enough to verify the total excess ADIT broken down by specific plants.

Southwestern argued that transmission customers “are improperly penalized because they do not have sufficient justification for the calculations by Ameren Illinois.”

FERC also denied Ameren’s rehearing request that its renewable energy credits (RECs) should be classified as inventory rather than a prepaid expense.

“RECs should not be removed from the books of account because they are still available for use by the owner,” the commission said.

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Software Error Could Mean ERCOT Price Revisions

ERCOT said Wednesday it will seek board approval for a potential price correction needed because of software errors that occurred on Feb. 15 when the grid operator shed 20 GW of load after losing half its generation at the height of a winter storm.

The grid operator said in a market notice that an initial staff analysis determined that the errors affected dispatch instructions for 79 intervals between 9:45 a.m. and 10:35 p.m. that day. Correcting the pricing errors would increase prices by 1 cent/MWh to $1,241.68/MWh, with an average increase of $58.36/MWh.

ERCOT said it also reviewed whether the programming error affected prices for the Feb. 16-17 operating days. However, it found that market prices for those days were already subject to the Public Utility Commission’s order that implemented $9,000/MWh scarcity pricing and were not affected.

The grid operator’s protocols allow it to take the price-correction request to its Board of Directors for approval. The board is scheduled to meet on April 13.

An ERCOT spokesperson said the Technical Advisory Committee will discuss the issue during its meeting on March 24.

Staff found that ERCOT’s market management system software contained programming errors that resulted in the use of an incorrect megawatt amount for the estimated deployed emergency response service (ERS) component of Security Constrained Economic Dispatch’s (SCED) real-time online reliability deployment price adder on Feb. 15. ERCOT was at its highest energy emergency alert that day and deployed all ERS resources. Those resources remained deployed during the EEA until their deployment obligations were exhausted.

ERCOT Price Revisions
ERCOT operators manage the grid during calmer times. | © RTO Insider

ERCOT said that while it was able to determine accurate prices for the affected SCED intervals, it is still developing software fixes to address the noted issues.

The market notice attracted attention from some in the Texas media, given the current controversy over whether to reprice $16 billion of market transactions on Feb. 18-19. (See Texas Senate Passes Bill to Reprice ERCOT Feb. Sales.)

However, price corrections because of software input errors are not uncommon. Last October, the board approved price corrections for 25 operating days as a result of two unrelated events. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

ERCOT stakeholders subsequently approved a nodal protocol revision request (NPRR1024) that isn’t expected to go into effect until April 1. The measure requires ERCOT to seek board review of real-time prices if, within 30 days of the affected operating day, staff determines correcting an error would result in “an absolute value impact to any single counterparty” based on certain metrics.

The grid operator also alerted market participants that it has posted an application for gas facilities that provide fuel to generators so they can request designation as a “critical load-serving electric generation and cogeneration.”

Almost half of ERCOT’s natural gas-fired generation was lost during the winter weather because power was cut to gas infrastructure not listed as critical load.

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Texas RE Helping with FERC, NERC Inquiry

The Texas Reliability Entity will spend much of this year working on issues related to the fallout from the February extreme weather that almost collapsed the ERCOT grid.

Texas Reliability Entity
Texas RE CEO Jim Albright | Texas RE

First-year Texas RE CEO Jim Albright said during the organization’s board meeting Wednesday that three staffers will be working with NERC and FERC on their joint inquiry into the February winter storms that led to outages in ERCOT, MISO and SPP. FERC would like to release key findings in September, he said.

“This is going to be pretty fast and furious work,” Albright said. “Every region is involved, even those not involved in the event. We want to learn from this and hopefully not see a similar situation occur.”

He also told the board that NERC is considering accelerating the schedule for its cold weather standard project (Project 2019-06). Poorly insulated power plants and natural gas infrastructure have been blamed for knocking out significant portions of generation.

The cold-weather proposal could go before the ERO’s Board of Trustees in June. (See NERC Cold Weather Team to Seek Faster Finish.)

Board Fills Committee Slots

The board, meeting for the first time this year, filled out a pair of committees for 2021.

The Hearing Body, a non-standing committee that meets only if a contested case hearing is requested, will comprise independent Directors Crystal Ashby and Jeffrey Corbett and affiliated Director Curt Brockmann.

The three directors will also serve on the Director Compensation Committee along with Albright and Liz Jones, chair of the Member Representatives Committee.

Board Chair Milton Lee welcomed Corbett and Suzanne Spaulding to their first Texas RE board meeting.

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Virginia Passes EV Rebates Without Funding

Lawmakers in Virginia have passed a bill offering consumers a sizable rebate for buying electric vehicles — but without the funds that would put the money in people’s pockets.

The legislation, HB 1979, offers buyers an immediate $2,500 rebate when purchasing a new or used EV. An “enhanced rebate” of $2,000 is also available for purchasers with household incomes of less than 300% of the current poverty rate, $37,470 for an individual or $77,250 for a family of four.

The House of Delegates originally passed HB 1979 with $5 million set aside for rebates and administrative costs. But the Senate stripped away the funding, and the bill remained unfunded coming out of conference, said Del. David Reid (D), the bill’s sponsor.

Gov. Ralph Northam has until March 31 to sign the bill into law as is.

“This bill is part of a comprehensive program to address the supply, demand, infrastructure and funding components of a broader electric mobility transition, with a particular focus on helping low-income Virginians,” Reid said in an interview with NetZero Insider.

But budget curtailing brought on by the COVID-19 pandemic forced lawmakers to make hard decisions when funding bills to reduce carbon emissions in the transportation sector. HB 2118, which would create a grant program to help Virginia schools replace diesel school buses with electric ones also passed the General Assembly, but with the proviso that it could only use federal or other non-state funds. It is currently awaiting action in the Senate. (See Rural Virginia School Districts Skeptical of Electric Buses.)

Republican opposition to the rebate program was fierce as it moved between chambers. Many rural Republicans said HB 1979 favors Northern Virginia, which has the highest numbers of EVs in the state, at the expense of other areas with a less robust charging infrastructure.

Del. R. Lee Ware (R) said he “disagrees with the underlying premise” of the bill “that we ought to incentivize these purchases at the levels of millions of dollars.”

Del. Terry Austin (R) described the bill as “somewhat unfair.” Citing personal experience, Austin said that during his 175-mile drive from his home in Botetourt County to Richmond, he doesn’t have time to stop and charge his vehicle. “I think we’re going down a path that’s not equitable or not fair to people who cannot buy or cannot use electric vehicles,” he said.

Reid said he understands Republicans’ concerns but argued the rebates and savings on fuel and maintenance for EVs should attract middle- and lower-income families, which will, in turn, increase deployment of charging stations, including DC fast chargers that can top up an EV battery in 20 to 30 minutes.

Virginia currently has about 2,000 charging stations, mostly in Richmond and Northern Virginia, and a recent study from the Department of Transportation rated the state as not yet ready for mass EV deployment.

Reid hopes his bill will dispel the myth that EVs are only for high-wage earners. With rebates, a reliable used EV would be within the budget of most middle- or lower-income Virginians, Reid said.

For example, Carvana, an online car dealer, has used Nissan Leafs listing for around $11,000; the $4,500 in rebates offered under HB 1979 would bring the cost down to $6,500, a price range affordable for most people, he said.

Reid also noted that most EVs are charged at home at a much cheaper cost than gasoline or diesel. Additionally, maintenance costs for EVs are lower than for vehicles with an internal combustion engine, saving owners hundreds of dollars a year, he said.

Rebates Critical for Success

As of 2017, 48% of Virginia’s carbon emissions come from transportation, versus 29% for the electric power sector, according to the U.S. Energy Information Administration. The state’s Democrats view EVs as key to reducing transportation emissions; they provide “the most gains now in terms of getting carbon out of the atmosphere,” Reid said.

Even with EV prices coming down, supporters say that rebates are critical tools in the transition from gasoline to electric. The National Conference of State Legislatures now lists 45 states as offering various incentives for EVs and plug-in hybrids. While Virginia does not offer cash incentives, the state does exempt EVs from emissions inspections, and the local utilities offer rebates and special charging rates for customers installing home chargers, according to NCSL.

Federal tax credits of up to $7,500 are also available for most EVs and plug-in hybrids, except for Teslas, which no longer qualify for the credit.

“At the moment, EVs are more expensive vehicles, and rebates help them sell,” said Don Hall, president and CEO of the Virginia Automobile Dealers Association. “As we have seen in other states, such as Georgia, [when] rebates disappear, EVs stop selling.”

Blair St. Ledger-Olson, program manager with clean energy nonprofit Generation 180, told a House panel in early February that higher upfront costs remain a barrier to widespread EV purchases. “Financial incentives can help bridge the price gap,” she said.

As of Dec. 31, 2020, out of 8 million cars on the road in Virginia, only about 24,000 were EVs or plug-in hybrids. according to the Department of Motor Vehicles. A Generation180 survey found that 53% of Virginians said they are likely or highly likely to consider an EV if they were to buy a car within the next two years, and 71% support the state providing incentives.

Another study by the Virginia Department of Mines, Minerals and Energy found that a comprehensive rebate program would cost the state about $43 million. An early draft of HB 1979 set the rebate budget at $20 million, a figure both parties said was prohibitive in the era of COVID-19. After “redefining success,” Reid sought $5 million this year, with approximately $1 million going toward administrative costs, according to the bill’s language.

Should Gov. Northam sign the bill into law without funds, Reid sees other options. Northam could add funding to the bill during a special session or use state taxes and fees on transportation or the universal service fee, Reid said.

Virginia expects to receive about $6.7 billion from the recently passed federal stimulus package, according to figures from the U.S. House Oversight and Reform Committee. “I really do hope we find a source of funding,” Reid said. If not, he intends to reintroduce funding legislation in the next regular session.

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Gas Industry Brings Fight Against Building Electrification to NC

North Carolina has joined what is fast becoming a national debate over building electrification and efforts by the natural gas industry to forestall such changes via laws ensuring “consumer energy choice.”

Introduced March 3, House Bill 220 would prohibit cities and counties across the state from enacting building codes or other regulations that promote building electrification — for heat, hot water and cooking — by banning natural gas hookups in new buildings. The bill received a favorable vote from the House Energy and Public Utilities Committee on March 16 and is now headed to the House Commerce Committee.

Speaking before the energy and committee, Rep. Dean Arp (R), a bill sponsor, acknowledged that no such bans are currently on the books anywhere in the state, prompting Rep. Kelly Alexander (D) to question the need for the bill. It would be, Alexander said, a “solution to a problem that you admitted that North Carolina does not have.”

“Energy policy is a state issue,” Arp countered. Passing pre-emptive legislation protecting consumer choice “absolutely clarifies that before it becomes a problem,” he said.

North Carolina natural gas
| Shutterstock

North Carolina municipalities should not adopt these “California-style building electrification measures,” Arp said, referring to bans on natural gas hookups in new home construction in dozens of cities across that state. The California Energy Commission is currently considering whether to include a natural gas ban in an update of the state’s already rigorous building efficiency code, which would go into effect in 2023.

The natural gas industry has responded with a campaign to promote laws ensuring natural gas hookups remain an option for builders and consumers. A March 2020 presentation by the American Gas Association, first reported by NPR, promoted pre-emptive legislation like HB 220 as a key part of its strategy to “keep natural gas as an integral part of a clean energy future.”

At present, Arizona, Louisiana, Oklahoma and Tennessee have passed such consumer choice laws, and 15 more, including North Carolina, are considering them, according to the Natural Resources Defense Council.

Rep. Pricey Harrison (D) pointed to the AGA connection in her opposition to the bill. “Buildings are responsible for 12% of greenhouse gas emissions,” she said, citing a figure from EPA. “I think this is bad policy, and I would urge my colleagues to vote against it.”

Whether Gov. Roy Cooper (D) would sign the bill, if it passed in both houses of the General Assembly, is uncertain. Cooper has committed the state to reducing its GHG emissions 40% below 2005 levels by 2025, a goal which includes a 40% improvement in state building energy efficiency.

But, Arp said, the independent North Carolina Energy Policy Council, which advises the governor and legislature, supported consumer choice legislation in its biennial report on state energy policy. “Using legislation adopted in Tennessee and Arizona as examples, local governmental entities should not ban customer energy choices,” the report says. “The North Carolina General Assembly should not allow local governmental entities to make such decisions, thereby depriving citizens of the ability to select their energy source.”

“I believe that this is a not a local issue and is not something that is constraining,” Arp concluded. “I thought it was actually pretty straightforward and makes clear the point that state energy policy is state energy policy and can’t be abridged by local input outside … of processes we already have.”

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Bill Plans Resilience Investing for Connecticut Green Bank

Gov. Ned Lamont wants to expand the role of the Connecticut Green Bank to include addressing climate change adaptation through a bill he proposed as one of his 2021 legislative priorities.

The Act Concerning Climate Change Adaptation (House Bill 6441) would build on the success of the green bank, according to Rebecca French, director of the office of climate planning for the Connecticut Department of Energy and Environmental Protection.

“We want to bring that success to implementing environmental infrastructure in the state,” French said during a green bank-hosted webinar last week on environmental finance.

Upon its creation in 2011, the Connecticut Green Bank had a mandate to flip the government-subsidized approach to clean energy investments by working with private sector entities on long-term project financing.

Since its inception, the quasi-public entity and its private investment partnerships have yielded $1.94 billion for clean energy projects across the state. Projects through FY 2020 show that for every $1 of public funds committed by the green bank, an additional $6.60 in private investment is added to Connecticut’s economy.

Under the proposed bill, the green bank would be authorized to make investments in climate adaptation and resilience infrastructure in addition to water, waste and recycling, agriculture, land conservation and environmental markets with carbon offsets. It would be allowed to use its bonding authority and seek additional grant funding to invest in and stimulate more private investment.

Wayne Cobleigh, vice president for client services for GZA GeoEnvironmental, said public and private grant funding “is the way most people have been financing [climate] resilience.”

Local governments, however, do not have the “financial wherewithal” to make a difference in building climate resilience, Joyce Coffee, president of Climate Resilience Consulting, said, adding that there is “a lot of activity” in Connecticut to enable local funding for environmental infrastructure.

“State grants and loans and authorization of municipal stormwater authorities, enabling municipalities to adopt buyers’ conveyance fees, adding flood prevention and climate resilience to erosion control boards and expanding Green Bank functions are all crucial to ensuring that more funding and finance flows toward climate change action including towards climate change resilience,” Coffee said.

The Connecticut Green Bank could emulate the Rhode Island Infrastructure Bank (RIIB) if the bill becomes law, according to Jeff Diehl, RIIB CEO and executive director. RIIB invests in infrastructure programs focused on clean water, roads and bridges, brownfield remediation, energy efficiency and renewable energy projects for municipalities, quasi-state agencies, commercial and residential property owners.

“We look through all of this within a lens of climate resilience,” Diehl said. “We’ve invested over $2 billion into these sectors here in Rhode Island — about two-thirds private sector capital that we’ve mobilized, and the rest is our capital.”

Diehl said RIIB specializes in “creative capital solutions.”

“We understand one size doesn’t fit all, but we look to tailor a solution across all of our programs because we are fairly broad in our authorities and the access to capital that we have to fit the problems,” Diehl said. “We’ve joined forces with other entities, nonprofits and others to craft holistic solutions, which serve both the technical advisory and capital needs of our communities.”

Coffee said that jobs, public health, climate resilience and social equity are the “fundamentals” that private investors look at first when considering an environmental finance project. For example, public and private housing developers might seek support to build better onsite energy security, she said.

“Distributed generation seems to be something that a lot of housing developers are now willing to pay for,” Coffee said.

The bill is currently before the Joint Committee on Environment, which held a public hearing for the bill on March 8.

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NY Green Bank Targets Solar + Storage Market

NY Green Bank is working to fill financing gaps for solar-plus-storage projects as it backs off opportunities for solar-only investments, Managing Director Jason Moore said Thursday.

“There’s a whole lot of liquidity in the market for solar right now,” Moore said during a New York State Energy Research and Development Authority webinar on energy storage investments. In the solar sector, he said, yields are down for large portfolios; there are a lot of investors, and portfolio financings often are oversubscribed.

“We love that the market has fully embraced solar, particularly distributed solar in New York. [It] has been a long process to get lenders comfortable there,” he said.

NY Green Bank, a division of NYSERDA, focuses its investments on market gaps for technologies, and right now, it sees a need to support solar-plus-storage projects, Moore said.

“Solar projects may or may not be a fit for us anymore, however solar-plus-storage is in our wheelhouse right now,” he said. “That’s where we can be a bridging capital in the market to prove out the investment strategy, prove out the regulatory framework and prove out the ultimate success of the market.”

The Green Bank is also focusing on addressing disadvantaged communities and environmental justice issues.

“Projects that support communities that are historically underrepresented in the clean-energy economy are extremely important to NY Green Bank,” Moore said.

Storage Forecast

The outlook for energy storage opportunities in New York is bright, Schuyler Matteson, senior project manager for energy storage at NYSERDA, said during the webinar.

Growth in energy storage is being driven by planned offshore wind development, expansion of onshore renewables, stronger carbon reduction regulations and increased electrification, Matteson said.

New York has planned 9 GW of OSW projects that will be delivering energy to Long Island or New York City, and energy storage can “play a big role” in integrating and firming that energy, Matteson said.

NY Green Bank
With the proliferation of solar projects in New York, like the 32-MW Long Island Solar Farm, NY Green Bank says its services are needed to help the state’s solar-plus-storage market grow. | Brookhaven National Lab

In addition, he said there is a “huge opportunity” for energy storage from the state’s emissions reductions targets. Storage could replace about 3 GW of peaking power plants that NYSERDA expects will shutter in southern New York State, Matteson said.

Storage can also provide utilities flexibility as loads increase from electric vehicles and heat pumps. “Storage is one of the best resources you could ever imagine to deal with those new load patterns,” he said.

Studies by NYSERDA and NYISO show that the state’s goal to decarbonize its electric system through 2040 will require 10 to 15 GW of energy storage under a least-cost scenario.

“That’s something we’re taking very seriously as we evaluate where the market is today, where it’s going and what that means for the duration of storage,” Matteson said.

Program Funding

NYSERDA’s energy storage program has been popular over the last two years, but Matteson said opportunities for participation are still available.

The agency is working to meet the Climate Leadership and Community Protection Act’s 3,000-MW energy storage target for 2030. In 2019, the agency budgeted $400 million in grants for its energy storage program, with portions going to bulk projects (5 MW or larger offering wholesale market services), retail projects (under 5 MW) and projects sited on Long Island. NYSERDA has awarded funding for 1,200 MW of energy storage projects to date.

“About $41 million remains unallocated as we design and assess new programs and try to figure out what’s working, what might need to be changed and where that money can make the most impact as we move forward,” Matteson said.

Funding for the agency’s bulk storage program is fully allocated, but Matteson said that developers still have other funding options. Two solicitations are coming this year: one from NYSERDA for large-scale solar paired with storage and another from New York’s utilities for operation and dispatch rights to bulk storage systems. Dates for those solicitations have not been set.

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Bill Would Track Nevada Renewable Trade Flows

A Nevada lawmaker has introduced a bill that he says would increase transparency around how much renewable energy the state is producing and how much of it is sold to customers in other states.

Sen. Joseph Hardy (R) is the sponsor of Senate Bill 197, which would require a report from the Public Utilities Commission in odd-numbered years.

The report would include:

      • how much electricity is generated in the state from renewable resources, including solar, geothermal, hydroelectric and wind, with the amount broken down by type;
      • the amount of electricity from renewable resources generated in Nevada and sold to retail customers outside the state; and
      • the amount of electricity generated from renewable resources outside Nevada, and how much of that is sold to retail customers in the state.

The Senate on Growth and Infrastructure Committee held a hearing on the bill Wednesday. Hardy said the information was important in light of Question 6, a ballot measure that voters approved in November. The measure requires the state’s electric utilities to acquire half of their electricity from renewable sources by 2030. Because the question proposed an amendment to the state constitution, it needed voter approval in two elections. Voters previously passed it in 2018. (See Nevada Clean Energy Amendment Winning.)

“Do we have enough [renewable energy] for ourselves; do we have enough to share; do we deserve some way to get recompense for what we share as citizens of the state; or is that going to go just to the investors?” Hardy said.

SB197 would also require an assessment of how much land in the state is being used for renewable electricity generation, how much land is available for that purpose and how much would be needed to meet the requirements of Question 6.

Jennifer Taylor, deputy director of intergovernmental relations in the Governor’s Office of Energy, said during the hearing that some of the questions posed by SB197 would be easier to answer than others.

The U.S. Energy Information Administration produces state electricity profiles that include a state’s net generation and net interstate exports, Taylor said. EIA also has information on renewable energy used for electricity generation inside Nevada.

Taylor said that the question of how much renewable energy generated in the state is sold out of state “is complicated by the fluidity of energy markets, including the Energy Imbalance Market and the Western Area Power Administration.”

“Excess supply generated in-state may be sold into those markets, which then utilize those resources to balance the entire system both in- and out-of-state,” she said.

Taylor said the governor’s Office of Energy wasn’t aware of any public sources of information that would answer SB197’s questions about land.

Sen. Keith Pickard (R) said the information the bill is seeking is important.

“This is all information we need,” Pickard said. “It’s impossible for us to make an estimate of whether or not we can even meet these requirements if we don’t have an understanding of what’s available and what we may need.”

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Wash. Bill Proposes Mileage Charge for EVs

As electric cars become more common, fewer drivers will buy gas at the pump, resulting in Washington state collecting less gasoline tax money to spend on roads.

Sen. Rebecca Saldaña (D) has introduced a bill (SB 5444) to tax electric vehicles 2 cents for every mile driven starting July 1, 2026. On Wednesday, the Senate Transportation Committee approved the bill 10-5, sending it to a full Senate vote.

If passed, the bill would bump that tax up to 2.5 cents per mile on July 1, 2029. And the bill would eliminate the current $150 in annual fees EV owners pay to the state, beginning July 1, 2026.

In an interview with NetZero Insider, Saldaña said gasoline tax revenues will inevitably decline as more electric EVs come into use. She said that General Motors plans to produce only EVs by 2035 and that Ford announced last month its European plants will produce only EVs by 2030.

At a Senate Transportation Committee hearing Feb. 18, lobbyist Jim Justin, representing Lyft, said that his business has a goal of net-zero carbon emissions by 2030.

Also at that hearing, Sen. Steve Hobbs (D) said: “Electric vehicles use the same roads as gas vehicles. … Right now, there is a big giant [$150] fee, and no one likes that.” Hobbs co-sponsored Saldaña’s bill and is chairman of the Transportation Committee.

A major difficulty is how the driven miles would be tallied and transmitted to the state government to calculate the tax bills. Saldaña speculated that three methods could be used: transmitters on the vehicles, photos of the odometer sent monthly to the state government and a special software app.

Transportation Committee member Sen. Phil Fortunato (R) opposed the bill: “This can be devastating to farmers with 90% of their driving being on their farms, which would be off [public] roads.”

Two citizens testified against the bill by arguing that heavier EVs that batter highway pavements more should be taxed at a higher rate than tiny electric cars. “Don’t make the odometer a cash register, please,” Ashly Knapp said. “This taxation will hurt EV sales.”

Other testimony on Feb. 18 ranged from neutral to strong support. Supporters focused on the expectation that gasoline tax revenues will drop as more electric cars end up on the road, and a mechanism is needed to make up for the lost revenue. Cities and counties depend on state gasoline taxes to maintain roads. So far, the state government has not nailed down the predicted speed of the growth of EVs.

“We have to do something about the future of our transportation systems,” said Jane Wall, representing the Washington State Association of Counties and County Engineers.

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Wash. PUD Breaks Ground on Hydrogen Plant

Construction of Washington’s first hydrogen production facility began earlier this month just outside of East Wenatchee.

Using power from the 840-MW Wells Dam 50 miles upstream on the Columbia River, the plant is expected to start production in November to eventually provide renewable hydrogen for the state’s first hydrogen fuel-cell vehicles (FCEVs). The state’s first hydrogen recharging station is earmarked for southwestern Washington.

State Sen. Brad Hawkins (R) wants to appropriate money for two more hydrogen fuel-cell stations in his central Washington district in a legislative transportation package that will likely be nailed down in April.

The $20 million plant is expected to produce two tons of hydrogen per day with plans to expand when more output is needed, said Meaghan Vibbert, spokesperson for the Douglas County Public Utility District, which owns the plant and dam.

The idea for the plant came from global warming melting Cascade Range snowpack too early in the spring, sending more water barreling toward the Wells Dam. That means the dam and its sister dams on the river produce more electricity than the Northwest wholesale market can absorb, leaving Douglas PUD to pay other utilities to accept the excess power.

Washington PUD hydrogen
Douglas County PUD will use output from its Wells Dam in Central Washington to electrolyze Columbia River water to produce hydrogen gas. | Douglas County PUD

The PUD’s alternative is to spill the extra water over the top of the dam, which would create nitrogen bubbles that kill fish.

Consequently, Douglas PUD decided to build the hydrogen plant to make use of its surplus energy, Vibbert said. The electricity and water taken from the Columbia River are to be sent to the plant where a hydrogen electrolyzer — to be installed in July — would separate the hydrogen to be stored and oxygen to be released into the air. The hydrogen would be compressed into tanks and then shipped by tanker trucks to future customers.

The project is aided by a Hawkins bill passed in 2019 that allows Washington PUDs to manufacture and distribute hydrogen.

The PUD currently does not have any signed contracts for the plant’s output but is in discussions with some potential customers, Vibbert said.

Meanwhile, another Hawkins bill (SB 5000) unanimously passed the Washington Senate on March 3 to apply a partial sales tax exemption to hydrogen FCEVs, which range in price from $34,000 to $58,000. The bill is now in the House Finance Committee. (See Strong Bipartisan Support for Wash. FCEV Bill.)

The exemption would only apply to new vehicles, and after eight years, it would be re-evaluated.