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November 19, 2024

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Dixie Fire Finding Inopportune for PG&E

The finding by state investigators this week that a Pacific Gas and Electric line sparked last year’s immense Dixie Fire arrived at an awkward time for the beleaguered utility, which is hoping to be released from five years of federal probation later this month.

The California Department of Forestry and Fire Protection said Tuesday its investigation had found that a tree falling onto a PG&E distribution line ignited the nearly 1-million-acre wildfire, the second largest in state history, which destroyed more than 1,300 structures and killed one person.  

“The Dixie Fire investigative report has been forwarded to the Butte County District Attorney’s Office” for possible criminal prosecution, Cal Fire said in a news release.

The finding was not a surprise. PG&E said soon after the fire began in mid-July that its line may have sparked the fire that burned for more than three months across the northern Sierra Nevada. (See PG&E Expects $1B in Costs from Dixie Fire.)

“As we shared in our public statement in Chico in July after the start of the Dixie Fire, a large tree struck one of our normally operating lines,” PG&E said Tuesday. “This tree was one of more than 8 million trees within strike distance to PG&E lines.”

Cal Fire rendered its conclusion one day after federal Judge William Alsup said in a hearing that he would consider extending PG&E’s probation beyond its current end date of Jan. 25 if federal prosecutors ask him to. The U.S. Attorney’s Office is expected to decide this week whether to file such a request, and Alsup scheduled a hearing on the matter for Monday.

Cal Fire’s findings regarding the Dixie Fire could weigh into a decision by the judge, who has been one of PG&E’s harshest critics.

In November, Alsup found that PG&E had likely violated its probation for felonies related to the 2010 San Bruno gas explosion by starting the 2019 Kincade Fire and the 2020 Zogg Fire. Cal Fire determined a tree that fell on a PG&E line started the Zogg Fire. The cause of the Kincade Fire remains under investigation. (See PG&E Likely Violated Probation, Judge Finds.)

County prosecutors have filed charges against PG&E in both cases, while the utility has denied it was criminally liable for either fire.

Also in November, the independent monitor appointed by the court to oversee PG&E during its probation said the utility needs to make substantial improvements in its efforts to prevent wildfires through vegetation management and grid hardening.

“Multiple years of horrific wildfires” started by PG&E equipment showed “its progress regarding wildfire mitigation obviously has been inadequate, and we doubt anyone would seriously dispute that, given the ongoing and profound safety issues in that area of operations,” the law firm Kirkland & Ellis, which the court appointed monitor, wrote in its report to Alsup.  

Fires started by PG&E equipment that failed or was struck by trees included the 2018 Camp Fire, which destroyed the town of Paradise and killed at least 84 people.

“Including the Camp Fire fatalities, over 110 people have died as a result of wildfires where CAL FIRE has determined PG&E equipment was involved since the San Bruno incident,” the monitor wrote.

Its reviews of PG&E safety practices showed the utility had missed thousands of dangerous trees near its lines and failed to detect worn or broken equipment. PG&E still has a vast backlog of problems to fix from a 2019 inspection of 685,000 distribution poles, 50,000 transmission structures and 200 substations in high-fire threat districts, the monitor noted.

“There are over 500,000 tags from 2019 to present that remain unresolved to date,” it said.

The monitor also expressed skepticism about PG&E’s plans to bury 10,000 acres of power lines in fire-prone areas. CEO Patti Poppe announced the effort in July during the same media event in which she discussed the utility’s possible role in starting the Dixie Fire. (See PG&E Proposes Undergrounding 10K Miles of Distribution.)

“The Monitor team applauds PG&E’s commitment to undergrounding to mitigate wildfire risk but notes that some serious questions and issues remain regarding PG&E’s implementation of the undergrounding initiative,” it said.

The utility did not give a timeframe for the work but has plans to underground just 66 miles of lines in 2021 and a total of 327 miles over the next three years, the monitor said.

Even if greatly increases its efforts over a 20-year period, “there is substantial skepticism among PG&E field personnel that PG&E can feasibly underground more than 500 miles per year using current technology and hardening methodologies,” the monitor said.

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FERC Accepts ISO-NE Request to Terminate Killingly CSO

FERC on Monday accepted ISO-NE’s request to yank the capacity supply obligation for the Killingly Energy Center in eastern Connecticut, dealing another near-fatal blow to the contentious 650-MW natural gas plant under development (ER22-355).

The RTO has said that Killingly, which secured a CSO for the 2022/2023 capacity period, has failed to meet developmental milestones and is on track to not be in commercial operation by the required date of June 1, 2024, two years after the start of that period. Developers have up to two years to find other resources to meet their CSO obligations if they themselves cannot.

Developer NTE Energy disagreed with ISO-NE’s claims about delays on the project, saying they were out of its control because of factors including legal challenges and the COVID-19 pandemic. The company claimed in November that financing is “imminent” and challenged what it called “an incorrect assumption” by the RTO that led to a “premature” decision. (See ISO-NE Seeks to Terminate CSO for Conn. Power Plant.)

But in an order issued Monday, FERC sided with ISO-NE, saying it was “persuaded by the evidence” presented that Killingly will not achieve critical milestones by 2024. After consulting with NTE, which it did in several meetings over two months, the RTO has the right to terminate the CSO, FERC said.

As a result of FERC’s ruling, the company will lose its CSO, forfeit financial assurance associated with the terminated megawatts and no longer be eligible for the next Forward Capacity Auction in early February.

NTE, Opponents React

NTE says it’s not giving up on the project.

“We are very disappointed and do not agree with FERC’s decision,” the company’s managing director, Tim Eves, said in a statement. “The Killingly Energy Center is important for grid reliability, and we will continue to work to be the bridge for the region’s carbon-free future.”

But the plant’s future is cloudy. The company itself has said in filings that FERC’s approval of ISO-NE decision would cause it “irreparable” damage and lose it hundreds of millions of dollars of revenue.

Environmental groups in Connecticut, which have opposed Killingly and sued over the project in a case that was ultimately decided by the state Supreme Court, celebrated this week at the latest dimming of the project’s future prospects.

“It was the outcome we hoped for, and we’re happy,” said Samantha Dynowski, director of the Connecticut chapter of the Sierra Club.

She said the plant ever being built appears “very unlikely” without a CSO.

“In the face of [ISO-NE] not wanting them and Gov. [Ned] Lamont saying he doesn’t want the plant … they’d really just be forcing themselves on a market that doesn’t want them here,” Dynowski said.

The order has broader implications for ISO-NE, and the events leading to it should spur action by the RTO, said Dan Dolan, president of the New England Power Generators Association.

“Moving forward, more needs to be done to ensure that new facilities only offer into the market when they are ready to come in on time,” Dolan said in an email to RTO Insider. “Market reforms should include proposals like escalating penalties for delays. This will help make continued improvements to provide reliability value for New England consumers and competitive revenue opportunities to those facilities providing the reliability services.”

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PG&E Building ‘Remote Grids’ in Fire-prone Areas

Pacific Gas and Electric plans to build more standalone “remote grids” in California this year, allowing the utility to remove distribution lines serving small groups of isolated customers as a way to reduce wildfire danger.

After finishing its first remote grid project in Briceburg, Calif., last year, PG&E said it was setting a target of having up to 20 remote grids up and running by the end of this year.

And community choice aggregators are partnering with PG&E on some of the projects. Sonoma Clean Power, which serves Sonoma and Mendocino counties, is hoping to have its first remote grid project completed within a year.

Sonoma Clean Power CEO Geof Syphers said the remote grids could increase the use of clean energy, decrease wildfire risk and reduce costs to electric ratepayers.

“It could be a triple win,” Syphers told NetZero Insider.

Solar, Storage and Backup

PG&E decided to build the Briceburg remote grid after the 2019 Briceburg Fire destroyed a distribution line serving five customers. The power line ran across rugged terrain in a high fire-threat area near Yosemite National Park.

The Briceburg remote grid consists of solar panels, battery storage and backup propane generators. It serves two homes, a visitor center, and telecommunications and transportation facilities.

The remote grid uses ground-mounted and container-mounted solar panels provided by BoxPower, a Grass Valley-based company. The containerized microgrid system may streamline development of future remote grids at similar sites, according to a release.

The remote grid includes a fire suppression system, and PG&E and BoxPower can monitor and control the grid via satellite.

The system is expected to provide up to 89% renewable energy per year.

“This hybrid renewable option reliably powers five customers without the need to rebuild the overhead line, and the remote grid is intended to meet customer needs at lower lifetime costs and a significantly lower risk of fire,” PG&E spokesperson Paul Doherty said in an email.

PG&E said there are hundreds of potential sites for remote grids in its service territory. The company is evaluating high fire-threat areas in El Dorado, Mariposa, Sonoma, Tulare and Tehama counties.

Lessons learned from Briceburg and other early projects will guide PG&E’s remote-grid expansion, the company said.

PG&E plans to provide an update on the remote grid program next month when the company files its 2022 Wildfire Mitigation Plan.

CCA Involvement

Community choice aggregators are helping PG&E with remote grid projects by reaching out to customers who might be good candidates for joining a remote grid.

Syphers at Sonoma Clean Power said the outreach includes a discussion on how to maximize the use of renewable energy. Thus far, one customer has agreed to a 100% renewable system, he said.

The trade-off for 100% renewable is the potential for reduced reliability, Syphers said. But he noted that customers might already be experiencing periods of public safety power shut offs while overhead distribution lines stay in place.

Syphers said a typical remote grid site would include one to three customers at the end of a power line running through a high fire-threat area.

Electric use for a remote grid should be on a residential scale, he said, although some non-residential uses such as agricultural water pumping could be accommodated.

It’s ultimately up to PG&E to decide whether a remote grid makes sense for a particular site, Syphers said. One factor is how the cost of a remote grid compares to the cost of hardening an overhead distribution line in a high fire-threat area, which could involve replacing bare overhead conductor with covered conductor, installing sturdier poles or moving the line underground.

“This is an opportunity to just be smarter about how we’re using ratepayer dollars,” Syphers said.

Sonoma Clean Power’s remote-grid planning also includes a “top-to-bottom” energy-efficiency retrofit.

Syphers said he could envision larger remote grids that include seven to 10 customers, but he noted that all customers must be willing participants.

“It could grow as we learn more,” he said.

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MISO Makes 2nd Plea for Time on ROE Refunds

MISO has made another attempt to coax more time from FERC to calculate refunds to transmission customers over the commission’s ever-changing return on equity percentage.

The RTO has now asked for an extension until May 31 to complete the refunds (EL14-12-004).

The grid operator previously requested a June 30 deadline to determine refund amounts; FERC granted a delay until Feb. 28 from its original Sept. 23, 2021, deadline to calculate the reimbursements. (See MISO, TOs: More Time Needed for ROE Refunds.)

MISO said it has good cause to support a spring deadline, saying the “overall resettlement task remains unchanged” since it first requested an extension. The RTO said it and its transmission owners have completed resettlements from 2013 to 2019, but said the remaining refunds require a more complex calculation that relies on forward-looking transmission rates and true-up mechanisms.

The grid operator said it expects to crunch numbers through April, with transactions to take place in May. MISO Senior Manager of Transmission Settlements Christina Drake said it remains “infeasible to implement all of the directed refunds within the timeframe set forth by the commission’s orders.” It promised the refunds will include interest at FERC-approved rates.

MISO said as an example, 2020’s refunds involve 103 transmission owners and “all charges made under related tariff schedules and attachments that use those parties’ ROE, including the systemwide average rate for through-and-out service.”

The RTO’s extensive refund calculations stem from a return on equity that FERC changed several times over a handful of years as it tried to nail down an appropriate baseline for investors backing transmission projects.

The commission in 2020 enacted a 10.02% ROE for transmission rates effective Sept. 28, 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were at different times intended to replace the 12.38% ROE established in 2002, which FERC deemed excessive almost a decade ago. In all, MISO TOs must pay refunds for the period of November 2013 to February 2015 and September 28, 2016, to December 23, 2020. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)

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CAISO Working Groups Start EDAM Design

Three stakeholder working groups charged with designing key elements of CAISO’s proposed day-ahead market for the West began work this week and plan to meet twice weekly until mid-March to finish the job.

The groups’ intensive schedules reflect the importance of the extended day-ahead market (EDAM) in CAISO’s bid to broaden its Western Energy Imbalance Market (WEIM) from a real-time to a day-ahead market in the next two years.

The working groups must address some of the thorniest issues that could threaten EDAM’s viability, including resource sufficiency evaluations, transmission commitments and greenhouse gas (GHG) compliance, all of which could provoke dissent among would-be participants.  

Previous stakeholder complaints about transmission rights and other matters, along with the energy emergencies that CAISO faced in summer 2020, put the EDAM initiative on hold until last fall, when the ISO revived it. (See CAISO Reconvenes EDAM Stakeholder Meetings and EDAM Design Could Undermine Tx Rights, Critics Say.)

Composed of WEIM member representatives, the working groups are starting with a broad set of design principles developed last year by a select group of stakeholders. Group members can accept or rework the design principles; they also must try to agree on more detailed design elements.

“A lot of the opportunity that exists here is that there aren’t any hard-and-fast rules other than the principles, which are subject to reevaluation as well. Nobody is stuck in any deep details,” Kevin Smith, a lawyer representing the Balancing Authority of Northern California, said in Monday’s first meeting of working group 1 on supply commitment and resource sufficiency evaluation (RSE).

RSE became a controversial issue in the WEIM when CAISO updated it last year to include measures dealing with the uncertainty of weather-dependent renewable resources, transmission outages and other variables. Some contended the “uncertainty” components of the RSE skewed test results and led to failures.

Participants also raised concerns around demand response resources, capacity counting rules and consideration of load conformance. (See CAISO Reevaluating WEIM Resource Sufficiency Test.)

The resource sufficiency test is meant to ensure that each WEIM participant has enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

The RSE for WEIM’s well-established real-time market is being reexamined in a stakeholder initiative, while the working group must wrestle with resource sufficiency in the proposed day-ahead market.

“Consistent with the ‘prevention-of-leaning’ concept supported by the existing EIM resource sufficiency test, the EDAM would have robust resource sufficiency requirements,” the common design principles say. “This test would be developed and applicable to all participating entities in order to qualify for EDAM market participation each day.”

The initial list of questions for working group 1 include, “What resources qualify for showing within the EDAM RSE?” and “What is the expected granularity and detail of the EDAM RSE?”

The second working group, which held its initial meeting Tuesday, is addressing transmission commitment and congestion rent allocation. Its common design elements include maximizing the amount of firm or high-priority transmission available to EDAM while respecting open-access transmission principles.

The group is being asked to “define how transmission across EDAM entity network is made available, including consideration of any restrictions or limitations,” and to consider the timing and duration that transmission is made available, among other topics.

Working group 3, which also met for the first time Tuesday, is weighing questions around greenhouse gas accounting, including whether state boundaries will form GHG “compliance areas” and how GHG compliance costs will be recovered.

Group 3 plans to meet every Tuesday and Thursday afternoon through mid-March. Working group 1 will meet on Monday and Wednesday afternoons during the same period; working group 2 is scheduled to meet on Tuesday and Thursday mornings until March 16.

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FERC Approves $40K Penalty for Santee Cooper

FERC on Dec. 30 approved a settlement between South Carolina Public Service Authority (Santee Cooper) and SERC Reliability under which the state-owned utility will have to pay $40,000 for violations of NERC reliability standards.

NERC submitted the settlement to the commission at the end of November in a spreadsheet Notice of Penalty, along with settlements between SERC and Louisville Gas & Electric, and between ReliabilityFirst and CenterPoint Energy (NP22-6). The latter settlements did not carry any monetary penalties.

FERC indicated last week that it would not review the agreements — in addition to separate NOPs concerning settlements between RF and American Electric Power, and between WECC and NaturEner Wind Watch — leaving the penalties intact. (See AEP to Pay $570K in NERC Penalties.)

Santee Cooper’s settlement concerns FAC-009-1 (Establish and communicate facility ratings), specifically requirement R1, which states that transmission owners and generator owners must “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associated facility ratings methodology.” The utility self-reported in 2018 that it had violated the standard; SERC later determined that the infringement also involved requirement R6 of FAC-008-3 (Facility ratings), which superseded the earlier standard in 2012.

During a review of facility ratings prior to a SERC audit, Santee Cooper “discovered four instances of incorrect element ratings at one substation”; as a result the utility’s facility ratings did not match its methodology. Correcting the element ratings led to three facility rating increases and one decrease. As part of the audit, SERC later conducted a walk-down of the substation and found seven additional incorrect element ratings, though these did not affect the facility rating.

An extent-of-condition review and walk-down of all of Santee Cooper’s generation and transmission facilities after the audit revealed incorrect facility ratings at 18 of 319 transmission facilities (including the one that the utility discovered before the audit). Misratings were also found at nine of Santee Cooper’s generating units.

Santee Cooper found that the oldest incorrect facility rating dated to June 2007, when FAC-009-1 took effect. The utility finished revising all incorrect element and facility ratings by March 18, 2021.

SERC determined that the root causes of the violations were “deficient procedure at [Santee Cooper’s] generating facilities and inadequate training at its transmission facilities.” In the case of the generating facilities, the procedure did not identify “specific instances where [Santee Cooper] should use a calculation instead of manufacturer nameplate values or when multiple elements could be considered in a single rating.” Business units associated with the transmission facilities were not aware of the utility’s process for communicating changes to the transmission system.

In addition to correcting the element and facility ratings, Santee Cooper conducted several mitigating actions. First, it gave the transmission project management and area engineering business units more visibility into the facility rating process by adding their representatives to the model validation and dynamics review team; now the team “includes representation from all areas that have a key role in the facility ratings process.” The utility also established a team focused on minimizing data discrepancies between database and field assets, comprising representatives from multiple departments.

In addition, Santee Cooper undertook a standardization of database and field assets and equipment inputs, along with an annual internal control targeted at validating at least 20% of its transmission facilities every calendar year. Moreover, the entity revised its generation facility ratings methodology to “provide clarity” on such factors as the use of nameplate ratings rather than calculations and how to evaluate generator step-up transformers.

SERC also applied mitigating credit for Santee Cooper’s internal compliance program, which it said “includes strong oversight and an ongoing internal control to walk down 20% of its facilities every year.” The regional entity found no previous instances of noncompliance to warrant aggravating the penalty.

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Solar Developer Objects to New York DEC Analysis

A NextEra Energy (NYSE:NEE) subsidiary developing a 180-MW solar project in upstate New York since 2017 is urging the state’s Siting Board to reject as “faulty” the Department of Environmental Conservation’s project description and analysis, especially on wetlands classification and mitigation (Case No. 17-F-0598).

In a December rebuttal to DEC staff testimony the previous month, North Side Energy Center said it was illogical for the department to classify the project as an industrial-use facility and thus render it incompatible with state wetlands regulations.

North Side said the term “industrial use facility” dates from 1985 and is associated with impacts from constructing buildings, accessory roads and parking areas that can impede rainwater absorption and roil streamflow, in turn creating more erosion and sedimentation.

“Here, solar technology for the project was selected to avoid concrete foundations. There will be no buildings. Panels will be mounted on racking systems supported by driven posts, resulting in minimal ground disturbance,” said North Side, a wholly owned, indirect subsidiary of NextEra Energy Resources, itself a subsidiary of NextEra.

Access roads for the 2,200-acre project, sited a few miles from the Canadian border, will not be paved entirely, but virtually all of the roads will be gravel, allowing rain to soak into the ground. Therefore, North Side argued, the project will not create the kind of impact imagined when industrial-use facilities were included in state regulations.

The Siting Board will rule in July on the project’s application for a certificate of public convenience and necessity. Meanwhile, three administrative law judges have established a procedural timeline, with a status conference this Friday followed by a Jan. 14 deadline for submission of exhibit list; witness list and testifying order; contested issues; and areas for cross examination.

An evidentiary hearing will be held Jan. 24, with post-hearing briefs due Feb. 28 and reply briefs on March 15.

Evaluation Crosstalk

DEC biologist Christopher Balk testified in November that department staff calculated that the project, as currently proposed, will result in direct impacts to 621 acres of protected wetlands and 136 acres of adjacent areas.

Asked if DEC staff were commenting on the applicant’s system energy efficiency plan (SEEP) guide as it related to wetlands and waterbodies, Balk said, “No, department staff’s proposed certificate conditions differ from the applicant’s in such a manner that review of the SEEP guide as it relates to wetlands and waterbodies would not result in any meaningful comments from staff.”

North Side argues that DEC staff assume that the entire area under the panels — which it says will be reseeded and restored and which the record shows will improve functions to previously disturbed wetlands — should be treated as an avoidable adverse impact and thus requires mitigation.

The “regulation [that the department] asks the Siting Board to exert over non-mapped wetlands is unprecedented, limitless, prejudicial and groundless. By adopting this ad hoc, unlawful approach to wetland regulation, developers will not be able to rely upon existing law and regulations for fear that the DEC staff will go beyond it,” North Side said.

DEC staff recommend approximately 1,100 acres of wetlands be created or restored to serve as mitigation, which North Side said would make the project unfinanceable. The market rate from a least one organization that creates wetland mitigation (Ducks Unlimited) is approximately $100,000/acre, the developer said.

By that estimate, DEC staff’s recommendation would mean a wetland mitigation cost of approximately $110 million for a solar project for which the capital cost is approximately $300 million.

Alternatively, DEC staff argue that the Siting Board amend the official wetland maps and treat the non-mapped wetlands as Class I, which would prohibit any facilities from being located there.

“As the applicant has no alternative site, that DEC strategy would also kill the project,” North Side said.

It also noted that a preliminary jurisdictional determination issued in October by the U.S. Army Corps of Engineers (USACE) said it will exert jurisdiction over those non-mapped wetlands, so the company would not seek a permit from it.

A crucial difference between the corps’ requirements and the DEC staff position in this case is that USACE requires compensatory mitigation only for permanent jurisdictional wetland losses resulting from the placement of fill for activities such as grading, the construction of access roads and placement of concrete pads, North Side said.

“The USACE does not recognize the installation of driven piles (such as the solar array posts) into wetlands as fill and therefore the placement of the solar racking system and the panels themselves would not require mitigation, as the action would be non-jurisdictional to USACE,” North Side said.

Compatibility Tests

A project in New York must pass three compatibility tests in order to be permitted:

  • would be compatible with preservation, protection and conservation of the wetland and its benefits;
  • would result in no more than insubstantial degradation to, or loss of, any part of the wetland; and
  • would be compatible with the public health and welfare.

North Side argues that the project meets all three tests. It says most of the proposed impacts are in the form of conversion, which typically constitutes conversion of land cover through clearing of non-aquatic vegetation associated with panel installation to eliminate the potential of shading effects caused by vegetation. In addition, the discontinuance of agricultural activity will improve wetlands in areas used for row and field crops, the company said.

The project meets the second test because placing solar posts, access roads and inverter and substation pads do not amount substantial degradation of the land, the developer said. It also said it is ready to comply with USACE mitigation requirements, which it estimates would amount to approximately 15 acres of wetland mitigation.

Finally, North Side said the project meets the third test because no significant adverse impact on the environment, public health and safety were determined through the many studies it performed to prepare the application.

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Flood of Climate Bills to Greet Washington Lawmakers

The Donald Trump “election fraud” conflicts across the nation will likely affect how Washington state will deal with climate change in its upcoming legislative session.

In November, the Biden administration convinced Washington’s moderate Republican Secretary of State Kim Wyman to join the federal Cybersecurity and Infrastructure Security Agency to improve election security.

After Wyman’s move, Democratic Gov. Jay Inslee appointed as her replacement state Sen. Steve Hobbs, a moderate Democrat, who had been chairman of the Senate Transportation Committee.

In the legislature’s last two sessions, the senate’s Democratic caucus split between its moderate and progressive wings on how much it would support Inslee’s agenda to combat climate change. Hobbs’s Transportation Committee served as a brake on some of Inslee’s proposals, as many global warming bills have a transportation component.

With Hobbs out of the picture, the Senate Democratic caucus picked Sen. Marko Liias (D) to chair the Transportation Committee. One of the chief stewards of Inslee’s climate change bills, House Environment and Energy Committee Chair Joe Fitzgibbon (D), told NetZero Insider that he thinks Hobbs’ absence removes an obstacle to keeping climate change bills intact.

More than a dozen climate change bills will try to make it through Washington’s legislature in a short 60-day session that begins Jan. 10. Consequently, any obstacles within the legislature’s two Democratic caucuses, which hold majorities in each chamber, could stop any global warming-oriented bill. Liias’ appointment as transportation chairman will likely smooth the path for any transportation-related climate bills.

‘Rapid Tornado’

The bulk of the legislation will be in Inslee’s new follow-up package of climate bills totaling $626 million in appropriations, which the governor contends will require no new revenue sources. This package follows the passage last spring of most of his 2021 proposals. Inslee’s biggest 2021 climate change victories were passages of a cap-and-trade bill on industrial emissions and a low-carbon fuel standard for vehicles. (See Wash. Becomes 2nd State to Adopt Cap-and-trade and LCFS Bill Passes Washington Legislature.)

“Climate change is a rapid tornado of damage going through Washington. … We’ve made progress, but we have not made enough progress,” Inslee said at a press conference.

The biggest planks of Inslee’s requested legislative package for the 2022 session include having all new construction in the state to be “net-zero ready” by 2034. Another plank is a $50 million allocation to tackle how Washington companies can compete with foreign competitors that don’t have to implement carbon emission measures.

One Inslee proposal that will inevitably end up in the Senate Transportation Committee will be tax rebates for Washingtonians buying electric vehicles. Also going through that committee will likely be requests for money to build two, 144-car hybrid-electric ferries and to convert another conventional ferry to a hybrid-electric model.

Independently of Inslee’s package, Democrats are eying a bill to install a fee on financial institutions providing money to fossil fuel projects. After being stalled last year, another bill will be revived to add climate change to local government land-use policies. Another bill has been introduced to tackle methane emissions from landfills.

A potentially bipartisan bill is in the works to speed up the state’s response to any droughts that are declared in 2022.

Republican Efforts

However, the biggest Republican climate change bill will likely go nowhere. Rep. Mary Dye (R) plans to introduce legislation to reroute funds from the state’s new cap-and-trade program.

The cap-and-trade law set up a task force to create a system to annually set total industrial carbon emissions in the state, a cap that slowly decreases through the years. Four times a year, large emitters would submit bids to the state in an auction for segments of that year’s overall limit and be allowed to emit that amount in greenhouse gases. Companies will be allowed to trade, buy and sell those allowances. The law anticipates the auctions would raise several hundred million dollars every budget biennium that the state can allocate to low-income neighborhoods and communities of color, plus other projects yet to be determined.

Dye’s proposed bill would reroute some of that money to improve forests in state parks, tackle wastewater polluting Puget Sound and mitigate flood and drought damages. “There’s a huge backlog in needed development in our state parks,” Dye told NetZero Insider.

However, Fitzgibbon said her bill won’t gain any traction in his committee.

Meanwhile, Sen. Judy Warnick (R), chair of the Washington Joint Legislative Committee on Water Supply During Drought, plans to introduce a bipartisan bill to deal with future droughts. Inslee declared a drought emergency for most of Washington last July after extremely dry conditions caught the state government and legislature off guard.

“We learned a hard lesson this year. … We need more flexibility in time of drought; we need more certainty,” Warnick said.

Her expected bill is intended to provide state grants to drought-stricken communities, better define what constitutes emergency funding and speed up the state’s responses to declared droughts. “I hope we get pragmatic and get something in,” Warnick said.

Inslee Wish List

Inslee’s package will dominate a large part of the 2022 session. In addition to the net-zero provision, Inslee’s construction bill will likely include language allowing the state to regulate the energy performance of buildings down to 20,000 square feet, compared with 50,000 square feet currently.

Another bill would require that gas utilities submit decarbonization plans to the Washington Utilities and Transportation Commission every four years. These plans would include emission reduction strategies and how to support renewable hydrogen and electrification efforts.

Fitzgibbon and the proposed bill’s sponsor, Rep Alex Ramel (D), expect significant pushback on the bill by gas utilities because it will cut back on their customer base in the long run. Ramel also said the proposed legislation would likely stress the use of “renewable natural gas,” which would come from methane produced by landfills, sewage plants and dairy ranch digesters. Renewable means that these sources would absorb carbon dioxide from the atmosphere in roughly the same amounts of carbon that they exude into the air. “We still have some kinks to work out,” Ramel said.

Other Inslee-backed bills include:

      • A $50 million allocation to tackle how Washington companies can compete with foreign competitors that don’t have to implement carbon emissions measures. These industries include steel and aluminum production, pulp and paper mills and food processors. Meanwhile, Fitzgibbon has introduced a bill to provide no-cost allocations of emissions allowances to companies in that position, which will gradually phase out through 2050.
      • A request to have tribal consultants advise on climate change matters, including early notification of ventures that would impact their lands and treaty rights. Inslee faced political blowback after vetoing that provision in the cap-and-trade bill passed last spring.
      • The creation of tax rebates for residents buying EVs. To qualify for the rebate, a person would have to earn less than $250,000 as a single tax filer, or a couple less than $500,000 as a joint household filer. The proposed rebates are $7,500 for a new vehicle and $5,000 for a used one. An additional $5,000 rebate would go to an EV purchaser earning less than $61,000 annually, which is 60% of the state’s median income.

In a gesture to some politically conservative areas of the state, Inslee wants to provide appropriations to help revive a dormant smelter in Whatcom County to return lost jobs while giving off fewer carbon emissions and to create a solar panel manufacturing plant in Grant County.

The proposed restart of the smelter would require equipment that would trim carbon emissions below August 2020 levels, when Alcoa shut down the plant, leading to the loss of 700 jobs. Two unidentified companies have expressed interest in buying and reviving the plant.

A political wrinkle is that most of Whatcom County is in a district represented by two Democratic House members and Republican Sen. Doug Ericksen, a climate change skeptic who had been the legislature’s leading opponent of most of Inslee’s environmental measures. Ericksen’s position usually had been that environmental measures kill jobs. Also, an opponent of Inslee’s vigorous COVID-19 vaccine and masking measures, Ericksen last month died after contracting COVID-19 in El Salvador, although the virus has not yet been confirmed as the cause of death.

Independent Bills

Besides Inslee’s package, other independent climate change bills are in the pipeline.

Rep. Davina Duerr (D) has introduced a bill that would add municipal landfills and limited-purpose landfills to the other such facilities covered by a state law requiring monitoring and methane collection systems for landfills exceeding levels of heat and methane emissions.

Sen. Reuven Carlyle (D), chairman of the Senate Environment, Energy and Technology Committee, plans to introduce a bill to create a “climate resiliency fee” on global financial institutions in the state that fund fossil fuel projects. (See Wash. Senator Seeks Fee on Fossil Fuel Financers.)

Carlyle wants to add a surcharge to a financial institution’s business and occupation tax, the state’s tax on a firm’s gross income. He expects the surcharge to raise $80 million to $100 million annually for climate resilience measures, such as creating public cooling centers, relocating infrastructure at risk from floods and sea level rise and helping farmers and communities obtain critical water supplies during more frequent and severe droughts. The bill would reduce the surcharge as an affected institution decreases its investment in fossil fuels, eventually reaching zero when a bank’s investments in fossil fuel projects reach 5% or less of its 2022 level.

Duerr is also expected to revive a dormant bill to incorporate climate change in the state’s land-use planning law — the Growth Management Act.

House Bill 1099, sponsored by Duerr, stalled in Senate Transportation Committee — then chaired by Hobbs — last April after passing the Democratic-controlled House by a partisan 56-41 vote. (See Wash. Land Use Measure Nears Passage.)

The Growth Management Act, which is almost 30 years old, regulates long-range land use planning for Washington’s city and county governments. It requires counties and cities to review and, if needed, revise their comprehensive plans and development regulations every eight years. Duerr’s bill would have added climate change as a factor in the Growth Management Act and require comprehensive strategies, development regulations and regional plans to support state greenhouse gas emission targets and improve resilience to climate impacts and natural hazards.

Her bill would have required climate change to be considered in land-use and shoreline planning for the largest 10 of Washington’s 39 counties and in cities of 6,000 people or larger. Washington’s 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland, Ore. A legislative memo said 246 county and city governments would be affected, including 110 jurisdictions outside the 10 most populous counties.

The bill called for the state Department of Commerce to set guidelines by 2025 on how those areas can reduce greenhouse gas emissions and vehicle miles traveled. Because 40 to 45% of Washington’s greenhouse gases come from motor vehicles, traffic issues would become a major priority in those guidelines.

Finally, a bill introduced by Sen. Jeff Wilson (R) would require the Washington Department of Ecology to set up a program by 2024 covering how manufacturers of wind turbine blades would recover worn blades and recycle the materials.

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NY Adds Clean Trucks Rule to Low-emissions Vehicle Program

New York has joined the short list of states to finalize regulations designed to spur the market for zero-emission medium- and heavy-duty vehicles (Z-MHDV).

The Department of Environmental Conservation on Wednesday adopted amendments that incorporate California’s Advanced Clean Trucks (ACT) rule into New York’s existing low-emission vehicle program. New Jersey, Oregon and Washington also adopted the regulations last year.

Under the rule, which California added to its state codes last spring, Z-MHDV sales requirements will increase gradually starting with model year 2025.

In 2035 and thereafter, New York’s annual Z-MHDV sales must be:

  • 55% for vehicles weighing 8,501 lb. to 14,000 lb., such as full-size pickup trucks, small utility trucks, cargo vans, and passenger vans;
  • 75% for vehicles weighing more than 14,000 lb.; and
  • 40% of MHDVs designed to pull trailers.

Manufacturers will accrue credits for in-state Z-MHDV sales that can be banked and traded in New York. In addition, the rule requires manufacturers to report sales information and credit trades annually to demonstrate compliance.

New York has about 685,000 MHDVs that emit 15.4 million metric tons of greenhouse gases annually, representing 24% of the state’s on-road vehicle emissions, according to an analysis of the state’s ACT program that was backed by the Natural Resources Defense Council.

Adopting ACT, according to the report, will provide an estimated net societal benefit of $19 billion through 2050. Those benefits include annual electric utility bill savings of $325 million from increased electricity sales for Z-MHDV charging.

ACT also will cut MHDV fleet fossil fuel use in half by 2050, and fleet charging will increase electricity use from an estimated baseline for the year by 7% to 10.1 million MWh, the report said. In terms of GHGs, the report said ACT will reduce emissions by 64 million metric tons over 30 years.

Adoption of the regulations demonstrates the state’s commitment to protecting communities from pollution, said Mary Barber, director of regulatory and legislative affairs at Environmental Defense Fund.

“Now, policymakers, utilities and the private sector must come together to build the charging infrastructure necessary to fuel these zero-emission trucks, which will ensure they are on New York’s roads as soon as possible,” Barber said.

Statewide, there are only 128 fast-charging ports available to any vehicle, the report said, adding that fleet owners, government and private entities need to invest $131 million per year in charging infrastructure from 2025 to 2050 to support the new regulations.

New York Gov. Kathy Hochul in September signed a bill requiring all new passenger cars and trucks sold in the state to be zero-emission by 2035. The law includes a mandate for all MHDVs to be zero-emission by 2045, where feasible. In addition, it directs lead state agencies to develop a zero-emission vehicle market strategy by January 2023.

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Winds of Climate Change Policy Sweep Through West in 2021

Western lawmakers and regulators produced a whirlwind of climate initiatives last year, advancing numerous bills, regulations and proposals to reach net-zero emissions by 2050. 

Washington Adopts Cap-and-trade, Low-Carbon Standard

The passage of Senate Bill 5126 in April made Washington the second state in the nation behind California to adopt a cap-and-trade program, fulfilling a longtime objective of Democratic Gov. Jay Inslee. A task force appointed by Inslee is leading brainstorming efforts for the program, to be implemented by the state’s Department of Ecology. The program could potentially link up with the Western Climate Initiative trading pact, which currently includes California and Quebec. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)

Washington lawmakers last spring also passed a bill (HB 1091) implementing a low-carbon fuel standard (LCFS). The new law requires that carbon emissions from gasoline and diesel fuel sold in the state be cut 10% below 2017 levels by 2028 and 20% by 2035. The rules exclude emissions from fuel exported out of state or used by water vessels and railroad locomotives. (See LCFS Bill Passes Washington Legislature.)

The legislature also approved a bill (HB 1287) that requires the state’s Department of Transportation to establish a system to predict the growth of electric vehicles in the state and the expected number and locations of charging stations. The legislation also calls for utilities to use state predictions to map out where charging stations should be installed in their own areas. 

Inslee vetoed a portion of the bill that called for the state to implement a “road usage” charge for EVs — a fee based on vehicle miles traveled — saying he didn’t want Washington’s conversion to electric vehicles to be legally linked to such a charge. (See Inslee Vetoes Part of Wash. EV Mapping Bill.)

A new Republican-sponsored law (SB 5000) will cut Washington’s 6.8% vehicle sales tax in half for the first 650 hydrogen fuel cell vehicles (FCEVs) sold in the state. (See Green Transportation Bills Headed for Inslee’s Desk.) Douglas County Public Utility District last year broke ground on the state’s first green hydrogen production facility, which is intended to provide fuel for the FCEV fueling stations.

Ore. Tackles Cap-and-invest, Clean Power, Landfill Methane

In Oregon, the state’s Environmental Quality Commission last month approved a cap-and-invest program that sets declining caps on greenhouse gas emissions from the state’s fuel suppliers, targeting a 90% cut by 2050. The cap portion of the new Climate Protection Program (CPP) will cover natural gas local distribution companies and suppliers of gasoline, diesel and propane. Another CPP component requires certain industrial stationary sources to reduce their GHG emissions using best available emissions reduction approaches, with plans subject to review by the state’s Department of Environmental Equality (DEQ). (See Oregon Adopts GHG Cap-and-invest Program.)

Oregon lawmakers last spring passed the country’s most ambitious clean energy mandate (HB 2021) (tied with New York), requiring the state’s investor-owned utilities to serve their customers with 80% emissions-free electricity by 2030 and 100% by 2040. IOUs serve about three-quarters of the population. (See West Coast Could Be Net Zero by Midcentury.)

In the fall, Oregon also adopted the nation’s most stringent landfill gas emissions standards, part of an effort to reduce the release of heat-trapping methane. The DEQ estimates that landfills accounted for 37% of Oregon’s carbon dioxide-equivalent emissions from stationary sources in 2019, excluding power generators. (See Oregon Adopts Nation’s Strictest Landfill Emissions Rules.)

On the EV front, an advisory group convened by Oregon’s Department of Transportation published a report last summer showing that the state must have 155,249 public chargers in place — compared with about 3,500 today — to accommodate the 2.5 million EVs that policymakers expect will be registered by 2035. The report also outlined recommendations for how the state should get there. (See Oregon Study Charts Explosive Growth of EV Chargers.)

Sweeping Bill in Nev.

Nevada lawmakers in May passed a far-reaching bill (SB 448) to expand electric transmission and boost the presence of EV chargers across the state. (See Nev. Bill Would Ramp up Tx, EV Spending, Prepare for RTO.)

“This bill would create a framework by which we could then develop transmission lines across the state of Nevada and be able to access wind in Wyoming, solar in the Southwest, hydro in the Northwest, and provide power to our neighbors in Southern California and Central California,” said Sen. Chris Brooks (D), the bill’s chief sponsor.

The new law also aligns utility planning processes with the state’s decarbonization goals. Another provision requires utilities to join a regional transmission organization by 2030, a process Gov. Steve Sisolak got underway last month with the appointment of a task force that will advise the governor and legislature on the process. (See Nev. Gov. Sisolak Appoints Regional Tx Task Force.)

Regulators in Nevada and neighboring Arizona late last year both approved plans encouraging utilities to adopt electric vehicles. The Nevada Public Utilities Commission approved NV Energy’s plan to spend $1electr00 million over three years to develop about 1,820 EV chargers at 120 sites, in accordance with SB 448. (See NV Energy Gets Green Light for $100M EV Charger Plan.) Meanwhile, the Arizona Corporation Commission directed that state’s IOUs to develop transportation electrification plans that base future investments on a “high-adoption scenario” for EVs.

Additionally, Nevada’s Legislative Commission voted in October to adopt Clean Cars Nevada, a regulation that aligns the state’s zero-emissions vehicle (ZEV) policies with California and provides automakers with credits for selling ZEVs in state. Although the regulation won’t take effect until model year 2025, automakers will be able to begin earning “early” credits this year. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)

Winds Blow from Calif.

Despite the policy actions elsewhere in the West, California in many respects remained the climate policy trendsetter for the region and the country, advancing new initiatives related to cap-and-trade, EVs and building decarbonization.

At the U.N. Climate Change Conference of the Parties (COP26) in Glasgow, Scotland in November, California demonstrated its clout when it entered an agreement with Quebec and New Zealand to cooperate on carbon markets and other climate actions. The pact, signed by California Air Resources Board (CARB) Chair Liane Randolph, calls for the three governments to explore alignment of their cap-and-trade programs through program features such as cap setting, auctions, credit allocation and market rules. (See Calif., Quebec, NZ Pledge Cooperation on Climate, Carbon Markets.) 

California leads the nation in ZEV ownership, and CARB last year moved broadly to help the state accelerate uptake of the vehicles. 

In August, the agency proposed a plan to give auto manufacturers environmental justice (EJ) credits for selling ZEVs at a discount to community programs that offer services such as ZEV car sharing. Manufacturers could use the EJ credits to boost the number of total credits they earn under the state’s existing ZEV credit program, which is based on a purchased vehicle’s range on a single charge. (See CARB Plan Aims to Broaden Access to ZEVs.)

In October, CARB proposed to allow car manufacturers selling vehicles in the states that follow California’s ZEV regulations to transfer ZEV credits among states, starting with model year 2026. Twelve states have so far adopted California’s ZEV rules. (See CARB Plan Would Allow Interstate Transfer of ZEV Credits.) 

CARB in November approved a $1.5 billion clean transportation funding plan that includes $515 million for a popular electric car incentive program, $570 million for the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project, and $75 million for a program that encourages low-income residents to replace old cars with zero- or near-zero-emissions vehicles. The plan also gives $195 million to the Clean Off-Road Equipment Voucher Incentive Project, which provides incentives for equipment such as zero-emission tractors and forklifts. (See CARB Approves $1.5B Clean Transportation Package.)

On the building decarbonization front, the California Energy Commission last summer approved a major state building code update expected to “juice the market” for heat pumps, according to Commissioner Andrew McAllister. The new code sets requirements for electric heat pumps for space and water heating, solar paired with battery storage in commercial buildings, and wiring homes to equip them for all-electric appliances. (See Calif. Energy Commission Adopts 2022 Building Code.)

“California is being forced to lead even more than before, and that’s a good thing,” McAllister said when the CEC approved the code. “The winds are blowing through California. They start here and blow elsewhere.”

This story relied heavily on the previous reporting of John Stang, Elaine Goodman and Hudson Sangree.