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November 1, 2024

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NJ Retools Electric MHD Truck Charger Proposal

A revised version of the New Jersey Board of Public Utilities (BPU) straw proposal designed to stimulate the development of chargers for medium- and heavy-duty (MHD) electric trucks would provide extra support for private fleets that put chargers in overburdened communities but would also place greater demands on the fleets.

The new proposal, which is scheduled for a public hearing on Jan. 17, seeks to “refine” the original package issued in June 2021 with several enhancements. Some were triggered by stakeholder arguments in a series of public hearings in August and September 2021 that with so many trucks working in and around overburdened communities, the BPU would need to offer more benefits to private fleets to get enough to act and significantly cut emissions in those areas.

The original proposal offered limited assistance to private fleets, mainly technical help provided by electric distribution companies. It focused on supporting the development of charging sites in overburdened areas that were open to the public.

The new package makes a private fleet eligible for incentives of up to 100% of the cost of “make ready” work — the pre-wiring of electrical infrastructure at a parking space for future installation of a charger — in overburdened areas. To receive the full subsidy, the fleet charging depot must be located in an overburdened community and must displace existing fossil-fueled vehicles rather than adding new electric vehicles to an existing fleet.

The fleet also must agree to participate in a “managed charging,” which requires it to charge vehicles in off-peak periods, generally overnight, to help reduce the load on the grid.

Legacy of Disinvestment

The MHD charger proposal is part of the state’s effort to cut emissions in its largest polluting sector, transportation, which accounts for about 42% of carbon emissions in the state. Long- and short-haul single unit and combination trucks account for 18% of the greenhouse gas emissions from road vehicles, with another 43% generated by light commercial and passenger trucks, according to the proposal.

At present, electric vehicles account for only a tiny number of the state’s 500,000 MHD trucks, which are major emissions contributors and are especially problematic to communities located near freight corridors, warehouses, distribution centers and ports.

The proposal says that although MHD trucks and buses account for only 4% of the vehicles on the road in New Jersey, they contribute nearly 25% of greenhouse gas emissions.

Gov. Phil Murphy wants the state to reach 100% clean energy by 2050, and the state’s 2019 Energy Master Plan assumes that 75% of medium-duty trucks and 50% of heavy-duty trucks will be electric by 2050.

“The physical and monetary costs of emissions in overburdened municipalities, particularly in urban settings, require ratepayer investment to ensure that EV adoption’s positive impacts are distributed equitably cross the state,” according to the proposal, which was released Dec. 22.

It adds that “staff is convinced that partial socialization of private fleet depots located in or primarily operating in overburdened municipalities is critical to meeting the governor’s commitment to improving environmental conditions in the communities struggling under the legacy of disinvestment and discrimination.”

The proposal does not require that a fleet depot to be located in the overburdened community to be eligible for benefits under the proposal. But if it isn’t, the fleet needs to “primarily operate” there, a phrase that has still to be defined but could include the fleet’s trucks driving a large portion of their mileage in the area, according to the proposal. In example, it cites the definition in the Zero-Emission Incentive Program (ZIP), which is run by the New Jersey Economic Development Authority (EDA) and awards purchase subsidies for light and medium trucks that in some circumstances hinge on the truck doing up to 50% of its miles in overburdened communities.

In another addition to the earlier proposal, the new package makes sites that install chargers higher than 500 kW, sometimes known as “ultra-fast” chargers, eligible to receive technical assistance from utility companies, who could then charge the cost to ratepayers. The earlier proposal allowed the utilities to provide technical assistance only to public and private fleets.

The assistance provided by the utilities is expected to range from picking site charging locations to planning for fleet and charging growth and determining “when, and if, additional grid support is needed,” according to the proposal.

The BPU straw proposal, in both the initial and revised forms, envisions private developers and investors installing, owning and operating EV service equipment and marketing the sites to customers. Utilities would help wire and provide the backbone infrastructure necessary but would not be able to own chargers developed under the program, except in certain circumstances, mostly when no other developer steps forward.

The proposal drew criticism from several fronts on its release. At one hearing, Zachary Kahn, senior policy adviser for Tesla, argued that the private fleets deserved more support because they were already making a serious investment in buying electric trucks and had shown they clearly had “significant skin in the game.”

An attorney for the Sierra Club, Zachary Fabish, said that regardless of whether a charger is private or publicly accessible, it would make the same contribution to reducing emissions and that is essential to combating climate change. (See NJ Electric Truck Rules Face Many Questions.)

In the latest proposal, the BPU says it is working to “define the appropriate level of ratepayer investment in this sector.”

“Many of the issues that this straw proposal seeks to explore include questions about who should construct, own, operate and pay for the MHD network necessary to make New Jersey a national leader in the adoption of electrified MHD fleets and the buildout of an MHD EV ecosystem,” the proposal states.

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Oregon Report Calls for Greater Heavy-duty EV Incentives

When it comes to zero-emission truck incentive programs, Oregon stakeholders want to see a program similar to California’s popular HVIP, and they recommend keeping incentive programs consistent along the West Coast.

Those were some of the findings of a new report from the Oregon Department of Environmental Quality and the state Department of Transportation. The report, “Incentives to Support the Transition to Zero Emissions for Medium- and Heavy-Duty Sectors in Oregon,” was prepared in response to direction from the state legislature.

The report found that current incentives are not enough to promote a rapid transition to zero-emission trucks.

“State and federal grant programs are underfunded, too narrow in scope or both,” ODOT’s Climate Office said in summarizing the report’s key takeaways. “New programs must be flexible and established quickly.”

A variety of incentives are needed for zero-emission vehicles alone, infrastructure, or a combination of vehicles and infrastructure, the report said. In addition, federal, state and utility incentive programs should work together so that the incentives can be “stacked.”

And equity should be a priority, the report said. Incentive programs should earmark funding for fleets that serve communities disproportionately impacted by emissions, and small businesses should be offered assistance in navigating the programs.

Stakeholders Weigh In

As part of the process for developing the report, DEQ and ODOT held listening sessions with fleet owners, nonprofits and other interested parties.

Commenters spoke highly of California’s Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which offers point-of-purchase incentives that vary with the type and model of truck.

“[Stakeholders] supported adoption of a similar, if not identical, program in Oregon,” the report said.

Commenters also called for consistency among zero-emission truck incentive programs on the West Coast, speculating that better incentives in other states would discourage ZEV purchases in Oregon. On the other hand, Oregon might not be able to sustain incentive programs that are too generous.

Stakeholders suggested calculating ZEV incentives as a percentage of vehicle purchase price or basing them on the cost difference with diesel trucks. Another suggestion was to give incentive recipients more time to buy a ZEV or install infrastructure, due to ongoing supply chain issues.

Another California strategy that was discussed is the state’s requirement for utilities to implement “make ready” systems to streamline infrastructure installation.

“A similar approach in Oregon may cut down installation time — which is currently anywhere from 18 to 24 months — once supply chain issues are resolved,” the report said.

ZEV Truck Collaboration

In 2021, Oregon joined a coalition of 19 jurisdictions — 17 states, the District of Columbia and Quebec — that signed a memorandum of understanding to accelerate the transition to zero-emission medium- and heavy-duty trucks. The group set a goal of making at least 30% of new medium- and heavy-duty truck sales zero-emission by 2030, with 100% ZEV sales by 2050.

In July, the group released an action plan with more than 65 strategies and recommendations aimed at encouraging zero-emission truck adoption. The Oregon agencies incorporated recommendations regarding incentive programs into the new report.

For example, one recommendation is for states to reduce or waive sales tax and registration fees for zero-emission trucks until they cost the same as diesel vehicles.

An analysis by the California Air Resources Board found that model year 2024 ZEV trucks will cost an expected $14,000 to $87,000 more than conventional vehicles, according to the Oregon report.

That cost difference is expected to disappear by 2030.

“While 2030 is not far out, the amount of emission and GHG from diesel vehicles will be costly to the environment and to the health of Oregonians,” the Oregon report concluded. “Incentivizing adoption of ZEV now is imperative to support climate initiative and the livability of Oregon.”

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FERC Accepts SPP Order 845 Compliance Filing, Grants Tx Planning Waiver

FERC late last month accepted a pair of SPP tariff revisions related to generator interconnection procedures and transmission planning.

The commission on Dec. 29 accepted SPP’s Order 845 compliance filing, effective Jan. 1. The 2018 order amended FERC’s pro forma large GI procedures and agreement, intended to improve the interconnection process and ensure it is just and reasonable (ER23-333).

SPP proposed expanding the transfer or use of surplus interconnection service beyond Order 845’s intent by allowing requests for surplus interconnection service (SIS) that require network upgrades in certain situations. Order 845 had required transmission providers to offer SIS to reduce costs for interconnection customers by increasing the use of existing interconnection facilities and network upgrades, rather than requiring new upgrades.

FERC said that by expanding the use of SIS, the RTO’s proposal will accomplish Order 845’s purpose. It found that the proposal would not “undermine” the order’s “open and transparent process for surplus interconnection service.”

“SPP’s proposal includes clear and objective criteria and protects against adverse effects on other interconnection customers in the SPP generator interconnection queue,” the commission said.

It also said the proposal would not result in “inappropriate queue jumping,” as its expansion of SIS is “limited by the requirement that there are no material adverse impacts on the cost or timing of any generator interconnection requests pending at the time the surplus interconnection service request is submitted.”

In a separate order issued the same day, FERC granted SPP’s waiver request for a six-month extension of its deadline to complete its 20-year assessment transmission planning study, from December 2022 to July 2023 (ER23-201).

The RTO said that when it began scoping the long-term assessment with stakeholders, it also began experiencing milestone delays for completing the 2020, 2021 and 2022 Integrated Transmission Planning (ITP) studies as the COVID-19 pandemic began.

Staff and members agreed in 2021 to pause the 20-year assessment and shift staff to the other planning studies to avoid further delays. SPP pointed out that the long-term study only looks for transmission solutions of 300 kV or higher and does not require approval to build transmission projects, as do the other ITP assessments. (See “Tx Planning Mitigation Gets OK,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

FERC said the waiver request met its criteria of being made in good faith, being limited in scope, addressing a concrete problem and not having undesirable consequences.

Co-ops File Complaint vs PSCo

In a complaint filed with FERC on Dec. 30, four Colorado cooperatives charged Public Service Company of Colorado (PSCo) with imprudently planning for and not supplying them with gas for electric generation during the severe February 2021 winter storm.

CORE Electric Cooperative, Grand Valley Rural Power Lines, Holy Cross Electric Association and Yampa Valley Electric Association said the Xcel Energy subsidiary failed to follow its own supply plans and wound up having to buy gas on the spot market at higher prices. They are asking the commission to return to them $6.9 million in fuel charges.

“PSCo’s failure to adhere to its monthly supply plan caused the company to purchase significantly more spot gas than called for in the monthly supply plan, actions a reasonable utility management would not take, constituting evidence of more than a ‘bare allegation of imprudence,’” the co-ops said.

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EPA Proposes Lowering Limit for Small Particle Pollution

EPA wants to cut the annual levels of PM2.5 ― the very small particles of soot produced by fossil fuel combustion ― by as much as 25% from the current standard, which was set in 2012 and kept in place through 2020 by former President Donald Trump.

In a Notice of Proposed Rulemaking announced Friday, EPA said it plans to revise the annual National Ambient Air Quality Standards (NAAQS) from its current level of 12 micrograms per cubic meter (μg/m3) to 9 or 10 μg/m3.

The revised standard is “based on scientific evidence that shows the current standard does not protect public health with an adequate margin of safety, as required by the Clean Air Act (CAA),” the agency said in a fact sheet released with the 569-page NOPR.

PM2.5 is scientific shorthand for particulate matter with a diameter of 2.5 microns or less, which is about 30 times smaller than the diameter of a human hair and invisible to the human eye. “Most particles form in the atmosphere as a result of complex reactions of chemicals such as sulfur dioxide and nitrogen oxides, which are pollutants emitted from power plants, industries and automobiles,” according to information on EPA’s website.

“Long- and short-term exposures to PM2.5 can harm people’s health, leading to heart attacks, asthma attacks and premature death. Large segments of the U.S. population, including children and older adults, people with heart or lung conditions, and minority populations, are at risk of adverse health effects from PM2.5,” EPA said in the fact sheet.

The agency could also be considering revising the standard to as low as 8 μg/m3 or as high as 11 μg/m3, according to the announcement, which asks for comments on each of the proposed figures.

“Our work to deliver clean, breathable air for everyone is a top priority at EPA, and this proposal will help ensure that all communities, especially the most vulnerable among us, are protected from exposure to harmful pollution,” EPA Administrator Michael Regan said.

Doris Browne, former president of the National Medical Association, also stressed the equity and environmental justice impacts of the proposed new standards. “No one should be sickened by the environment they live in, and EPA’s proposal marks the start of changes that will have lasting impacts in communities all over, especially Black and brown communities that often experience increased PM pollution.”

According to the EPA, setting the annual standard at the lower 9 μg/m3 would prevent up to 4,200 premature deaths and 270,000 lost workdays per year. Overall public health benefits could total $43 billion by 2032, the agency said.

While focusing primarily on the annual PM2.5 standard, EPA said it will not propose revisions to the 24-hour standard for PM2.5, now set at 35 μg/m3, noting that “scientific evidence does not clearly call into question the adequacy of the current standard.” However, the agency does ask for comments on lowering the daily standard to 25 μg/m3.

The 24-hour standard for PM10, a somewhat larger form of particulate matter, would also stay unchanged at 150 μg/m3, EPA said.

Publication of the NOPR in the Federal Register will begin a 60-day comment period. EPA will also hold a virtual public hearing on the proposed standards at a date to be announced.

If a region’s air quality fails to meet the new standard, state governments must execute plans to meet the requirement. 

“For PM2.5, such a plan could involve cutting car traffic by improving public transit or instituting carpool lanes. Or, if there are some industrial facilities like coal plants that do not have modern scrubbing technology, the state can compel them to clean up,” said Earthjustice’s Ben Arnoldy in a  blog post. 

A Compromise? 

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The NOPR announcement is part of broader group of actions taken by EPA and the Biden administration, the agency said, pointing to the clean truck rules issued in December as one example. (See EPA Announces Tougher Emission Rules for Heavy-duty Vehicles.) While the proposed revisions would not directly target greenhouse gases, cutting PM2.5 from sources like power plants and cars could also result in lower carbon emissions.

EPA started setting standards for both PM2.5 and PM10 in 1971. According to the agency, the annual and 24-hour standards serve distinct purposes. The lower, annual standard provides protection against health impacts caused by short- or long-term exposure to PM2.5. The higher 24-hour standard is intended to protect against short-term exposures, particularly in areas that could experience high peaks in PM2.5 concentrations.

The EPA Green Book, which tracks compliance with a number of clean air standards, shows Pennsylvania with one county currently not in compliance with existing PM2.5 standards: Allegheny, in the western part of the state. California has 14 counties out of compliance: Fresno, Imperial, Kern, Kings, Los Angeles, Madera, Merced, Orange, Plumas, Riverside, San Bernardino, San Joaquin, Stanislaus and Tulare.

A revised standard of 9 μg/m3 could throw 112 counties, many in California, out of compliance, based on current reported emission levels.

The suggested standard of 9 or 10 μg/m3  appears to be a compromise between two options contained in a March 2022 report from EPA’s Clean Air Scientific Advisory Committee (CASAC).

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EPA

A majority of committee members recommended the lower 8 μg/m3  standard, while a minority said the higher 11 μg/m3 would be sufficient. Similarly, the CASAC had a split decision on the 24-hour standard, with some supporting no change and others suggesting a cut to 25 to 30 µg/m3.

“There is substantial epidemiologic evidence from both morbidity and mortality studies that the current standard is not adequately protective. This includes three U.S. air pollution studies with analyses restricted to 24-hour concentrations below 25 µg/m3,” CASAC Chair Lianne Sheppard wrote in a letter introducing the report.

The nonprofit Clean Air Task Force cited CASAC in its statement, calling on EPA to go with the lower standards.

“An annual standard of 8 µg/m3 and a 24-hour standard of 25 µg/m3 would require more aggressive action under the Clean Air Act either by states or the federal government to address this problem in polluted areas,” said Hayden Hashimoto, associate attorney for the group. “Therefore, we will continue to urge EPA to set the standards at these levels, as it is critical for public health and the environment that they reflect the current scientific understanding of the threats posed by particulate matter.” 

In response to the announcement, the Edison Electric Institute highlighted the industry’s emissions reductions to date and its intention to take an active role in discussions about any revisions to the standards.

Alex Bond, EEI’s deputy general counsel, said U.S. utilities have cut emissions of sulfur dioxide and nitrogen oxide 94% and 88%, respectively, since 1990, and now produce 40% of their power from “emissions-free sources, including nuclear energy, hydropower, wind and solar energy.”

EEI will work with EPA “to ensure that implementation of the standard is consistent with our industry’s ongoing clean energy transformation,” Bond said.

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Competitive Power Ventures Entering Retail Market

Competitive Power Ventures (CPV) announced Friday that it is launching CPV Retail Energy, a subsidiary to sell power from its “low-emitting” combined cycle plants within the PJM grid to commercial and industrial customers.

“CPV is excited to launch this new platform, which will enable the company to share the benefits of its renewable and world-class low-carbon fleet directly with customers,” Qadir Khan, president of CPV Retail Energy, said in an announcement of the launch. “The retail team has decades of experience in building successful retail platforms, and we look forward to developing this new customer-focused platform.”

Matt Litchfield, director of external and regulatory affairs, told RTO Insider that CPV has a unique generation fleet in that most of its traditional thermal assets have come online since 2016, meaning its units have some of the most efficient and low-emission technology. The company also has more than 4,000 MW of renewables in its development queue across the nation, which brings its total generation to 7,000 MW in development, construction and operation.

“There’s other companies out there that offer renewable options, which we will as well, but there’s not a lot of other companies out there offering a low-carbon product as well,” Litchfield said of the company’s reasons for entering the retail market.

The company is also embarking on a $3 billion development of an 1,800-MW combined cycle facility equipped with carbon capture technology in West Virginia, in part using tax credits under the federal Inflation Reduction Act. Litchfield said the project is indicative of the type of low- and zero-carbon emitting generation options the company will offer to consumers.

With the majority of the company’s assets based within the PJM footprint, CPV Retail Energy will begin by focusing its operations in Delaware, Illinois, Maryland, New Jersey, Ohio, Pennsylvania and D.C. The company has plans to expand into New York and New England.

“With plans and products from CPV Retail Energy, customers will have access to reliable electricity sourced from a company that is not only committed to the environmentally responsible production of electricity, but that also places a strong emphasis on being a good corporate citizen and operating with integrity,” Khan said in the announcement. “We can’t wait to get started growing CPV Retail Energy into a premier ‘Greentailer’ in the retail electric power industry and offer customized pricing plans including 100% renewable options.”

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Regulators File Emergency Motion in Ongoing Grand Gulf Battle

The convoluted and long-running clash over refunds due from years of alleged mismanagement and performance issues at Entergy’s Grand Gulf Nuclear Station took another twist last week when regulators accused the utility of publicizing a false narrative.

The Arkansas and Louisiana commissions and New Orleans’ city council filed an emergency motion Jan. 3 after an Entergy press release one week before.

The utility claimed FERC’s recent decision on Grand Gulf tax maneuvers meant it owed no additional refunds to ratepayers. The regulators, who were expecting hundreds of millions in refunds, asked FERC to correct the press release immediately (EL18-152, et al.).

The regulators and New Orleans have complained for years about mismanagement and substandard operations at the nuclear plant and sought refunds and rate reform on more than $1 billion in costs passed on to Entergy customers in their states and Mississippi. They said that despite expensive upgrades, the plant has been plagued by frequent outages at the expense of customers. (See Entergy Regulators Ask FERC to Settle Grand Gulf Dispute.)

The uproar centers on Entergy subsidiary System Energy Resources Inc. (SERI), majority owner and wholesaler of Grand Gulf’s output to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans subsidiaries. In a pair of December orders concerning the nuclear plant, FERC ruled that SERI excluded decommissioning liability accumulated deferred income tax (ADIT) balances in rate bases from 2004 into the present, violating FERC’s tax normalization requirements (ER18-1182).

The commission also decided that SERI overcharged on the $17 million in Grand Gulf annual lease payments it collected from 2015 through 2022, ordering $149 million in ratepayer refunds (EL18-152).

FERC said the refund amount “appropriately captures the revenue requirement impact resulting from the exclusion of all ADIT amounts resulting from SERI’s decommissioning uncertain tax positions during the entire 2004 to present period of noncompliance.”

Entergy CEO Drew Marsh said in the company’s press release that the utility was “pleased that FERC’s remedy results in no additional refunds due to customers beyond those already provided in 2021 on the uncertain tax positions taken by SERI.”

Entergy said FERC’s refund ruling means that the issue will be completely addressed through its previously enacted $69 million rate base credit to customers for Grand Gulf’s expected lifetime and its one-time credit of $25 million in 2021 to remedy 2015’s decommissioning tax deduction.

The company said the commission’s decision stipulated that the refunds must not “re-establish” SERI’s ADIT balances for tax positions that were denied by the IRS and therefore didn’t benefit the company. The utility explained that except for a $100 million partial acceptance of its 2015 tax position, the IRS didn’t permit any of SERI’s other uncertain decommissioning tax positions.

“Under the remedy specified by FERC, for uncertain tax positions that the IRS fully disallowed, and for which SERI received no tax benefits, no refunds are due. We therefore calculate the remaining refund for the uncertain tax positions issue to be $0,” Entergy said.

“The position Entergy asserts in its press release is a blatant and perhaps intentional misrepresentation of the commission’s orders,” the state and city regulators told FERC. “Unless corrected, it may cause substantial damage to Entergy investors and at the least will mislead those investors and the consuming public. A clarifying statement from the commission can diminish these consequences.”

Entergy released a statement on Thursday addressing regulators’ emergency motion. It said it was “following FERC’s regulatory process” and plans to file compliance “detailing the refunds that we believe are required by the FERC order.”

However, the utility doubled down and said SERI owed no additional refunds stemming from its ADIT tax positions.

“As we’ve consistently said, SERI’s tax strategy was conducted in the best interest of our customers and ultimately saved millions of dollars in operating expenses. Those cost savings have already been passed on to our customers, and we believe we have already paid the refunds due under the remedy FERC outlined on the uncertain tax positions taken by SERI,” the company said.

Entergy added that a global settlement of all SERI dockets is in the “best interest of all parties.”

The state regulators and New Orleans also allege Entergy recovered the costs of lobbying, image advertising and private airplane use in rates through the plant’s sales agreement.

Entergy has offered its regulators nearly $600 million to resolve the Grand Gulf complaints, with $235 million to the Mississippi Public Service Commission, $142 million to the Arkansas Public Service Commission, $116 million to the New Orleans City Council, and $95 million to the Louisiana Public Service Commission. Only the Mississippi PSC has taken Entergy up on its offer. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

Entergy also said last week that it will seek a rehearing of FERC’s decision that SERI owes nearly $150 million in refunds because it improperly billed the costs of Grand Gulf’s sale leaseback renewals in its formula rate. The utility said the sale leaseback renewal “was entered into to lower costs to customers, which is a benefit that FERC previously recognized.”

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Cap-and-trade Revenues Still an Unknown for Wash. Lawmakers

Washington lawmakers won’t know until mid-March how much cap-and-trade revenue they will be able to spend during the 2023-25 budget period.

That will be five to six weeks prior to the end of the 2023 legislative session, which is scheduled to finish April 24. Traditionally, both the Washington House and Senate unveil their individual biennial budget proposals in early March to begin talks to reconcile the two measures. The 2023 session begins Jan. 9.

The bottom line is that a mid-March unveiling of cap-and trade figures will create a time crunch in Washington’s budget deliberations.

Following a brief introduction by Gov. Jay Inslee, officials from the state’s Ecology and Commerce department on Wednesday briefed the press on what is next in implementing the state’s new cap-and-trade and low-carbon fuels laws. Both went into effect on Jan. 1.

“It’s a happy day when the state can take a huge bite out of climate change,” Inslee said.

Ecology Director Laura Watson and Commerce Assistant Director Michael Furze said they don’t know how many of the initial 6.185 million allowances will actually be sold during the program’s first auction on Feb.28. “We have seen businesses positively responding here,” Watson said. Watson also said her agency cannot provide an estimate on final prices in the auction.

Revenue figures will be provided to the legislature a couple weeks after the auction, Watson said. Initial speculation is that the figure could be in hundreds of millions of dollars. Last year, Ecology officials told legislators the program should yield about $500 million in annual revenues. (See Cap-and-trade Projected to Provide Wash. $500M Annually.)

Some lawmakers are seeking to use cap-and-trade money to fund proposed tree-planting programs to replace trees lost to development and shade rivers and streams that provide routes for migrating salmon. Republicans want to use a portion of the funding to create an Office of Puget Sound Water Quality to provide help and supervision to municipal sewage treatment plants to decrease the amount of nitrogen-laden nutrients dumped into the sound, which harm fish. (See Climate Still on Wash. Agenda After Landmark Legislative Sessions.)

No dates have been set yet for the second, third and fourth auctions in 2023.

Meanwhile, state officials contended Wednesday that the new low-carbon fuel standard (LCFS) that went into effect on Jan. 1 will have little effect on gasoline prices. Watson said no gas tax increases are expected from either cap-and-trade or the LCFS. 

“The price impacts are pretty minimal,” said Joel Creswell, climate policy section manager at the Ecology Department.

They were responding to contentions by critics that California’s low-carbon fuel standard increased gas taxes — or fees — there by 40 to 50 cents per gallon.

Washington’s new LCFS requires that carbon emissions from gasoline and diesel fuel sold in Washington motor vehicles to be cut by 10% below 2017 levels by 2028 and by 20% by 2035. The bill excludes from these goals fuel that is exported out of state, and fuel used by vessels, railroad locomotives and aircraft. The goals apply to overall vehicle emissions in the state and not to individual types of fuels. 

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Texas Petitions SCOTUS to Review ROFR Ruling

Texas has petitioned the U.S. Supreme Court to review the 5th U.S. Circuit Court of Appeals’ 2022 ruling that the state’s law giving incumbent transmission companies the right of first refusal to build new power lines is unconstitutional.

In a Dec. 28 filing, with Texas Public Utility Commission Chair Peter Lake as the lead petitioner, the state asked the high court for a writ of certiorari, a formal request to review a lower court’s judgment against the petitioning party.

The petition comes after the 5th Circuit’s August decision in NextEra Energy’s challenge to a 2019 Texas law (Senate Bill 1938) that set up ROFR within state lines.

The appeals court ruled that Texas’ ROFR law violated the U.S. Constitution’s dormant Commerce Clause. It remanded the case back to the U.S. District Court for Western Texas, saying it should proceed beyond the lawsuit’s pleading stage (20-50160). (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

The district court in 2020 rejected NextEra’s claim that the Texas law violated the clause because it only allowed the incumbent state owners of a transmission line’s end points to build, own and operate new lines. The court said the legislation doesn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.” (See District Court Dismisses Texas ROFR Repeal.)

Texas said the question in the proceeding is whether “consistent with the Commerce Clause, states may exercise their core police power to regulate public utilities by recognizing a preference for allowing incumbent utility companies to build new transmission lines … or if such a preference necessarily violates the Commerce Clause, as the 5th Circuit held.”

Noting that the Supreme Court has said regulating utilities is “one of the most important of the functions traditionally associated with the police power of the states,” Texas said it exercises this power by regulating electric transmission throughout the state.

“For decades, the accepted view across the nation was that system reliability, efficiency and cost for ratepayers are all best served when new transmission lines are built by the owners of the endpoint facilities to which the new lines would connect,” Texas said in its petition. “Even when [FERC] changed course [in Order 1000], it expressly preserved states’ ability to maintain that policy.”

Lake was joined as a petitioner by his four fellow commissioners. The respondents include NextEra Energy Capital Holdings, NextEra Energy Transmission (NEET), NextEra Energy Transmission Midwest, Lone Star Transmission, NextEra Energy Transmission Southwest, Southwestern Public Service, Entergy Texas, Oncor, LSP Transmission Holdings II and East Texas Electric Cooperative.

The high court says it receives about 10,000 petitions requests for writs of certiorari each year. Only 100 or so eventually receive the writ and have oral arguments before the court.

NextEra subsidiaries were involved in two projects in Texas’ non-ERCOT footprint that ran afoul of the ROFR law. NEET Midwest won a competitive bid in 2018 for a $130 million, 500-kV project in East Texas. MISO said last year that planned capacity in the region had negated much of the project’s economic benefits. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

NEET Southwest also applied to the Texas PUC in 2018 to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s East Texas footprint. That application was withdrawn in 2020 after SB 1938 became law (48071).

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New Mission Means New Name for Advanced Energy Economy

Advanced Energy Economy has started 2023 with a new name, Advanced Energy United, reflecting both the progress the group has made since its founding and the challenges ahead.

The group’s original name reflected its goal of creating an economy powered by advanced energy. Now, although there is broad consensus around its objective, the group says, the challenge is harmonizing the technologies needed to achieve it and breaking down the barriers in the way.

“It’s a recognition of the moment in time,” President Heather O’Neill said in an interview with NetZero Insider. With $369 billion — or more — in clean energy tax credits, incentives and new programs available under the Inflation Reduction Act, the group’s goal is “having the industry come together to accelerate the energy transition and take advantage of the massive opportunities in front of us,” she said.

Advanced Energy was founded in 2011 by two early clean energy investors, the hedge-fund manager and philanthropist Tom Steyer and venture capitalist Hemant Taneja. Neither is currently involved with the organization, but, O’Neill said, “they came together with the belief that there was a need for a national entity that could serve as the bipartisan, data-driven business voice for clean energy to change the landscape and market opportunity.”

The organization numbers more than 70 corporate members, including independent power producers and technology companies. In addition to its federal advocacy, the organization works with a range of state and local officials and regulators in 12 states: Arizona, California, Colorado, Florida, Illinois, Indiana, Michigan, Nevada, New York, Pennsylvania, Texas and Virginia.

Advanced Energy said it hopes to expand its state advocacy in the West and Northeast this year, targeting Connecticut, Maryland, Massachusetts, New Jersey and Rhode Island, as well as New Mexico. The organization’s PowerSuite database tracks energy policies in all 50 states.

In anticipation of the IRA rollout, the group released three “toolkits” for state officials with information on how to plan for and access the law’s various programs and incentives: one for governors and other state administrators; one for legislators; and one for regulators.

Advanced Energy’s shift is the latest rebranding among energy-related trade groups, often reflecting mergers or the evolution of their missions as technologies and markets also evolve. In 2021, the American Wind Energy Association revamped as the American Clean Power Association, which absorbed the U.S. Energy Storage Association last year and claims more than 800 members. (See Unity Touted at American Clean Power’s First Conference.)

The American Coalition for Clean Coal Electricity (ACCCE) renamed itself America’s Power in 2018, according to its IRS form 990. In a 2016 cost-cutting move, the American Petroleum Institute absorbed America’s Natural Gas Alliance, which represents independent natural gas exploration and production companies. (See API, ANGA Merge in Cost-Cutting Move for Oil Gas Lobby.)

The same year, the Solar Electric Power Association became the Smart Electric Power Alliance, later merging with SGIP — Smart Grid Interoperability Panel — an industry consortium focused on grid modernization.

Advanced Energy United is hoping to avoid any abbreviation of its name, at least for the time being, said Adam Winer, the group’s strategic communications director. As inevitable as they seem to be in D.C., abbreviations don’t help people understand an organization’s mission, and most wouldn’t recognize the new name if it is abbreviated, he said.

O’Neill answered other questions about Advanced Energy’s rebrand and the group’s priorities for the new year in the interview below, which has been edited and condensed.

NetZero Insider: In your announcement of the new name, you talk about Advanced Energy being a “unifying voice” for the industry. How un-unified is the clean energy sector? Why does it need a unifying voice?

O’Neill: Traditionally our industry has been siloed by technology, and there’s increasing recognition that working together, there are tremendous benefits. It’s going to take all our technology solutions ― grid-scale, distributed energy resources of all types ― if we’re accelerating this transition to 100% clean energy in the U.S. It’s a recognition, I think, of the opportunities presented at this moment … [for] really bringing all of our technologies together and presenting systemwide solutions to policymakers.

We’re able to unlock solutions that are market-transforming, market-wide transformations, because we’re not looking at problems or identifying solutions from one narrow technology, but really looking across the energy system and looking for wins that will scale clean energy writ large.

Advanced Energy is one of the cohort of clean energy trade and advocacy groups in D.C., many with overlapping missions and priorities. How are you different? What are you offering that that the others aren’t?

We do represent all clean energy technologies and clean transportation technologies together; so really looking at an integrated approach, ranging from demand response, energy efficiency, storage, traditional renewables ― both utility-scale and distributed ― and into the transportation space. So really [it’s] a broad swath across what are the technologies and the companies that are going to accelerate this energy transition in the U.S.

The other thing that I think is relevant — and again, not new, but certainly part and parcel of who Advanced Energy United is — is that we’re deeply rooted in the states, as well as in key wholesale markets. So, even when we’re focused on work in Washington, D.C., it’s a virtuous cycle with the work in the states.

The incentives and programs in the IRA come with a lot of money but also a lot of requirements; the law has a lot of moving pieces. What are you hearing from your members? What are the challenges you see ahead?

What we’ve seen is just that there’s a tremendous appetite from folks on the ground in the states to understand what is available and how they can help unlock some of this massive transition. And so, what we’ve done and what we’ll be continuing to do, we put out toolkits right towards the end of the year … to really articulate all of the various energy provisions that were contained [in the law] and the ways in which they should be thinking about setting up programs really unlocking the potential here.

Toolkits are fine in and of themselves, but really, then, the work is spending the time in the states, with decision makers, and working through whatever their particular structure is set up to afford them to do. That’s the work that will be ongoing for our teams in this early part of the new year.

Big question: How are you going to work with the Republican majority in the House of Representatives?

I think [we will be] really focused on not just IRA implementation but also looking at critical minerals, at domestic manufacturing. How can we expand domestic manufacturing and advanced energy technologies? I think that is a bipartisan issue. That’s a priority for us in this coming year ― to really think about how do we both enhance access to critical minerals and support recycling that builds on some of the provisions in the Inflation Reduction Act.

I don’t want to put words in your mouth, but what I’m hearing is you’ll be looking to find the issues where you think there is good bipartisanship.

Yes, both good bipartisanship and [issues that] are important to our industry. If we’re going to scale the clean energy transition, we need to expand domestic manufacturing; we need to be thinking about where we’re getting some of the critical minerals from and how we’re improving the processes around those. So absolutely thinking about both what are issues that will resonate across the aisle, and what are issues that are incredibly important for our industry in order for it to scale.

Dare I ask, what’s your take on permitting reform?

For us as an organization, we’re thinking about working on, acting on [it] in states and regions. How can we help build things? And that includes issues related to transmission; that includes issues related to interconnection and to siting. All of those pieces are part and parcel of the work that we do and the work we’re focused on in the states.

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Massachusetts Floats FCEM Proposal

The energy department of outgoing Massachusetts Gov. Charlie Baker left behind a gift on the governor’s last day in office: a Forward Clean Energy Market proposal.

The document, put together by Massachusetts Department of Energy Resources officials along with Brattle Group and Sustainable Energy Advantage, is intended to be a first draft that could eventually make its way into the NEPOOL stakeholder process.

It will add new weight to longtime discussions about creating a clean energy market in the region for the purpose of encouraging the buildout of more renewable and non-emitting energy sources.

FCEM is the preferred regional decarbonization solution of the states, which are wary of the political implications of carbon pricing. But ISO-NE has warned that FERC or the courts could find the proposal discriminatory.(See NE States, ISO-NE Start to Wrestle with Next Steps on Pathways.)

“Massachusetts views the FCEM as a critical, and presently missing, institutional pillar that will be required to support equitable, affordable, and reliable clean energy transition,” the proposal says.

Structure and Governance

The proposal calls for creating a new independent nonprofit to administer the FCEM, led by representatives of each of the six New England states. Whether it would be FERC jurisdictional is up for debate. Under the main proposal it would, but the proposals’ authors also acknowledge that they might need an alternative structure separate from ISO-NE and overseen exclusively by state officials.

The FCEM’s auctions would line up with ISO-NE’s existing capacity market, taking place every three years. Buyers in the market (such as state agencies, competitive retailers, utilities, municipalities and private companies), taking part voluntarily, could procure one of a number of types of clean electricity certificates.  

The FCEM would include several other mechanisms that the proposal says are designed to “facilitate the financing of large volumes of new clean electricity resources.”

Those include a new resource price lock-in that guarantees new resources a clearing price for a term of 15 years at the rollout of the FCEM, the option for buyers to specify that their demand must be fulfilled by new resources and the option for buyers to submit a “phased entry” demand bid that offers greater flexibility in the startup date for projects that can offer a more competitive price if they initiate operation in future years.

Multiple certificates on offer 

The system would be designed to handle both several region-wide products and whatever certificates states want to put forward on their own, the proposal says.

The first region-wide product would be a New England Renewable Energy Certificate that would be comprised of onshore and offshore wind, solar, hydroelectric and some distributed energy resources.

The second would be a Clean Energy Attribute Certificate, representing “energy generated by any non-emitting energy resource,” including renewables as well as nuclear.

The third is a GHG Marginal Abatement Certificate that includes all of the above, as well as storage and demand response.

And the fourth is a Clean Capacity Certificate that represents all of the above plus clean capacity imports.

States could then list their own products, with no limits on scale or technology types.

“These state-defined rules need not match the rules applicable to similar regional FCEM-defined products. However, over time, the experience with innovative product offerings within the FCEM and across participating New England states may be mutually informative, improving the economic efficiency and efficacy of both state policies and the FCEM products,” the proposal says.

Buyers would have the option to procure their certificates from any combination of the products listed.

The FCEM would use the NEPOOL Generation Information System to track certificates.