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November 9, 2024

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Mahony Named Mass. DOER Commissioner

Elizabeth Mahony, a former deputy of new Massachusetts Gov. Maura Healey, has been picked to lead the state’s Department of Energy Resources.

Mahony was an assistant attorney general focusing on energy and telecommunications when Healey was Massachusetts’ attorney general, working in that office since 2015. She also previously spent three years at DOER as general counsel.

“I’ve worked with Elizabeth for many years,” said Energy and Environmental Affairs Secretary Rebecca Tepper, who also joined the Healey administration from the AG’s office, where she was energy bureau chief. “I’ve seen her in action, thinking up creative solutions to complex problems and delivering real results for the commonwealth. Elizabeth will be at the epicenter of our clean energy transition, and I know she will prioritize ratepayers and advance equity in everything she does.”

Mahony has worked closely with the solar and wind industries, as well as with environmental groups and on environmental justice issues such as the Merrimack Valley gas explosions.

She’s also a veteran of the ISO-NE process, working for years on the grid operator’s Consumer Liaison Group, most recently as chair of the coordinating committee, a position she took up a year ago. (See “Leadership Change,” Overheard at ISO-NE Consumer Liaison Group: March 10, 2022.)

“I’m thrilled to be returning to the Department of Energy Resources to continue the important work of achieving the commonwealth’s bold clean energy goals,” Mahony said in a statement.

“We will be intently focused on preparing our grid for this transition; updating our housing stock for electrification; encouraging more solar, storage and wind; and creating a fertile ground for the clean technology economy to flourish — all while centering environmental justice communities in the work,” she said.

She will replace Patrick Woodcock, who has served as DOER commissioner since December 2019.

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Study: Program Boosted Calif. Home Solar Above US Average

A California incentive program may have helped boost the rate of solar installation in new homes in the state to 40% in 2019, well above the non-California national average of less than 1%, according to a new study.

Within California, the percentage of new homes with solar varied widely by region. Much higher deployment was seen within the territories of investor-owned utilities, Lawrence Berkeley National Laboratory researchers said in their new report, “Starting with Solar.” The study, by researchers Grace Brittan and Ben Hoen, was the subject of a webinar last week.

One potential reason for the regional differences is a solar incentive that was available to IOU customers.

The New Solar Homes Partnership (NSHP) program was launched by the California Energy Commission in 2007. The program accepted applications until April 2018 and issued payments through 2021.

The cash-rebate incentive for solar energy systems in new homes ranged from 50 cents to $1.25/watt. The incentive was available in the service territories of Pacific Gas and Electric, San Diego Gas & Electric and Southern California Edison.

“In investor-owned utility areas of the state where NSHP incentives were available, recent new solar home penetration rates were approximately 50%,” the researchers said. “Outside those IOU areas, penetrations were less than 5%.”

As part of their study, the researchers talked to building industry representatives.

“[We] take advantage of the regulatory environment in each state,” said one large builder, who was not identified. “Net metering and other incentives are central to new solar homes penciling out.”

In contrast to the NSHP incentive, net metering is offered both inside and outside of IOU territories, Hoen noted.

The NSHP program preceded California’s solar mandate for new homes. The CEC approved the mandate in 2018, and it took effect on Jan. 1, 2020.

Regional Differences

In contrast to the new-home solar deployment rate of 40% in California, the rate in the U.S. outside of California was about 0.5% in 2018/19, the study found.

But some areas did better than others. The rate of new-home solar was just over 4% in Arizona, nearly 3% in Nevada and about 1.3% in Utah.

In Las Vegas, three zip codes made the top 10 list for new-home solar deployment outside of California, with rates of 79%, 50% and 24%. Bellingham, Wash., also made the top 10, where 25 out of 114 new homes were equipped with solar, or 22%.

Within California, new-home solar deployment in 2018/19 was highest in three counties — Placer, El Dorado and Yolo — where it hit 70%.

The Berkeley Lab study compared solar systems on new homes in California versus existing homes. The size of systems installed on existing homes in the state has been gradually increasing, to about 7 kW in 2020. In contrast, system size on new homes has been relatively flat from 2015 to 2020, around 4 kW.

“While new homes generally have smaller system sizes than existing homes, this may be due to having more energy-efficiency measures (less load),” the researchers said.

Builder Differences

From 2018 to 2020, about 7% of solar installations on existing homes in California included battery systems. In contrast, less than 1% of new-home solar systems came with batteries, the study found.

The researchers also looked at solar deployment among home builders who had the largest market share in California. Some, but not all, of the top new home builders had high rates of solar-equipped homes.

For Lennar, which had about 10% of the market share in 2018/19, around 90% of new homes in IOU territories were solar-equipped. Woodside Homes, with about 3% of the market share, was also close to 90% solar deployment in IOU territories.

The researchers noted that Lennar installed the solar systems themselves, while other builders subcontracted solar installation.

The NSHP program goal was the installation of 360 MW of solar energy capacity on new housing by the end of 2021. According to the program’s final report, $241 million in incentives were paid through the program for the installation of 232 MW of solar energy capacity.

About 12% of the total incentive payments went to affordable housing projects, which had a total capacity of 22 MW.

The CEC report noted that the program began with large incentive rates that were gradually reduced as hardware costs dropped over time. The installation of solar on new homes “is now cost effective without additional incentive money,” the report said.

CEC called the NSHP program a success.

“The NSHP program furthered the transition to a clean energy economy and has served as a model for new renewable and energy efficiency incentive programs across the United States,” CEC said in the report.

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EPA Reaffirms Power Plant Mercury Regulations

EPA last week reversed a 2020 Trump administration decision that undermined the legal basis for the Mercury and Air Toxics Standards (MATS) for power plants, reaffirming that the rule is “appropriate and necessary.”

The agency’s final rule reaffirms the scientific, economic and legal underpinnings of MATS, which was designed to curb the release of harmful substances from coal- and oil-burning power plants.

EPA says there are about 519 electric generating units at 250 locations that are subject to MATS. “Because the EPA is not amending the MATS rule, there are no cost, environmental or economic impacts as a result of this action,” the agency said. “However, finalizing this affirmative threshold determination provides important certainty about the future of MATS for regulated industry, states, other stakeholders and the public.”

“Retaining these protections is a critical first step,” said Georges C. Benjamin, executive director of the American Public Health Association. “We now urge EPA to strengthen them. We need stronger standards to protect all communities from these pollutants, especially those living near power plants.”

MATS has been at the center of a long-running seesaw battle that has changed directions with legal rulings and with control of the White House.

Amendments to the Clean Air Act in 1990 gave EPA authority to regulate electric utility steam-generating, and the agency under the Clinton administration concluded in 2000 that regulations were “appropriate and necessary.” Under the George W. Bush administration, EPA reversed itself in 2005 and said the regulations were neither.

The Obama-era EPA reversed itself again and issued the final MATS rule in 2012; it said resulting improvements to public health alone would be worth $37 billion to $90 billion a year, given the impacts of mercury and toxics such as hydrogen chloride and selenium. Coal- and oil-burning plants were by far the largest domestic source of these contaminants, EPA said, and among the largest emitters of pollutants such as arsenic, chromium cobalt and nickel.

In Michigan v. EPA in 2015, the U.S. Supreme Court ruled that EPA must consider the cost of implementing regulations it was ordering. EPA in 2016 said it had done so, and reaffirmed that its regulations remained necessary and appropriate.

President Donald Trump famously declared an end to “the war on coal,” and in May 2020, EPA found it was no longer appropriate and necessary to regulate electric utility steam-generating units through MATS.

EPA also said the residual risk and technology review (RTR) mandated by Section 112 of the Clean Air Act showed that emissions had been reduced to the point that residual risk was at acceptable levels, and that there were no new advances in emissions controls that would provide further cost-effective reductions.

President Biden issued a flurry of executive orders on his first day in office in January 2021, among them No. 13990, which directed EPA to revisit the May 2020 action.

The decision EPA announced Friday revokes the 2020 decision and reaffirms the 2016 decision.

In its news release Friday, EPA hinted at political considerations, speaking of its 2020 actions as having been carried out by “the previous administration.” It said the 2020 action undercutting MATS “was based on a fundamentally flawed interpretation of the Clean Air Act that improperly ignored or undervalued vital health benefits from reducing hazardous air pollution from power plants.”

Mixed Reaction

Reaction was divided.

Edison Electric Institute President Tom Kuhn commended EPA, saying in a statement that his members had been successfully implementing MATS during the yearslong regulatory process.

“EEI’s member companies, and the electric power industry collectively, have invested more than $18 billion to install pollution-control technologies to meet these standards,” Kuhn said. “Since 2010, our industry has reduced its mercury emissions by more than 91%, and we have seen a significant change in our nation’s energy mix, which is getting cleaner and cleaner every day.”

U.S. Sen. Tom Carper (D-Del.), chair of the Senate Environment and Public Works Committee, cheered the move.

“When the previous administration chose to remove the legal underpinnings of the MATS rule, they ignored the irrefutable science on the devastating impacts that mercury has on children’s health,” he said in a news release. “Fortunately, EPA is now correcting course and bolstering the MATS rule. This decision will help ensure that our nation’s power plants continue to run on effective pollution-control technology that protects communities’ health and economic wellbeing.”

The committee’s ranking member, Sen. Shelley Moore Capito (R-W.Va.), said in a news release that EPA would now be even more opaque in its rulemaking process and more likely to overstep its legal authority.

“With today’s announcement, we are once again reminded that the Biden administration’s end goal is to shut down American coal plants, fire American coal workers and do everything in its power to make America less energy independent,” she said.

Earthjustice welcomed EPA’s announcement and called for the agency to go further. “Coal-fired and oil-fired power plants are among the worst of the worst polluters, and their toxic emissions fall hardest on communities of color and low-income communities,” Earthjustice attorney Jim Pew said in a news release.

In its announcement Friday, EPA highlighted the health impacts: “Controlling these emissions improves public health by reducing fatal heart attacks, reducing cancer risks, avoiding neurodevelopmental delays in children and helping protect our environment. These public health protections are especially important for anyone affected by hazardous air pollution, including children and particularly vulnerable segments of the population such as indigenous communities, low-income communities and people of color who live near power plants.”

It said that the requirements of MATS, and concurrent advances in the technology used by the power industry, had by 2017 resulted in emissions reductions of 96% in acid gases, 86% in mercury and 81% in other metals.

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NARUC Panel Calls for Clean Energy, GHG Emissions Tracking Standards

WASHINGTON ― President Biden wants all federal agencies to use 100% carbon-free electricity (CFE) ― 50% of which will be matched hour for hour 24/7 ― by 2030. Rhode Island’s Renewable Energy Standard will require the state’s retail electricity suppliers to ensure that 100% of the power they provide is from renewable sources by 2033. And Google (NASDAQ:GOOGL) is targeting 100% clean energy, matched hour for hour 24/7, by 2030.

Despite their very different goals, these clean energy buyers all face a common challenge: figuring out how to keep track of both the clean energy they use and the carbon emissions they cut, according to a Feb. 13 panel discussion at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.

“The way we account [for] CFE — in fact, the way the industry generally counts CFE — is not actually aligned with the way greenhouse gas emissions are counted for Scope 2 emissions,” said Tanuj Deora, director of clean energy at the White House Council on Environmental Quality.

Scope 2 emissions are the greenhouse gas emissions generated by the electric power purchased by an organization. Scope 1 are the emissions an organization directly owns or controls, while Scope 3 are the emissions produced from sources an organization neither owns or controls, such as from companies in its supply chain.

“One could take actions that result in a 100% CFE score but [with] some emissions being … assigned to the user,” Deora said. “On the other hand, we could actually zero out our Scope 2 greenhouse gas emissions but not actually be consuming only carbon-free electricity.”

Moderating the session, Rhode Island Public Utilities Commissioner Abigail Anthony framed the panel as the beginning of a discussion on the need for “harmonized certificate tracking and emissions accounting systems” for clean energy and emissions reductions. States with and even without renewable or clean energy mandates are affected, Anthony said, as whether or not they have a legal obligation, businesses in a state may have their own clean energy targets.

“I want all my regulator colleagues to understand their role as a market regulator of … generation certificates,” she said. “This is not a conversation we sit on the sidelines of. … Some states are going to need to be able to defend their own claims of emission reductions, and then you need to have systems that allow us to defend those claims legally,” as will corporations doing business in those states.

While not calling on NARUC for an official working group on the issue, Anthony would like to see the organization provide “another space for us to work together to develop standards that would allow the determination of who has what and will allow new products to be developed more easily to enable more complex emission accounting.”

She pointed to PJM’s recent announcement of its new clean energy tracking service that will provide certificates broken down by the hour as an example of the level of detail and innovation that will be needed. (See related story, PJM EIS Announces New Hourly Clean Energy Certificates.)

“It’s really important for us to figure out how to reconcile” these issues, Deora agreed. With more than 300,000 federal buildings across the U.S., the federal government is the country’s largest energy consumer, with a load of about 54 TWh of electricity a year, he said. Producing that much clean energy, at least half of it 24/7, will require accounting standards that are “going to be inclusive of both the statutory requirements across all the states who have their own rules, as well as each individual buyer’s specific targets and goals,” he said.

Betsy Beck, who leads global energy markets and policy for Google, said the company has been procuring enough clean power and retiring the associated renewable energy credits to cover its global operations. But, Beck said, developing accounting standards for its 24/7 goals means “you need to think about the grid at a more granular level.”

“It’s not enough to just balance at a high level,” Beck said. “Now we really need to be thinking about what are the right sources we need to fully decarbonize the grid. It can’t just be building the cheapest renewable energy sources, which have been wind and solar, but what do we need for the carbon-free energy supply in all hours of all days so that we do not need other fossil resources kind of backing renewables up?”

Who Has the Carbon Emissions?

As a member of NEPOOL, Rhode Island uses a relatively straightforward method for emissions accounting based on energy certificates, and not only for renewables, said Todd Bianco, chief economic and policy analyst for the state’s PUC.

“Coal has certificates too, and we follow those certificates to sort of understand what our emissions are,” Bianco said in a Monday phone interview with RTO Insider. “And we use renewable ones to help us calculate how much we’ve reduced emissions from the baseline.”

But, echoing Deora, Bianco said the clean energy and emissions certificates are not aligned.

“Folks have … focused on … the renewable aspect, which is great, but when you try to do the actual carbon emissions, you also have to have the highest fidelity to be able to show, well, who does have those carbon emissions? You’re in a power pool; there’s gas and coal and oil, let’s say, so if you didn’t use them, who did?”

During the NARUC panel, Bianco ran through a few scenarios in which the allocation of certificates could get blurred or just confusing. For example, if two businesses are on the same power system, and one is procuring wind energy and one gets electricity from a fossil fuel plant, who gets the certificates for the clean energy?

If a state agency is just looking at compliance for a renewable portfolio standard, Bianco said, it might use the clean energy credits from the wind-powered business to zero out the greenhouse gas emissions from the firm getting its electricity from the fossil fuel plant.

The agency could make “a legally defensible claim that the state is not evading emissions consistent with our statutory mandate,” he said. “But what would those two businesses tell their investors?

“And that’s where the certificates could go to the next level. Everybody has to agree,” Bianco said. “It’s no longer that I can make my claim in a bubble. Everyone has to agree to how they’re going to measure.”

Common Tool Set Needed

The General Services Administration announced its first 24/7 CFE agreement in November, working with Entergy to provide clean power to federal buildings in Arkansas. Moving ahead, Deora said, the federal government could be modeling its clean energy procurements on corporate practices.

“We’re going to [be] technology neutral, so we’re inclusive of all carbon-free electricity technologies beyond what is traditionally considered renewable,” he said. Nuclear, hydropower and fossil generation with carbon capture will be included.

Federal guidelines released in August also stress “temporal matching” on an annual and hour-for-hour basis, and “locational matching,” so that CFE is generated in the same region or service territory in which it is consumed, Deora said.

Like the federal government, Google is looking beyond wind and solar, Beck said, and the diversity of energy resources is going to make data accessibility and transparency critical for clean energy and emissions accounting.

“Whether your state has an RPS or not, you’ve probably got the federal government in your state; you probably have Google and other large energy customers,” she said. “Sorting out these inconsistences [in emissions accounting] and having systems in place to enable this data and this transparency is going to be critically important.

“We cannot continue figuring out these systems in silos,” Beck said. “Our sustainability goal is not going to be same as the government’s; it’s not going to be the same as the next company’s. But if we have a common tool set, we can use that to achieve our goals, hopefully in a meaningful and transparent way.”

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Texas PUC Rejects CCN for Grid United’s Pecos West

Texas regulators last week denied Grid United’s request to build an intertie between ERCOT and the Western Interconnection, saying they did not have the authority to approve the application.

The Public Utility Commission cited state law Thursday in rejecting a partial certificate of convenience and necessity for Pecos West, a proposed 280-mile, 525-kV HVDC intertie connecting the Lower Colorado River Authority’s (LCRA) system with El Paso Electric (EPE), which sits in the Western Interconnection (53758).

Will McAdams Peter Lake (Admin Monitor) Alt FI.jpgCommissioners Will McAdams (left) and Peter Lake during PUC’s open meeting. | Admin Monitor

PUC staff argued in a preliminary order that state law prohibits the commission from granting Grid United’s request. They said only LCRA and EPE, as owners of the facilities that would be interconnected, can be granted the CCN.

“Grid United Texas does not qualify under [Texas’ Public Utility Regulatory Act] as an entity that could be designated by El Paso Electric or LCRA to exercise the CCN rights reserved to them,” staff said. “Thus, under no circumstance can the commission legally grant Grid United Texas a CCN or any rights emanating from a CCN for the proposed interconnection.”

Houston-based Grid United had sought “partial authorization” from the commission. It said its application was limited to the intertie and not the right to construct or operate the line. Intervening parties supporting the application said state law should not apply because the proposed line is not a transmission facility, but staff rejected that argument.

“Only the owners of the existing facilities to which the proposed interconnection will directly interconnect can be certificated for the proposed interconnection,” they said. Staff pointed out that, as Grid United is not a utility under Texas law, it can’t be designated by either LCRA or EPE to exercise their respective rights to “build, own or operate a new transmission facility.”

Initial ERCOT studies last year determined Pecos West would offer “significant” reliability benefits to the Texas grid, providing new markets for producers and reduced curtailment of renewable resources with “negligible” impact on prices.

At issue, however, is Texas’ right-of-first-refusal law, which was passed in 2019 and is now before the U.S. Supreme Court. Texas last year asked the high court to review an appeals court’s remand back to a district court over the latter’s claim that the ROFR law violates the U.S. Constitution’s dormant Commerce Clause. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

Commissioner Jimmy Glotfelty said he would have preferred to set the docket aside and wait for the Supreme Court’s ruling or further ERCOT studies, but he indicated his hands were tied.

“I think the law, unfortunately, tells me that a right of first refusal is a right of first refusal. And according to this docket at this time, I would have to support the staff’s position,” he said.

Jimmy Glotfelty (Admin Monitor) FI.jpgJimmy Glotfelty reads his statement on Grid United’s CCN application. | Admin Monitor

Glotfelty, who has worked with Grid United founder Michael Skelly in the past, said he struggled with the decision. (See related story, Skelly’s Grid United Quickly Making Waves.) He noted the HVDC tie would provide the state with resilience, reliability and low prices, “three things that our citizens need and that our [legislative] leadership has directed us to improve.”

“There are numerous points in the filings that in my opinion are right on target, and we should be able to permit these types of lines,” he said. “The biggest barrier to HVDC in this case is the [ROFR] law that the legislature has passed. … I want to push this line and other lines, but this law was passed and it’s our job to implement the statute.”

“We’re always looking for ways to increase competition in the market. Competition delivers great results, and we’ve seen that historically,” Commissioner Lori Cobos said. “At this time, the law is just not written to allow this type of construct.”

Grid United withdrew the application on Friday, asking that it be dismissed without prejudice. Spokesperson Ally Copple said the company remains committed to developing Pecos West. It has identified preliminary corridors and hoped for regulatory approvals in 2024. Under that scenario, Pecos West could be operational as early as 2029, Copple said.

“We have reviewed the preliminary order and the relevant statute, and we are confident there are other paths to move the project forward,” she said.

PUC Joins Lawsuit vs. EPA

The PUC agreed to join Texas’ lawsuit before the 5th U.S. Circuit Court of Appeals over the EPA’s rejection of the state’s proposed plan to control emissions that drift into neighboring states. Texas Attorney General Ken Paxton says the agency had “no good reason” to reject the plan (23-60069).

The state is one of more than 20 that, under EPA’s Cross-State Air Pollution Rule (CSAPR) plan, must establish NOx emissions budgets beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations. (See “Staff Defer Comment on CSAPR,” ERCOT Technical Advisory Committee Briefs: July 27, 2022.)

The PUC also agreed to join with the Texas Commission on Environmental Quality in its comments to EPA over its process for developing state plans to reduce greenhouse gas emissions.

Cobos, McAdams Step up at RTOs

Cobos, the PUC’s liaison with MISO, will serve as president of the Entergy Regional State Committee. Comprising state regulatory commissioners from Arkansas, Louisiana, Mississippi and Texas, and members of the New Orleans City Council, the committee provides input on Entergy’s transmission system operations and upgrades in MISO South.

Cobos is also the secretary for the Organization of MISO States, the RTO’s state regulatory body, and sits on the grid operator’s Advisory Committee.

“I can’t say ‘no’ to really big challenges,” she said.

PUC Chair Peter Lake complimented Cobos and Commissioner Will McAdams, the commission’s representative on SPP’s Regional State Committee. McAdams was recently selected to lead the grid operator’s newly created Resource and Energy Adequacy Leadership team and appointed as the RSC’s treasurer.

“You’re both clearly gluttons for punishment,” Lake said.

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Bill Seeks to Promote Clean Aviation Fuel in Washington

A legislative effort to make Washington more attractive to the alternative jet fuel industry has reached the state Senate’s Ways and Means Committee.

The committee scheduled a Feb. 20 hearing on Senate Bill 5447 , which would set a business and occupation (B&O) tax rate of 0.275% for any plant that would produce at least 20 million gallons a year of low-carbon jet fuel. A B&O tax is a tax on a business’ gross receipts, and most B&O rates in Washington range from 0.47% to 0.9%.

Senate Majority Leader Andy Billig (D) and Rep. Vandana Slatter (D) each introduced versions of the bill in their respective chambers. It is a common behind-the-scenes legislative practice to pick one of two similar bills to send to both chambers, while letting the other stall in committee. Billig’s bill was selected to advance further in the legislature.

The Port of Seattle has expressed interest in using jet biofuels at SeaTac International Airport since 2017. Low-carbon biofuels would be mixed with existing petroleum-based jet fuels to reduce their carbon intensity.

The only existing alternative jet fuels plant on the West Coast is near Los Angeles, and the two proposed bills seek to develop a second plant in Washington. A few years ago, the predicted cost of building such a plant was at least $1 billion.

Support for SB 5447 was overwhelming at a Feb. 1 hearing before the Senate Environment, Energy and Technology Committee. Supporters included Alaska Air Group (NYSE:ALK), Delta Air Lines (NYSE:DAL), sustainable aviation fuel supplier SkyNRG, BP America (NYSE:BP), the Port of Seattle, Amazon (NASDAQ:AMZN), Washington State University and the Association of Washington Business.

Their representatives said the aviation fuels sector is difficult to decarbonize, but that the effort is needed to meet the state’s goal to eliminate most of its greenhouse gas emissions by 2050. The low tax rate will attract alternative fuel plants, they said.

At a Feb. 7 hearing before the House Environment and Energy Committee, Darrin Morgan, a representative of Netherlands-based SkyNRG, said: “We’d like a facility to be here in Washington state.”

“We have a chance to capture the market,” Slatter said. “With this bill, Washington would be a leader in this new industry.”

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California Energy Commission Grants $31M to Manufacture Futuristic ZEVs

The California Energy Commission on Wednesday continued its recent practice of making large grants to in-state manufacturers of zero-emission vehicles, including futuristic three-wheeled cars with built-in solar panels and hydrogen-powered big rigs.

The CEC awarded Aptera Motors Corp. $22 million to “produce an affordable solar ZEV that uses the sun to fuel up to a 40-mile daily commute without the need for grid-connected charging,” the agency said in a grant document.

The car’s range on a plug-in charge is up to 1,000 miles in a version with the most battery capacity, Aptera says on its website. Other versions can reach 250, 400 and 600 miles on a charge, the company says.

“That looks like a Jetsons kind of [vehicle]. Is that something that is capable of going freeway speeds?” CEC Chair David Hochschild asked Pablo Ucar, Aptera’s vice president of production and procurement.

The car’s top speed is 110 mph, “so it drives like a real vehicle,” Ucar said. “The reason it is a three-wheeler is because we want it to be the most efficient vehicle in the world. Three wheels are more efficient than four wheels. It is a two-passenger vehicle. It performs and behaves like a regular car on the highway.”

The CEC grant, matched by $26.4 million from Aptera, will pay for installing vehicle production equipment at two manufacturing facilities in Carlsbad and Vista, California, cities in San Diego County.

The vehicle is on preorder and expected to be available to buyers later this year. Aptera plans to produce 20,000 vehicles annually by 2025 and to create 444 manufacturing jobs, the CEC said.

Commissioner Patty Monahan, the lead commissioner for transportation programs, acknowledged Aptera’s car is unlike anything on the road in the U.S. and involves uncertainty. But one of the CEC’s goals is to encourage new concepts in zero-emission vehicles from companies such as Aptera, she said.

“We’re taking calculated risks in terms of really wanting to support innovation in the ZEV ecosystem and recognizing that electrification offers this opportunity to be really innovative,” Monahan said.

The CEC approved a $9 million grant to Symbio North America, with a company match of nearly $11 million, to expand its facility in Poway, also in San Diego County, and to establish a new facility in Temecula, in Riverside County, for hydrogen fuel cell vehicle power systems and vehicle assembly. The expansion will create 63 jobs and establish a hydrogen fuel cell workforce training program in partnership with nearby universities and colleges, the company said.

“These California facilities will assemble regional long-haul heavy-duty fuel cell class 8 trucks and have an annual combined maximum production capacity of 250 trucks and 250 to 300 fuel cell power systems to expedite fuel cell truck deployment in California,” the grant request said.

Hochschild asked Symbio North America General Manager Rob Del Core how the company’s big rigs would compare with battery-powered electric trucks being produced by Tesla and others.

“We’re looking at applications where a hydrogen fuel cell could really dominate in terms of the benefits for things like fast-fueling, long range and of course payload capacity,” Del Core said.

That will include trucks that can travel 400 miles from Southern to Northern California without refueling on a route with 70 mph highway speeds and a winding 4,000-foot mountain pass.

The CEC’s grants are part of a major push to encourage ZEV manufacturing and job creation in California using funds allocated by state budgets in 2021 and 2022.

As of January, CEC staff had recommended 13 projects for funding totaling $199.4 million.

Last month the CEC awarded more than $46 million in grants to four manufacturers of electric tractors, forklifts, car batteries, and charging stations with the intent to bolster in-state production of zero-emission vehicles and equipment.

Ranging from about $8 million to more than $14 million, the grants were among the largest manufacturing subsidies ever granted by the CEC. (See CEC Awards $46 Million for ZEV Manufacturing.)

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PJM MRC/MC Preview: Feb. 23, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

As part of its consent agenda, the MRC will be asked to endorse:

B. proposed revisions to Manual 27: Open Access Transmission Tariff Accounting to conform to the settlement agreement approved by FERC in PJM’s filing to change its administrative cost recovery charges (ER22-26).

C. proposed revisions to Manual 40: Training and Certification Requirements resulting from a periodic review.

Endorsements (9:10-9:20)

3. Manual 6 FTR Bid Limits (9:10-9:20)

PJM’s Emmy Messina will present a proposal to increase the number of bids a corporate entity may submit into FTR auctions, alongside corresponding revisions in Manual 6: Financial Transmission Rights. The committee will be asked  to endorse the proposed solution and associated manual revisions. (See “FTR Bid Limit Increase Endorsed Under Fast Track Pathway,” PJM MIC Briefs: Jan. 11, 2023.)

Issue Tracking: FTR Auction Bid Limits

Members Committee

Consent Agenda (12:35-12:40)

As part of its consent agenda, the MC will be asked to endorse:

B. a proposed solution to implement the second phase of PJM’s hybrid resource rules, along with corresponding tariff and Operating Agreement revisions. (See PJM Releases Phase 2 of Energy Transition Study.)

Issue Tracking: Solar-Battery Hybrid Resources

C. a proposal to revise PJM’s day-ahead zonal load bus distribution factors and corresponding revisions to tariff section 31.7. (See “MIC Endorses Proposal on Hybrid Resources,” PJM MIC Briefs: Nov. 2, 2022.)

Issue Tracking: Day-ahead Zonal Load Bus Distribution Factors

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Nuclear Bill Advances in Washington House

OLYMPIA, Wash. — The House Environment & Energy Committee unanimously recommended Thursday that the full House of Representatives pass a bill to add advanced nuclear reactor technology to the alternative power sources that the state uses to replace fossil fuels.

House Bill 1584, sponsored by Rep. Stephanie Barnard (R), would add advanced nuclear to solar, wind, hydroelectric dams, landfill methane and other sources of non-fossil fuel power sources. Washington is legally required to eliminate 95% of its greenhouse gas emissions by 2050. Barnard represents the Tri-Cities, home of the 1,200-MW Columbia Generating Station nuclear plant, which produces roughly 12% of the state’s electricity.

The owner of the plant, Energy Northwest, supports the bill, as does the Grant County Public Utility District, which is considering building a small modular reactor (SMR) complex within its territory.

Each modular unit would be a mini-reactor capable of generating 50 to 300 MW. SMRs are designed to allow additional modules as needed, with 12 modules being the theoretical maximum. Compared with conventional nuclear, the concept is supposed to result in lower costs, faster construction times and more flexibility in tailoring a reactor complex to its customers’ needs.

Grant County PUD is looking at a design by Maryland-based X-energy but has not decided whether to pursue an SMR.

“We’re looking at advanced nuclear technology because of growth in our county,” Bill Clarke, a lobbyist representing the PUD, told the committee.

NuScale Power of Portland, Ore., became the first SMR developer to receive approval for its 60-MW design by the Nuclear Regulatory Commission. The company plans to submit an improved follow-up version of that design to the commission that includes increasing output to 77 MW each. The company is pursuing building its first complexes in Idaho Falls, Idaho, and Romania by the end of this decade.

Leaders from both Energy Northwest and the Tri-Cities want to attract NuScale to build at the site of two never-completed reactors next to the Columbia plant. That site has infrastructure in place to build either reactors or reactor components.

At Thursday’s committee hearing, Roger Lippman of Nuclear Free Northwest opposed the bill, saying the term “advanced nuclear technology” is not defined in the bill. He added that no advanced nuclear technology plants have begun operating in the U.S., meaning the technology does not have a proven track record.

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FERC Affirms MISO’s Seasonal Auctions, Accreditation

FERC on Thursday rejected two rehearing requests over MISO’s seasonal capacity auction and availability-based resource accreditation, clearing the way for the RTO to conduct its first seasonal auctions in April.

The commission affirmed its previous decision that the seasonal, availability-based accreditation will incentivize availability and more accurately represent when generating units contribute to resource adequacy (ER22-495).

Commissioner Allison Clements, as she did in FERC’s original order last year, disagreed with MISO’s accreditation inputs, saying it “glosses over MISO’s failure to adequately justify key details in its proposal.”

Clements zeroed in on what she called “two of the most problematic design flaws”: MISO’s selection of resource adequacy hours that allow resources up to 12 hours to be counted in its operating reserve margin calculation, and the 24-hour lead time before resources are excluded from being assumed as available during those hours.

“In defense of its position, the only explanation MISO gave is that its choice of a 12-hour lead time was better than an alternative of 24 hours, which would have included even more resources incapable of delivering capacity when needed,” she wrote in a concurring opinion. “But the Federal Power Act is not a ‘Price is Right’ showcase showdown, and the fact that a proposed rate is closer than an unjust and unreasonable option does not demonstrate it to be just and reasonable. One hundred dollars for a gallon of milk is not a fair price, and the fact that $50 is a better alternative does not make it reasonable.”

Clements said MISO’s decision to credit resources that take up to a full day to start up will lead to extending credits for resources that are ineffectual during reliability issues.

“Incredibly, while MISO’s only defense of using 12 hours as the lead time threshold for including resources in its calculation of operating margin is that doing so is more accurate than using a 24-hour lead time, it proposes to use the even-less-accurate 24-hour lead time when determining which resources get credit for delivering capacity,” she said.

FERC last year approved the grid operator’s request to conduct four seasonal capacity auctions, with separate reserve margins, and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours,” covering 65 hours during the year when resource availability is less than 25% of operating margin.

Louisiana and Mississippi regulators, Consumers Energy, Entergy (NYSE:ETR), DTE Energy (NYSE:DTE) and Alliant Energy (NASDAQ:LNT) sought rehearing of the order’s accreditation portion. They said a harsher accreditation based on risky hours that can’t be predicted with certainty will result in fluctuating accreditation values, undue penalties to generation and won’t reflect MISO supply fundamentals. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

DTE and Alliant accused the commission of “cursorily sweeping aside” concerns over accreditation instability. They said the accreditation framework could potentially cause about a “ten-fold increase in year-to-year accreditation volatility for some market participants” and could cause members to overbuild generation on the MISO system.

Entergy noted that according to the RTO’s own analysis, a quarter of all market participants’ total accredited capacity will experience a standard deviation between 7.7% and 15.5% from one planning year to the next in the spring season. Entergy said that translates into a 20% chance that a market participant’s total accredited capacity will “undergo a year-to-year change of 20%.”

The utility said a resource can experience “a significant reduction” in accredited capacity if it is unavailable during “even one or two days.” Mississippi and Louisiana agreed that the design will cause “large swings” in accreditation year over year.

Before last year, MISO accredited its thermal resources annually based on the asset’s historic three-year equivalent forced outage rates.

The commission was unpersuaded by the arguments and said the new accreditation’s benefits still stand to outweigh the small amount of aggregate volatility it introduces across planning resources’ capacity values.

FERC said the accreditation will lead to “increased accuracy, increased confidence in generator availability during high-risk hours, better coordination of resource outages and stronger incentives for resources to be available in times of need.”

The commission disagreed with a coalition of clean energy organizations that said thermal resources shouldn’t have a different accreditation framework from renewable resources. It said resource classes can be accredited using different methods.

The clean energy groups also took issue with MISO’s response should a season not have at least 65 resource adequacy hours. The grid operator will use resource performance data from other high-risk hours throughout the year as a “backfill” to ensure there are 65 resource adequacy hours.

They also said MISO’s proposal to top off the risky hours to make sure it meets a minimum 65 hours, or 3% of a season, “creates an artificial profile for these resources and assumes risk in a season during hours where there are none.” FERC responded that maintaining a minimum target of hours to base accreditation upon “mitigates the volatility concerns.”

The commission also supported MISO’s 120-day advance notice requirement for planned generator outages; a capacity replacement obligation for resources on planned outages lasting longer than 31 days; and the RTO’s plan to treat offline resources with lead times greater than 24 hours as unavailable during resource adequacy for accreditation purposes.

It resisted calls to delay the seasonal launch until the 2024-25 planning year to let market participants get their bearings in the new environment. FERC said market participants have attended stakeholder workshops that warned of the change as far back as 2019.

FERC’s decision arrives as MISO may revise the availability-based accreditation method. The grid operator wants to adjust unit-level accreditation by a capacity value determined by loss-of-load expectation rather than its existing unforced-capacity values that rely on forced outage rates.

The design would apply to all resources and require edits to the new availability-based design. MISO currently uses a unit-level effective load-carrying capability calculation based on a peak hour contribution for wind resources. (See Stakeholders Cry Foul on MISO’s Resource Accreditation Pivot.)

Clements contended that FERC violated the Administrative Procedure Act because it did not respond to arguments that many resources with nearly a full day’s startup time cannot maintain reliability when they’re offline during resource adequacy hours.

She found it “laudable” that MISO is seeking to improve “its outdated capacity accreditation framework. “

“It is clear that … today’s markets must be designed to address increasingly complex reliability challenges. Although MISO’s proposal fell short of the mark, this does not suggest that changes to MISO’s resources adequacy rules are not appropriate. To the contrary, further changes appear necessary,” she said.