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July 7, 2024

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Calif. Looks to Streamline Process for Issuing NEVI Funds

California officials are exploring how to improve the dispensation of hundreds of millions in federal funding to build a public network of electric vehicle charging stations.

At a March 12 workshop, officials from the state’s Energy Commission (CEC) and Department of Transportation (Caltrans) sought feedback on how dispensation worked during the first round of grant solicitations from the National Electric Vehicle Infrastructure (NEVI) program, which aims to build a national network of chargers to encourage EV uptake.

A part of the federal Infrastructure Investment and Jobs Act (IIJA), NEVI will provide $5 billion to states to build 500,000 direct current (DC) fast chargers that will enable data collection, reliability and long-distance travel in zero-emissions vehicles. California’s share of the funding is expected to be $384 million allocated over five years (See Federal Plans to Electrify Highway Corridors Advancing.) 

The first tranche of funding was released in October 2023 and awards are expected to be granted in late April. The second round of funding is slated to be released in August, and applications are due by November to the Joint Office of Energy and Infrastructure.  

The workshop provided an opportunity for the CEC and Caltrans to present and solicit feedback on the proposed structure and requirements for the second NEVI grant funding opportunity based on comments received about the first solicitation.  

Structure of the Plan

EV charging projects must meet basic requirements to be eligible for NEVI funding. Key among them is the requirement for stations to be publicly available, located no more than one mile from a highway designated as an “alternative fuel corridor” and placed no more than 50 miles apart from each other. The stations also must contain at least four DC chargers of at least 150 kW per port.

Under the 2023 California NEVI Deployment Plan, designated highway corridors are broken into segments containing one or more charging stations. Groups of corridor segments then are identified by geography and ranked to fund the highest-priority areas first. Only private entities, including investor-owned utilities, are eligible to bid into the competitive solicitations to build, own and operate charging stations.

Speaking at the workshop, Jane Berner, strategic investment analyst at the CEC, identified 21 corridor groups in California ranked by characteristics that determine whether the segment is high-priority, including the percentage of the corridor located in a disadvantaged or low-income community, the number of chargers needed along the corridor to complete the 50-mile range requirement and whether the area interlaps with tribal land.

NEVI requires that at least 50% of funded chargers be in disadvantaged or low-income communities and at least 40% in Justice 40 communities, those that are marginalized by underinvestment or overburdened by pollution.  

California’s first solicitation awarded $40,500,000 in grants to six corridor groups. The second round of solicitations offers $110,220,000.

At the workshop, planners discussed two options for establishing corridor groups in the second round: two-part and standalone projects. The two-part project plan would involve breaking 16 corridor groups into priority-based halves. Participants would complete one application to build stations in as many corridor groups as they choose and could be awarded up to three areas. This approach offers available funds more manageably and enables faster deployment and advanced planning, Berner said.  

The standalone option is smaller, involving application to only one corridor group, which could enable a larger applicant pool, Berner said.  

Ranking the corridors by the two-part project structure, a group consisting of Bay Area interstates and I-80 to Sacramento received the highest score, followed by Southern California I-8 and I-10 to the state’s eastern border, and Northern coastal corridors.  

Stakeholder Feedback

Kristian Corby, deputy executive director of the California Electric Transportation Coalition, asked to work with the CEC and Caltrans on utility verification forms — required to inform the level of grid readiness for a project site — to ensure utilities can respond to the volume of forms in a timely manner.

“PG&E got something like 70 requests for completing that form in the lead-up to the past solicitation deadline,” Corby said. “That type of inundation is very difficult for the utilities to process quickly and to give the applicants good information, so we’re working on some recommendations for that.” 

Corby also was concerned that allowing participants to choose between higher- and lower-ranked groups in the two-part project structure would leave out some areas, though he suggested lower-priority groups could be offered as standalone projects.  

“This does open up, I think, the risk that we might get some particularly lower-ranked corridors that maybe no one applies to,” Berner said. “We’ll have to figure out how we’ll handle that case and it think it would probably be that we would just handle them separately.”  

The CEC and Caltrans are developing California’s 2024 NEVI deployment plan. Comments on the plan are due March 25.

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Granholm Receives Chilly Reception at CERAWeek 2024

HOUSTON — A year ago, attendees at S&P Global’s CERAWeek warmly greeted U.S. Energy Secretary Jennifer Granholm with a standing ovation for her role in passing the Inflation Reduction Act (IRA) and its $369 billion in energy security and climate change investments. 

Granholm’s CERAWeek audience offered only tepid applause during her annual appearance March 18, an apparent response to the Biden administration’s January permitting pause for new LNG terminal projects. 

Acknowledging the elephant in the room, CERAWeek Chair Daniel Yergin began his interview with Granholm by asking her, “The LNG pause: What is it and what isn’t it?” 

She responded by pointing out the pause was enacted to study the environmental effects of approved LNG projects. The U.S. remains the world’s largest LNG exporter at 14 million Bcf, Granholm said. She said an additional 12 million Bcf is under construction and 48 million Bcf has been authorized, with an additional 22 million Bcf authorized but waiting on final investment decisions. 

“This pause does not touch any of that. This is just a pause to see what the future could bring,” Granholm said. “We have a responsibility under the Natural Gas Act to approve authorizations for LNG if they are in the public interest. This study is like other studies we’ve done in the past, just assessing where we are so that we can move forward.” 

Turning to Yergin, she said, “Dan, I predict that when we sit here next year — she says with confidence — this will be well in the rearview mirror.” 

Noticing the muted response in the ballroom, Granholm added, “I think that’s an applause line.” 

U.S. Sens. Joe Manchin (D-W.Va.) and Dan Sullivan (R-Ala.) piled on later during appearances with Yergin and in a visit to the media center. 

U.S. Sen. Joe Manchin | © RTO Insider LLC

“The pause needs to be paused,” Manchin said, calling the move a “political gesture” and saying the environmental study has not yet been conducted. 

He noted LNG production has gone from nothing in 2016 to 14 million Bcf today and natural gas prices are still $2/MMBtu or less. 

“I’m afraid that the market will be shorted here. The United States consumer will pay more, or the economy in the United States could be threatened. None of that’s ever been discussed,” Manchin said. “The pause has to be stopped until the facts of what we’re dealing with support the target. You just don’t throw a curveball and scare the bejesus out of the markets and our allies.” 

Sullivan said the pause was the talk of last month’s Munich Security Conference, where he co-led a bipartisan group of a dozen U.S. senators. He disputed recent comments Granholm made before Manchin’s Energy and Natural Resources Committee, when Sullivan said she “essentially said our allies weren’t that concerned [about the pause].” 

“That’s not what we’re hearing in Asia and in Europe. Every ally that we spoke to [in Munich] had major concerns about the Biden administration’s LNG moratorium. I mean, the most senior German officials, [European Union] officials, everybody,” he said. “It’s not the time to be taking away one of the most critical weapons that we have provided our fellow allies in Asia and in Europe, and that’s American energy. A lot of us think it’s about domestic politics, but it’s having serious consequences with regard to our national security and the national security of our allies.” 

The pause is driving interest and potential investment in countries like Qatar, Sullivan said. In a letter he co-wrote with three other Republican senators intended for John Podesta, the administration’s senior adviser for international climate policy, Sullivan said the Middle Eastern country plans to expand its LNG production, which could result in control of 25% of the global market by 2030. 

U.S. Sen. Dan Sullivan | © RTO Insider LLC

Noting that Russia reached out to Germany after the pause’s announcement, Sullivan said, “That is exactly the opposite of the policies that we’ve been trying to undertake in a bipartisan way after the brutal invasion of Ukraine, which is to enable our allies to get off Russian oil and gas. This is a strategy that is upside down in terms of what we’re trying to do as a country.” 

Granholm and the senators did reach common ground on improving the energy infrastructure permitting process. a task that sometimes seems insurmountable. 

“We keep talking about getting a permitting bill, we keep trying to have it, but it’s hard to get cooperation,” Granholm said. “There is some bipartisanship around permitting reform and moving quickly. We’re doing what we can on the executive side.” 

As an example, Granholm said, the administration has instituted a two-year “shot clock” permitting transmission on public lands.  

“We’d love to see that kind of shot clock for all kinds of permitting in the U.S.,” she said. 

Asked about his energy committee’s objectives for the rest of the year, Manchin, who chairs the committee, said, “I’ve got to get permitting done. I’m doing everything we can. We want to get it done. And I think people are concerned about it. We are so close.” 

Manchin said he enjoys not just the administration’s support, but the support of all stakeholders. 

“Everybody’s supportive,” he said, “but what happens is everybody is supportive of any good idea, but they end up letting the perfect be the enemy [of the] good.” 

“It’s critical to the country, critical to every state,” Sullivan said of the reform. “You talk to any mayor in America, you talk to any governor in America, it doesn’t matter what party, they know that it’s killing us that it takes some nine years to permit a bridge. It’s imperative that we get it done, and I do think there’s a political will. It just makes sense.  

“There’s a whole bunch of ways in which we can tighten up our permitting system that makes our country stronger and all our research development projects … so I’m going to keep pressing it as long as I’m in the U.S. Senate.” 

Back in the ballroom, Granholm said the IRA, described last year as a “big carrot,” is being “gobbled up voraciously” by investors.  

“It’s just amazing how the tax credits are doing the work of reshoring manufacturing and making that happen,” she said, reminding attendees that the IRA is also a jobs program. “It’s really so gratifying to see that we now have an industrial strategy in this country and that we’re not just going to be passive bystanders to the loss of manufacturing jobs.” 

She also announced the release of DOE’s latest Pathways to Commercial Liftoff report, focused on geothermal energy, and the new Regional Energy Democracy Initiative. REDI is meant to empower communities to work with businesses, community groups, academic institutions and philanthropists to “weave” equity and justice into DOE-funded clean energy projects. 

The initiative will begin with a pilot program along the Texas and Louisiana Gulf Coast but could expand with DOE’s plans to award more than $8 billion for carbon-reduction and clean energy infrastructure projects.  

“Ultimately, we have two clear goals: first, meet the needs of today, and second, move quickly and intentionally for the realities of tomorrow,” Granholm said. “It’s a question of will. I know there may be some in this room who would prefer to wait and see or to maybe push the burden of tackling climate change onto others. But let’s be clear. Consumers are calling for change. Communities are calling for change. Investors are calling for change.” 

Granholm called on her audience to help manage the transition “responsibly and with urgency” and to provide opportunities for investors, communities and workers. She said they have the power to increase their companies’ investment returns and “heal our planet.” 

“But make no mistake, what we are witnessing now, what we are participating in, is historic,” she said. Dropping a reference to the musical “Hamilton,” Granholm closed by saying, “You are going to be able to tell your grandchildren that you were in the room where it happens. It is a once-in-a-lifetime challenge and a once-in-a-lifetime opportunity.” 

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Calif., Quebec, Wash. to Explore Linking Carbon Markets

Washington state could be closer to joining the California-Quebec carbon market after the three governments issued a statement March 20 saying they will explore linking their cap-and-trade systems. 

The announcement came about a year after Washington held its first quarterly auction of carbon allowances following its cap-and-invest program’s launch in January 2023.  

California implemented cap-and-trade in 2013, followed by Quebec in 2014, with the two subnational governments merging their systems in 2014. Advocates of adding Washington to the mix cite the expectation that a larger market would increase liquidity in allowances and reduce costs for businesses and other organizations needing to meet greenhouse gas reduction targets.  

“Linking the California-Quebec carbon market and the Washington carbon market would enhance the ability of all three jurisdictions to work together to develop and implement cost-effective programs to fight climate change, while allowing each jurisdiction to maintain authority over its own program’s design and enforcement,” the March 20 statement said. 

In a linked market, allowances issued by each government could be used by businesses in any of the three jurisdictions to comply with their emissions caps.  

“The three jurisdictions would host joint auctions, and market participants could trade across jurisdictions — so allowance prices would be the same across the jurisdictions,” the statement said. “Each government would retain authority over their respective programs, but businesses would gain access to a larger pool of allowances.” 

‘Mutual Interest’

Wednesday’s joint statement notes the three jurisdictions already are cooperating by “sharing best practices regarding program design and implementation” through their membership in the Western Climate Initiative. A shared market would deepen that cooperation significantly.

“Though Washington has formally expressed interest in joining the California-Quebec carbon market, today’s joint statement is the first time that all three governments have expressed their mutual interest in forming a shared market,” Caroline Halter, spokesperson for the Washington Department of Ecology, which oversees that state’s program, told NetZero Insider via email

Details around integrating the markets will have to be hashed out among the three governments. 

“The three jurisdictions are following their respective processes to explore linking carbon markets. If the three jurisdictions enter into an agreement to link, linkage would then be attained through updates to regulations adopted by each jurisdiction,” the statement said. 

Washington already has advanced on that front. Last month, lawmakers in both Democrat-controlled houses passed a bill along party lines to align the state’s carbon market regulations with those of the California-Quebec market. While Republicans warned against linkage, House Majority Leader Joe Fitzgibbon (D) argued that New York, Massachusetts and Maryland are watching Washington’s efforts with the idea of creating their own cap-and-trade programs to eventually join the bigger market. (See Bill to Link Wash. Cap-and-trade with Calif.-Quebec Passes Both Houses.)  

The earliest the proposed linkage could take place is 2025. Lurking in the background is a Republican-backed November referendum in Washington on whether to repeal cap-and-invest, which critics have blamed for the state’s relatively high gas prices. 

In the auctions held last year, Washington carbon allowance (WCA) prices ranged from $48.50 to $63.03, reaching levels significantly above those in the California-Quebec market. But the first auction of 2024 held earlier this month saw prices for WCAs drop sharply to $25.76, well below the clearing price of $41.76 in the most recent California-Quebec auction.  

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MISO Members Send off OMS Leader Hawkins to Wisconsin PSC

DALLAS — Outgoing Organization of MISO States Executive Director Marcus Hawkins appeared before the RTO’s Advisory Committee for a final time before starting as a member of the Wisconsin Public Service Commission. 

At the March 20 Advisory Committee meeting, Chair and Indiana Utility Regulatory Commissioner Sarah Freeman jokingly introduced Hawkins as OMS’ “short-term” executive director. 

Wisconsin Gov. Tony Evers (D) appointed Hawkins to the Wisconsin PSC the previous week. Hawkins’ term begins April 8 and runs until March 1, 2027. 

“The OMS executive director has resigned his position effective April 5,” Hawkins said to laughter while delivering a final report before the committee. 

Hawkins said he hopes OMS has a “challenging task” ahead of it in selecting a candidate from a qualified pool. 

“If you want, reach out to me. I have some unique insights into that position,” he joked. 

“You have moved OMS forward, and you have left it in a better place than you found it. … You have taken it to a different level,” Robert Kuzman, MISO’s head of stakeholder relations, told Hawkins, eliciting applause. Kuzman added he’s eager to work with Hawkins in his new role. 

“We look forward to continuing our work together,” Freeman seconded. 

OMS is accepting applications for a new executive director through March 29. 

Hawkins has been with OMS since 2016, joining the organization as its director of member services and advocacy. He was promoted to executive director two years later. Before his time at OMS, Hawkins was a senior engineer at the PSC and a program manager and engineer at the Wisconsin Energy Conservation Corp. 

Hawkins holds a bachelor’s in nuclear engineering and a master’s in mechanical engineering from the University of Wisconsin-Madison. 

In a statement at the time of the announcement, Hawkins said he was proud to return to the commission “during such a critical time of rapid change in the utility industry.” 

Hawkins’ appointment occurs two months after Wisconsin’s GOP-controlled Senate refused to confirm former Public Service Commissioner Tyler Huebner’s PSC nomination, though he had been performing duties unconfirmed for four years until that point. The Senate’s refusal to confirm Huebner continues a pattern of Republican senators rejecting Evers’ picks to state commissions and boards. (See Wisconsin Senate Votes to Fire Commissioner Huebner 4 Years into Job.) 

Hawkins will exit the organization before OMS holds its annual Resource Adequacy Summit on May 14-15 in Ames, Iowa, in partnership with Iowa State University. Until his departure, Hawkins will continue to organize the summit. 

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ISO-NE to Study Offshore Wind Points of Interconnection

Building on its 2050 Transmission Study, ISO-NE plans to study the effects of shifting two offshore wind points of interconnection (POIs) from Maine to Massachusetts and analyze regional offshore wind interconnection points, the RTO told its Planning Advisory Committee (PAC) on March 20. 

The 2050 Transmission Study found the transmission upgrades to meet the region’s projected 57-GW 2050 peak load will cost $22 billion to $26 billion. One key constraint identified by the study was the region’s ability to send power from renewables in Maine and New Hampshire south to meet load in the Boston area. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

These results are partially contingent on where ISO-NE has modeled offshore wind projects connecting to the grid, locations that are hardly set in stone. 

The finalized Gulf of Maine Wind Energy Area released March 15 (see BOEM Designates Gulf of Maine Wind Energy Area.) is located farther south than ISO-NE initially expected, with much of the lease area “as close, or closer, to Boston as it is to Maine,” Dan Schwarting of ISO-NE told the PAC. 

In response to stakeholder feedback, ISO-NE is proposing to essentially rerun the 2050 Transmission Study with two POIs shifted from Maine to Massachusetts to see if it would reduce the scale and cost of transmission upgrades.  

“These changes result in very little change in the mileage of offshore cables but are expected to significantly reduce stress on the Maine-New Hampshire and North-South interfaces,” Schwarting said.  

Schwarting added that ISO-NE does not expect the changes to eliminate the need for north-to-south upgrades, but that the RTO anticipates “at least some of the upgrades would fall off the list.” 

Additionally, ISO-NE will conduct a “high-level screening of various offshore wind points of interconnection” to provide general information on transmission constraints at different POIs and outline “how much offshore wind can realistically be interconnected into different parts of New England before major transmission upgrades are required.” 

This analysis will be based on loads projected for 2033, instead of projections out to 2050, given the uncertainty of projecting generation and load data beyond 10 years. While the 2050 Transmission Study modeled offshore wind at reduced output levels “to ensure that load could be reliably served during low-wind peak conditions,” the POI screening will study wind projects at their full nameplate capacity. 

ISO-NE will study the POIs up to a capacity of 2,400 MW to determine “an approximate maximum interconnection size before major transmission upgrades are required.” 

While ISO-NE’s loss-of-source limit constrains single points of interconnection to 1,200 MW, the RTO is leading an effort with PJM and NYISO to study raising the limit to 2,000 MW. 

ISO-NE is planning to study sites independently and then consider combinations of feasible POIs to see which can be used concurrently and which are “mutually exclusive,” Schwarting said. 

Schwarting emphasized that the screening “is not a full interconnection study and does not replace the need for such a study.” 

Several stakeholders supported the proposals but cautioned that transmission-system constraints are just one factor in the selection of a POI.  

“There’s a whole lot that goes into interconnecting offshore wind at a particular site,” said Dave Burnham, director of transmission policy at Eversource. “[ISO-NE] is really only looking at a sliver at what it’s going to take.” 

Bob Stein of Signal Hill Consulting Group said moving interconnection points from Maine to Massachusetts could bring political challenges due to the local economic benefits that are expected to accompany POIs. 

“There’s a potential political problem with what good engineering suggests we should do,” Stein said. 

ISO-NE is asking for stakeholder feedback on the proposal by April 4, and anticipates results “at some point in quarter three of 2024.” 

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BOEM Proposes Second OSW Auction in Gulf of Mexico

The federal government is teeing up a second wind energy auction in the Gulf of Mexico. 

The U.S. Bureau of Ocean Energy Management on March 20 proposed a lease of four areas totaling 410,060 acres off the Texas and Louisiana coastlines.  

The proposed sale notice will be published in the Federal Register on March 21, triggering a 60-day public comment period in which BOEM hopes to receive feedback on the size and location of the proposed lease areas, and on potential lease revisions to include hydrogen production with the electricity generated there. 

Also, BOEM is considering lease stipulations requiring that historically underserved communities be considered and engaged early and often in the development process. 

If BOEM decides to go through with this second auction, it would publish a final sale notice. 

BOEM and some industry observers had expressed optimism for the first Gulf of Mexico wind auction, in August 2023, but it drew minimal interest. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

Only one of the three lease areas offered drew bids, and the winning bid by RWE Offshore US Gulf was just $5.6 million — much less than winning bids submitted for lease areas off the Atlantic and Pacific coasts. 

August 2023 was not a good time for the emerging U.S. offshore wind industry — early movers off the Northeast Coast were struggling mightily with supply chain, financial and infrastructure constraints. 

But beyond that, the Gulf of Mexico presents challenges of its own: weaker winds, softer seabed geology and an annual hurricane threat. 

After the first Gulf auction fizzled, research firm Clearview Energy Partners flagged other factors for its clients: Electricity is relatively inexpensive in the Gulf Coast region and there is not a strong push by state leaders to get electrons flowing from sea to land. 

Production of green hydrogen might be a key motivator for offshore wind development in the region, Clearview wrote, but at the time, the IRS had not issued guidance on the Inflation Reduction Act’s clean hydrogen tax credit. 

The IRS has since issued proposed guidance and may finalize it before a second auction. This could offer developers a clearer picture of the potential economics of offshore wind in the Gulf. 

BOEM said it would use new, more efficient software for the second Gulf auction.  

BOEM Director Elizabeth Klein said in a news release: “We look forward to receiving feedback from tribes, other government agencies, ocean users, local communities and others to minimize any impacts to natural and cultural resources, reduce potential conflicts with ocean uses, and maintain a healthy marine ecosystem.” 

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Automakers Get More Time, Flexibility in EPA’s Final Vehicle GHG Rule

WASHINGTON — EPA still wants U.S. automakers to cut greenhouse gas emissions from their light-duty vehicles almost in half by 2032, but the agency’s final rule released March 20 aims to give the industry more time and flexibility on how to reach that ambitious target compared to the proposed rule issued in May.

Whereas the proposed rule predicted electric vehicles would comprise 67% of new car sales by 2032, the final rule sees a broader mix, with about 56% EVs and 13% plug-in hybrid electric vehicles (PHEVs), according to a senior administration official speaking on background. The rule covers the model years 2027 to 2032.

In addition to light-duty vehicles (LDVs) — passenger cars, SUVs and light trucks — the rule also calls for a 44% reduction in emissions from medium-duty vehicles (MDVs), defined as delivery trucks and vans weighing between 8,501 and 14,000 lbs.

At a rollout event in D.C., EPA Administrator Michael Regan hailed the final rule as “the strongest vehicle pollution technology standard ever finalized in the United States,” targeting GHG emissions of 85 g ― just under a fifth of a pound ― per gallon for LDVs by 2032.

“This technology-neutral and performance-based standard gives the auto industry the flexibility to choose the combination of pollution control technologies best suited to their customers,” Regan said. “Whether it is battery electric, plug-in hybrid, advanced hybrid or cleaner gasoline vehicles, we understand that consumer choice is paramount.”

John Bozzella, Alliance for Automotive Innovation | EPA

EPA’s current LDV standard for 2026 is 168 g/gallon, edging up to 170 g/gallon in 2027 before tapering off to 85 g/gallon by 2032 ― a decrease of 17 g/gallon per year. The 2032 target for MDVs is 274 g/gallon, down from 461 g/gallon in 2027.

The “multipollutant emission standards” also will result in a 95% decrease in tiny particulate matter, commonly referred to as PM2.5, which has been linked to heart and lung disease, according to EPA. Nitrogen oxides and other pollutants are expected to drop 75%.

Promoting the final rule, Regan, President Joe Biden and other administration officials have repeatedly said major cuts in vehicle emissions will not mean higher costs for consumers, lost jobs in the auto industry or snowballing effects on the economy in general.

“These technology standards … will avoid more than 7 billion tons of carbon pollution,” Regan said. “That’s four times the total carbon pollution from the entire transportation sector in the year 2021.”

Those reductions will translate to “fewer hospital visits and premature deaths … fewer illnesses like lung cancer and heart disease,” he said.

In a statement from the White House, Biden said the new rule would allow the U.S. to meet his “ambitious target that half of all new cars and trucks sold in 2030 would be zero-emission … and race forward in the years ahead.”

Citing the billions of dollars in private investments announced for new EV and EV battery manufacturing plants ― buoyed by tax incentives in the Inflation Reduction Act ― Biden said the U.S. “will lead the world in autos, making clean cars and trucks, each stamped ‘Made in America.’”

National Climate Advisor Ali Zaidi also stressed the benefits for workers, consumers and the economy. “On factory floors across the nation, our autoworkers are making cars and trucks that give American drivers a choice — a way to get from Point A to Point B without having to fuel up at a gas station. From plug-in hybrids to fuel cells to fully electric, drivers have more choices today. Since 2021, sales of these vehicles have quadrupled, and prices continue to come down.”

Zaidi noted that U.S. drivers now can choose from more than 100 EV and PHEV models.

EPA estimates reduced emissions will generate $99 billion per year of economywide benefits, including $13 billion in public health savings from improved air quality and $62 billion in lower fuel, maintenance and repair costs for consumers. The average savings for individual consumers buying EVs are estimated at $6,000 over the life of the  vehicle.

Not a Rollback

When released in April 2023, the proposed rule triggered immediate pushback from many in the auto industry, mostly based on its call for a sharp ramp-up in EV sales beginning in 2027.

Albert Gore III, Zero Emission Transportation Association | EPA

With EV sales not increasing as fast as some automakers had predicted, the industry has been pumping the brakes on how quickly it will get new EV models to market.

During a recent earnings call, General Motors CEO Mary Barra said her company is targeting 200,000 to 300,000 EV sales for 2024 and is considering introducing a PHEV model for certain markets, all depending on consumer demand. GM’s last PHEV, the Chevy Volt, was discontinued in 2019.

Administration officials, however, framed the changes to the final rule not as a rollback resulting from industry pressure, but as a way to make the rule more robust and durable. The fast increase of EV sales envisioned in the proposed rule had been based primarily on computer models, a senior official said. The final rule leverages data from automakers and dealers, which indicated the same result in emission reductions could be achieved if the industry had a longer lead time and more flexibility in the mix of vehicles that automakers  would produce.

It also takes into account increased efficiency and lower emissions resulting from technological advances in gas-powered cars.

The more industry-friendly rule didn’t pass muster with Sen. John Barrasso (R-Wyo.), who criticized the rule and the Biden administration as out of touch and “trying to force Americans into expensive electric vehicles they don’t want, don’t need and can’t afford.”

“Republicans will fight to overturn the Biden car mandate and put Americans back in the driver’s seat,” Barrasso said.

Speaking in D.C., John Bozzella, president and CEO of the Alliance for Automotive Innovation, was more conciliatory, acknowledging he had been a thorn in the administration’s side for months, advocating for changes in the rule.

“Automakers are committed to electrification, and we want this transformation to EVs … to succeed over the long haul,” he said. “The reason we had strong views on the feasibility of the original proposal and what it required in terms of EV sales is because we know the challenges of [a] choppy EV sales market, public charging still coming online, new supply chains that must be built, all while preserving a customer’s ability to choose the vehicle that works for them and their families. …

“Our message was not whether this can be done ― it can ― but how fast can and should it be done,” he said.

Albert Gore III, executive director of the Zero Emission Transportation Association, noted that the best-selling car in the world in 2023 was electric, Tesla’s Model Y. Tesla also claimed the top four spots on Cars.com’s American-Made Index, with its models Y, 3, X and S.

“We have everything we need today in terms of technology and know-how to meet and exceed this standard,” Gore said. “And if all the manufacturers [at the event] dedicate themselves to meeting and exceeding these goals, like America always does, we will firmly secure our future in a position of global leadership.”

The PEF Calculation

Getting a jump on EPA, the Department of Energy on March 19 also released a final rule on the petroleum equivalent fuel (PEF) calculation, which is a measure of the “fuel efficiency” of EVs; that is, the amount of petroleum-based fuel needed to produce the same amount of energy an EV uses

How the PEF is calculated is important — and political — because it is used by EPA in determining automakers’ compliance with the Corporate Average Fuel Economy (CAFE) standards — the federal fuel efficiency levels for automakers. The calculation first was set in the 1980s and has been reviewed periodically, most recently in 2000.

In 2021, the Sierra Club and the Natural Resources Defense Council petitioned DOE to update the two-decade-old calculation. “By overstating the miles per gallon equivalent of any EVs in automakers’ fleets, the prior calculation enabled automakers to continue to sell far more [gas powered vehicles],” the Natural Resources Defense Council said in a press release welcoming the new calculation.

“The old calculation included a multiplier of nearly seven that significantly inflated the calculated fuel economy of electric vehicles. DOE’s final rule phases out the multiplier while updating other data used in the calculation with more current figures,” NRDC said.

The Sierra Club noted that the PEF calculation “is wholly separate and has no impact on compliance” with EPA’s final vehicle emissions standards.

The updated PEF calculation is based on a complicated formula taking into account factors such as average electricity generation and transmission efficiency and average petroleum refining and distribution efficiency.

The PEF is measured in watts-hours per gallon. The current standard, 82,049 Wh/gallon, will be in effect through the end of 2026. DOE’s final rule ramps down the PEF to 79,989 Wh/gallon in 2027 and bottoms out at 28,996 Wh/gallon in 2030 and beyond.

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PJM Monitor Finds Markets Overall Competitive

Average load-weighted electricity prices in PJM fell by about half in 2023, the Independent Market Monitor said in its annual State of the Market Report, finding the lower prices came largely from a drop in natural gas prices that reversed a record-high spike last year.

The decrease brought real-time load-weighted LMPs to an average of $31.08/MWh in 2023, down from $80.14 the previous year. In a briefing ahead of the March 14 report, Monitor Joe Bowring said the correlation between declining electricity and natural gas prices demonstrates PJM’s markets are working to translate lower fuel costs into savings for consumers. (See PJM Monitor: Rise in Fuel Costs Led to Record-high Prices in 2022.) 

Bowring said it’s unclear how the March 12 ruling from the 3rd U.S. Circuit Court of Appeals partially vacating FERC’s order permitting PJM to revise the reliability requirement for the DPL South zone will be implemented and how it may affect prices. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

The Monitor’s report found PJM’s energy and capacity markets were competitive in 2023, though local and aggregate markets within both had the potential for market power to be exercised, and the capacity market design’s effectiveness was mixed. The regulation and financial transmission rights markets both were found to have flawed market designs limiting competitiveness, and while the reserve markets performed well, some subzones saw high supply concentration. 

In the local energy market, transmission constraints created opportunities for market power, and the Monitor said not all resources that fail the three-pivotal-supplier (TPS) test are being properly mitigated to their cost-based offers. 

“The goal of competition in PJM is to provide customers reliable wholesale power at the lowest possible price, but no lower. The PJM markets have done that. The PJM markets work, even if not perfectly,” the Monitor wrote. 

The Monitor identified future economically and policy driven generation retirements as a leading challenge PJM will have to face, with up to 58 GW of generation at risk of deactivation through 2030. But Bowring said the actual number may be lower if a drop in the number of resources available to offer capacity leads to higher prices. If clearing prices double in coming auctions and a portion of the economic retirements are delayed, he said the number of resources going offline could be about 43 GW. PJM’s February 2023 “4R’s” report found about 40 GW of generation is at risk. (See “PJM White Paper Expounds Reliability Concerns,” PJM Board Initiates Fast-track Process to Address Reliability.) 

“PJM stands by the estimates in our 2023 report, ‘Resource Retirements, Replacements and Risks,’ which documents that 40,000 MW of generation are at risk of retirement by the end of this decade. The IMM’s higher at-risk retirement numbers are the result of more conservative assumptions,” spokesperson Jeff Shields said. 

“Our greatest concern remains the pace at which new generation projects are getting built once the PJM process is complete. Currently there are approximately 40,000 MW in new generation projects that have been cleared for interconnection by PJM but are not being built; a number of a factors outside of PJM’s influence, including siting, financing and supply-chain, continue to hold up the completion of projects.”

Bowring said several changes to PJM’s rules around resource deactivations could correct market signals and limit costly reliability-must-run (RMR) contracts. Because transmission needs aren’t a factor in the reliability metrics used to determine Base Residual Auction procurement needs, he said it’s possible for a generator to not clear the auction and file for deactivation only to be told it’s needed to prevent transmission issues. 

The cost of retaining a generator on an RMR contract can be steep; Bowring said the cost-of-service recovery rate for Indian River Unit 4 has been about 10 times the capacity revenues the 410-MW coal unit would have received since its RMR contract began in June 2022.

PJM’s practice of counting resources operating under an RMR contract toward reliability procurement targets in the capacity auction also could be suppressing market signals incentivizing generation needed for long-term resource adequacy. 

Shields said PJM’s notification requirements for deactivating resources and its compensation structure for RMR contracts is under discussion at the Deactivation Enhancements Senior Task Force. 

“We hope that the IMM will continue to work with us and capacity market participants to ensure that all market-seller costs, including risk, are includable in market offers so that economically viable resources can recover their costs and therefore remain in service,” he said. 

Bowring argued that an ongoing stakeholder process to facilitate transferring capacity interconnection rights from a deactivating resource to replacement generation under the same ownership should be rejected and PJM instead should use any transmission headroom freed up by resources going offline to advance the interconnection of any planned resources that could resolve transmission violations that may be caused by the deactivation. 

The report urged PJM to analyze the amount of firm gas capability in its region while expecting much of the needed new capacity will come from gas-fired generation. While it notes there is more than 200 GW of intermittent generation in the interconnection queue, the report argues that based on historical completion rates and capacity derates, that will amount to about 11 GW. 

“PJM and federal and state regulators cannot hope to balance supply and demand without first having a clear and reasonably accurate measure of both existing and expected supply and demand. Providing clear information to regulators and market participants about the actual and expected supply-demand balance is essential so that decisions about market design, about the timing of environmental regulations, about pipeline siting and about transmission siting can all recognize the likely impact on the balance between supply and demand and therefore reliability,” the report says. 

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Key Energy Bills Win Crossover Votes in Md. General Assembly

Maryland’s House of Delegates on March 18 approved an ambitious plan for introducing time-of-use (TOU) rates for residential customers of the state’s investor-owned utilities, but only after provisions for a default, opt-out introduction of TOU was amended to a voluntary, opt-in program.  

The Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act (H.B. 1256) instead calls for the state’s Public Service Commission (PSC) to conduct a study of the impacts of the voluntary TOU program, determine whether a default rate would be justified and deliver a report to the General Assembly by Dec. 31, 2027. 

As originally drafted by Del. David Fraser-Hidalgo (D), H.B. 1256 was intended to combine the default TOU rates with incentives for distributed renewable energy technologies to promote electrification of homes and transportation, while also promoting load management and flexibility to minimize impacts on the grid as electricity demand grows.  

The bill was one of several pared-down energy bills that passed in the House or Senate on or before March 18, the General Assembly’s “crossover day,” when bills introduced in one house must be approved and sent on for a committee hearing and possible vote in the second house.

One example, Del. Lorig Charkoudian’s (D) H.B. 505, would have prohibited the state’s utilities from including the costs of any lobbying, political activities, membership fees or sponsorships in industry trade groups in their rates. Maryland is one of 11 states that have been considering such legislation to curb utilities’ political spending with their customers’ funds. (See Utilities Facing Increased Scrutiny Over Political Activities.) 

Those provisions were crossed out in the amended version of the bill, which the House passed 99-38 and was sent to the Senate Committee on Education, Energy and the Environment. But in an interview with NetZero Insider, Charkoudian said the bill’s remaining provisions still would provide consumer savings and utility accountability. 

Specifically, H.B. 505 would require Maryland utilities to become members of PJM, rather than join voluntarily. Under FERC rules, voluntary members get a 50-basis-point return on equity adder, which, Charkoudian said, translates to an extra $20 million in costs for the state’s consumers. Mandating membership in state law would save consumers “a significant amount of money,” she said. (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) 

The other remaining section of the bill would require utilities to submit yearly reports to the PSC, detailing all their votes at RTO meetings, regardless of whether the proceedings and voting records already had been reported publicly. 

Another Charkoudian bill, H.B. 1112, would allow the PSC to require the state’s utilities to acquire or contract for utility-scale energy storage projects if the commission finds storage to be a more cost-effective and efficient alternative to a reliability must-run (RMR) contract to keep a power plant running past its planned retirement date. 

Charkoudian sees the bill as a new way to respond to situations like the potential closure of the Brandon Shores coal-fired power plant in 2025 and PJM’s efforts to keep the plant open with an RMR until 2028. PJM recently rejected the idea of storage as an alternative solution, as proposed in a recent report from GridLab and Telos Energy. (See PJM Rejects Storage as Alternative to Brandon Shores RMR.) 

Passage of H.B. 1112 could provide a new option for Maryland, Charkoudian said. “We could spend all this money on reliability must-run, and [at] the other end, all we have is more greenhouse gas emissions and more pollution. Or we could take that very same money and spend it on battery storage, and we get the same reliability.” 

But, she acknowledged, even if the PSC were to decide that storage would be a better option, PJM still would have to sign off on it.  The bill passed 101-37 and was sent to the Senate Committee on Education, Energy and the Environment.  

Other Bills Crossing Over

S.B. 1, sponsored by Sen. Malcolm Augustine (D), would require the state’s retail electricity providers that offer “green power” to their customers to document whether they actually are selling electricity generated by a renewable power project or the renewable energy certificates (RECs) from a project that could be located outside the state. 

To offer green power, a retail supplier must show that the electricity being provided is at least 51% from renewables or RECs or at least 1% more than the amount of clean power required under the state’s renewable portfolio standard. For 2024, the state’s RPS calls for about 37% of Maryland’s power to come from renewables, but Gov. Wes Moore (D) has committed the state to 100% clean power by 2031.

Retailers also would have to have visible disclosure statements on their websites, explaining the purchase of a REC would not necessarily mean renewable energy also has been purchased.  

The green power provisions are part of a larger bill focused on regulation of retail power suppliers. S.B. 1 passed in the Senate 33-14 on March 8 and was referred to the House Committee on Economic Matters. 

Fraser-Hidalgo also is a lead sponsor on H.B. 689, which would replace Maryland’s $3,000 excise tax credit for electric or fuel cell vehicles with a rebate of the same amount, which auto dealers would provide at the point of sale. The original bill would have limited rebates based on consumers’ income, but those requirements were stripped out. The bill also includes $1,000 rebates for electric motorcycles and $2,000 rebates for three-wheeled motorcycles or “autocycles.” 

The bill passed 103-36 on March 18 and has been referred to the Senate Committee on Budget and Taxation.  

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Industry Sends Back NERC Cyber Monitoring Standards

In a 20-day ballot period that ended March 18, industry stakeholders voted down NERC’s proposed reliability standard that would require entities to implement internal network security monitoring (INSM) on certain cyber systems.  

As a result of the ballot, which saw the proposed CIP-015-1 receive a 48.52% segment-weighted vote for approval — a two-thirds majority is required for passage — the standard will be sent back to the standard drafting team for Project 2023-03 for revision. Future ballot periods for the standard may be shortened in accordance with a decision by NERC’s Standards Committee at its February meeting to authorize reducing additional comment and ballot periods to as little as 10 days. (See NERC Committee Greenlights Shortened INSM Comments.) 

The SDT created CIP-015-1 after a previous proposed standard, CIP-007-X (Cybersecurity — systems security management), failed to pass its initial comment and ballot period in January with only a 15.42% segment-weighted approval. Due to feedback received during that comment period, team members said they felt creating a new standard would “ensure that the purpose and requirements [of the standard] are clear and allow for future expansion if necessary.”  

Although this technically was the first ballot for CIP-015-1, NERC elected not to form a new ballot pool, keeping the same stakeholders that voted on CIP-007-X. The project’s page on NERC’s website said no changes will be made to CIP-007, which “will revert to the currently enforced version,” CIP-007-6. 

Respondents generally were supportive of breaking out the security monitoring requirements into a new standard, although some commenters asked why the SDT hadn’t gone further. James Keele and Gail Golden, both representing Entergy, pointed out that “other standards already require [cybersecurity] monitoring,” naming CIP-003-8 (Security management controls), CIP-005-7 (Cybersecurity — electronic security perimeter(s)), CIP-007-6 and CIP-010-4 (Cybersecurity — configuration change management and vulnerability assessments). 

Keele and Golden suggested the SDT consolidate the security monitoring requirements from those standards into the new standard as well. An unnamed commenter representing the Tennessee Valley Authority shared similar sentiments — though only mentioning CIP-007 and CIP-003 to be consolidated — as did Alain Mukama from Hydro One Networks. 

Keele and Golden also expressed reservations about requirement R1 of the proposed standard, which provides guidance to help registered entities “identify network data collection location(s) and method(s) by implementing a risk-based approach focused on network security risks.” Their comments said the wording of the requirement was not “clearly aligned with expectations in the measures [section of the standard] and the technical rationale,” putting entities at risk of being found noncompliant in audits. 

“The wording of CIP-015-1 R1.1 … appears to provide entities the latitude to identify [data collection locations and methods] based on risk, but without an expectation of an exceedingly robust methodology and without an expectation to consider all possible network data collection locations,” Keele and Golden said. “The requirement should be updated to … start with a list of all/many [network monitoring] locations and apply well-defined risk criteria … against that list to arrive at the final locations subject to the program.” 

Cain Braveheart, writing on behalf of the Bonneville Power Administration, also suggested the requirement’s language “leaves it open for auditor interpretation” and “some level of deference must be offered to an entity’s risk management approach,” or that NERC should “create auditor guidance on what a risk-based approach looks like.” He also asked the SDT “clarify the term ‘locations’ in the requirement, adding context currently only found in the technical rationale.”  

NERC’s Standards Committee will hear an update on Project 2023-03 at its upcoming meeting on March 20; the SDT will meet the following day to consider its next steps. The ERO considers the INSM effort a high-priority project because FERC has ordered it to submit standards requiring INSM by July 9 of this year. (See FERC Orders Internal Cyber Monitoring in Response to SolarWinds Hack.)