SEATTLE — EPA on Wednesday announced it is distributing nearly $1 billion in grants to 389 school districts across the U.S. to buy cleaner buses, most of them electric.
Made available by the Infrastructure Investment and Jobs Act, the funding targets school districts in all 50 states, D.C. and U.S. territories, with a focus on assisting low-income, rural and tribal areas. Wednesday’s awards are the first in a five-year, $5 billion program created by the law.
The initial grants will help support the purchase of more than 2,400 clean school buses to “accelerate the transition to zero emission vehicles and produce cleaner air in and around schools and communities,” EPA said in a press release.
Vice President Kamala Harris joined EPA Administrator Michael Regan and Washington Gov. Jay Inslee at Lumen Field, home to the NFL’s Seattle Seahawks, to announce the funding. Harris pointed out that 25 million U.S. children take buses to school each day, but that “95% of our school buses are fueled with diesel fuel, which contributes to very serious conditions that are about health and about the ability to learn.”
Harris said the new buses would reduce incidences of childhood ailments such as asthma. She also cited reducing greenhouse gases and the economic boost to local industries involved in building the buses as additional reasons for the appropriations.
“Our electric school bus program really does represent an intersection of all these points, on top of the importance of investing in domestic manufacturing,” the vice president said. “We all know when, during the height of the pandemic, we saw what it means when we don’t have domestic manufacturing around things we need every day; it slows us down.”
“Not only does this stop climate change, but its stops asthma in our kids because they don’t have to breathe in diesel smoke,” Washington Gov. Jay Inslee told the audience.
EPA originally allocated $500 million for the 2022 grants, but it received so many applications that it almost doubled the pool of money available, Regan said. Ultimately, EPA distributed $913 million to 389 districts to purchase 2,463 buses, he said.
In Washington state, four school districts received a total of about $2.7 million. Each of them — Easton, Pomeroy, South Whidbey Island and Toppenish — are rural areas.
And while rural school districts dominated the national list of recipients, some large metropolitan ones, such as Atlanta and New York City, won among the largest rewards of about $9.9 million each.
“Those school districts who received an award can now proceed with purchasing new buses and eligible infrastructure,” EPA said in its announcement. The agency said it is partnering with the U.S. departments of Energy and Transportation to provide recipients “with robust technical assistance to ensure effective implementation.”
In a statement, Sue Gander, director of the Electric School Bus Initiative at the World Resources Institute, said the EPA program “marks a huge step forward in efforts to equitably electrify the nation’s school bus fleet. We are excited that school districts from coast to coast, large and small, urban and rural, will be receiving one or more electric school buses, including in twelve states and Washington, D.C, that previously had none on the way.”
Gander also had advice for bus makers. “For any manufacturers who are wondering about where to focus their investments, today’s announcement demonstrates loud and clear that the future is electric. It is time to step up and scale up production and job training for an inclusive transition.”
“Today’s announcement is the result of years of advocacy by families, students and community members seeking federal funding to facilitate their local school districts investing in a clean ride for kids,” Carolina Chacon, coalition manager for the Alliance for Electric School Buses, said in a press release. “These new electric buses will eliminate dangerous toxins in the air our children and communities breathe and reduce climate-harming pollution. For students and drivers, this means quieter rides, better health and fewer missed days of school or work due to preventable respiratory illnesses.”
Regan said EPA will soon establish a $1 billion pool to take another round of applications for clean bus grants. “Improving lives of young children around the country is near and dear to the EPA’s mission,” he said.
Global use of fossil fuels will peak by 2030, but to reach a worldwide net-zero economy by 2050 — and keep the increase in the global average temperature to 1.5 degrees Celsius — clean energy investments must double to $4 trillion per year at the same time, according to the International Energy Agency’s World Energy Outlook 2022.
The current worldwide energy crisis, triggered by Russia’s invasion of Ukraine, has become “a turning point in the history of energy by accelerating clean energy transitions,” Fatih Birol, IEA’s executive director, said during an online launch event for the report Thursday. “We are seeing an unprecedented increase in different clean energy options — solar PV, wind, batteries, heat pumps, nuclear power, energy efficiency — in all of them.”
Further, Birol said, “the biggest driver of renewable energy in many parts of the world is energy security, not necessarily climate commitments as it was before.” Climate commitments are still important, he said, but another key factor is that “many governments want to be part of the new industrial era based on clean energy manufacturing.”
Just taking into account current stated policies, IEA projects, the world’s energy supply will depend increasingly on renewables, mostly wind and solar, by 2030. | IEA
Birol pointed to the passage of the Inflation Reduction Act in the U.S.; the EU’s REPowerEU initiative to cut the region’s dependence on Russian fossil fuels by 2030; and Japan’s Green Transformation as evidence of a historic pivot in clean energy policy and investment.
Those policies and investments will trigger a series of turning points in the coming decade, said Laura Cozzi, IEA’s chief energy modeler. “What’s happening is very clear: Clean energy technologies, solar in particular, are becoming very cheap. Supporting policies like the IRA are really helping to make solar even cheaper.
“The expectation is that in the next five years, [global] solar installed capacity will surpass that of coal to become the No. 1 capacity installed for electricity generation,” she said.
Overall, clean energy technologies, including nuclear, will surpass electricity generation from all fossil fuels by the end of the decade, Cozzi said. “We will see a peak in electricity sector emissions very soon, and emissions will start to decline,” she said.
Laura Cozzi, IEA | IEA
The report does see a near-term increase in fossil fuel use and emissions as countries around the world scramble to provide secure, affordable energy for their citizens, and Russia loses its dominance as the top exporter of fossil fuels. Worldwide inflation also means that an estimated 75 million people who recently gained access to electricity will not be able to afford that power, raising the number of people living without electricity for the first time since IEA started tracking those numbers, the report said.
“With energy markets remaining extremely vulnerable, today’s energy shock is a reminder of the fragility and unsustainability of our current energy system,” the report says. “Today’s energy crisis has underscored that, in practice, the future of energy markets is likely to be disjointed, subject to geopolitical friction and prone to regular market imbalances” — in other words, messy.
Synchronizing Change
The report lays out three scenarios for the pace and scale of the global energy transition between now and 2050, based on current stated energy policies (STEPS), the announced pledges countries made at or after the 2021 U.N. Climate Conference in Glasgow (APS) and a net-zero energy goal (NZE).
The STEPS scenario results in a 2.5-degree Celsius temperature increase by 2050 versus an increase of 1.7 degrees in the APS scenario. The NZE scenario hits 1.5 degrees in 2050 and edges down to 1.4 degrees by 2100, the report says.
Ramping up clean energy investment, especially in emerging and developing economies, will be critical for closing those gaps, Birol said.
Emerging market and developing economies, other than China, account for two-thirds of the global population, but their share of clean energy investment is both low and declining, IEA says. | IEA
Looking toward the upcoming 27th U.N. Climate Conference of the Parties (COP27) in Sharm El Sheikh, Egypt, next month, he said, “It is time for advanced economics, so-called ‘rich’ countries, to show that they are serious about climate change by providing support for the clean energy investment in developing countries, especially in Africa. … I would like to see strong support of advanced economies for African or in general developing countries’ energy transitions, and having empathy for the political, economic and social priorities of the countries in Africa and beyond.”
The report also offers a list of recommendations for minimizing some of the bumps and turmoil of the coming years, beginning with a close synchronization of changing investments in clean energy and fossil fuels.
Tim Gould, IEA | IEA
“For the next few decades, at least, we will be drawing down a system based on fossil fuels and building one up based on clean energy,“ said Tim Gould, IEA’s chief energy economist. “But we need both parts to function well for the duration of that transformation. … The speed and security of the transition depends on synchronizing changes across the different parts of the energy system.”
At present, for every dollar spent on fossil fuels, $1.50 is spent on clean energy, Gould said. Getting to net zero does not necessarily mean no further investments in fossil fuels, he said, but rather a very different ratio, with clean energy getting $9 in investment for every $1 in fossil fuels.
“Under those circumstances we have choices about how we choose to guard against the possibility of future volatility,” he said.
Flexibility Quadrupled
Still another core element in the transition will be the role of governments in providing “strategic direction” for markets, the report says, noting that current markets “may not be configured to deliver net zero at lowest cost to consumers.
“One early task for governments is to eliminate distortions and barriers that actively hinder energy transitions, such as lengthy permitting procedures, unnecessary trade barriers, inefficient fossil fuel subsidies and outdated market arrangements that favor incumbent producers and technologies,” the report said.
A price on carbon is one solution. “Governments have to take the lead in ensuring secure energy transitions, but they can be significantly assisted by well functioning markets and market mechanisms that reflect the costs of pollution, by bringing in private capital and allocating it efficiently,” the report says.
Other recommendations in the report include:
prioritizing energy efficiency and demand management. Efficiency is critical now and going forward as houses, cars and other infrastructure built today will still be in use by 2050, the report says. Beyond lowering household electricity bills, efficiency “also brings energy security benefits, especially at a time when the world is moving towards a decarbonized energy system, by reducing strains on fuel markets and the need for costly and uncertain investments in new supply.”
investing in flexibility. Increasing electrification and electricity demand, coupled with increasing amounts of variable renewable energy on the grid, will require a quadrupling of flexibility by midcentury, the report says. Batteries and demand management are expected to provide a quarter or more of the needed flexibility.
fostering climate resilience of energy infrastructure. The increasing frequency and intensity of extreme weather events means that “governments need to act to ensure that the system has the ability to anticipate, absorb, accommodate and recover from adverse impacts,” the report says. Noting that both natural gas plants and solar panels are less efficient at high temperatures, the report says, “making reliable climate and weather data publicly available could help energy suppliers better understand potential climate risks and impacts.”
Pacific Gas and Electric said Thursday it would incur $100 million in costs from this year’s Mosquito Fire, two days after regulators proposed fining the company $155 million for 2020’s deadly Zogg Fire.
The potential losses from the Mosquito Fire were reported in PG&E’s third-quarter earnings report to the Securities and Exchange Commission and discussed in an earnings call Thursday.
The Mosquito Fire began Sept. 6 in the Sierra Nevada foothills about 50 miles northeast of Sacramento. It burned through nearly 77,000 acres, mainly in the El Dorado and Tahoe national forests, and destroyed 78 structures.
The U.S. Forest Service launched a criminal investigation of PG&E for its role in starting the fire and seized utility equipment near the ignition point, including a PG&E transmission pole. PG&E previously told the California Public Utilities Commission (CPUC) that it had recorded “electrical activity” on the suspect line when the fire started.
PG&E CEO Patti Poppe said Thursday the wildfire costs would be covered by insurance.
“We added the Mosquito Fire to our CPUC reportable ignitions greater than or equal to 100 acres,” Poppe said. “Though the investigation is not complete, we can see that the fire started near the base of our 60-kV steel pole … [and] we booked a liability for the Mosquito Fire of $100 million, which is well within our range of insurance.”
On Tuesday, the CPUC proposed fining PG&E $155.4 million for the Zogg Fire, which killed four people including a mother and her young daughter who were overtaken by flames while fleeing the blaze.
The fire started Sept. 27, 2020, when a gray pine tree fell onto a PG&E distribution line in rural Shasta County, the California Department of Forestry and Fire Protection found. It burned 56,000 acres and destroyed more than 200 structures.
A contractor working for PG&E had failed to remove the pine tree even though it was leaning dangerously toward the power line and had shallow roots, a federal judge overseeing PG&E’s criminal probation said in a February 2021 hearing. The line that the tree struck had remained energized even though PG&E had ordered widespread public safety power shutoffs in the surrounding area because of high winds, the judge learned.
“I think it was reckless, maybe criminally reckless, for PG&E to have left that tree, that gray pine looming,” Judge William Alsup said in the hearing. “It was leaning at a 60-degree angle over that line. Gray pines … have a shallow root system. That tree had also been burned earlier. That tree was a clear and present danger to the line, and whoever made the decision to leave that tree up should be looked at very carefully. And PG&E did leave it up.”
The CPUC said in its proposed order Tuesday that the utility had failed “to remove two trees [including the gray pine] previously flagged for removal due to a combination of poor recordkeeping, poor communication, and lack of caution. Juxtaposing PG&E’s failure to remove the trees with [an arborist’s report] — showing that the tree was clearly likely to fall — demonstrates a high degree of culpability in PG&E’s conduct.”
After the CPUC finalizes its order, PG&E will have 30 days to request a hearing or to agree to pay the penalty and submit a corrective action plan. The plan must show that PG&E has a system in place to keep track of trees slated for removal.
The actions against PG&E for the Zogg and Mosquito fires are the latest in a series of financial penalties, criminal convictions and payments to wildfire victims related to catastrophic fires started by PG&E equipment in the past five years.
The wildfires included the Northern California wine country fires of October 2017; the Camp Fire, which killed at least 84 people and leveled the town of Paradise, in November 2018; the Kincade Fire, which tore through Sonoma County in October 2019; and the nearly 1-million-acre Dixie Fire, the state’s second largest wildland blaze, which raged for months in 2021.
The company filed for bankruptcy protection in January 2019 following the Camp Fire and emerged from Chapter 11 proceedings in June 2019, after agreeing to pay a total of $25.5 billion to fire victims, insurance companies and local governments for the wine country fires and the Camp Fire.
PG&E reported third-quarter earnings of $456 million (21 cents/share), compared with losses of $1.09 billion (.055 cents/share) in Q3 2021. Its stock closed at $15.60 on Thursday.
New Jersey’s Board of Public Utilities (BPU) on Wednesday approved a $16.15 million allocation of funds from the Regional Greenhouse Gas Initiative to create the state’s first program designed to promote the installation of fast chargers for medium- and heavy-duty (MHD) electric vehicles.
The program, which includes an emphasis on smaller owner-operator trucking companies located in overburdened communities, will provide incentives of up to $225,000 for the purchase and installation of up to six direct current fast chargers (DCFCs).
With a two-pronged focus, the program aims to stimulate the development of community charging stations — those in locations where they could serve several trucking companies — and private fleet chargers, to incentivize trucking companies to go electric.
Saying that the state until now had no MHD incentive programs, the order creating the program said it “could help remove a key electrification obstacle for businesses” in environmental justice areas.
“A significant portion of MHD vehicles are independently owned and operated, and since investment in charging infrastructure is often cost prohibitive, there is a need to provide publicly accessible MHD charging for those vehicles near their base of operations and along their travel routes,” said the order, which the board approved unanimously.
Growing EV Fleets
The initiative comes as the BPU seeks to reduce transportation emissions, which account for 42% of the state’s emissions, with a particular focus on the trucking sector’s large contribution.
The state’s multipronged effort includes a June 2021 straw proposal to design a program to promote the development of charging sites for MHD electric trucks and ensuring they are distributed across the state in line with the needs of trucks, buses and other users. No final program has yet been released, and the design process is ongoing.
Other initiatives to get more EV trucks on the road include the state Department of Environmental Protection’s adoption in December of EV truck sales targets, and the New Jersey Economic Development Authority’s (EDA) two-year-old NJ Zero-Emission Incentive Program (NJZIP). The program, which the EDA said in July had funded the purchase of more than 150 light- and medium-duty trucks, awards vouchers to help buy an electric truck.
Pamela Frank — CEO of ChargEVC-NJ, an advocacy group that champions electric vehicle policies — said the state “certainly benefits from electrification of the MHD segment, and the linkage with this program and EDA’s ZIP program makes good sense.” Frank has in the past expressed concern that the state is not moving fast enough to promote heavy-duty electric vehicles.
“We need an all-hands-on-deck approach to tackle premium costs for these vehicles, which are declining, especially with respect to the lighter delivery trucks; and the costs associated with responsible grid integration,” she said.
Under the program announced Wednesday, the “BPU will develop new or enhance existing programming enabling low- and moderate-income households, particularly those in environmental justice communities, to participate in and benefit from the state of New Jersey’s efforts to improve access to clean transportation.”
The program will fund up to 100% of the purchase and installation costs of DCFC chargers with a capacity of 150 kWh or greater for community charging stations, to a maximum of $225,000 with no more than six chargers per location. To be eligible, the recipient must be located in or operating in an overburdened community.
New Jersey defines overburdened communities as any census block in which at least 35% of the households qualify as low-income; at least 40% of residents are minorities; or at least 40% of households have limited English proficiency. They account for about 4.7 million people, or slightly more than half the population of the state.
“The goal of the community charging track of this program would be to identify areas with a significant presence of, or interest in growing the operation of, electric MHD vehicles,” the order said. “The optimal locations for community chargers are those that are accessible by several local businesses that have or are interested in acquiring MHD EVs, such as warehouses or depots, with preference given to those that can demonstrate close proximity to businesses that currently own or operate MHD EVs.”
Initiatives under the private fleet charging sector would be eligible for incentives to cover 75% of the purchase and installation of DCFCs to a maximum of $175,000 and a cap of six chargers per location. The chargers in that case would not be required to be accessible to the public. Incentives in the fleet program will only be available to private fleets that have been awarded funding under the state’s NJZIP program and are either in an overburdened community targeted in the first phase of the program or have received an incentive that has been enhanced because of its location in an environmental justice area.
“The optimal locations for community chargers are those that are accessible by several local businesses that have or are interested in acquiring MHD EVs, such as warehouses or depots,” the order says, adding that there would be “preference given to those that can demonstrate close proximity to businesses that currently own or operate MHD EVs.”
Trucker Reluctance
New Jersey truckers have been slow to embrace EVs, however. Like those around the nation, they cite the lack of heavy-duty charging sites as a key obstacle to greater use of electric trucks. Other barriers cited by truckers in the past include the limited number of truck models available, the short range of existing electric trucks — which for larger trucks is about up to 250 miles — and the high cost of the vehicles.
The EDA, in line with the New Jersey Energy Master Plan, is seeking to transition 75% of the state’s medium-duty trucks and half of its heavy-duty trucks to EVs by 2050.
The NJZIP program, which is now in its third year, initially awarded purchase vouchers only for the purchase of light and medium trucks located or to be used in Newark or Camden, both of which are overburdened communities, or within 10 miles of the two cities. Newark is also next to the Port of New York and New Jersey, into which thousands of trucks drive each day.
The program was later expanded to include New Brunswick, in Central New Jersey, and to include communities in and around the Jersey Shore. The EDA allocated funds of $24.25 million to award vouchers of between $25,000 and $100,000 for the purchase of trucks of size Class 2B through Class 6. But the EDA in July expanded the program, adding $46.6 million in funds and for the first time awarding incentives of up Class 7 and Class 8, the largest in use, and a maximum incentive of $175,000. (See NJ Adds $46.6 Million to Electric Truck Incentives.)
Public Service Enterprise Group (NYSE:PEG) and three trade groups told the New Jersey Board of Public Utilities (BPU) on Friday that utilities should play a greater role in owning and operating storage facilities than the one allowed under a proposal by the agency.
During an over three-hour hearing into the storage plan that attracted 300 participants, PSEG pushed back on the BPU’s plans to limit utility participation in order to encourage private investment and ownership of the new facilities that the state hopes to develop as part of its plan to have 2,000 MW of storage in place by 2030.
The BPU’s proposed Storage Incentive Program (SIP), released on Sept. 29, would go to privately owned and operated storage, consistent with New Jersey’s “restructured competitive market structure.” But “there will also need to be a robust effort by EDCs [electric distribution companies] to ensure that the grid is capable of connecting storage devices at the distribution and transmission levels,” the proposal says.
“Thus, while the New Jersey SIP does not propose to allow for utility ownership or operation of devices, EDCs will play a key role in building the grid infrastructure necessary to enable the effective dispatch of energy storage devices,” it says.
“So it wouldn’t be just ‘OK, the utilities can just install and ratebase’” the development of new storage, explained Paul Heitmann, a BPU staffer who presented the proposal at the hearing.
But a PSEG representative argued that given the “urgency” of reaching the state’s goal, utilities should be able to do more under the plan.
“We believe that the board needs to use every available resource to meet this challenge,” said Kate Smith, managing counsel for PSEG’s state regulatory group. “And we respectfully suggest that the these goals may not be feasible without more participation from the EDCs and that the EDC should be a resource that should be more a part of this New Jersey SIP solution now.”
Smith said the utility believes “that we need to be more of a part of these solutions from a utility deployment standpoint.” She noted that PSEG in 2018 filed a proposal for the utility to develop 35 MW of storage. That plan, in which PSEG proposed to spend $180 million, is still pending, and the utility has agreed to put it on hold while the BPU develops its policy.
“We don’t believe that the goals expressed here, and the plan that’s put forth here, are mutually exclusive to utility investment,” Smith said. “We think that the EDCs can support and complement private investment.”
Storage is ‘Critical’
The hearing, the first of three to be held on the SIP, is part of the BPU’s effort to jumpstart the development of a storage sector after several years of inactivity. The next meetings are on Nov. 4 and 14.
The state Energy Master Plan in 2019 said the state would need 9 GW of storage capacity to manage its clean energy goals, and the state Clean Energy Act, enacted in 2018, said that the BPU should create a process for putting 600 MW of storage in place by 2021 and 2,000 MW in place by 2030. Yet the state today has only about 500 MW in place, much of which is decades old. (See NJ Lagging in Energy Storage Progress.)
The SIP sets a target of building 1,000 MW of four-hour-plus storage by 2030 and is part of a two-pronged approach to reaching the 2,000-MW goal. The remaining 1,000 MW would come from the Competitive Solar Incentive (CSI) program, which is designed to provide incentives for grid-scale solar projects, along with co-located storage. Final rules for the CSI program are expected to be released this year.
Storage is widely seen as a paramount element needed to manage electricity supply without relying on fossil fuel as intermittent renewables increasingly dominate the resource mix.
“Whether it’s the board’s energy [plan], or New Jersey’s Energy Master Plan, or any number of other pathways to 100% clean energy, energy storage is really a critical element in keeping the grid balanced and making sure that we can do the clean energy transition on time and on budget,” Abe Silverman, executive policy counsel for the BPU, told the hearing.
The BPU’s plan would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.
Speaking at the hearing, Sarah Steindel of the New Jersey Division of Rate Counsel said the BPU needs to closely monitor the cost of the plan and look beyond ratepayers for funding, such as federal infrastructure money and private research funding.
“We need a plan for how much we’re going to spend on this, including the costs of utility infrastructure, and how much measurable non-speculative benefits we’re going to get from this,” she said. “The board’s well aware that many ratepayers are already stressed. They’re already paying for solar, offshore wind, nuclear subsidies” and electric vehicles. “And we need to think carefully about the money we’re spending and how we’re spending it.”
Seeking an Additional Utility Role
Other speakers also said they were not convinced that allowing solely private investment in storage would enable the state to reach its storage targets, and they advocated for utilities to be able to participate more.
“Given the magnitude of the state’s storage goals — in addition to efforts for electric vehicles, energy efficiency, peak demand reduction, renewable targets, and the need to ensure reliability and resiliency — EDC ownership should remain a viable option because of the expertise and knowledge the EDCs have about their unique systems,” said Christopher Wehr, staff analyst for FirstEnergy (NYSE:FE), parent of Jersey Central Power & Light. “And they’re kind of best suited to identify the areas where these strategic investments will provide the benefits to customers.”
That view was echoed by trade groups including the New Jersey Utilities Association, the New Jersey Alliance for Action and New Jersey Energy Coalition. Allison McLeod, public policy director for the New Jersey League of Conservation Voters, encouraged the BPU to look for an additional role for the utilities, saying that “their participation could be a valuable resource to the board and to the overall efforts to electrify.”
Too Little Support Early on
Other speakers focused on the allocation of incentives in the proposal.
Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), questioned the impact of what the SIP proposal describes as a “declining block structure” for allocating incentives. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower incentive rate. BPU officials say the system would enable the agency to assess the demand for incentive’s to build storage capacity at certain rates and adjust it if there are too few applications at particular levels.
Elias said that SEIA is concerned at the “size and cadence of the capacity blocks.”
“Backloading most of the capacity to later years and later blocks means that a single grid supply project, for instance, could eat up the entire capacity” for a year, he said.
Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said he also believes that there needs to be more incentives in the first two years of the program. In addition, his organization is concerned by the SIP’s plan to allocate incentives to develop three times as much storage from grid projects as from distributed energy projects. Given that the BPU plans to secure half of its storage development from solar-tied storage in the CSI program, which would also come from grid-scale projects, the state is giving too little focus on the distributed energy sector, Rawling said.
“There should be a much greater emphasis on distributed” energy storage, he said. With “distributed generation, there’s a lot of pent-up demand ready to go. So this can quickly be deployed to meet the goals.”
WASHINGTON — Decarbonizing the hardest-to-decarbonize industries will likely involve some failures, said Geraldine Richmond, the Department of Energy’s undersecretary for science and innovation.
“We have to accept that some things are going to fail, that things are not going to go out as fast as we want. But that’s because we’re moving hard and we’re trying to do the best we can,” Richmond said at Resources for the Future’s Net Zero Economy Summit on Thursday. “But if you don’t take those risks, you’re not going to get anywhere. … So, we’re just going to have to suck it up and keep going. It can’t stop us.”
Tackling industrial decarbonization is now widely recognized as essential to U.S. and global efforts to cut greenhouse gas emissions to net zero by 2050, and it has become a regular part of the agenda for any clean energy conference. At RFF’s event, discussions ranged from steel and cement to international aviation.
During an industrial decarbonization panel, both Richmond and Alan Krupnick, industry and fuels program director at RFF, argued for the value of the lessons learned from failure. Krupnick pointed to the Petra Nova carbon capture project, a much hailed project at a coal plant in Texas, which received about $190 million in DOE funds and closed down in 2020.
Referring to funding for carbon capture in both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, Krupnick said, “Even failures can provide us learnings. … What we have to do … going forward, we have to expect failure. We have to learn from it and then move forward.”
The DOE’s Earthshots initiative is aimed at solving some of the core challenges of industrial decarbonization, such as the Hydrogen Shot’s goal of cutting the price of green hydrogen to $1/kg within the decade and the Industrial Heat Shot’s effort to reduce emissions from industrial heat processes by 85% by 2035.
The goal, Richmond said, is “to take everything from a discovery science all the way to the applied science and demonstration, so they can pass them off to deployment.”
Each of the shots has a goal, she said, that has “in mind a cost, has in mind efficiency, has in mind stumbling blocks that we have to get over in order to make progress. In the past the Department of Energy hasn’t been as coordinated as it is right now with regards connecting the discovery science to the applied science. … Now we’ve gotten tight; we’re rolling so that we can make sure that the discoveries get all the way to deployment.”
‘A New DOE’
With the midterm elections looming, Krupnick said the DOE is creating challenges of its own in its effort to get the IIJA and IRA funds out the door as quickly as possible “before the possible change in control of Congress and before a possible change in the presidency to the Republicans.”
Referring to the DOE’s recent funding announcement for hydrogen hubs, he said, “we’ve taken the discipline of the market in making decisions across technologies, and we’ve moved it basically to DOE, [which] has to pick winners out of let’s say there might be 30 or 25 hydrogen hub proposals, and only a fraction of that will get go/no-go decisions for the next round. … It puts a lot of responsibility on DOE to make correct choices.” (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)
Still another factor in the funding process is President Biden’s Justice 40 initiative, which requires that 40% of the benefits from federal funding go to low-income and disadvantaged communities.
“It’s important for us to make sure that we are putting these facilities in places that have had their factories shut down,” Richmond said. “So, we’re really paying a lot of attention to that, whether it means we’re thinking about putting a nuclear plant where there was a coal mine so that it provides jobs for workers in that place.
“It’s a new DOE,” she said. All basic science programs at labs and universities that apply for funding “must put [in] a plan on how you’re going to be inclusive in your operation. … That means the students that you’re going to train for the future, those that have been marginalized, those that have been left out in the past because they couldn’t afford to, for example, go to graduate school, you have to show what you are going to do to get those students into the workforce.”
Cement
Sean O’Neill, senior vice president of government affairs for the Portland Cement Association, an industry trade group, talked up his organization’s roadmap to make the cement and concrete industry net zero by 2050. The processes involved in making cement require high temperatures, generally provided by coal and carbon capture utilization and storage which “is a critical part” of the PCA’s roadmap, O’Neill said. “We cannot reach our goals without CCUS,” he said, while also noting that the industry is experimenting with other, lower-carbon fuels, such as biomass and natural gas.
But the one thing O’Neill says his members are not talking about is cutting back on production, particularly in light of the need for cement and concrete for infrastructure projects funded by the IIJA. “It’s not a conversation we’re having,” he said. “The conversation that we’re having is how can we continue to meet infrastructure needs in this country, in the world, while also looking to decarbonize the process.”
One example, he said, is Portland limestone cement, which has a higher limestone content and lower carbon intensity than traditional cements. But the industry is still struggling to get it included in project specifications, O’Neill said. Instead of “prescriptive specifications” for big infrastructure projects, he called for “performance-based specifications … [that] will drive the market for our low-carbon cement and concrete.” (See Challenges Loom for Decarbonizing Concrete.)
Looking ahead, O’Neill said the industry is focusing on “what can we do to ensure there is a market for these materials. A lot of it has to go to standards and specifications. … At the end of the day, a contractor or owner who’s going to be constructing an asset, they want to have the confidence that the lower-carbon concrete that they’re using to build whatever they’re building will perform.”
Aviation
International aviation is notoriously hard to decarbonize “because lightweight liquid transportation fuel is pretty tough to beat when it comes to the challenge of lifting a heavy aircraft off the ground,” said Annie Petsonk, assistant secretary for aviation and international affairs at the U.S. Department of Transportation.
Even most “sustainable” fuels are carbon-based, Petsonk said during an on-stage conversation with Billy Pizer, RFF’s vice president of research and policy. “They, when burned in the engine of the aircraft, emit carbon dioxide. … But what sustainable aviation fuels are better for the environment is on a lifecycle basis from the time that your feedstock was produced to transporting the fuel to the airfield.”
Developing standards for that analysis took the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), an international body, seven years, she said.
Another longstanding challenge has been how to allocate emissions from international flights. “If the plane is taking off in one country and landing in a different country, whose emissions are they — the emissions of the country of departure, the country of arrival? The [nationality] of the aircraft or the airline … may be different. How about the people on the plane?”
Earlier this month, the International Civil Aviation Organization, an UN agency, adopted a long-term “aspirational goal” of net-zero emissions for the industry by 2050, “with the [provision] that each country implement it in its own way,” Petsonk said. At the same meeting, CORSIA also set an emissions reduction baseline for international aviation of 85% of 2019 emissions beginning in 2024.
“What this means is that, for the first time, global aviation has both a near- and mid-term goal from now to 2035 … and a long-term goal, which is a really important signal to send, the 2050 goal, since aviation is a long capital stock industry,” she said. “It takes many years to develop [a plane], test it, fly it and [put] it into production and keep it in production for decades.”
The international lifecycle standards are being used as a baseline for the IRA’s tax credits for sustainable aviation fuels, Petsonk said. The tax credit starts at $1.25 per gallon “if the fuel is at least 50% better than fossil fuel on a lifecycle basis.”
It goes up a penny per gallon “for every percentage point improvement in lifecycle [emissions] up to completely carbon neutral,” she said. “We’re already seeing a terrific market response to this. … We’re hearing a lot from investors,” who already want the tax credit extended beyond the IRA’s 10 years, she said.
The commission Tuesday evening published a revised version of the report, correcting a passage related to ERCOT’s probabilistic assessments. Staff corrected the original language by adding “low” before probability and deleting “significant” before risk.
That changed the original sentence from describing ERCOT’s 2022-23 winter probabilistic assessment as indicating a “probability of a significant risk of declaring an EEA [energy emergency alert] Level 1” to indicating a “low probability of a risk of declaring an EEA.”
The original assessment apparently drew the attention of the Texas Public Utility Commission, which has regulatory oversight over ERCOT. A PUC spokesman said the report contained “inaccuracies” and that ERCOT had called on FERC to correct the record.
“ERCOT’s assessment reflected a ‘low’ probability of energy emergency events occurring during the expected daily peak load hour. We have asked FERC to correct this error, which they have done,” spokesperson Trudi Webster said in an email to RTO Insider.
The Texas grid operator plans to release its final winter assessment in mid-November.
In its assessment, FERC said that with above-average temperatures expected across most of the continental U.S., the country’s electric reliability appears well positioned for this winter. However, the commission singled out ERCOT, ISO-NE and MISO as being in danger of “especially tight” capacity during extreme weather conditions. (See “ERCOT, MISO Vulnerable to Winter Weather,” FERC: Natural Gas Prices to Rise During Mild Winter.)
During a press conference following FERC’s monthly open meeting Oct. 20, Chairman Richard Glick was asked whether the commission is confident ERCOT has addressed the issues from the February 2021 winter storm.
“Things have been moving in the right direction, but I think it would be premature and probably an overestimate to say everything is hunky-dory,” he said. “There are concerns going into this winter. The assessment … does discuss that ERCOT is one of the areas of concern.”
ERCOT has added winterization requirements for its members’ generating units after legislation and PUC rules passed in the wake of the winter storm. Staff dedicated to winterization now inspect generators to ensure compliance, and the PUC can also assess financial penalties on those that fall short of the requirements. Other generators have added firm fuel supply service to strengthen their availability.
The grid operator has also brought more generation online sooner and purchased additional reserve power, especially when the weather forecast is uncertain, as part of its conservative operations posture.
“The reliability of the Texas electric grid is our No. 1 priority,” Webster said.
PUC Chair Peter Lake and Gov. Greg Abbott, who appointed Lake to his post after the winter storm claimed the careers of his three predecessors, have both frequently said the Texas grid is more reliable than it has ever been.
FERC Chair Richard Glick speaks before SPP’s board and stakeholders. | SPP
“Things are improving, but there’s still a lot of work to be done in terms of winterizing plants,” Glick said.
Twice in the last week, Glick has recommended that ERCOT interconnect with its neighbors to be able to share power during emergencies. He noted that SPP and MISO did not suffer the same problems as ERCOT because they were able to import power.
“Texas, quite frankly, they’re a little bit stubborn because they don’t want to be subject to FERC regulation, and I understand that part,” he said during last week’s press conference. “But do you really want to cut your constituents off from power because you don’t want to be subject to FERC regulation and then have people die? That’s just not the right way to do it.”
On Tuesday, Glick made his first visit to SPP’s headquarters in Little Rock, Ark. His comments before the RTO’s Board and Directors and Members Committee were starker.
“We get pushback from Texas in particular saying, ‘Well, we don’t want to be subjected to FERC regulation,’” he said. “Well, I understand that’s an important issue. But are you willing to actually have hundreds of people die? Are you willing to have massive blackouts, four- or five-day blackouts, because you don’t have power from elsewhere?”
RENSSELAER, N.Y. — Gas supplies to Eastern New York (ENY) could be limited during freezing weather in winter because of demand exceeding interstate pipeline capacity, resulting in a reliance on imported LNG from New England, NYISO’s Market Monitoring Unit told stakeholders last week.
Speaking to the Installed Capacity/Market Issues Working Group on Oct. 20, Potomac Economics’ Joseph Coscia said the findings suggest NYISO should adjust its resource adequacy models and capacity accreditations to reflect the gas limitations likely to occur in winter. Such constraints would force the ISO to rely on imported LNG from New England, he said, a region that itself relies on imported LNG during winter for reliability.
Coscia also said the ISO should discount emergency assistance from non-firm gas from out-of-state generators during the winter and consider the availability of oil-fired units with limited capacity to ensure grid reliability in the case of very cold days when heat demand peaks.
The analysis focused on the availability of gas to the greater region of ENY and New England because it is served by eight critical interstate pipelines, such as the Iroquois, Algonquin and TETCO pipelines; has greater constraints limiting total flows than the rest of New York; and local distribution companies have systems in the area that serve many of the consumers in the entire state.
LDCs secure supply to meet their “design days”: the estimated maximum retail gas demand based on the historically lowest temperatures. Peak winter demand for design days hovers above 10 million dekatherms/day. Potomac found that the estimated total import capability of the interstate pipelines, excluding LNG, was roughly 8 million dekatherms/day, which is both “far below the total design day demand of the local gas utilities” and “is even below the estimated peak demand of the coldest winter seen in the past five years.”
LNG and compressed natural gas is available, but these should be thought of as limited fuels because they are restricted to “either cargoes contracted in advance” or serve as “limited storage” for short periods of time.
The analysis found that “an increasing sense of tightness of the gas system in the region” had meant that LDCs in ENY have held “large amounts of firm pipeline capacity” and are increasingly “relying on holding rights to the firm transport capability in order to satisfy design day requirements.”
ENY and New England are heavily reliant on LNG storage and imports to meet peak regional supply demands. Potomac emphasized that LNG importers generally do not “provide speculative supply or short-notice cargoes to the region,” threatening ENY’s reliability during extreme winter storms.
Potomac recommended that the NYISO resource adequacy model “discount external assistance from New England” to avoid “counting on imports from a region affected by the same set of gas constraints affecting winter reliability.”
Mark Younger, president of Hudson Energy Economics, asked Coscia if Potomac had seen “other areas of New York indicating significant concern” around gas supplies.
Coscia replied that gas bottlenecks are “primarily at the borders of the ENY and NE region.” Though it is possible that “pockets of specific generators elsewhere in the state have difficulty accessing gas,” they are “less acute outside of the ENY region.”
One stakeholder questioned the relevance of the analysis, noting that “New York has a state policy pushing for the elimination of every molecule of gas” and that this problem might “vanish” as the state “continues to electrify the heating, building and generation sectors.”
Coscia responded that “even with aggressive implementation” of state climate or energy policies, downstate New York utilities are anticipating “core gas demands to grow” over the next couple of years, so even if residential heating demands decline quicker than expected, the MMU is “focusing on the system as it is today.”
The ERO Enterprise continued its campaign against facility rating violations last week with the publication of a new report that builds on the work of NERC and the regional entities over the last several years.
The report, “ERO Enterprise Themes and Best Practices for Sustaining Accurate Facility Ratings,” aims to spread awareness among registered entities about the importance of maintaining accurate ratings of the equipment at their facilities. In the introduction, the authors note that “incorrect facility ratings can result in operating in an unknown state, uncontrolled widespread service outages and fires,” and can also make modeling the grid more difficult while hindering the planning of future expansions to the bulk power system.
Many recent penalties levied on utilities by their REs have involved violations of NERC’s reliability standards facility ratings. Just last month FERC approved a $105,000 penalty that the Texas Reliability Entity assessed against the Buffalo Gap Wind Farm because the rating for the facility did not match the utility’s documents. (See FERC Approves $105K Penalty for Texas Wind Facility Misratings.) So far this year, facility rating violations have accounted for $1.2 million in FERC-approved penalties.
4 Key Themes
NERC and the REs based their report on data that they have collected during their outreach and education efforts, as well as compliance monitoring and enforcement activities. They identified three common themes across the infringements involving inaccurate facility ratings.
First is an entity’s lack of awareness regarding the state of its equipment. This can include failure to adequately document or maintain an accurate equipment inventory, failure to understand the current carrying series equipment within its electrical system or an ineffective facility ratings validation program.
Lack of awareness can cause misratings to “go undetected for long durations, thereby potentially posing a greater risk to the reliability and security of the BPS.” The report said it may become a factor when an entity’s facility ratings program lacks internal controls for verifying and validating equipment in the field, instead relying on ratings provided by the manufacturer, or outdated diagrams and drawings. The authors recommended that entities “remain vigilant … and never assume that facility ratings issues do not exist on their systems.”
The second theme is inadequate asset and data management. In this context, asset management means the identification, management and tracking of physical facility ratings assets, while data management refers to the collection, validation and storage of data associated with ratings. Data may be spread across various locations or business groups within an entity, and moved back and forth as part of normal operations.
Failures related to data management include entities consolidating equipment in a database instead of listing it individually, or setting up programs that “do not identify and account for all necessary pieces of equipment or the equipment’s ownership in the field when determining a facility rating.”
In one instance, a transmission owner found two bundled transmission line conductors transitioned to a single conductor outside a station, wired to a switch using a single conductor because of physical constraints of the system. The utility “had situations where it failed to consider the switch configuration” and did not realize that the switch was the most limiting element of the facility.
The next identified theme is inadequate change management, involving failures by entities to document changes to equipment in the field or update their ratings documents to reflect newly installed or altered equipment. The ERO documented multiple instances of inadequate change management leading to inaccurate facility ratings, such as a generator and transmission owner replacing a transformer with a new piece of equipment with a higher rating, meaning the transformer is no longer the most limiting element, but not updating the facility’s rating.
According to the authors, failing to track, document and communicate all field changes creates “an increased risk of using inaccurate facility ratings.” To avoid this, utilities should implement strong change management processes that include:
requirements for data entry verification by qualified personnel;
a clear approval process prior to a change being implemented;
notifications to update equipment inventory after a change is implemented;
confirmation that the change was completed as planned;
validation through periodic reviews; and
checklists to verify that all necessary follow-up actions are taken after a change.
Finally, the fourth theme involves inconsistent development and application of facility ratings methodologies (FRM), referring to the methodology that each registered entity is required to have for determining facility ratings of its solely and jointly owned facilities.
An entity’s FRM can draw on many inputs, including manufacturer’s nameplates, engineering evaluations, testing or performance history, and physical or mechanical factors that might restrict a piece of equipment’s performance. However, the ERO said it has observed multiple issues in this regard, such as an entity considering only the electrical elements of a facility and failing to account for mechanical limitations. In addition, many entities fail to identify the next most limiting element in a facility, meaning that when the most limiting element is removed, they cannot quickly update the rating.
The report recommended that entities “strive to use a single consistent methodology and apply the same criteria when rating like components of a facility rather than using a mix of options.” While deviations from a single FRM may be inevitable, utilities should take care to minimize these events while ensuring that these deviations are “justified, consistently applied [and] well documented, and [that they minimize] inconsistent facility ratings.”
SERC Release Formed Report’s Basis
The ERO’s report is similar to a document released earlier this year by SERC Reliability, “Facility Ratings Themes and Lessons Learned,” which touched on similar points and even identified the same themes, with the exception of the fourth.
While the ERO-wide report does not explicitly mention SERC’s report, Tim Ponseti — the RE’s vice president of operations — said at the North American Generator Forum’s Annual Compliance Conference earlier this month that SERC had submitted its report to NERC to serve as the basis for a broader analysis. (See NAGF Attendees Discuss Facility Ratings Challenges.) He also credited the ERO with finding “a fourth theme that we missed” — likely referring to the inconsistencies in FRM methodologies.
California transit agencies are enthusiastically adopting zero-emission buses, industry representatives said, but regulators are worried that ridership downturns will stall ZEB progress.
The concern is great enough that members of the California Air Resources Board (CARB) have discussed modifying a zero-emission bus regulation so that ZEB purchase requirements are tied to the availability of funding for the vehicles.
“Public transportation is in crisis,” CARB member Daniel Sperling said. “We’re asking these transit agencies not only to spend a huge amount of new money [for zero-emission buses], but also to revamp their operations.”
“We need a principle that says compliance is dependent on funding becoming available,” from federal, state or other sources, he said.
Sperling’s comments came during a CARB board meeting last month, where board members heard a report on the Innovative Clean Transit (ICT) program. CARB adopted an ICT regulation in 2018 that will phase in requirements for public transit agencies to buy zero-emission buses starting next year.
The report looked at whether transit agencies are ready for next year’s ZEB purchase requirements and concluded that they are. That’s in large part due to more than a decade of ZEB roll outs and demonstrations.
Among roughly 200 transit agencies in California, more than 50 have purchased zero-emission buses. Three agencies have fully electrified their bus fleets, including the Antelope Valley Transit Authority, which became the first all-electric transit agency in North America this year.
Out of a total of about 13,000 public transit buses statewide, transit agencies had 510 ZEBs in service and another 424 on order at the end of 2021, according to CARB. The totals include 56 fuel cell buses deployed and 62 on order.
Transit Uncertainties
But the future of public transit is uncertain. Sperling said that ridership, which had been decreasing before COVID-19, took a major hit during the pandemic and has yet to fully recover. Federal and state funds that were used to bail out transit agencies are likely to dry up, he added.
Against that backdrop, ZEB purchase requirements under the ICT regulation are set to start next year.
For large transit agencies, the rule will require 25% of new bus purchases to be zero-emission from 2023 to 2025, increasing to 50% of new bus purchases in 2026 to 2028. Requirements for smaller transit agencies start with a 25% ZEB purchase requirement in 2026 to 2028. The regulation includes credits for early ZEB purchases.
All new buses purchased by transit agencies in the state must be zero-emission in 2029 and beyond.
CARB member Davina Hurt said she’s worried about how transit agencies will meet the more stringent ZEB purchase requirements that start in 2026.
“I’m really concerned about these agencies moving into the future and meeting some of our ambitious requests,” she said. “Some of these agencies are at a financial cliff.”
Board member John Balmes said the idea of tying ZEB purchase requirements to funding availability is “a very key issue.”
“The reality of the pandemic and the decreased ridership … it’s dire,” Balmes said. “I think we need to consider a course correction.”
But “if conditions change and there’s a lot more money available for the transit agencies, I think that’s great and we can keep going full blast,” he added.
The board took no formal action on the item, which was intended as an informational report on the ICT program.
Agencies ‘Lean In’ to ZEBs
The CARB board also heard from members of the California Transit Association, a nonprofit trade organization, on their experiences with zero-emission buses.
Michael Pimentel, the association’s executive director, said the group was initially skeptical of the ICT regulation, but has decided to “lean in” to the zero-emission transition. The organization now describes itself as a leading advocate for ZEBs at the state and federal levels.
Michael Hursh, CEO and general manager of AC Transit, said his agency is running battery-electric and fuel cell buses and comparing vehicle performance. On a cost-per-mile basis, the battery electric buses are less expensive to run than diesel or hydrogen-fueled buses, he said. And the rising price of hydrogen is a concern.
But Hursh said last month’s extended heat wave and urgent demands to reduce power use raised red flags regarding battery electric buses.
“If there’s an earthquake, if there’s a massive grid-down situation, can we get the fleet out?” he said. “With hydrogen and a diesel generator, I can run my fueling station and keep my buses on the road.”
Doran Barnes, chairman of the California Transit Association’s ZEV Task Force and CEO of Foothill Transit, said there is “great enthusiasm and excitement and energy” in the transit industry for a ZEB transition.
But the industry faces challenges including the greater cost of ZEBs compared to conventional buses, in terms of vehicle cost, infrastructure and workforce expenses. In addition, ZEBs may have range limitations or not be readily available, he said.
“We’ve got to figure all of these things out, and we’ve got to do it at a rate of change and learning that’s much quicker in the next three years as we move to 2026 than we’ve seen in the past 10,” Barnes said. “That momentum’s really got to build.”
EPA Administrator Michael Regan | © RTO Insider LLC
Washington Gov. Jay Inslee | © RTO Insider LLC
