Reports: Clean Electricity Performance Program Killed by Manchin

Democrats’ proposed Clean Electricity Performance Program (CEPP) is dead or on life support, doomed by Sen. Joe Manchin’s (D-W.Va.) opposition, according to numerous news reports over the weekend.

The CEPP, which would reward utilities that exceed emission reductions of 4% annually and penalize laggards, has been widely described as the “linchpin” of President Biden’s climate plan. News of its demise, coming just two weeks before the U.N.’s COP26 climate talks in Glasgow, had some environmentalists in despair.

But others said the $150 billion program would be bad policy and insisted its loss would not necessarily doom the Biden administration’s pledge to reduce U.S. greenhouse gas emissions to 50% below 2005 levels by 2030. They said efforts to decarbonize the power sector will continue, thanks to federal tax credits and supportive state policies.

“The CEPP is overshadowing the real star proposal”: about $300 billion to extend existing tax credits for utilities, commercial businesses and homeowners that use or generate electricity from zero-carbon sources, The Economist wrote.

CEPP: One-third of Reductions?

An analysis this month by Energy Innovation: Policy and Technology, an energy and environmental policy firm, said the most powerful emission-reduction provisions in the bipartisan infrastructure bill and the broader legislation Democrats hope to pass on party-line votes (referred to as the “infrastructure bills”) “is the combination of clean energy tax credits and the Clean Electricity Performance Program, which drives the power sector to 70 to 85% clean energy.”

The group said its modeling “underscores how important the CEPP is to achieving deep power sector decarbonization. Without it, emissions are likely to be 250 to 700 MMT higher per year in 2030, which could eliminate more than a third of the total emissions reductions under the infrastructure bills.”

“This is absolutely the most important climate policy in the package,” Leah Stokes, a climate policy expert advising Senate Democrats, told The New York Times, which reported Friday that CEPP was dead.

David G. Victor, co-director of the Deep Decarbonization Initiative at the University of California, San Diego, said both carrots (tax incentives) and sticks (penalties) are needed to clean up electric generation. “You need not just to deploy new stuff, but a way to retire old stuff,” he told The Wall Street Journal. “The combination of the two is key.”

The news had some proposing Hail Mary passes to save the program. “Time to make a deal with [U.S. Sens. Susan] Collins [R-Maine] and [Lisa] Murkowski [R-Alaska] to carve out the CEPP to get to 50 votes,” suggested author Herb Simmens.

Manchin was unapologetic.

“Sen. Manchin has clearly expressed his concerns about using taxpayer dollars to pay private companies to do things they’re already doing,” Manchin’s office said in a statement. “He continues to support efforts to combat climate change while protecting American energy independence and ensuring our energy reliability.”

West Virginia Coal, Gas Ties

Many of those weighing in about CEPP’s demise on Twitter took note of Manchin’s financial and political ties to the coal and natural gas industries. West Virginia ranks second in coal and seventh in natural gas production among the 50 states. Enersystems, a coal brokerage Manchin founded in 1988 and now run by his son, represents 30% of his net worth. He reported $491,949 in dividend income from the company in 2020, 71% of his total investment income.

But others said Manchin had valid policy concerns.

“The media narrative that [Manchin] is single handedly blocking the president’s agenda is absurd and unfair,” tweeted former FERC Chair Neil Chatterjee. “There are FIFTY other U.S. senators who strongly oppose this legislation.”

“CEPP was a lucrative giveaway for utilities to consolidate their monopoly power and generouslyyyyy incentivize already cost-effective generation,” tweeted Maggie Clark, director of government affairs for Pine Gate Renewables, a North Carolina-based company that does project development and strategic financing of utility-scale solar and storage projects.

“A clean energy standard as traditionally designed is one thing. Crafting that policy to fit under reconciliation parameters led to progressives rallying around a government giveaway as the magic solution to climate change. Come on,” she said. “Clean energy wins on price today. The barrier to widespread adoption is inadequate infrastructure. Take every dollar away from CEPP and put it towards grid upgrades and then we’re getting somewhere.”

Others noted that in addition to the clean energy tax credits, the Democratic bill also includes $32 billion in tax credits to encourage the purchase of electric vehicles, $13.5 billion for electric car charging stations, $9 billion to update the electric grid and $17.5 billion to reduce carbon dioxide emissions from federal buildings and vehicles.

“Clean energy tax credits are nothing to sneeze at,” tweeted Robin Dutta, who works on market development and policy in the federal affairs staff of rooftop solar company SunPower. “And might be more effective than whatever CEPP could do.”

“Despite the attention paid to it, CEPP is actually less potent as a greenhouse-gas slayer than those boring tax credits, which are less controversial because they do not overtly penalize coal or gas,” The Economist reported.

“Two energy veterans, one at a top renewables lobbying outfit and the other at a fossil-heavy utility, agree that the tax credits would sharply boost investment in low-carbon technologies,” it said. “That is because they improve the current setup by replacing stop-go uncertainty with a predictable long-term tax regime and make tax breaks ‘refundable’ rather than needing to be offset against tax liabilities, meaning even utilities that do not have such tax liabilities can enjoy them as freely as cash in the bank.”

In addition, more than half the states are implementing their own climate policies. Twenty-six states, representing 61% of the U.S. economy, have joined the U.S. Climate Alliance, which was created after former President Donald Trump announced the U.S. would withdraw from the Paris Agreement.

CEPP Vital Signs Waning

The Times reported that Manchin, chairman of the Senate Energy and Natural Resources Committee, was considering a clean electricity program that would reward utilities for switching from coal to natural gas. But last week, it said, Manchin told the White House he was completely opposed to a clean energy program.

CNN reported that it will “likely be dropped,” and Bloomberg reported it had confirmed the Times’ report.

“Per a person familiar, while a final decision hasn’t been made, without Manchin’s support there isn’t a path forward for the climate program,” Bloomberg’s Ari Natter tweeted.

The Journal reported the program was “is in danger of falling out” of the Democrats’ bill.

The Washington Post reported: “White House officials have not decided to completely jettison the CEPP but are instead looking at how to make changes that would ensure Manchin’s support for the broader economic package.”

“It’s not dead yet, per people familiar, but it’s struggling to stay in the talks given Manchin’s opposition,” tweeted POLITICO’s Zack Colman, who reported Wednesday that Democrats and the White House were discussing ways to amend the CEPP to allow natural gas and coal power plants with carbon capture to participate. “The changes I reported Wednesday are part of what’s being explored to bring Manchin to the table, but this latest reporting suggests the needle hasn’t moved.”

Manchin has recently expressed doubts about the viability of carbon capture. “It’s so darn expensive that it makes it almost impossible,” he said last month.

Legislative Scramble as COP26 Approaches

Progressive Caucus Chair Pramila Jayapal told MSNBC on Saturday that “there’s no decisions that have been made. The negotiations are continuing.

“We understand that we have to get 50 senators on board and that Sen. Manchin obviously has a very big role to play on this,” she said. “We’re open to that negotiation as long as we have strong climate protections that bring down carbon emissions. That’s the discussion that’s under way right now.”

The Post reported Saturday that White House officials are “still looking at whether they can preserve the clean energy program by providing a way for coal and natural gas plants to keep operating for longer.” It said another idea being considered was a voluntary emissions trading system among aluminum, steel, concrete and chemicals manufacturers that would provide federal funding to help them reduce emissions.

Earlier last week, Special Presidential Envoy for Climate John Kerry suggested Biden’s position at the COP26 talks beginning Oct. 31 would be weakened by the lack of a climate deal with Congress. Failure to pass such legislation “would be like President Trump pulling out of the Paris Agreement again,” he told the Associated Press.

On Friday night, Biden called Kerry’s comments “a little hyperbole.”

“It’d be good to have agreement on the climate piece, but we’re going to get the climate piece,” he said.

October 17, 2021

CARB Plan Would Allow Interstate Transfer of ZEV Credits

Car manufacturers selling vehicles in states that follow California’s zero-emission vehicle regulations would be able to transfer ZEV credits among states under a new proposal from the California Air Resources Board (CARB).

The proposal is part of the Advanced Clean Cars II regulation, which CARB is developing as an update to Advanced Clean Cars rules now in effect. CARB staff discussed the proposal during a workshop on Wednesday.

Under the proposal, transfers between states would be allowed for ZEV credits generated in model years 2026 through 2030.

An automaker would be able to transfer credits earned in one state to another state after the credit requirement in the initial state is met. For model year 2026, transferred credits could be used to satisfy up to 15% of a state’s ZEV requirement. The percentage allowed would decrease each year, dropping to 10% in model year 2030.

Credits from model years 2025 and earlier would not be eligible for transfer, nor would credits from a newly proposed environmental justice ZEV credit.

CARB said the idea behind the credit transfer allowance is to provide “flexibility to address varying needs and circumstances” of the different states “by giving automakers flexibility in the early years while ensuring sales ramp up to levels needed to achieve the states’ climate and air quality goals.”

The ZEV program is one part of Advanced Clean Cars; the regulation also includes a low-emission vehicle program that sets standards for vehicle emissions.

The ZEV program requires car manufacturers to earn a certain number of credits each year by providing zero-emission vehicles, such as battery-electric vehicles or fuel-cell electric vehicles, for sale in the state. Sales of plug-in hybrid electric vehicles also earn credit.

The goal is to increase the availability of ZEVs to car buyers. Twelve states so far have adopted California’s ZEV program, and several other states may soon follow suit.

Durability Standards

Advanced Clean Cars II will also include durability requirements for ZEVs.

CARB has proposed a requirement for battery-electric vehicles and fuel-cell electric vehicles to be designed to maintain 80% of their range for 10 years or 150,000 miles. That’s a change from an earlier proposal for maintaining 80% range at 15 years or 150,000 miles.

To check compliance, CARB would have authority to procure and test in-use vehicles that haven’t had an “excessive” amount of fast-charging or vehicle-to-grid operation.

Another proposed requirement would set a minimum warranty period of eight years or 100,000 miles for batteries, with warranty failure occurring when the battery falls below 80% of “state of health.”

CARB staff acknowledged that more stringent durability requirements could lead to higher costs for ZEVs.

In addition, a number of factors outside a manufacturer’s control may contribute to range degradation, CARB staff noted. Those include a vehicle owner’s charging and driving behavior, average ambient temperature and battery age.

EJ Credits Modified

CARB staff is also fine-tuning a proposal for environmental justice (EJ) credits in the ZEV program. The agency introduced the concept of EJ credits during a workshop in August. (See CARB Plan Aims to Broaden Access to ZEVs.)

The proposal would provide EJ credits to automakers that sell electric vehicles at a discount to community programs offering services such as ZEV car sharing. As proposed in August, the level of discount required to receive a credit would be based on the manufacturer’s suggested retail price for the vehicle, maxing out at 25%.

CARB’s latest proposal simplifies the discount requirement, setting it to a minimum of 25% for any vehicle sold to a community program. The program must serve low-income or disadvantaged communities.

Another way a car maker could earn an EJ credit would be by keeping ZEVs in California after their lease expires, thereby increasing the state’s supply of used ZEVs. As proposed in August, the credit would be available only to zero-emission vehicles; CARB’s latest proposal now includes ZEVs and plug-in hybrid electric vehicles.

The new proposal also adds a requirement that the used car be registered to a qualifying low-income household in California.

An automaker could use the optional EJ credits to increase the number of ZEV credits they receive for a particular vehicle. EJ credits for a single vehicle would range from 0.2 to 0.5.

The EJ credits would be available for model years 2026 through 2031. An automaker could use EJ credits to meet up to 5% of their ZEV credit requirement in a year.

CARB is still collecting feedback on its Advanced Clean Cars II proposals. The agency expects to present a rulemaking package to the CARB board in June 2022.

The regulations are expected to take effect starting with model year 2026.

October 17, 2021January 15, 2025

Stakeholders Ask FERC to Support E&AS Market Changes

Participants at the final session of FERC’s technical conference on energy and ancillary services (E&AS) Tuesday agreed overall that market participation rules need to be revised to ease the entry of new and emerging resource types into the wholesale electricity markets (AD21-10).

“The panelists informed us of a lot about this incredibly complicated, challenging problem” of incenting new resources while maintaining grid reliability, concluded Emma Nicholson, an economist at FERC who helped moderate the day’s sessions. “We at staff are heartened by how many bright, smart people are analyzing this problem from different points of view so we can crowdsource some really good solutions here.”

The commission held the first session of the conference last month and now will likely issue a call for comments, she said. (See Flexible Ramping Grows as Ancillary Service.)

Revising RTO/ISO Market Models

Investors in new technologies such as storage resources, hybrid and co-located resources, aggregated distributed energy resources, and standalone variable energy resources want to be sure that the new assets will be able to offer their full operational capability in the market.

Emma Nicholson, FERC | FERC

On the other hand, RTOs and ISOs wrestle with the difficulty of adapting their market software and rules to accommodate such resources — an uncertainty factor — while fulfilling what many consider to be their primary responsibility of maintaining reliability.

There are two sides to the challenge of incorporating uncertainty into market software because providing electricity “is really preserving ramp capability from one interval to the next so that [it] can be available and deliverable in the next market run where uncertainty potentially materializes,” said George Angelidis, principal for power systems and market technology at CAISO.

The second aspect is coming up with a reasonable methodology for calculating the uncertainty requirement without tremendous effort because you have to do it constantly as the market runs to update the requirements, Angelidis said.

George Angelidis, CAISO | FERC

For Jinye Zhao, principal analyst for advanced technology solutions at ISO-NE, the first question is how to reduce the magnitude of uncertainties; in other words, how to reduce the problem size.

“Given that there are always uncertainties in the system, what solution strategies can we use to manage uncertainties?” Zhao said.

Erik Ela, program manager for the Electric Power Research Institute, gave his perspective on ERCOT, which is not under FERC’s jurisdiction. Day-ahead forecasts for load, wind and solar used by the Texas grid operator are currently only used in the reliability unit commitment (RUC) process. This is run after the day-ahead market, with a primary focus of committing sufficient resources that require a day-ahead notification time while minimizing commitment costs, so resources committed in the day-ahead market are not de-committed, he said.

Jinye Zhao, ISO-NE | FERC

“If for example the renewable forecast is higher than the renewable bids, it is often the case that the incremental energy costs are ignored or largely discounted so that only the commitment costs are of concern,” Ela said.

The value of improved forecasts depends on both the amount of renewables and thermal units in the system, said Bethany Frew, senior engineer at the National Renewable Energy Laboratory.

“We’ve seen consistently across different studies almost a transition zone where as you start to increase the amount of renewables on your system, specifically variable renewable resources like wind and solar, and you start to reduce the amount of thermal units in the system, there’s this transition beyond which commitment-related impacts can be diminished,” Frew said.

Erik Ela, EPRI | FERC

Specifically, start-up costs are one of the areas where NREL researchers see a lot of value in improved forecasts, but as thermal units are removed or they get retired in future scenarios, the value of those forecasts declines, she said.

“There’s really this interesting kind of interplay between what’s happening in the rest of the system and the forecast quality,” Frew said.

Arne Olson, senior partner at Energy and Environmental Economics, had multiple recommendations. First, market operators must develop scientific methods for determining the quantity of ancillary services needed based on continually changing grid conditions. The upward and downward reserve product should also be specified and procured separately. Wind and solar projects have asymmetric cost functions, which are only partly ameliorated when the services dispatch upward in real time, Olson said.

Bethany Frew, NREL | FERC

“Finally, and most ambitiously, we should look to market software to optimize the use of energy storage,” Olson said. “This is the most flexible resource available in the market, but its costs are entirely defined by market opportunities to buy low and sell high. As substantial quantities of storage are added, it will be increasingly important for market software to optimize its use.”

Ultimately, the ideal state at MISO would be to design and modify markets to remove barriers and create incentives for emergency-only resources such as load-modifying resources, said Laura Rauch, director of settlements for the RTO. “In particular, that long-lead emergency resources be committed and dispatched to market operations is a paradigm that enhances market efficiency for greater transparency.”

Arne Olson, E3 | FERC

SPP deploys an uncertainty response team that talks on a daily basis and looks at the amount of uncertainty that the grid operator projects it will have to deal with, “and then the bulk responsibility of this team is to recommend some amount of capacity of generation that needs to be online,” said Yasser Bahbaz, manager of reliability coordination for the RTO. “And these are all recommendations that are made out-of-market because we don’t have a product that specifically deals with density and uncertainty.”

NYISO has been doing a good job for 20 years reducing out-of-market commitments, said Liam Baker, vice president of regulatory affairs for Eastern Generation. “Because of all the market power rules in New York City, I have to offer most of my products at cost or at zero. So as an investor … I want to see accurate price formation,” Baker said.

System Flexibility

One panel discussed whether energy and ancillary service market participation rules need to be changed to ensure that resources have incentives to offer operational flexibility to the RTO and ISO markets.

Yasser Bahbaz, SPP | FERC

The panelists stressed the importance of system flexibility in the markets.

Nicole Bouchez, principal economist in NYISO’s market design department, said New York is focused on the wholesale energy products that are needed for reliability “in the face of an evolving resource mix.” At the same time, Bouchez said, NYISO is also attempting to ensure the “broadest set of resources possible” can participate in the markets.

Bouchez said NYISO’s structure of market rules are designed to increase the financial returns for resources that perform flexibly and reliably in the real-time markets and reduce compensation for inflexible resources. Co-optimization in the energy and ancillary service markets and not in the day-ahead and real-time markets, Bouchez said, causes the prices to “reflect the cost of systems” that provide ancillary services and provide compensation when a unit “would otherwise be providing energy.”

“This opportunity to sell different products also has the potential to encourage resources to make investments or modify operating practices to participate in those markets,” Bouchez said. “These investments can, however, be costly, which is why the focus on reliability and the products needed to maintain reliability is so important.”

Nicole Bouchez, NYISO | FERC

Joseph Daniel, manager of electricity markets and the climate and energy program for the Union of Concerned Scientists, stressed why he believes flexibility to be important. Daniel said flexibility boils down to “reliability and affordability” with a more flexible grid lowering costs for consumers and bringing reliability through new technologies.

Daniel said sometimes he finds it difficult to “disaggregate” some of the flexibility issues with what he calls “uneconomic behavior in the markets.” He said when he looks at the current rules governing the energy and ancillary services markets, he’s concluded that “most of today’s rules were written for yesterday’s resources” and all someone has to do to see the future is look at the generation queues of RTOs and ISOs to see the changing resource mix.

Joseph Daniel, UCS | FERC

Daniel said he’s encouraged by FERC orders 841 and 2222 that demonstrate the commission is “working to find ways to accommodate that inevitable wave of lower cost, more flexible resources.” But he said rules governing the commitment and scheduling of resources “tend to bias towards inflexible, long lead-time resources” and work against newer, flexible technologies.

“FERC should pursue market fixes to promote competitive resources and to offer in the full range of possibility,” Daniel said. “As we make these steps towards creating market rules that will promote flexibility, we should recognize the limitations to that and try to find ways to make sure the market rules objectives actually achieve what we’re solving for.”

Michael McLaughlin, director of FERC’s Division of Economic and Technical Analysis, asked, “Do any existing RTO/ISO energy and ancillary service market rules, requirements or procedures actually encourage resources to offer into the market inflexibly, and if so, what changes should be made?”

Catherine Tyler, Monitoring Analytics | FERC

Catherine Tyler, deputy market monitor for Monitoring Analytics, the Independent Market Monitor for PJM, said the way McLaughlin’s question was framed is “not quite the right” one. Tyler said stakeholders shouldn’t be worried whether resources offer flexibly but instead focus on the “need” for resources to perform flexibly.

Tyler said PJM rules require offering flexible parameters, including must-offer requirements in energy and reserve markets. She said there’s “plenty of flexibility on paper,” but there’s a “general lack of accountability” when it comes to performing flexibly in the markets. For example, there are no repercussions in the outage or uplift rules for failing to meet must-offer requirements. A potential solution would be penalties based on capacity market prices, which are paid for meeting certain performance standards.

“The market needs to account for the performance of the resources,” Tyler said. “Customers pay a premium for capacity that is meant to meet performance standards.”

Emerging Resources

Panelists discussed some of the issues keeping new technologies from entering and flourishing in markets.

Jason Burwen, ESA | FERC

Jason Burwen, interim CEO of the Energy Storage Association, said one of the early lessons with the development of energy storage technology is that flexible storage is running into market processes that are not providing “commensurate operator control” and weren’t written with that technological capability in mind. It’s important for the commission to take a “wide view” on the paths forward on potential market rules to “continue to ensure policy keeps up with technology” and not allow technology limitations “constrain our future.”

“The grid of the future will need more flexible, fast-starting resources, and we need to make sure that we reflect the cost of a lack of performance meeting that,” Burwen said.

Aaron Siskind, an economist with FERC, asked whether existing RTO/ISO energy and ancillary services market rules, practices or procedures prevent or otherwise obstruct relatively new and emerging resource types, such as variable, hybrid and storage, from fully participating in RTO/ISO markets and offering the operational flexibility they are capable of providing from a technical standpoint.

Walter Graf, PJM | FERC

Michael DeSocio, director of market design for NYISO, said the current market structure is “built to reward those that can move quickly, follow dispatch instructions closely and be responsive to emerging grid needs.” To be prepared for the continuing energy transition and the grid of the future, stakeholders need to “think more broadly” on solutions for market structures to ensure resources continue to respond to grid needs and operator instructions. He said there is also “a need to provide additional information more frequently” by resources submitting more data to the RTOs and ISOs for more efficient operations.

“This promotes improved efficiency and better price formation,” DeSocio said. “All of these pieces and parts are important.”

Walter Graf, senior director of economics for PJM, said the objective should not be to maximize operational flexibility but to “incentivize the efficient level of operational flexibility across all resources.” PJM is behind other areas in the country in respect to the penetration of emerging and intermittent technologies, giving it the “benefit” of having more time to address market design deficiencies “before they become problems.”

Graf said PJM “continues to believe in the ability of the competitive market to signal value through prices” and the ability of market participants to best make decisions. Graf said incentivizing flexibility and ensuring that sufficient flexibility is available when needed is the role of the energy and ancillary service markets.

“PJM believes that operational needs should guide the design of needed services and should not be compromised to accommodate resources that are unable to comply,” Graf said. “That said, there are cases where value can be unlocked or enabled without compromising operational requirements.”

October 17, 2021June 14, 2023

New Analysis Sets Low-carbon Focus for NY Climate Plan

The New York State Climate Action Council met Thursday to discuss an integration analysis toward shaping its final scoping plan by year-end to help reach the environmental goals outlined in the state’s Climate Leadership and Community Protection Act (CLCPA).

NYSERDA CEO Doreen Harris | NYDPS

“While we will see results based on a few key scenarios … these scenarios have been designed to bound the analysis and certainly not to set up an either-or situation where we pick our favorite scenario,” said Doreen Harris, CEO of the New York Energy Research and Development Authority (NYSERDA) and Council Co-chair.

The analysis provided by state agencies and consultancy Energy and Environmental Economics (E3) “is essentially yet another input and will provide an important point of reference as we head into 2022, and I fully expect that over the next year, once the draft scoping plan is issued, we will continue to discuss and debate the various strategies, challenges and tradeoffs that advance us to our goals,” Harris said.

The 22-member council aims to hold public meetings throughout 2022 before releasing a final plan in 2023.

Low-carbon Focus

The scenarios discussion focused on the strategic use of low-carbon fuels and an accelerated transition away from combustion.

Carl Mas, NYSERDA | NYDPS

“The strategic use of low-carbon fuels will achieve a system predominantly based on a grid that is wind, water and sunshine,” said Carl Mas, director of energy and environmental analysis at NYSERDA.

New York will have a heavily electrified system that includes strategic use of bioenergy, mostly derived from biogenic waste and agricultural residues, forest residues, and a limited amount of purpose-grown bioenergy as well as green hydrogen juxtaposed against that, Mas said.

The state is looking to limit and, in some cases, have no combustion, so no bioenergy combustion and no hydrogen switching to fuel cells where hydrogen might be used for long duration storage and the flow of new technologies that may come, he said.

“As a response we’ve had to accelerate our electrification and energy efficiency, so we’ll see how those play out both in terms of different health impacts and different cost structures,” Mas said. “We set the bar of trying to more comprehensively look at health than anyone has in the past, and I think we have succeeded.”

Bob Howarth, Cornell University | NYDPS

The building sector is now getting closer to the 40% reduction in greenhouse gas emissions from 1990 levels that the CLCPA calls for by 2030, but transportation is still at around 27%, said Bob Howarth, professor of ecology and environmental biology at Cornell University. He asked what more the state can do to push that sector even harder.

Transportation takes more time partly because of where the sector is today, which is an actual increase since 1990 that’s unmatched in any other sector, Mas said.

“Our grid has gotten much cleaner since 1990,” Mas said. “Our buildings have actually gotten better over time, and transportation has gotten more efficient, but we’ve just been driving more, and we’ve been driving bigger, so there’s a higher mountain to climb for transportation.”

Building Stock Turnover

There could be a lot of things that need to change, and consumers need to have incentives to change, said Gavin Donohue, president and CEO of the Independent Power Producers of New York.

IPPNY CEO Gavin Donohue | NYDPS

Does the state believe that the models being put in place “are going to be adequate to make those consumer changes, or are we going to need a whole new suite of additional regulations and laws to make that change workable?” Donohue asked.

Mas turned the question back to the Council: “That’s what this deliberative body needs to discuss and debate. How are we going to do this and what structures do we have in place, and can we expand those existing structures?”

For electrifying the building sector, the state has a very gradual ramp-up and then a more accelerated path after 2025. That pathway represents about 5% per year of New York’s building stock of around 8 million households, but that is not the key statistic, Mas said.

New construction is really a small percent of the turnover of the “huge built environment,” he said, adding that retrofitting existing buildings is very important, and that usually happens when a building changes hands.

The model includes an assumption of the opportunity space and the opportunity timing, according to Mas.

The New York State Climate Action Council met virtually October 14, 2021 to discuss integration analysis scenarios. | NYDPS

“What you see predominantly happening for the first couple years is that any existing turnover of gas systems [for residential heating] is to a more efficient system, but pretty quickly by 2024-2025 we’re starting to see the bending of the gas curve as well,” Mas said.

It will be an efficient electrification process, Mas said. “So when you’re working with a customer, you’re not just necessarily only switching out a furnace, but taking that opportunity to also look at upgrades.”

October 17, 2021November 5, 2023

Geothermal Plant Seeks Full Ramp-up After Volcanic Disruption

The operator of Hawaii’s only geothermal plant is working to bring the facility back to full capacity after it was shut down by a volcanic eruption three years ago.

Ormat Technologies subsidiary Puna Geothermal Venture (PGV) discussed its efforts to ramp up its geothermal plant on the Big Island during a public meeting Wednesday.

When running at its full 38 MW of capacity, the PGV plant accounts for about 30% of the Big Island’s renewable energy.

The plant was shut down in 2018 when an eruption from the Kīlauea volcano caused a lava flow that destroyed access roads and several sections of the plant. The company repaired enough of the facility to bring it back online last November, but at limited capacity.

“Currently the plant is producing 25 to 26 MW,” Zachery Adachi, PGV operations supervisor, said during the meeting. “We have nine of 11 [Ormat energy convertors] online right now. Out of the two that are down we have one that is down for annual maintenance,” while the other unit is “still under recovery from the whole lava event.”

Adachi noted the company is “just waiting on parts” for the energy converter still under recovery and expects it to be operational “in a month.”

Responding to a question from a community member, Ormat Senior Director of Hawaii Affairs Michael Kaleikini said that PGV has no construction plans for the next few months but will be performing maintenance on its KS5 production well that is still covered by lava.

Kaleikini explained that one reinjection well had also been covered by lava. “We checked the mechanical integrity, received all the proper approvals to use it again, and it’s back in operation. So we’re crossing our fingers that KS5 will be available for use in the near future.”

Kaleikini also pointed to the value of geothermal energy relative to solar energy, saying, “The solar farms with battery storage do contribute to the state’s mandate, but their technology is not available 24/7 like geothermal.”

Other community questions centered on the safety of the plant and if damage caused by the eruption will cause any unwanted emissions of hydrogen sulfide, a toxic volcanic gas. Kaleikini said that PGV is a closed-loop facility, meaning it does not have “continuous emissions of hydrogen sulfide” and thus should not pose a threat. He also explained that PGV is responsible for notifying the state of any dangers.

PGV and Hawaiian Electric Light Co., a subsidiary of Hawaiian Electric Co., are currently negotiating an amended power purchase agreement to increase the facility’s capacity from 38 MW to 46 MW. According to an Oct. 8 letter from PGV to the state’s Office of Planning, the amended PPA will also allow PGV to “enhance its operational efficiency” so that it can “displace annually approximately 10 million gallons of fossil fuel.”

Those efficiency gains would consist of replacing the plant’s 12 existing generating units with three newer, more efficient units that will “use the same amount of geothermal resource as is currently used.”

October 17, 2021

PJM MRC/MC Preview: Oct. 20, 2021

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

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

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Stakeholders will be asked to endorse the 2021 reserve requirement study (RRS) results for the installed reserve margin (IRM) and the forecast pool requirement (FPR). The study was unanimously endorsed at the Oct. 5 Planning Committee meeting. (See “Reserve Requirement Study Endorsed,” PJM PC/TEAC Briefs: Oct. 5, 2021.)

C. The committee will be asked to endorse proposed updates addressing behind-the-meter generation (BTMG) business rules on status changes and corresponding revisions to Manual 14D, Manual 14G and the tariff. The updates were developed in special sessions of the Market Implementation Committee. (See “Manual 14G Updates Endorsed,” PJM PC/TEAC Briefs: Aug. 31, 2021 and “Manual 14D Endorsed,” PJM Operating Committee Briefs: Sept. 10, 2021.)

D. Members will be asked to endorse proposed revisions to Manual 15: Cost Development Guidelines, the Operating Agreement and the tariff to address incremental and no-load energy offers. The Cost Development Subcommittee proposed revising the no-load cost and incremental energy offer definitions to clearly define what costs can be included, including operating costs, tax credits and emissions allowances. (See “Manual 15 Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)

E. Stakeholders will be asked to endorse the proposed solution and manual revisions to address the calculation of the energy efficiency add-back in Reliability Pricing Model auctions. The proposal, which called for modified language to section 2.4.5 of Manual 18 to reflect revisions to the EE add-back method, was endorsed at the Oct. 6 MIC meeting. (See “Energy Efficiency Add-back Endorsed,” PJM MIC Briefs: Oct. 6, 2021.)

Endorsements (9:10-10:55)

1. Resource Adequacy Senior Task Force Charter (9:10-9:35)

The committee will be asked to approve the proposed charter to create a new senior task force to discuss topics related to resource adequacy listed in an April 6 letter from the Board of Managers and to recommend possible changes to the capacity market. (See “Resource Adequacy Charter,” PJM MRC Briefs: Sept. 29, 2021.)

3. Undefined Regulation Mileage Ratio Calculation (9:35-10)

Members will be asked to endorse PJM’s proposal to change the undefined regulation mileage ratio calculation in Manual 28 and the tariff. The proposal will also be voted on at the MC meeting on the same day. If the proposals fails, stakeholders will be asked to vote on a separate proposal from the Independent Market Monitor. (See “Regulation Mileage Ratio Calculation Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)

4. ARR/FTR Market Task Force Update (10-10:35)

Stakeholders will be asked to endorse a joint PJM-stakeholder proposal with corresponding manual and tariff revisions to address the RTO’s auction revenue rights and financial transmission rights. The proposal was endorsed at the October MIC meeting. (See “ARR/FTR Market Task Force Proposal,” PJM MIC Briefs: Oct. 6, 2021.)

5. Max Emergency Revisions (10:35-10:55)

The committee will be asked to endorse proposed revisions to Manual 13: Emergency Operations addressing the maximum emergency category. Stakeholders are being asked to endorse the revisions upon first read.

Members Committee

Endorsements (1:45-2:55)

1. Initial Margining Solution (1:45-2:15)

Stakeholders will be asked to endorse proposed tariff revisions on rules related to initial margining that close out the work of the Financial Risk Mitigation Senior Task Force (FRMSTF). A joint proposal from Perast Capital and Duke Energy was endorsed at the September MRC meeting after hours of debate. (See PJM Stakeholders Endorse Initial Margining Proposal.)

3. Manual 34 Revisions (2:35-2:55)

The committee will be asked to approve proposed revisions to Manual 34: PJM Stakeholder Process addressing the inclusion of forums as a stakeholder body. The revisions were originally discussed at the Stakeholder Process Forum and presented for a first read at the September MC meeting. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Sept. 29, 2021.)

October 17, 2021November 17, 2023

ERCOT’s Jones Looks Ahead, not Behind

HOUSTON — Introduced as “clearly a man of courage and conviction to take this job at this time,” interim ERCOT CEO Brad Jones stepped up to the speaker’s podium and briefly rehashed February’s events that led to his leadership position with the Texas grid operator.

“The media said we weren’t prepared [for the February winter storm]. That’s not true,” he told an in-person and virtual audience Thursday during the University of Texas School of Law’s Gas and Power Institute.

Referencing a similar winter event that led to suggested weatherization recommendations, Jones added, “The generators were prepared, but to 2011 standards.”

But rather than revisit history, Jones made it clear his focus is on what lies ahead.

“The future of ERCOT depends on more than our response to the winter storm. It depends on our response to an extraordinarily fast-changing market,” he said.

Brad-Jones-2021-10-15-(RTO-Insider-LLC)-Content.jpg

Speaking without notes, Jones said his 60-point roadmap to grid reliability, given home-page prominence on ERCOT’s website, addresses the grid operator’s concerns “today and tomorrow.” Twenty-nine of the roadmap’s items have been completed, with all but one of the remaining 31 listed as being “on track.” (Placing senior-level representatives from each member organization on the Technical Advisory Committee has been delayed until the new Board of Directors is fully in place.)

“The seeds of what we want to fix are in the [February] problems,” he said. “Weatherization has to improve. We can’t rely on 2011 standards. The weather is not waiting for the PUC to get [its] rules in place. ‘Winter is coming,’ as we’ve all heard.”

Jones said he has been contacted by generation owners who told him they are investing “tens of millions of dollars” in weatherizing their facilities. “They’re investing because they see where the weather is going and they need to get ahead of it,” he said.

ERCOT staff this November will begin inspecting nearly 300 generating units’ weatherization, concentrating on those responsible for the 80% of lost megawatts from the February storm. The grid operator is staffing up for the effort, which includes filing a report with the Public Utility Commission.

“I hope gas suppliers are moving forward, just like the generators,” Jones said. The FERC-NERC joint inquiry on the storm and other reports have all placed most of the blame for generation outages on the lack of natural gas supplies. Texas politicians have found the gas industry’s response to be lacking. (See Texas Senators Call for New RRC Weatherization Rules.)

Noting ERCOT’s interconnection queue is heavily weighted in favor of renewable energy projects, Jones said their “extraordinarily valuable” low prices need to be balanced with more reliable generation. He brought up the RACE acronym he often uses with the public: reliable, affordable, clean electricity.

“For too long, it’s been CARE. We’ve got to put the R back in front,” Jones said. “One of the things the state has failed to do over the last 20 years is to put reliability first.”

Jones said ERCOT would like to see “stout” firm fuel contracts, dual-fuel capabilities and underground storage to ensure thermal plants have a reliable fuel supply. Citing rising gas prices, he also said he wants to separate generation from relying on natural gas, should the power equation’s gas side again fail during extreme weather.

“We want to ensure there’s language in the contracts to firm them up as much as possible and to give them some teeth to ensure reliable delivery,” Jones said.

Asked whether a capacity market would have resolved ERCOT’s problems during the winter storm, Jones said he is a fan of capacity markets and that they work “very well.”

“The problem is, it takes so much time to tune the rules and change things to drive certain outcomes,” he said. He used PJM’s capacity market as an example of a market that “drives the type of reliability we need” with its firm-fuel requirements.

“It’s also true that we can build those same tools outside of a capacity market,” Jones said. “It’s not necessarily true that a capacity market would have saved us. We had the capacity; it just didn’t operate.”

A capacity market would have helped in the billions of market charges assessed to participants in the two days after the storm subsided, Jones said. During that time, the PUC kept market prices at $9,000/kWh to encourage generation to stay online. He said capacity markets typically have $1,000 offer caps because capacity resources are paid on an annual basis.

“The financial storm would have been little more than 1/10 of what actually occurred,” Jones said.

The scars from February still remain. Jones said during a recent call with North Texas mayors, he was asked about the likelihood of another winter storm in 2022. Calling February’s a one-in-130 year event, he said one could assume a 1% chance of a similar destructive storm. However, weather forecasters have also said there’s a higher likelihood of another winter event the year after another one, Jones said.

“So not a 2021, but perhaps a 2011 storm,” he said, placing the chances in the 10-15% range. “We have to be prepared for something like that … and we are getting ready. I feel very confident we will be ready.”

Uncertainty for ERCOT Board, Market

Two energy lawyers both expressed uncertainty about changes to ERCOT’s governance structure and market design.

Meghan Elaine Griffiths, an attorney with Jackson Walker, said a questioner’s guess “is as good as mine” when queried about how the political appointees to the ERCOT board will affect the market and stakeholder process. Under new legislation passed earlier this year, the board’s structure of unaffiliated directors and market segment representatives has been replaced by a selection committee’s appointees, with the committee itself selected by the state’s political leadership. (See 2 New ERCOT Directors Named, Replacing Current Board.)

“One of the benefits of having market stakeholders on the board is they have a deep knowledge of the business and a deep knowledge of the protocols as they’re developed,” Griffiths said. “I think there’s a very steep learning curve for our new ERCOT board members. We’ll see how that plays out over time.”

Already, one media report has highlighted board Chair Paul Foster’s tie to Republicans. According to The Dallas Morning News, Foster has since June donated $1.775 million to Gov. Greg Abbott’s campaign committee.

Michael Nasi, a partner with Jackson Walker, shared a quote on market design from PUC Chair Peter Lake before the State Legislature: “‘I want to reassure you that we are not tweaking on the edges or making marginal changes. We are taking a blank-slate approach for a full overhaul and redesign of this market to drive reliability. Full stop.’”

“This market has been cited as the envy of many and potentially modeled in many places in this country and around the world,” Nasi said, referring to pre-February perspectives. “And then to have Chairman Lake say we’re going to fundamentally redesign this … I welcome the change, but how does it get done? It will be hard work, but it’s doable. ERCOT can still be a model for others.”

October 17, 2021

OSW Grid Strategy Must Extend Beyond Current Proposals, Utility Says

BOSTON —
Offshore wind developers need to think on a larger scale than current projects in the pipeline when it comes to transmission planning, according to Nabil Hitti, director of U.S. business development for National Grid (NYSE: NGG).

“The existing plans and sizes are manageable, and the question is, ‘Can we go bigger?’” Hitti said at a panel for the American Clean Power Association’s Offshore WINDPOWER 2021 conference on Wednesday.

The U.S. Bureau of Ocean Energy Management this week set a goal to hold up to seven new offshore lease sales by 2025 to meet the Biden administration’s goal for 30 GW of OSW by 2030.

Coastal states are already facing the challenge of how to integrate existing OSW proposals into the transmission network, along with how to increase transmission capacity in general to “unlock the potential of renewables across the nation,” Hitti said.

BOEM is reviewing nine projects following its approval of the Vineyard Wind project off the coast of Massachusetts earlier this year.

Ocean Wind, the largest project under review with the agency, is expected to have a total capacity of 1,100 MW.

“PJM has been very helpful to us in trying to come up with the transmission that is going to provide the maximum rate of return for ratepayers,” Upendra Chivukula, New Jersey Board of Public Utilities commissioner, said during the panel discussion.

But New Jersey is at the forefront of issues with OSW interconnection, including establishing charges and costs, Chivukula said.

“Currently the planning system is fragmented, I think, due to transmission owners having incentives to construct and recover costs from transmission projects with little or no oversight,” he said. Those costs are then passed to ratepayers.

When developers approach state agencies for OSW renewable energy certificates, the “largest component of risk is associated with transmission costs,” said Tim Burdis, senior manager of policy solutions for PJM.

“You can quantify a lot of the other costs, but you don’t necessarily have specificity around what are going to be the upgrade costs that an ISO or RTO might be sticking with the bill,” Burdis said.

Transmission upgrade and replacement decisions in anticipation of a skyrocketing OSW industry need to be made now to save money and time on integrating the renewable resource, instead of “having to make a minimal upgrade and then come back later and make a bigger upgrade for OSW that wants to come on to the system,” Burdis said. “The state of public policy says it is going to be on in 10 years.”

October 15, 2021June 14, 2023

NAGF Speakers Highlight Resource Mix, Cyber Challenges

Speakers at the North American Generator Forum’s (NAGF) Virtual Compliance Conference this week repeatedly urged grid planners to take seriously the challenges of the changing resource mix and other threats to the reliability and security of the grid.

NERC Board Chair Kenneth DeFontes | NAGFIn his keynote remarks on the first day of the meeting, NERC Board of Trustees Chair Kenneth DeFontes praised NAGF for its “longstanding partnership with NERC” and the “tremendous input and support” it has recently provided as the ERO sought to manage the myriad emerging threats to bulk power system reliability.

Citing the 2021 ERO Reliability Risk Priorities Report published in August, DeFontes emphasized that grid transformation remains one of the most pressing risks facing the ERO Enterprise. (See Grid Transformation, Cybersecurity Lead 2021 ERO Risk Report.) He warned utilities that they may not be taking the challenges of the transition to renewable resources seriously enough.

Two recent reports lent weight to DeFontes’ concerns. The first was NERC and FERC’s joint inquiry into February’s winter storm that led to unprecedented outages in the Midwest and left hundreds dead in Texas (AD21-28). The final report has not yet been released, but preliminary findings and recommendations were presented at the commission’s open meeting last month. (See FERC, NERC Share Findings on February Winter Storm.)

The second report was NERC and ERCOT’s review of an incident earlier this year in which multiple solar and wind facilities near Odessa, Texas, suffered voltage reductions. (See NERC-ERCOT Report Reviews Texas Solar Issues.) In both incidents, investigators found that entities had not implemented recommendations in NERC’s nonbinding reliability guidelines despite widespread knowledge of their existence and the reasons for them.

“As we learned in the February cold-weather report, there can be dire consequences when guidelines are not followed. I am concerned that we’re seeing a similar trend when I look at the Odessa disturbance report,” DeFontes said. “We see the industry is well aware of the guidelines; they have considered them and adopted some parts of them; but they are not widely and comprehensively being followed, which has left us with potential reliability gaps.”

Noting that FERC Chairman Richard Glick and NERC CEO Jim Robb have promised that the winter storm report “will not sit on the shelf,” DeFontes urged utilities to study the Odessa disturbance report and make a real effort to apply its lessons. He promised that if nonbinding guidelines prove to be insufficient, NERC will “move forward to improve [mandatory] standards.”

Gugel, Lauby Emphasize Changing Grid Conditions

Howard Gugel, NERC’s vice president of engineering and standards, continued the discussion of the changing grid in his presentation. Comparing predictions NERC made in 2008 of fuel mix changes over the next 10 years versus the actual conditions in 2017, Gugel observed that natural gas, wind, solar and nuclear all increased more than expected — gas and wind grew more than four- and threefold, respectively — while coal’s presence in the BPS actually declined, rather than rising as NERC had anticipated.

The growing presence of weather-dependent resources such as wind and solar — along with behind-the-meter resources like rooftop solar, home battery storage systems and grid-connected electric vehicles — poses a problem for system planners, who will “have to become very creative in understanding [the] differences” between these generators and traditional resources.

“Our system was not designed or planned with that in mind, but that reality is coming,” Gugel said. “The question is, how do you adapt for that? How do you become resilient?”

Gugel identified several problems that planners are going to have to solve, including a lack of transparency into current load and status of behind-the-meter resources; inability to quickly ramp up generation among wind and solar resources in the event of an emergency; voltage regulation; and underfrequency load shedding. All of these will require a level of communication that prior generations never anticipated.

Mark Lauby, NERC | NAGF

NERC Chief Engineer Mark Lauby concurred with Gugel’s warning about the assumptions underlying traditional BPS planning, saying that “that world is slowly disappearing” and that establishing essential reliability services is becoming much more difficult in a world of distributed, smaller, asynchronous generation resources that require much more automation to manage remotely and programming to “ride through minor system disturbances so as not to make them worse.”

The increasing reliance on electronic grid management systems also means that the BPS must be hardened against cybersecurity threats, Lauby observed. Noting recent cybersecurity events like the SolarWinds and Microsoft Exchange Server attacks, he observed that hackers “are not dumb; they are persistent,” having learned how to target a wide range of industries.

“So far, fortunately, we haven’t really seen a breach from [information technology to operational technology], though we have had vulnerabilities we’ve identified and are working to address them,” Lauby said. “But as we start digitizing more … we’re going to have to keep in mind that we design a system that’s robust against those kinds of attacks … so that we’re not as much of a target.”

SERC Shares Self-report Tips

The meeting also featured presentations from other stakeholders, including Janice Carney, senior compliance engineer at SERC Reliability. Carney discussed the importance of self-reporting potential violations of NERC reliability standards, observing that bringing potential compliance issues to a regional entity’s attention voluntarily is “a much better position for an entity to be in compared with a noncompliance found during an audit.”

Information needed in self-reports includes the date of discovery; start and end dates of the noncompliance, with a basis for each; a description of how the infringement was identified; the number of people, devices or systems involved in the noncompliance; the cause of the violation; and prior instances of noncompliance with the same standard.

Carney also emphasized the importance of writing style in self-reports, urging utilities to be as clear as possible by using active voice rather than passive and defining all acronyms on first usage.

Cold Weather Plans Coming Soon

Finally, Venona Greaff, manager of compliance at Occidental Energy Ventures, updated attendees on the new reliability standard EOP-011-2 (Emergency preparedness and operations), approved by FERC in August, and its requirement that generator owners implement plans to protect their units from freezing. (See FERC Approves Cold Weather Standards.)

“As generators, when we think about these standards and how they fast-tracked them after the February [winter storms], it seems like it’s a steam engine barreling down on us at a great pace,” said Greaff, who served on the standard drafting team for EOP-011-2 and the other cold-weather standards.

“But in reality, this has been coming for a long time,” she continued, noting previous cold-weather events that occurred in 2011, 2013 and 2018 — the last of which was the impetus for the cold-weather standards project. (See FERC Orders Cold Weather Reliability Standard.)

While the new standard will not take effect until April 2023, Greaff’s presentation was aimed at providing utilities a basis for starting to develop their plans, including basic attributes such as a purpose statement explaining what the procedure is meant to do and the applicable entity or facility; the personnel who will be responsible for specific activities, as well as for oversight of the entire plan; and critical components and instrumentation that need priority protection.

“One thing I want to remind you [members] of the NAGF is, collaboration and assistance is always an option,” Greaff said. “We currently have a cold-weather preparedness group [that] has 82 members. … I think that we have a lot that we can share with each other, and we can learn from each other in this working group. So I’d encourage you to think about joining the working group. It doesn’t mean that you have to take a lead role; it just puts you in that small group and allows you to be a part of the conversation.”

October 15, 2021December 13, 2023

NRDC Report Predicts a Decline in NJ’s EV Truck Costs

The average medium- or heavy-duty electric truck purchased in New Jersey in 2040 will cost $25,000 less over its lifetime than a comparable diesel vehicle, according to a new report released by the Natural Resources Defense Council (NRDC).

Fuel and maintenance cost savings totaling about $36,000 over the lifetime of the average electric medium- to heavy-duty truck will make up for the purchase price premium over a diesel vehicle, according to the report, New Jersey Clean Trucks Program.

Seeking to rebut the perception that EV trucks are prohibitively more expensive than diesel and gas vehicles, the NRDC argues that EV trucks will yield health benefits quickly and significant savings after a few years. The report models the environmental and health benefits and cost impact of three different scenarios of state EV truck policies. Based on the report, the NRDC argues that “accelerating the deployment of zero emission trucks and buses would dramatically lower pollution.”

Modeled on California’s Advanced Clean Trucks regulation, New Jersey’s ACT — if approved by the Department of Environmental Protection (DEP) — would require manufacturers to meet an escalating series of electric truck sales targets, starting in 2025. Manufacturers would be required to increase their sales of zero- or near-zero emissions vehicles to 55% of class 2b and 3 truck sales by 2035, 75% of Class 4 to 8 trucks and 40% of truck tractor sales by 2035. (See: NJ Electric Truck Rules Face Many Questions).

Environmental groups embrace the ACT rules. Hayley Berliner, clean energy associate for Environment New Jersey, said the NRDC’s report “certainly shows the importance of the Advanced Clean Truck rule, and the remarkable public health and environmental benefits,” she said.

The NRDC, along with Environment New Jersey and other environmental groups, wants the DEP to approve the rules by the end of the year so that trucks made in 2025 are covered. Any delay to the enactment of the rules beyond the end of 2021 would mean the first trucks covered by the rules will be those made in 2026, says the NRDC and other environmental groups.

Cost vs. Environmental Impact

Opponents say that electric vehicles are too expensive and the number of models available is too small to be attractive without sizable government incentives. They say that substantial cuts in emissions can be achieved with cleaner, more modern diesel engines, which cost much less than EV trucks.

The NRDC report agrees that the expense of EV trucks will outweigh the savings over the next few years. The lifetime expenses for a truck bought in 2025 — including the cost of chargers, charger maintenance and the initial vehicle purchase — will be about $45,000 more for the average medium- to heavy-duty EV truck than a regular truck, the report concludes. That compares to $40,000 in savings the EV will provide on fuel and maintenance at that time, the report says.

But with EV costs expected to fall as volumes increase, the maintenance and fuel savings will outweigh the higher purchase price of an EV.

The report also endorses the Heavy-Duty Omnibus Rules adopted by California in 2020, which mandate the use of newer trucks that emit less nitrogen oxide (NOx), as part of the strategy to cut greenhouse emissions. Both the ACT and Heavy-Duty Omnibus Rule are “pretty integral key pieces to reducing greenhouse gas emissions from the transportation sector,” Kathy Harris, clean vehicles and fuels advocate for NRDC, said in an interview. She said New Jersey has yet to advance the Heavy-Duty Omnibus Rule, and electric vehicles are the priority for NRDC in cutting greenhouse gases.

“It’s pretty clear that that while, yes, we need to get old diesel (vehicles) off the road, moving to new diesel (trucks) is not the solution,” she said. Cleaner diesel trucks are “still going to perpetuate those issues that are associated with diesel currently, which is not good air quality and potential health impacts from those vehicles.”

The DEP appears close to deciding on ACT. “We are working on an adoption document” for ACT, Peg Hanna, the DEP’s assistant director for air monitoring and mobile source programs, told a conference Wednesday on electric school buses. She said that the department is also “closely monitoring” another California rule, the Advanced Clean Fleets rule, which would “impose requirements on fleet owners to actually purchase these electric trucks and buses that the manufacturers are being required to sell.”

At the May hearing, representatives of the New Jersey Business & Industry Association (NJBIA) and the Truck and Engine Manufacturers Association, a national trade group, said they opposed the rules because the cost of compliance would be too high for trucking companies.

“We agree that the future of trucking and heavy-duty vehicles needs to be much cleaner, if not carbon free,” said Ray Cantor, a vice president at NJBIA, in an interview with NetZero Insider Thursday. “However, at this point in time, the technology for heavy-duty vehicles is just not there [and the trucks] are just not affordable.”

Cantor said the organization would like to see more consideration of trucks powered by alternative fuels, such as liquified natural gas.

Tightening Government Measures for EV Trucks

Truckers have been slow to embrace EV trucks in New Jersey. Trucking advocates say that aside from the expense, the vehicle range (about 150 miles) is too small to make them a viable alternative, especially for the large Class 8 tractor trucks that haul containers — and the state has too few charging stations to alleviate that fear.

The Diesel Technology Forum, which advocates for the use of diesel engines, argues that adopting the ACT would limit the choices of truckers in how they respond to climate change. Allen Schaeffer, the organization’s executive director argued, in a recent op-ed that 55% of trucks on New Jersey roads have engines that are newer than 2011 and armed with technology that makes them “near zero emissions.” The state should transition the 52% of older trucks to near-zero technology, he argued, saying that with 55% of New Jersey’s electricity powered by natural gas, the power for most electric vehicles will come from gas-fueled electricity anyway.

“Let’s consider what we can do now rather than just hope what the future might be,” Schaeffer wrote. “Even if the most optimistic of all policy, funding, technology and infrastructure scenarios fall into place, the time frame for zero-emission heavy-duty vehicles to make up a majority percentage of the commercial trucks on New Jersey roads and streets is going to be measured in decades, not years.”

What Policy to Adopt

The NRDC’s report tries to evaluate what can be achieved and the impact on New Jersey’s emissions, resident health and economic situation under three scenarios with varying levels of aggressiveness in promoting electric medium- and heavy-duty trucks.

One way it does so is to look at the “societal benefits” of each. The calculation of societal benefits includes: the monetized value of climate and public health benefits resulting from fewer hospital visits and deaths from pollution; the net cost savings to fleets from operating zero-emission trucks; and savings to all residential and commercial electricity customers due to lower electric rates made possible by the additional electricity sales for electric vehicle charging.

The three scenarios are:

Adopting ACT only: by adopting the ACT, 34% of the state’s in-use medium- and heavy-duty-trucks would become EVs by 2040 and 59% would be EVs by 2050, the report says. That would yield annual net societal benefits totaling about $1.1 billion (in constant 2020 dollars) through 2050, and a 43% reduction in nitrogen oxide (NOx) emissions. The annual cost savings to New Jersey trucking fleets in 2050 would be $446 million, and annual savings in the bills of electric utility customers in the state could reach an estimated $70 million, the report says.
Adopting ACT and the Heavy-Duty Omnibus Rule: The omnibus rule requires a 75% reduction in NOx emissions from diesel trucks sold between model year 2025 and 2026, and a 90% reduction for trucks sold beginning in the 2027 model year. Under that scenario all gas and diesel trucks would become low-NOx vehicles by 2044. Annual societal benefits would be about $1.1 billion.
Adopting ACT, the omnibus rule and other state measures to accelerate an increase in EV sales and ensure that virtually all new trucks are EVs by 2040. That would yield societal benefits of about $2.1 billion. The annual fleet savings would be $843 million and electric customer annual bill savings increase to an estimated $81 million, the report says.

In the first scenario, 34% of the state’s trucking fleet would be EVs by 2040, and the same would happen under the second scenario, although in addition many vehicles would become low NOx vehicles. In the third scenario, 52% of the fleet would be EV by 2040 and 96% would be EVs by 2050, the report says.