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December 30, 2024

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FERC Approves NERC Assessment, Seeks Comment on IBR Standards

FERC on Dec. 19 accepted NERC’s 2024 performance assessment while ordering a compliance filing in six months to explain how it will track its improvement in key areas (RR24-4).

In a separate filing issued during its last monthly open meeting of the year, the commission also proposed approving two reliability standards on protection settings and ride-through requirements for inverter-based resources (IBRs) after a 60-day comment period (RM25-3).

NERC submitted its performance assessment in July, as required by FERC regulations before it can be recertified as the ERO. (See NERC Submits Final Performance Assessment.) It covers 2019 to 2023, a time in which NERC said it strove to become a “nimbler organization while continuing to adapt to the changing needs of the electric industry.”

During the five-year cycle, the grid and the ERO Enterprise weathered the outbreak of the COVID-19 pandemic, several major severe weather incidents, the emergence of serious cybersecurity threats to grid reliability and the ongoing shift from traditional thermal generation to renewable resources. The assessment focuses on what NERC called its accomplishments in this context, in four areas:

    • Energy: addressing challenges arising from the changing resource mix, providing sufficient energy and essential reliability services, improving system performance during extreme weather and adding transfer capability;
    • Security: addressing cyber and physical security risks;
    • Agility: becoming “nimbler” in risk identification and standards development; and
    • Sustainability: investing in automation, eliminating single points of failure, and strengthening the ERO Enterprise’s long-term stability and success.

NERC also evaluated the regional entities’ performance, finding that they “satisfied the relevant statutory and regulatory criteria for delegation of … the ERO’s authorities.” In a supplemental filing, NERC discussed its work to improve the efficiency of its compliance monitoring and enforcement program (CMEP) and data collection. The ERO told FERC it plans to “establish metrics on noncompliance processing to ensure the streamlined compliance exception process produces the intended efficiencies.”

FERC found that the performance assessment satisfied its regulations and that NERC and the REs met the commission’s requirements. However, the commission also noted that NERC’s supplemental filing said the ERO is considering developing new performance metrics associated with the REs’ processing times.

To help this process along, FERC specified that NERC should develop metrics to track three areas:

    • implementation and consistence of risk-based compliance monitoring practices;
    • timeliness of violation processing; and
    • reduction in subsequent serious risk violations stemming from similar issues as prior noncompliance.

The commission directed NERC to submit metrics for the reliability standards development program and implementation and oversight of the CMEP in a compliance filing within 180 days of its order.

IBR Standards Proposed for Adoption

FERC’s second NERC-related order concerned reliability standards PRC-024-4 (Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers) and PRC-029-1 (Frequency and voltage ride-through requirements for IBRs).

The commission’s Notice of Proposed Rulemaking also proposed to adopt a new definition of “inverter-based resource” into the ERO’s Glossary of Terms.

NERC filed the two standards and definition with the commission Nov. 4, along with three more standards related to disturbance monitoring, reporting requirements and event mitigation for IBRs. The standards address the second milestone in FERC Order 901, issued Oct. 19, 2023. Milestone 2 standards cover performance requirements and post-event performance validation for registered IBRs. FERC did not mention the other three standards in its NOPR.

In addition to proposing to adopt the two standards and definition, the commission also proposed directing NERC to file two informational filings after they go into effect. These relate to a provision in PRC-029-1 that allows exemptions to the voltage and frequency ride-through requirements for legacy IBRs — resources that are already in operation when the standard goes into effect. Entities would have 12 months after the effective date of the standard to request an exemption.

FERC said it is curious about “the volume of exemptions, the circumstances in which entities have invoked the exemption provision and ultimately … what, if any, effect the exemption provision has on the efficacy of” the standard. The filings would be due 12 and 24 months after the conclusion of the exemption request period and would provide information on the total number of:

    • IBRs and their capacity for which generator owners will be subject to compliance;
    • IBRs and their capacity for which GOs requested exemptions;
    • IBRs and their capacity for which NERC granted exemptions;
    • granted exemptions by their type (voltage or frequency) and aggregated capacity; and
    • granted exemptions by IBR type and their capacity.

FERC will accept comments on the NOPR for 60 days after its publication in the Federal Register. At the meeting, Commissioners Judy Chang and David Rosner both encouraged industry stakeholders to share their thoughts so that FERC can make an informed decision.

“We’re threading the needle here, aimed at balancing the need to mitigate risk and make sure we have accurate information [and] get this decision right,” Rosner said. “So I look forward to seeing comments there.”

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NJ Legislators Back 2-year Delay on Electric Truck Mandate

A New Jersey Assembly committee Dec. 12 unanimously backed a two-year delay in the implementation of the state’s Advanced Clean Trucks (ACT) regulations that would mandate escalating electric truck sales. 

The Assembly Transportation and Independent Authorities Committee voted 13-0 to advance the bill, A4967, which would require that the rules adopted by the New Jersey Department of Environmental Protection start “no earlier” than Jan. 1, 2027, rather than Jan. 1, 2025. Trucking executives, dealers and business groups had argued that the state has neither the demand nor the infrastructure to comply with the program. 

The bill was one of two approved the same day that highlighted the growing importance of state actions in combating climate change as the transition to the second Trump administration casts a high level of uncertainty over federal initiatives to cut carbon emissions, many of which the president-elect opposes. 

The two bills show legislators pushing in two directions on the climate change debate: While the Assembly committee voted to slow the ACT rules, which Gov. Phil Murphy (D) has aggressively promoted, the Senate Environment and Energy Committee voted 3-2 along party lines to advance S3545, the “Climate Superfund Act,” which seeks to impose a “liability on certain fossil fuel companies for certain damages caused by climate change.” 

Both bills are far from becoming law: A4967 has not moved on the Senate side, and S3545 has yet to advance in the General Assembly. The bipartisan support for delaying the ACT rules, however, suggests that bill could advance. 

Assemblyman Clinton Calabrese (D), chair of the Transportation committee and one of the bill’s sponsors, opened the hearing by reiterating his “steadfast support” for the ACT regulations. But he added that “this bill seeks to address some of the significant challenges that have arisen during this implementation period.” 

Assemblyman Christian Barranco (R) said, “Electrification of the transportation sector is not a political problem, it is an engineering dilemma. 

“We have a very, very difficult problem being able to serve this with the [electricity] generation that we have in place.” 

But environmental groups and other ACT backers said the state has already made great strides and would not have trouble meeting the program’s sales targets. They urged legislators not to slow that progress and disrupt the certainty manufacturers and fleets need to make investments. 

“Based on recent estimates, manufacturers in New Jersey have, in fact, already met their compliance for next year,” with 1,000 battery electric trucks already on the road, said Karla Sosa, New York-New Jersey project manager for the Environmental Defense Fund. “To delay ACT would be a decisive blow to New Jersey’s ability to get clean trucks that we desperately need on the road.” 

Grid, Price Concerns

New Jersey in December 2021 became the third state to adopt rules based on California’s ACT regulations, which require manufacturers of vehicles weighing more than 8,500 pounds to sell an increasing number of electric trucks after 2025. 

The New Jersey rules will require that by 2035, electric vehicles account for 55% of class 2b and 3 trucks, 75% of class 4 to 8 trucks and 40% of truck tractor sales. Vendors would have to comply with a system of credits and deficits based on the proportion of electric trucks that manufacturers sell in the state compared to the number of diesel vehicles they sell. (See NJ Adopts EV Truck Sales Mandate.) 

The committee’s vote comes after the California Air Resources Board (CARB), facing pushback from truckers, voted to adopt amendments to its ACT rules, giving truck-makers more flexibility in reaching the goals. (See Calif. Revises Clean Truck Rules to Ease Compliance.) 

Representatives of the New Jersey trucking sector ― some of whom backed the idea of electric trucks — argued at the hearing that the state is far from ready to make the major transition to electric trucks. The DEP said in October there were 143 electric class 4 to 8 trucks registered in the state, and nearly 5,000 Class 2b and 3 trucks. 

Helder Rebelo, director of fleet maintenance and safety for Newark-based Daybreak Express and president of the New Jersey Motor Truck Association (NJMTA), said the industry’s “very small profit margins” make it very difficult for trucking companies to pay for an electric truck that is about three times as expensive as a $150,000 to $180,000 diesel vehicle. 

“To afford that truck, we are just going to have to pass it on to the consumer,” he said. He added that the grid around his employer’s depot “cannot handle” the heavy charge needed to fuel an electric truck, and company discussions with Public Service Electric and Gas leave it unclear when the necessary upgrade might happen. 

The association said supporters of the bill included South Brunswick-based Hermann Services, one of the foremost electric truck adopters in the state, which has one electric Class 8 truck and 15 on order. The company believes that the state’s infrastructure should be better developed before the rules take effect, the association said. 

Because of these and other factors, demand is way below the level required in the ACT sales mandates, said Joe Cambria, owner of truck dealership Cambria Truck Center of Edison. “Customers do not want to purchase these trucks,” and under the ACT regulations, “our manufacturers will not allow us to order any diesel trucks unless we provide zero-emission credits.” 

“We are hopeful, if delayed, some of these items can be addressed” to make electric trucks more “commercially viable,” he said. 

If not, the rules could create a competitive disadvantage for New Jersey for dealers, said Laura Perrotta, president of the New Jersey Coalition of Automotive Retailers. 

“You can go to Pennsylvania starting Jan. 1, 2025, and buy any truck you want,” she said. “In the state of New Jersey, unfortunately, the manufacturers are going to restrict allocation of diesel trucks” to those dealers that sell enough electric trucks. 

Business Uncertainty

But two EV manufacturers — Rivian Automotive and Tesla — urged the committee not to advance the bill. 

Zachary Kahn, senior policy manager with Tesla, said the company has planned for two years around the law and is ready to sell its Class 8 truck, which can do 500 miles and can be recharged in 20 to 30 minutes. 

Tom Van Heeke, senior policy adviser at Rivian, said any delay would “create regulatory uncertainty for our industry.” 

“Delaying implementation would actually make it more difficult for manufacturers to meet the requirements because it eliminates the gradual ramp up that’s built into the rule,” he said. “We’re building a business, and we’ve been counting on this regulation for several years.” 

Responsible Parties

At the Senate Environment and Energy Committee, legislators supporting the Climate Superfund Act said the evidence of the need for the bill is growing. 

The bill would require the state treasurer to compile an assessment of the damage to the state from climate change and determine the “responsible parties” for the greenhouse gas emissions. The legislation would create a DEP program to “secure compensatory payment from responsible parties” and disperse the funds in a grant program for “climate change adaption and resilience projects.” 

Sen. Bob Smith (D), the committee’s chair and one of the bill’s sponsors, listed extreme weather events, such as Superstorm Sandy and Hurricane Ida. “The people who brought you these damages should be responsible for paying for it.” 

Sen. John F. McKeon (D), the other sponsor, put the cost to the state of recovering from Sandy at $7.2 billion and said the bill is “a cost recovery tool.” 

“This is about who pays for the damage that’s unequivocally directed to climate change, period,” he said. “And here in New Jersey, either the taxpayer pays or the polluter pays.” 

Alex Daniel, counsel for the New Jersey Civil Justice Institute, which represents the business sector, spoke against the bill, arguing it raised constitutional concerns. 

“The simple fact is, for the last 100 years, our national government [and] state governments have actively permitted and encouraged petroleum extraction and refining as part of a national energy policy,” he said. “That national energy policy has resulted in petroleum products being at the very core of our energy industry. 

“The risk posed by retroactive litigation [and] liability is simple: There are settled expectations that people have that the due process protects them from disproportionate liability, particularly where you have an issue like greenhouse gases that aren’t simply an American problem.” 

Ed Waters, senior director of government affairs for the Chemistry Council of New Jersey, said the bill fails to “directly address the causes of carbon emissions and consumption.” 

“It goes unfairly after the companies that were refining, but the actual emissions are generated by the use of fossil fuels,” he said. Moreover, he said, “there was no law against them refining the fuels,” and the law would punish them for something they did legally. 

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Western Market Developers Compare Approaches to GHGs

On the surface, CAISO’s Extended Day-Ahead Market and SPP’s Markets+ will take similar approaches to accounting for greenhouse gas emissions — but important differences remain.

That was a key takeaway from a Dec. 16 webinar hosted by the Western Interstate Energy Board, where designers from both grid operators discussed how each market will deal with the patchwork of GHG pricing, accounting and reporting requirements across different Western states.

While California and Washington are currently the only two states with active carbon pricing policies, several others have carbon reduction goals and other climate regulations that utilities must meet.

That leaves EDAM and Markets+ with a common goal: to implement GHG tracking and reporting in a way that accounts for different approaches to reducing emissions.

CAISO’s Approach

Developing a GHG accounting mechanism for EDAM “wasn’t necessarily a new challenge” for CAISO because California has had a cap-and-trade program in place since 2014, Anja Gilbert, a lead policy developer at the ISO, said during the webinar.

But despite CAISO’s experience dealing with GHG accounting, it faces some new challenges in accounting for emissions in EDAM, particularly involving how to track emissions in states that don’t price carbon.

Key among those challenges is implementing a market mechanism that ensures a state or load-serving entity is only served by generation that meets a certain emissions threshold.

“This is really relevant for states that have climate policies not based on the price of carbon but might have reduction goals over time,” Gilbert says. “There’s a question of if that does need to be reflected in the market.”

Another challenge has to do with unspecified imports being valued at an unspecified emissions rate.

“It doesn’t provide that level of clarity in terms of what generation is really serving that load,” Gilbert said. “That high emissions rate could undermine showing progress toward an entity’s climate goals.”

In response to those challenges, CAISO has proposed to create a residual emissions rate, which would represent a dispatch-weighted average emissions rate of the market supply and allow market participants to reflect and account for the energy and associated emissions for which they’re responsible. Under this framework, leftover energy in the market would go into the residual supply and the emissions rate would be the average of the residual mix.

To respect state preferences, the market’s optimization won’t incorporate GHG costs outside of California and Washington, but CAISO’s market design does incentivize generators to make supply available to those states. For example, if a solar resource in Arizona wants to serve load in California and receives a GHG award, the generator is paid the marginal GHG price paid for by California load.

SPP’s Approach

Over the past year, SPP has been in the process of developing a design for GHG tracking and reporting, and it provided an overview of its approach, which is similar to CAISO’s.

Gentry Crowson, a lead market design engineer at SPP, said the Markets+ GHG framework rests on two “pillars” of pricing design and a tracking and reporting service.

“These two pillars are really going to enable the footprint to be respective of state programs that are in place, as well as with state GHG reduction goals that are also in place,” Crowson said.

SPP’s GHG tracking and reporting “vision” aims for comprehensive reporting through the centralized Market Emissions Tracking and Reporting (METra) application, Crowson explained. The system’s design intends to give Markets+’s load-responsible entities (LREs) the right to claim resources and energy they own or have contracted for, in addition to ensuring that the market accounts for all generation and associated emissions in one way or another.

The first step in SPP’s design approach is called the “mapping” step, where LREs’ registered resources are modeled in a commercial model and matched to a corresponding resource portfolio. In the second step, reporting entities have the option to bring in or send out other resources by submitting them into the METra portal. The third step is to establish a contract between the buyer and seller that is then reflected into LREs’ resource portfolios.

After the market runs and market operators and participants have a better understanding of the actual output, any generation that exceeds the load amount is deemed excess energy and is allocated to a residual energy report, similar to CAISO’s method.

“Once the market runs and you’re looking at a load-responsible entity’s resource portfolio, if that load-responsible entity has any excess energy, we had to come up with options to figure out how to calculate this residual energy pool as we pull together these emissions,” Crowson said.

The Markets+ GHG Task Force unanimously endorsed the tracking and reporting design in September, and the Markets+ Participants Executive Committee approved it in November.

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Biden Sets New US Emissions-reduction Target of 61-66% by 2035

As he prepares to leave office, President Joe Biden has submitted a new U.S. emissions-reduction target to the U.N., committing the country to cutting its greenhouse gas emissions economywide by 61 to 66% below 2005 levels by 2035.

Knowing that President-elect Donald Trump has pledged to pull the U.S. out of the Paris Agreement again, the Biden administration used the announcement of the new goal on Dec. 19 as a call to action for the states, cities and businesses that continued their efforts to reduce GHG emissions during Trump’s first term.

Biden rejoined the Paris Agreement on his first day in office in 2021. As he has throughout his four years in the White House, he linked action on climate change “to more good-paying jobs, more affordable energy, cleaner air, cleaner water [and] healthier environments for everyone.”

“It is also creating real momentum because we’re unleashing American ingenuity and innovation,” the president said in a statement. “American industry will keep inventing and keep investing. State local, and tribal governments will keep stepping up.”

White House Senior Adviser John Podesta was similarly “confident in America’s ability to rally around this new climate goal because, while the United States federal government may put climate action on the back burner, the work to contain climate change is going to continue in the United States with commitment and passion and belief.”

During a media briefing on Dec. 18, Podesta recalled the surge of subnational climate action that emerged in the wake of Trump’s first withdrawal from the Paris Agreement in 2017. One example was the formation of the U.S. Climate Alliance, a bipartisan coalition of 24 governors committed to enacting state policies to reach net-zero emissions economywide by 2050.

Following Biden’s announcement, the alliance committed its members to the new 2035 goal.

“President Biden’s bold leadership is keeping us on a path to achieve a clean energy economy, and together, the country’s climate-leading governors will carry the torch forward,” said New York Gov. Kathy Hochul (D), co-chair of the alliance. “This new collective goal will serve as our North Star, guiding us in the years to come and keeping America on track toward a cleaner, safer future.”

“The only thing clearer than the science and impacts of climate change is the benefit of taking action ― and we’re not slowing down,” agreed Hochul’s co-chair, New Mexico Gov. Michelle Lujan Grisham (D). “By continuing to stamp out climate pollution together, we’re safeguarding public health, protecting the environment, growing the economy and creating good jobs across the U.S.”

The White House said it will submit the new target to the U.N. Framework Convention on Climate Change secretariat as the U.S.’ nationally determined contribution (NDC) under the Paris Agreement. Signed by 196 nations in December 2015, the agreement commits the nations to cutting emissions to limit the increase in the global average temperature to 1.5 degrees Celsius.

As part of its NDC, the U.S. would also cut its methane emissions by 35% by 2035, which the White House said “is among the fastest ways to reduce near-term warming and is an essential complement to CO2 emissions.”

The White House noted “there are multiple paths to meeting these targets, and U.S. federal, state, local, territorial and tribal governments have numerous tools available to work with civil society and the private sector to mobilize investment in the years ahead.”

A recent study from the University of Maryland, College Park found that with a whole-of-society approach that includes “enhanced ambitions,” the U.S. could achieve a 65% reduction in emissions by 2035. But the report anticipated that without federal support, emission reductions of only 48 to 60% might be achieved, highlighting “the impact that non-federal actors can still have despite uncertainties at the federal level.”

The NDC itself has yet to be released, but the announcement raised questions about the current state of U.S. and global climate action following Trump’s election victory and the contentious 29th U.N. Climate Change Conference of the Parties (COP29) in Baku, Azerbaijan.

While advocates continue to talk about “keeping 1.5 alive,” global emissions and temperatures continue to rise. The National Oceanic and Atmospheric Administration has said 2024 has been the hottest year on record, with 2023 now in second place.

The U.N.’s 2024 Emissions Gap Report called for a global reduction in GHG emissions of 42% by 2030 and 57% by 2035 or “the Paris Agreement’s 1.5-C goal will be gone within a few years.”

Speaking on background, a senior administration official noted that the U.S. is currently on track to reduce its emissions 45% by 2030, falling short of the 50 to 52% target Biden set for the U.S. in his 2021 NDC. But the new NDC would confirm a U.S. commitment to the consensus reached in 2023 at COP28 on a “just, orderly and equitable” transition away from fossil fuels in this decade.

The final agreement at COP29 avoided any action on that consensus, but the official noted that the U.S. NDC acknowledges that the country could take multiple pathways to accelerate decarbonization across the economy, while continuing to increase private sector investments.

The White House also consulted with cities, states and tribes, integrating an analysis of their goals into the NDC, a second senior official said. Echoing Gov. Hochul, the official said the NDC is intended as an impetus to cities, states and others to raise their ambitions on climate policy and action.

The new NDC almost certainly will be quickly discounted by Trump and the Republicans who will control both houses of Congress in a matter of weeks, and much uncertainty surrounds the fate of Biden’s signature climate legislation, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act.

Trump campaigned on a pledge to claw back unspent funds from the laws, and some congressional Republicans are already taking aim at specific provisions of the IRA, such as its $7,500 electric vehicle tax credits, to help pay for extending Trump’s 2017 tax cuts, which expire at the end of 2025.

At the same time, those laws have built “a complementary architecture of federal standards that spur demand and generate the regulatory certainty needed to accelerate capital formation and encourage entrepreneurial risk-taking. It is an important combination that has changed the equation” on climate action, National Climate Adviser Ali Zaidi said.

They have also channeled billions in federal dollars and private investment into Republican states and districts, a fact continually raised by Democrats hoping to defend the law’s tax credits and clean energy incentives.

The White House is stressing by-now familiar arguments that the U.S. clean energy transition has hit a tipping point, and its economic and technical momentum will continue, regardless of who’s in the Oval Office. As one of the senior officials said, what will likely change with Trump is the pace and the level of ambition.

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EPA Approves Waiver for California’s Advanced Clean Cars II Rules

Just weeks before President-elect Donald Trump returns to the White House, the Biden administration has given California permission to enforce rules that require all new cars sold in the state to be zero-emission by 2035. 

EPA on Dec. 18 approved a waiver for California’s Advanced Clean Cars II rules, which require an increasing percentage of cars sold in the state to be zero-emission each year until 2035, when all new cars sold must be ZEVs or plug-in hybrids. 

The agency also granted a waiver for California’s heavy-duty omnibus regulation, which sets emission standards for medium- and heavy-duty vehicles. 

Opponents have 60 days to file a petition for review of the decisions. 

“Today’s actions follow through on EPA’s commitment to partner with states to reduce emissions and act on the threat of climate change,” Administrator Michael Regan said in a statement. 

EPA’s decision also means the 11 other states that have adopted Advanced Clean Cars II (ACC II), along with D.C., can proceed with enforcement: Colorado, Delaware, Maryland, Massachusetts, New Jersey, New Mexico, New York, Oregon, Rhode Island, Vermont and Washington.  

The Environmental Defense Fund noted that ACC II jurisdictions account for 33% of the U.S. new vehicle market. 

“EPA’s approval of these standards for California and numerous other states is a welcome action to reduce pollution, including in communities where it’s most needed,” Alice Henderson, EDF director and lead counsel for transportation and clean air policy, said in a statement. 

The California Air Resources Board (CARB) adopted Advanced Clean Cars II in August 2022, updating its previous Advanced Clean Cars regulations. (See California Adopts Rule Banning Gas-powered Car Sales in 2035.) 

ACC II begins with model year 2026, when 35% of new cars delivered for sale in California must be zero-emission. 

In addition to ZEV-transition requirements, the ACC II regulation includes low-emission vehicle (LEV) rules that set emission standards for cars with internal-combustion engines. 

ZEV Progress

California officials celebrated EPA’s approval of the two waivers. 

“Clean cars are here to stay,” Gov. Gavin Newsom said in a statement. “Naysayers like President-elect Trump would prefer to side with the oil industry over consumers and American automakers, but California will continue fostering new innovations in the market.” 

Officials noted that through the end of September, 2.1 million zero-emission cars had been sold in California, and 26.4% of new light-duty vehicles sold in the state in the third quarter of 2024 were ZEVs. 

“Consumers and fleets are increasingly making the choice to drive clean vehicles, and today’s waiver approvals will further that progress,” CARB Chair Liane Randolph said. 

Still, the EPA waivers — and other state climate policies — may face challenges under the new presidential administration.

During Trump’s first term as president, California filed more than 120 lawsuits challenging actions taken by his administration.

In a special session of the state legislature that began Dec. 2, lawmakers will consider funding for the state Department of Justice to quickly challenge actions taken by the Trump administration. Newsom convened the special session “to safeguard California values” — including the fight against climate change. (See Newsom Convening Legislature to Protect California ‘Values,’ Policies.) 

One tool often used to overturn federal agency rules following a change in administration — the Congressional Review Act — doesn’t apply to approved California waivers, Newsom’s office recently told the Los Angeles Times. 

But EPA waivers for other CARB regulations are still pending. Those include waivers for the Advanced Clean Fleets regulation, which requires truck fleets to transition to zero-emission vehicles; the in-use locomotive standards, which ban certain diesel-powered locomotives; and emission standards for small off-road engines, such as those used in landscaping equipment. 

Newsom traveled to D.C. last month to push for federal approval of pending items, including the Clean Air Act waivers, ahead of the incoming administration. 

“EPA continues reviewing additional waiver requests from California and is working to ensure its decisions are durable and grounded by law,” the agency said in a Dec. 18 release. 

Waiver Review

Under the federal Clean Air Act, California may adopt its own vehicle emission standards, but those rules must receive federal approval in the form of a waiver from EPA. Other states may then choose to stick with federal standards or adopt California’s rules. 

The idea is to strike a balance in which car manufacturers don’t face myriad emission standards, while allowing California to innovate on its own standards to combat poor air quality. 

The California standards must be in aggregate at least as stringent as the applicable federal standards. In deciding whether to grant a waiver, EPA considers three “prongs,” Regan explained in his 191-page decision. The burden of proof is on opponents to show that one of the reasons for denial has been met.  

The first is whether California was arbitrary and capricious in determining that its standards are at least as protective of public health and welfare as the federal standards. 

The second prong addresses whether California needs the standards to meet compelling and extraordinary conditions. The third prong looks at whether the standards are consistent with a section of the Clean Air Act that pertains in part to the feasibility of technology in the lead time provided, taking cost into consideration. 

In his decision, Regan addressed many of the comments EPA received arguing for or against the ACC II waiver. Commenters brought up issues such as vehicle affordability, effects on the electric grid and availability of public charging. 

“Although commenters often referred to these topics to support their position that the ZEV standards either are or are not feasible … topics such as these are not within the scope of factors EPA may consider in evaluating consistency with [the Clean Air Act],” he wrote. 

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Oklo, Commonwealth Fusion Unveil Ambitious Nuclear Plans

Two companies developing advanced nuclear technology recently made landmark announcements about their plans. 

Advanced nuclear fission reactor designer Oklo and data center developer Switch said Dec. 18 they had struck a 12-GW power agreement through 2044, saying it was one of the largest corporate clean power agreements ever signed. 

Commonwealth Fusion Systems, which calls itself the largest private-sector company advancing nuclear fusion technology, announced Dec. 17 it would build the first grid-scale commercial fusion plant in the early 2030s. 

Before these plans become reality, this week’s announcements must of course be followed by successful technology development, regulatory approval, siting and permitting processes, favorable public opinion, financing and other milestones. 

Small modular reactors like those Oklo is developing are widely considered to be several years from market-ready, and the running joke about commercially viable nuclear fusion is that it has been only 20 years away for the last half-century. 

But both companies claim a robust list of achievements as they continue on the path to workable and scalable solutions. 

The Oklo-Switch master power agreement is a nonbinding strategic partnership, a framework for collaboration that is expected to yield binding agreements as project milestones are reached. It calls for Oklo to develop and operate power plants to feed Switch facilities across the U.S. through a series of power purchase agreements. 

The master agreement fits with Oklo’s business model of selling power rather than selling power plants. It could accelerate Oklo’s early deployments and position it to scale up to meet the anticipated growth of demand. 

The agreement also serves the priorities of Switch, which says its mission is to build sustainable infrastructure while bolstering the voluntary market for clean and renewable energy. Since January 2016, it has been powering all its data centers with 100% renewable power — nearly 1 billion kWh of it per year. 

Commonwealth’s plan includes a nonfinancial collaboration with Dominion Energy to provide development and technical expertise, as well as leasing rights to a proposed site near Richmond, Va., that is owned by the utility. 

Commonwealth said it conducted a global search for a location to site its first commercial fusion plant. The company plans to independently finance, build, own and operate the facility, which it calls ARC and is expected to be rated about 400 MW. 

If it comes together as planned, ARC is expected to draw significant attention, capital investment and workforce development to that part of Virginia. 

“This is an historic moment for Virginia and the world at large,” Gov. Glenn Youngkin (R) said in a news release. “Commonwealth Fusion Systems is not just building a facility; they are pioneering groundbreaking innovation to generate clean, reliable, safe power, and it’s happening right here in Virginia. We are proud to be home to this pursuit to change the future of energy and power.” 

Both Oklo and Commonwealth have attracted attention among the crowded fields in which SMRs and nuclear fusion are being developed. 

A rendering depicts the design for Oklo’s Aurora powerhouse. | Oklo

Oklo is advancing on multiple fronts with its design of advanced plants that run on nuclear waste. Earlier in 2024, it announced two agreements to supply a combined 850 MW of power to data centers, plus a letter of intent to supply 50 MW to a Permian Basin oil and gas producer. 

Commonwealth is developing SPARC, the fusion demonstration machine that it expects to first produce plasma in 2026. Soon after, it expects SPARC to produce net fusion energy as the first commercially relevant design to generate more power than it consumes. 

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MISO Closing in on New LMR Accreditation

CARMEL, Ind. — MISO said it will finalize an availability-based accreditation for nearly 12 GW of load-modifying resources (LMRs) over the first quarter of 2025 ahead of a filing with FERC.

Some stakeholders remain skeptical of MISO’s plans to rely on past performance levels to accredit LMRs by the 2028/29 planning year.

During a special Dec. 17 Resource Adequacy Subcommittee teleconference, MISO reiterated that it plans to split LMRs into two categories — those that can respond in 30 minutes or less and those that can’t — and accredit them correspondingly.

The RTO said its faster category would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step two events.

On the other hand, the class of LMRs with slower response times would carry a maximum response time of six hours and would be readied earlier under tight conditions, when MISO declares a maximum generation warning. The RTO has long said it needs to be able to access LMRs before emergencies materialize.

MISO said the accreditation will extend to demand response resources participating in the capacity auction. Like the slower LMRs, demand response capacity resources would have a six-hour response requirement and must respond to at least one deployment per season if MISO issues instructions, with reduced accreditation for non-response.

Joshua Schabla, a MISO market design economist, said the RTO doesn’t expect to make major changes to the proposal in the coming months.

“The design is in a good spot. That’s not to mean it’s locked in, or we don’t expect a back and forth,” Schabla said. He added that MISO’s existing LMR accreditation is more than 15 years old and doesn’t reflect performance.

MISO has characterized the two classes of LMRs as “rapid” or “flexible.” However, some stakeholders have said it’s unrealistic to expect load reductions in 30 minutes or less, with many LMRs reasonably being able to respond within two hours. (See “New LMR Accreditation Looks Certain,” MISO Demand Response Under Increasing Scrutiny; IMM Warns of More Potential Schemes and MISO Tries to Win over Stakeholders on New LMR Capacity Accreditation.)

MISO said it will use backward-looking meter data from hours when capacity advisory declarations are in place to gauge availability and accredit resources.

The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year, giving equal weighting to performance during low-margin hours and in hours where capacity advisories escalated into maximum generation events, alerts or warnings. That’s a change from fall, when MISO said it would apply a 20% weighting to low-margin hours and an 80% weighting to capacity advisories and above.

“It’s a very broad framework to capture a very broad set of resources,” Schabla said.

Multiple stakeholders said the accreditation plan still seems too complex and destined to produce unintended consequences.

“We’re seeing accreditation not aligned with what these resources are capable of,” Schabla said. “The stack of resources we can rely on is shrinking.”

Schabla said emergency resources can currently clear the capacity auction “without making themselves available.” MISO said real-time availability data indicate anywhere from 6 to 7 GW of capability from an estimated 9.5 GW participation level, which is “far less” than the auction’s cleared quantity of 12 GW of LMRs.

Schabla said the new accreditation will link availability with accreditation and will motivate demand response operators to give MISO accurate availability data.

MISO said it would also halt its practice of accepting LMRs’ self-conducted testing to verify performance.

Schabla said it’s clear that LMRs’ self-testing is not providing a “good indication” of what the resources can do. He said rolling out MISO-initiated testing will keep cheaper resources that cannot perform from crowding out genuine demand response in the capacity auction.

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MISO Assessment Calls for 17 GW in New Resources Annually

MISO said its members must add an “unprecedented” 17 GW in new resources annually over the next two decades to reliably meet demand and decarbonization goals.

That’s according to the RTO’s finalized Regional Resource Assessment for 2024, which draws on its members’ resource plans to quantify resource expansion needs on a 20-year outlook.

MISO’s Armando Figueroa Acevedo said a 17 GW/year rate would require members to add more than three times their recent average additions of 4.7 GW/year. If members can achieve the more than 340 GW in additions, MISO would boast 515 GW in total installed capacity by 2042.

“Achieving this pace will require several factors, including overcoming supply chain, permitting, labor and interconnection queue delays,” Figueroa Acevedo told stakeholders at a Dec. 18 teleconference to discuss results.

The numbers are in line with results in the draft assessment MISO released in November. (See MISO Prelim Regional Resource Assessment Calls for 343 GW by 2043.)

Members so far have planned to add 163 GW in installed capacity by 2043, less than half of what MISO says is necessary. The RTO filled in a simulated 180 GW of wind, solar and battery storage in its assessment to meet states’ and members’ pollution-cutting goals.

Despite record influxes of renewable energy, Figueroa Acevedo said MISO’s thermal resources are still poised to contribute “the bulk” of accredited capacity by 2043. At that time, MISO expects its lower-accredited wind and solar to account for 62% of installed capacity and have the potential to reach 87% of annual energy.

Between 2029 and 2043, MISO expects 27 GW in thermal retirements and 11 GW in thermal additions, leading to a net loss of 16 GW.

Figueroa Acevedo said MISO’s emerging reliance on solar power is pushing ramping needs from the morning to the evening and will double or triple its average one-hour ramping requirements by the early 2030s.

“A lot of the accredited capacity we see on the system is retained thermal generation and battery storage” entering the system, MISO Director of Strategic Initiatives and Assessments Jordan Bakke said.

WPPI Energy’s Steve Leovy said MISO should consider adding some long-duration energy storage in its modeling. Other stakeholders said the RTO seemed to underestimate how much storage can help improve reliability.

Bakke said the long-term assessment is meant to reflect members’ planning and said next year’s results could change depending on how many new resources members can scale over the next few years. He said the assessment is meant to “highlight the challenges of what we’re collectively trying to do across the footprint.”

MISO’s resource projections in the assessment began with 2029, skipping the next few years, where the RTO has said it could come up short on capacity.

America’s Power CEO Michelle Bloodworth said MISO should be focusing in particular on the next five years, given the heightened danger to reliability. Staff said the Regional Resource Assessment is intended to examine long-term needs while the annual resource adequacy survey conducted by MISO and the Organization of MISO States concentrates on near-term capacity sufficiency.

MISO fared the worst among all regions in NERC’s 2024 Long-Term Reliability Assessment, being the only region categorized as high risk, with NERC calling attention to possible shortfalls starting in 2025. MISO leadership has also raised the possibility of shortages within a few months and said it’s crucial for the grid operator to devise a fast lane in its interconnection queue for necessary generation projects. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must.)

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ISO-NE to Work on State-backed RFP for Northern Maine Transmission

Backed by a new process conducted by the New England states, ISO-NE is moving forward with a request for proposals to build new transmission that would bring wind to market from Northern Maine.

The New England States Committee on Electricity presented its request at the ISO-NE Planning Advisory Committee’s meeting Dec. 18. The RTO plans to develop the RFP and release it by March.

“This is the first time that we’re using this process, and so we wanted to focus on investments that we have a high confidence in, that they’ll provide a lot of value for consumers; this concept of least-regrets transmission,” Jason Marshall, Massachusetts deputy secretary and special counsel for federal and regional energy affairs, said in an interview.

The RFP will be the first use of new rules FERC approved in July that allow states to identify a transmission need and then have the RTO run a solicitation to meet it. (See FERC Approves New Pathway for New England Transmission Projects.)

North-to-south transmission capacity in the region has been lacking, with Marshall saying it has limited the ability of generation to move to load centers to the south.

“As a result, resources have been really curtailed up there, and it’s limited our access to low-cost clean energy generation,” he added.

The RFP would also facilitate the interconnection of new wind resources, which have been held back by the lack of transmission to the resource-rich region, Marshall said.

“Strengthening the connections between northern and southern New England will enhance reliability and market efficiency by resolving known constraints on the transmission system and will also position the region to more efficiently integrate affordable resources in coming years,” NESCOE wrote in a memo to the RTO. “There is broad interest in addressing these longstanding system challenges, and strengthening the transmission system in Maine is a reasonable, measured first step toward the region’s needed transmission investment.”

The RFP targets increasing transfer capacity starting at a substation in Pittsfield, Maine — west of Bangor — and down through the southern part of the state into New Hampshire. Several parties asked in comments for the states to issue multiple RFPs based around the multiple needs for new transmission. (See ISO-NE Stakeholders Respond to Potential Long-term Transmission RFP.)

The states have been discussing the option for the multiple RFPs, and they also brought up that issue with the RTO, NESCOE’s Sheila Keane said at the PAC meeting.

“We understand that multiple RFPs could risk an unintended consequence of inefficient investment and extend the timeline for needed investment,” she added. “So, we certainly take that into mind in our final decision, and at this time, we accept that recommendation that a single, comprehensive RFP scope is the most efficient way forward.”

The tariff requires a complete solution for the needs identified, but Keane said the states are interested in maximizing competition in the process, and that could change in future RFPs.

The RFP is just one of several processes that could increase transmission from Northern Maine, where the grid is operated not by ISO-NE but by the Northern Maine Independent System Administrator and is connected to the Eastern Interconnection through New Brunswick.

The U.S. Department of Energy has offered an investment as an initial off-taker for a major line to the region. (See Long Road Still Ahead for Aroostook Transmission Project.)

The Maine Public Utilities Commission has opened a proceeding looking into better connections for the region, and Massachusetts has the authority to do out-of-state procurements for clean energy, Marshall said.

“I think we would view these activities as complementary,” he added. “They are different processes though, but again, at least for our state, we’re in an early phase.”

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Vistra Extends Baldwin Coal Plant Operations as MISO RA Risk Climbs

Vistra is extending the life of its coal-fired Baldwin Power Plant in Illinois through 2027 amid MISO delivering warnings over a supply crunch in its footprint.

The Irving, Texas-based company said Dec. 17 that it will keep the Baldwin plant running for an additional two years while still meeting EPA retirement and pond closure obligations. Vistra originally announced in 2020 that the 1,185-MW coal plant would close at the end of 2025.

The utility said the extension will buy the region some time to bring new generation online while helping to avoid a capacity shortfall.

“Vistra is committed to the responsible transition of our fleet in Illinois, and in this case, the most reasonable path forward is to continue to operate the plant as a reliable bridge to 2027, as we, and others, bring new generation assets online in the state,” CEO Jim Burke said in a press release. “As many organizations have recently raised concerns over reliability and resource adequacy in central and southern Illinois, we are taking action and delivering solutions that balance the needs of reliability, affordability and sustainability.”

The company has built a 68-MW solar farm and 2-MW/8-MWh energy storage facility at Baldwin; they began operations this month. It said its current coal-solar-storage setup at Baldwin “demonstrates the company’s commitment to evaluating how to best leverage the footprint, infrastructure and transmission connections already at the plant sites to meet the evolving electricity needs of customers.”

Vistra has planned on-site solar and storage at its other downstate coal plants as part of Illinois’ Coal to Solar and Energy Storage Initiative. It has completed a 44-MW solar and 2-MW/8-MWh storage facility at the Coffeen Power Plant and will begin construction of a 52-MW solar and 2-MW/8-MWh storage facility at the Newton Power Plant in 2025.

Vistra also noted it has begun construction on a 405-MW solar farm that will interconnect at its retired Joppa Power Plant.

MISO has said it could contend with a capacity shortfall as soon as the upcoming summer. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.) While the RTO and the Organization of MISO States’ five-year resource adequacy survey this year did not show the potential for such an immediate shortfall in southern Illinois’ Zone 4, nearby Zone 5 in Missouri was flagged for substantial risk.