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December 25, 2024

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PJM Stakeholders Discuss Capacity Market Changes After Winter Storm

PJM’s Independent Market Monitor has proposed a plan to eliminate performance assessment intervals (PAIs) and related penalties from the RTO’s capacity market, saying the non-performance charges stemming from the late-December cold snap have threatened the functioning of the market.

“Winter Storm Elliott provided the first real test of the [capacity performance] design. Elliott showed that the CP design does not provide effective incentives,” Monitor Joe Bowring said during the Jan. 31 meeting of PJM’s Resource Adequacy Senior Task Force.

Under the Monitor’s design concept, capacity resources would only be paid the capacity price when they are available in a given hour and would be required to have firm fuel, which entails access to dual fuel, multiple pipelines or a defined amount of onsite fuel storage, plus weekly testing to ensure that the resources can produce when called upon.

Capacity resources would also be subject to a must-offer requirement. When energy is valuable, resources that provide energy will be paid the high market prices for energy and reserves, as the energy market provides the correct energy pricing, Bowring said.

“If we can’t handle two days of cold weather without having a massive dislocation, we need to rethink how this market is designed,” Bowring said. “The penalties create potential threats to the incentives to invest in existing resources and to invest in the new resources that will be needed in the next three to five years.”

Bowring also said his design would replace the effective load carrying capability (ELCC) accreditation model for intermittent resources. By only paying such resources when they are delivering energy, he said the change would recognize that intermittent resources are not always available while still allowing them to be compensated for when they are online.

“ELCC is very quickly going to end up with a marginal value of zero for standalone solar and wind while continuing to have a performance obligation equal to its full capability. … What I’m proposing is something very different, which is paying capacity only when it’s available,” he said.

That tension between the reduced megawatts that qualify as capacity and the obligation to perform at the full megawatt value of the resource will make offering intermittent resources as capacity increasingly untenable under the ELCC approach.

The Monitor’s proposal would build on FERC’s 2021 rejection of the CP market seller offer cap (MSOC) and “would recognize that the capacity performance model was a failed experiment,” Bowring said. (See FERC Backs PJM IMM on Market Power Claim.)

“The only purpose of the capacity market is to make the energy market work. The fundamental mistake of the CP design was to attempt to recreate energy market incentives in the capacity market,” Bowring said. “The CP model was designed on the assumption that shortage prices in the energy market were not high enough and needed to be increased via the capacity market.”

Bowring noted that the CP design focuses on a small number of critical performance assessment hours, imposing large penalties on generators that fail to produce energy only during those hours. He said the use of capacity market penalties rather than energy market incentives created risk.

“While there are differences of opinion about how to value the risk, this CP risk is not risk that is fundamental to the operation of a wholesale power market. This is risk created by the CP design in order, in concept, to provide an incentive to produce energy during high demand hours that was even higher than the energy market incentive,” he said.

PJM has said that generators may be facing total penalties between $1 billion and $2 billion for as much as 46,000 MW in capacity being offline during the storm, including over a third of gas resources. That has raised concern about significant amounts of generation leaving the market, either through default or determinations that there is too much risk in the exchange. (See PJM Gas Generator Failures Eyed in Elliott Storm Re view.)

“Everybody knew what the potential penalties were. Nonetheless, the behavior did not match … that expectation. … Massive penalties are not the answer here,” Bowring said.

David “Scarp” Scarpignato, of Calpine, suggested that a third product may be needed alongside energy and capacity resources, noting the impact the fuel requirements would have on certain gas generators.

Combustion turbine plants connected to only one pipeline would no longer be able to participate as capacity resources and therefore lose their capacity interconnection rights. Without the guaranteed access to the transmission grid when shortage pricing is in effect, those units may no longer be economical, he said.

Steve Lieberman, of American Municipal Power, said the majority of generator conversations around the MSOC come down to properly defining their units’ capacity performance quantified risk (CPQR) — the risk that they will face non-performance penalties. AMP has proposed one of six design concepts currently being discussed by the RASTF, along with the IMM.

“I believe what Winter Storm Elliott has taught us is we need to put the scalpel away and it might be time for the chainsaw. … We do agree CP is a failure; it was an experiment that we implemented after the polar vortex,” he said.

AMP’s proposed design includes a higher degree of fuel availability for capacity resources, namely dual fuel or onsite inventory, and would expand the use of ELCC accreditation to thermal resources.

“An approach that’s similar for thermals and non-thermals alike is our preference,” Lieberman said, adding that he has reservations about ELCC, but feels that having one accreditation approach for all resources is best.

Stakeholders Seek More Clarity on Offer Caps

With deadlines approaching for June’s 2025/26 Base Residual Auction, Jeff Whitehead, of GT Power Group, said that generation owners will soon have to make decisions about their CPQR and unit-specific offer caps. He said guidance from PJM and the IMM on what will be allowable would aid in the drafting of those figures.

He noted that without changes to the current auction schedule, there are few parameters that can be changed in time, primarily the performance assessment hour assumption.

“I think we need to come to a common agreement on what is a reasonable basis for including Winter Storm Elliott, or I’ll say more broadly the changes in the penalty risk view that comes out of that event,” he said.

Bowring said he believes the current MSOC construct is correct and the best way to incorporate the winter storm data into offer caps is by rerunning the simulations the Monitor conducts with the data from Elliott added in. Part of his consideration of the storm’s impact is that to an extent the emergency conditions were the result of generators being unavailable.

“We have to operate in a rational defined space, and that space is going to be calculating what we think the impact on CPQR is of the actual facts of Elliott,” he said. “Given that this is the first significant PAI event since the introduction of the CP model, it is unlikely to have a large effect on CPQR.”

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Berkeley Study Finds Rising PJM Interconnection Costs

A study released by the Lawrence Berkeley National Laboratory last month found that interconnection costs have been steadily rising for decades in the PJM region and are disproportionately high for renewable resources.

“The core finding that we’ve had for PJM is overall interconnection costs have increased both for projects that have completed all the required interconnection studies, as well as for those projects still moving through the interconnection process,” said Jo Seel, principal scientific engineering associate with the lab. The study is part of a series looking at interconnection costs for each RTO in the U.S.

Drawing off available interconnection studies released by PJM, the study found that costs for generators that have successfully connected to the grid have doubled from 2000 through 2019. The average for completed projects has grown even more sharply over recent years, rising from $29/kW between 2017 and 2019, to $240/kW between 2020 and 2022.

Costs are highest for projects that ultimately dropped out of the interconnection process, at $563/kW, which Seel said could point to network upgrades being a driving factor behind projects leaving the queue.

“It seems to me pretty likely that high interconnection costs make a certain set of projects infeasible and they cannot move forward,” Seel said. “We see that especially well for solar projects, where the upgrade requirements for some of these solar projects is up to nearly 40% of the overall project [capital expenditures] … that just breaks project economics, so I think that’s a pretty good explainer of why some of these solar projects then do not move forward and ultimately withdraw.”

The study also found a wide gap in network upgrades for different resource types. Natural gas carries some of the lowest costs, with an average of $24/kW, while offshore wind was the highest at $385/kW. Onshore wind saw average interconnection costs of $136/kW, while solar projects had costs around $253/kW.

Scale of Rising Costs Questioned by PJM

PJM Senior Director of Interconnection Planning Jason Connell said he believes the study overrepresents the extent that network upgrade costs have grown because of the inclusion of feasibility studies in the data. Because the studies identify the upgrades that an individual project would require to interconnect prior to cost allocation between projects, he said it could result in double counting of costs if multiple projects needed the same upgrade.

“The issue is that those projects for which they’re scraping the data are in various stages of completion: some very early on in the feasibility stage, and some have signed and executed an interconnection service agreement. It doesn’t make sense to compare them as an aggregate, because those study costs get refined the further along a project is in the study process,” he said.

Seel said that wherever possible, the Berkeley team looked for the most recent and accurate data available, and only a small number of feasibility studies were included in their data. In those cases, they sought to correct for the possibility of double counting and, he believes, were able to formulate accurate findings.

“We used the best available data to categorize these costs,” he said.

Independent Market Monitor Joe Bowring said data accessibility at PJM has long been a challenge, making it difficult for studies to be conducted.

“If PJM wants more accurate studies done, they should provide more accurate data,” he said.

As the grid becomes increasingly complex and built up, Connell said costs are bound to rise to a degree. While the first few projects in a region may require replacing equipment at a substation, subsequent installations may necessitate the reconducting of lines or substation rebuilds. Despite the growing investments needed, there’s been no slowdown in the number of new requests for interconnection studies across resource types, including developers looking to install renewables.

“Each upgrade is an order of magnitude of difference for each of the newer projects,” he said.

The new approach for studying interconnection requests approved by FERC last year could provide more clarity on the costs developers could face, Connell said. The new methodology clusters projects together both for identifying network upgrades and allocating costs. It also requires that deposits be made throughout the process to discourage speculative filings. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Seel pointed to the medium-term transmission plans conducted by MISO as another approach for lowering network upgrade costs. The RTO’s plans identify larger network upgrades, and it makes the necessary investments itself, rather than allocating the expense between individual generators based on interconnection requests. A more holistic and forward-looking approach to evaluating grid upgrades can create efficiencies that outweigh the investments, he said.

Bowring said he’s hopeful PJM’s new interconnection process will decrease costs by making the interconnection process more efficient and reducing speculative filings, but he believes that retaining competition and accurate costs in the buildout of transmission is important to ensuring that generation is sited in the most economical locations. Upgrade costs rising are appropriate so long as they reflect the reality of the cost to interconnect, he said.

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Electric MHD Truck Incentives Promoted in NJ

For years, Faith Krausman, a Montclair, New Jersey, veterinarian who specializes in treating animal arthritis, drove her SUV to make house calls to attend to her patients.

So, when a patient’s owner mentioned that she had applied for a government grant to buy an electric vehicle, Krausman — whose interest in protecting the environment began in high school — immediately saw the possibilities for her business, Vet-On-Wheels.

“I always wanted to have a van to do this with the house calls,” Krausman said. A tall van, which allowed her to stand up, could be refitted as a mobile animal clinic in which she could see the patients in the van, instead of going into their homes and potentially making a mess, she figured.

“I would be able to do my full exam in the van with my nurse assisting,” she said. “And the owners would also be very happy that I’m not dirtying up their floor, like with shaving fur and getting blood, and this and that. So, their homes are kept nice and tidy.”

Moreover, she added, while similar mobile clinics generate carbon emissions because they run a gasoline or diesel engine to power the clinic during the examination and any surgery needed, Vet-On-Wheels’ electric vehicle would be emissions-free.

Krausman, who is outfitting the van, spoke about her project at a forum Thursday held by the New Jersey Economic Development Authority (EDA) to promote the program that provided her with the incentives to buy the van — NJ ZIP (New Jersey Zero Emission Incentive Program). The agency is stoking interest in EV truck purchases as it prepares to launch the second phase of the program, with $46 million in funding available, at the end of March.

The effort is part of an ongoing push by the state to trigger greater use of electric trucks as vehicle selection increases, drivers and fleet owners become more open to the concept, and the state’s early electric vehicle (EV) promotion policies mature.

Alongside the expansion of the NJ Zip program, the New Jersey Board of Public Utilities (BPU) in January began accepting applications for a $16.1 million program that provides incentives for the installation of chargers for medium- and heavy-duty (MHD) electric trucks. Receipts from the Regional Greenhouse Gas Initiative (RGGI) fund the program.

In addition, after a final hearing on Jan. 17 to solicit stakeholder input, the BPU is putting the final touches on a proposed rule framework that would stimulate the funding and development needed to create private and public chargers serving MHD trucks around the state. Transportation accounts for 42% of emissions in New Jersey, and MHD buses and trucks, although only 4% of all vehicles on the road in the state, account for 25% of the pollution, according to the BPU. (See NJ Retools Electric MHD Truck Charger Proposal.)

“We’ve all had the experience of driving behind a bus or truck and smelling the thick metallic diesel exhaust that emerges in its wake,” BPU President Joseph L. Fiordaliso said in a statement to announce the opening of the charger incentive program. “Through smart and strategic programs and investments, like those featured in this charging program, we can achieve cleaner air in overburdened communities and cost savings for business owners.”

Costly But Worth It

Krausman and two other grant recipients spoke at the NJ ZIP forum Thursday to help educate small businesses on the benefits of EV truck ownership as the EDA launches the second phase of the program, the state’s largest designed to promote the purchase of EVs. EDA officials said interest in the program, which awards funding on a first-come, first-served basis, is high. About 450 people signed up to learn about the program and hear from successful applicants.

The voucher-based program has awarded applicants $39 million so far for the purchase of 370 trucks, 89% of which have been Class 4 vehicles and the remainder Class 3, 5 or 6 trucks. The second phase of the program expands the focus to include the purchase of Class 7 and 8 vehicles — the largest trucks on the road, which typically haul trailers — and provide grants to trucks that will be located or working anywhere in the state, rather than in specific target areas.

Moises Luque, CEO of the Supreme Green Team, a delivery company that serves warehouses, told the forum that creating an environmentally friendly business was so important to him that his entire fleet of six trucks are electric, all funded by NJ ZIP.

He estimated that his fleet has avoided six tons of carbon emissions and said running on electricity is cheaper than on fossil fuel, especially given today’s elevated gas prices.

“It’s a little costly upfront,” he said, of opting for EV vehicles. “However, in the long run, it is well worth it.”

The program’s second phase will award $20,000 for a Class 2b truck and $90,000 for a Class 6 truck, levels that are designed to cover 75% to 110% of the extra cost of an electric vehicle over a fossil fueled vehicle, according to the EDA. The program will award up to $135,000 for a Class 7 truck and $175,000 for a Class 8 truck.

About one third — about $15 million — of the funds will be set aside for small business and another third for businesses that are located or work in environmental justice and overburdened communities. Applicants can increase the amount awarded with bonus increases if they operate a certified woman-, minority- or veteran-owned business or commit to driving 50% of the vehicle miles in overburdened communities for three years. School bus purchases also warrant extra bonuses.

Jessie Phillip, whose company renovates commercial and residential properties, said the distance limitations of an EV truck and the fact that it takes longer to charge up than it does to fill a truck with gas are certainly a factor. But they also force him to be more organized — to know where charging points are located and to closely plan his charging schedules, he said.

EVs are in some ways easier to operate, he said, noting the lower maintenance needed and the ease of charging vehicles at home overnight.

“Hey, I don’t have a gas station in my house,” Phillip said.

Public or Private Fleets

New Jersey officials know that to spark a widespread embrace of electric trucks they need to ensure plenty of charging options around the state. The RGGI-funded program to encourage installation of chargers for MHD trucks is a key part of that effort, aiming to reduce the much-cited concern that EVs can be stranded with no power because the driver couldn’t find a charging station.

The program, which will accept applications through May 12, is designed to encourage trucking companies to go electric by focusing on the development of chargers in two main areas: community charging stations in locations that could serve several trucking companies and depots to serve private fleets.

Developers of public chargers can get up to 100% of the purchase and installation costs, including up to $225,000 toward the purchase and installation of 150-kW or greater dual-port, networked DC Fast Charger (DCFC).

Funding of up to $175,000 is available for the purchase and installation of 150 kW or greater dual-port, networked DCFC for use charging a private fleet. Applicants can apply for funding for up to six chargers. (See NJ BPU Approves $16M for 1st MHD EV Charger Program.)

Stimulating Private Investment

The BPU’s straw proposal, however, seeks to establish a framework in which private funds are the driving force for charger development. The proposal is focused on “questions about who should construct, own, operate, and pay for the MHD network necessary to make New Jersey a national leader in the adoption of electrified MHD fleets and the build-out of an MHD EV Ecosystem.”

The BPU calls it a “shared responsibility” model that “promotes appropriate roles for both EDC and private investors as well as private efforts to drive MHD adoption.” The agency released a version in June 2021 and then reshaped it using stakeholder input from six public hearings, and released a new version in January (See NJ Retools Electric MHD Truck Charger Proposal.)   

The biggest change in the latest version is a shift to allow private fleets to obtain incentives and support for developing make-ready projects — those with the cables, equipment and infrastructure to hook up a charging station. To be eligible, private fleets must be located or primarily operate in overburdened communities.

Private fleet charging depots seeking incentives must also replace existing fossil-fueled vehicles with electric trucks rather than simply adding them and must also agree to participate in a managed charging program, requiring that 90% of its charging needs be done in off-peak periods to minimize the extra burden on the grid and help drive down electricity rates.

Charging Burden

Several speakers at the Jan. 17 stakeholder hearing expressed support for the revised proposal, but others had concerns, particularly over the managed charging requirements.

Zack Khan, senior policy manager for Tesla, which has developed the Semi electric truck, said the proposal does not go far enough in supporting private fleets. He called it “unnecessarily complicated and burdensome on fleets, when the priority should be getting the most zero emission trucks on the road in New Jersey as fast as possible.”

“We suggest the proposal be amended so that every private charging location for truck fleets be eligible for some level of make-ready funding,” Khan said. “If the state wants to target overburdened communities, which we support, it can make those chargers eligible for 100% of make-ready costs and make all others eligible for a lower amount, whether that is 50% or 75%.”

Khan said the managed charging requirement was “problematic” and could dissuade companies from electrifying their fleets if they’re concerned about limitations on “when and how they fast they can charge their vehicles.”

Nicholas Raspanti, director of business development for Zeem Solutions, a California company that develops fleet charging hubs, urged the BPU to be flexible in the requirement that 90% of charging be done off-peak.

“We feel that that could be overly burdensome,” he said, suggesting that the managed charging rules could impact the speed of EV truck adoption.

Judy McElroy, CEO of Fractal Energy Storage Consultants, called the BPU’s suggestion that utilities implement demand charges “the elephant in the room.” One suggestion in the proposal is that the managed charging rules could be enforced by increasing the charging cost during peak charging hours.

McElroy said that demand charges make sense from the utilities’ point of view, to make customers pay their share if they charge at peak hours, rather than making ratepayers foot the bill. But she encouraged the BPU to reevaluate the strategy.

“I commend the proposal on offering incentives to accelerate adoption, but unless there’s a vehicle to address the ongoing threat of demand charges, I don’t feel like this is scalable, sustainable or economically viable,” she said.

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New Coalition Aims for California to be in RTO

A new coalition of trade and environmental groups says California needs to be part of an RTO to achieve its clean energy goals and maintain reliability, adding its voice to those calling for Western organized markets and for CAISO to grow into a multistate RTO.

Calling itself Lights on California, the coalition’s members include national trade groups Advanced Energy United and the Solar Energy Industries Association, environmental organizations Natural Resources Defense Council and Environmental Defense Fund, and the California Chamber of Commerce, which wields significant influence in the state capitol.

Lights on California launched Monday with a news release and website, saying its purpose is to raise awareness about the “state’s options for building a more affordable, more reliable clean energy grid through participation” in a Western RTO and to advocate for that goal.

“We simply cannot afford to be left behind as the rest of the West looks for regional solutions that will enhance reliability,” Chamber of Commerce Policy Advocate Brady Van Engelen said in the news release. “An RTO is clearly one of the best ways to deliver it, providing a framework for tapping into vast wind, solar and other reliable, low-cost clean energy supplies across the West.”

The group’s announcement was the latest development in a reinvigorated effort to allow CAISO to become an RTO. Several prior attempts failed, the last in 2018, because lawmakers were unwilling to change the ISO’s rules to allow out-of-state members to serve on its Board of Governors.

Circumstances in the West have changed substantially in the years since, fueling a new push and giving advocates more hope of success.

The new conditions include strained supply in CAISO and its neighbors during Western heat waves, the need for new transmission to carry renewable power long distances across the West, and legal mandates for Colorado and Nevada transmission owners to join RTOs by 2030. In addition, more states are adopting clean energy and emissions reduction targets, which advocates say will be much easier to achieve in an RTO.

Potential competition from SPP, which plans to establish its own Western RTO, and from the Western Power Pool, whose Western Resource Adequacy Program could be a springboard to an RTO, are lending urgency to the latest CAISO governance reform effort.

The coalition cited last year’s unanimous passage of Assembly Concurrent Resolution 188, which asked CAISO to prepare a report for the state legislature summarizing studies of the benefits of regional market participation. Assemblymember Christopher Holden, who headed the 2017/18 effort to make CAISO a regional organization, authored ACR 188 with the intent of restarting the conversation on CAISO becoming an RTO. (See Plans Revive to Make CAISO a Western RTO.)

A draft of the report, performed by the National Renewable Energy Laboratory for CAISO, was published Jan. 13 with a final version due to lawmakers by the end of February. Among the studies it examined was one led by state energy offices in Utah, Colorado, Idaho and Montana that found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

“As the legislature considers how best to act on the CAISO/NREL findings, the Lights on California coalition will be working together to raise awareness about the benefits of an RTO for consumers, for businesses, for workers and for the environment,” the group said in its news release.

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Feds Charge Two in Alleged Conspiracy to Attack BGE Grid

The Department of Justice has charged neo-Nazi leader Brandon Russell and associate Sarah Beth Clendaniel with plotting to attack electric substations in Baltimore, saying they envisioned a “legendary” attack that would “completely destroy” the city.

Russell — a resident of Orlando, Fla., and the founder of Atomwaffen Division, which DOJ considers a “racially or ethnically motivated violent extremist” group inspired by Nazi beliefs — “provided instructions and location information” to Clendaniel, of Catonsville, Md., FBI agent Tom Sobocinski said at a press conference Monday morning. Clendaniel plotted to acquire the weapons for the attack and identified five substations to target, according to a media statement from DOJ.

“The accused were not just talking, but [were] taking steps to fulfill their threats and further their extremist goals,” Sobocinski said.

Conspirators Met While in Prison

The criminal complaint against Clendaniel and Russell is still sealed, but a copy of the complaint obtained by CNN went into more detail about the pair’s plans, as well as how the FBI discovered their operation. According to the complaint, the two have been acquainted at least since 2018, when they exchanged correspondence while both were incarcerated at separate facilities.

Brandon Russell Mugshot (Pinellas County Sheriff's Office) Content.jpgMugshot of Brandon Russell from his arrest in 2018. | Pinellas County Sheriff’s Office

Russell was imprisoned in January 2018 for possessing explosive material, after a former Atomwaffen member told investigators that Russell and other members were planning to attack infrastructure including power lines and a nuclear plant in Florida. When the FBI arrested him for the Maryland plot, he had just completed his five-year prison term and was on a three-year supervised release. The reason Clendaniel was in prison in 2018 was not given in the complaint, but it did explain that she had a history of drug and robbery convictions.

While in prison, Russell struck up an online correspondence in June 2022 with a third person working for the FBI, identified in the complaint only as “CHS [confidential human source]-1.” Russell encouraged CHS-1 to carry out attacks against critical infrastructure, specifically electrical substations. As part of their conversation Russell provided the informant with white supremacist publications that discussed attacking critical infrastructure and called “putting holes in transformers … the greatest thing somebody can do.”

Russell first mentioned Clendaniel to CHS-1 last month, saying she was “serious and can be trusted.” Later the same day Clendaniel introduced herself to the informant, saying that she was terminally ill and wanted to “accomplish something worthwhile” before she died.

The complaint only discusses the messages between Clendaniel and CHS-1 and between CHS-1 and Russell, with no record of messages sent between Clendaniel and Russell directly or of chats involving the three of them.

As the three continued to develop their plan over the next few weeks, Clendaniel identified five substations she planned to target in a “ring” around Baltimore and told the informant that she would like to destroy all of them in the same day. She told CHS-1 that a successful attack would “probably” cause a cascading failure of the local grid. The FBI later confirmed that all five substations were operated by Baltimore Gas and Electric, a subsidiary of Exelon (NASDAQ:EXC).

“If we can pull off what I’m hoping … this would be legendary,” Clendaniel said on Jan. 29, according to authorities. Clendaniel allegedly said if they hit several of the substations on the same day, they “would completely destroy this whole city.”

Russell’s conversations with the informant included comparing the planned substation attack to December’s mass outages in Moore County, N.C., when unknown attackers damaged two Duke Energy (NYSE:DUK) substations with rifles and caused more than 54,000 customers to lose power. (See Duke Completes Power Restoration After NC Substation Attack.) Asked by CHS-1 why specific substations were chosen, Russell explained that they were selected to have the biggest impact on the power grid.

Asked how many people could have been affected if the attacks had gone through as planned, Sobocinski said that the FBI “believes this was a real threat,” and that “our hope is that it would have been minimal, but we couldn’t … tell you what that result would look like.” While Sobocinski declined to provide details of the arrest, the complaint said that investigators determined that the people communicating with their operative were Clendaniel and Russell based on details they disclosed in their chat conversations. Agents who were familiar with Russell’s voice were also able to recognize him on voice messages left with CHS-1.

Incidents of Violence on the Rise

Russell and Clendaniel’s plans are reminiscent not only of the Moore County attacks, but also of a plot to damage electric substations to which three men pleaded guilty nearly a year ago. In that incident Christopher Cook, Jonathan Frost and Jackson Sawall each admitted to planning to destroy critical infrastructure in order to “sow hate [and] create chaos” inspired by “racially or ethnically motivated violent extremist views.” Like Russell and Clendaniel, the conspirators were caught by law enforcement before carrying out their goals. (See FBI: Conspirators Planned Grid Attack to Start Race War.)

The arrests come just days after the Department of Energy released a report showing incidents of deliberate physical damage to bulk power system facilities rose by 77% in 2023 from the year before. (See DOE: Physical Attacks, Sabotage Jumped in 2022.)

The charges against Clendaniel and Russell of conspiring to destroy an energy facility carry a maximum sentence of 20 years in federal prison.

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Low-carbon Propulsion is Changing Aviation

Commercial aviation can be carbon-free, say engineers and commercial airline planners who see the changes coming first in smaller electric aircraft built specifically for commuting and able to slip in and out of airports abandoned by major carriers.

Privately held Eviation, of Washington state, is one of a handful of companies designing electric aircraft powered entirely by batteries. Alice, its sleek nine-passenger electric commuter, successfully flew for the first time in September 2022, reaching an altitude of 3,500 feet. (See Electric Commuter Plane Takes Flight in Wash.)

Gregory Davis (BloombergNEF) Content.jpgEviation Aircraft CEO Gregory Davis | BloombergNEF

Eviation CEO Gregory Davis appeared last week at a BloombergNEF conference in San Francisco to talk about the company’s plans. He was joined in a seminar by representatives of Alaska Airlines and European aerospace company Airbus.

“We’ve shown that the technology exists to make an electric airplane, and it’s today’s technology,” said Davis. “We’ve addressed the technology of the batteries … in terms of the architecture and the certification of those batteries.”

The design of the aircraft — motor-driven props at rear behind the batteries and passengers in the front — was driven by “where we needed to put the batteries to make the aircraft perform properly,” said Davis.

The sleek fuselage and wings as aerodynamically efficient as possible were designed to maximize lift, he added.

“We’ve been working with the [Federal Aviation Administration]. We’re building a commuter category aircraft. So it is certified under a set of standards that are complimentary for the size of the airplane.”

The company is projecting it can begin selling Alice to fly routes of 250 nautical miles as soon as 2027, said Davis.

“That’s a regional market. It’s a market that really hasn’t been serviced globally and effectively in the past 20 to 30 years,” he added, explaining that airlines gradually discontinued service as airplanes became larger.

The switch to electric will not only be clean; it will have a profound impact on how commercial aviation serves the public, he argued.

Pasha Saleh, head of corporate development for Alaska Airlines, said the company is working with ZeroAvia, a company planning to incorporate a 3-MW fuel cell into an existing conventional turbo-prop aircraft, a De Havilland DHC-8-400.

“Range is overrated,” he said. “The De Havilland has a 1,200-mile range, but airlines don’t use it for 1,200 miles. It doesn’t have a proper galley for heated food. You don’t want to be on a turboprop for three and a half to four hours.

“It turns out that 90% of the routes we use [the DHC-8] on are below 200 miles; some are 98 miles long,” he said, meaning the airplane is using just 15% of its capacity. “It really comes down to what is the seat cost, the mile cost of operating.

“And that’s what’s exciting to me when I look forward five to 10 years, is that with these new technologies — whether they’re pure hydrogen, electric, hybrid, whatever it is — as an airline, we want to find the right niche for the market we’re using, because right now, it’s not all just about one variable, like range.”

Hugo Wagner (BloombergNEF) Content.jpgHugo Wagner, Airbus | BloombergNEF

Hugo Wagner, an executive with Airbus, agreed.

“I think many people don’t realize that … aircraft gas turbines as of today aren’t really optimized for some critical parts of the journey, namely the taxi, takeoff and landing part, meaning that actually almost 60% of the fuel consumption of the aircraft is below the 2,000-nautical-mile range.”

Davis added, “What we’re doing is we’re taking the technology, and we’re designing for the way that people are actually going to use the plane.”

The U.S. has 5,000 airports, he added, but only 500 are actively used, he said.

“So, 60% of the population of the United States lives within 10 miles of an airport, and 95% lives within 25 miles of an airport. And yet, you’re going to spend 45 minutes to an hour and a half getting to the airport to get on your flight.

“We’re not using our infrastructure right now. … An electric aircraft and sustainable aircraft mean that the operating economics are flipped upside down. So instead of a longer-range flight being the most economically efficient flight for a turbine aircraft, for an electric airplane, you don’t need to climb for efficiency, so there’s no burden of climbing up to 25,000 feet to save on fuel if your aircraft is equally efficient at sea level as it is up at altitude.

“And moreover, with that your operating economics are the same on the first mile as on the last, so there’s no incentive to stretch your flight to maximize the point-to-point utilization of fuel. On the airplane, your electrons get consumed the same way.”

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FERC Orders Changes to PacifiCorp and NV Energy Interconnection Rules

FERC on Friday ordered show cause proceedings on PacifiCorp’s and NV Energy’s generator interconnection rules while approving, in part, rules aimed at limiting speculative projects in Nevada.

The first show-cause order (EL23-26) found that PacifiCorp’s large generator interconnection procedures might be unjust and unreasonable due to rules that trigger restudy of lower-queued customers when an interconnection customer suspends its agreement. The commission also questioned the requirement that the suspending customer pay for the restudies.

FERC Order 2003 requires interconnection customers to pay for their own studies, even if it is a restudy caused by another firm’s decision to withdraw its higher-queued project. The order also allows projects to suspend their interconnection agreements for up to three years, which gives developers flexibility to deal with permitting and other delays that are likely to impact large projects.

FERC issued a preliminary finding that PacifiCorp’s requirement is unjust and unreasonable because the company can require restudies when a developer only suspends its interconnection agreement, even though a restudy would not be needed if the project ultimately proceeds.

The second show-cause order (EL23-27) directs Nevada Power to show why its large generator interconnection procedures are just and reasonable despite not specifying a method for allocating the costs of network upgrades among interconnection customers in a cluster.

FERC has approved serial cluster studies for both ISO/RTOs and independent utilities, including PacifiCorp and NV Energy, subsidiaries of Berkshire Hathaway Energy. NV Energy’s 2013 update to its large generator interconnection procedures includes pro forma language that said it “may allocate the cost of common upgrades for clustered interconnection requests without regard to queue position,” but the procedures do not specify how those costs are allocated.

The specific costs significantly affect rates and should be included in the utility’s tariff, FERC said. Without specific rules on file, the commission said, it cannot easily determine whether any cost allocations are consistent with its precedent.

The two utilities must show cause as to why their rules are just and reasonable within 60 days, or they can propose changes under Section 205 of the Federal Power Act to address FERC’s concerns. A 205 filing would put the show-cause proceeding in abeyance while the commission considers the proposals.

The third order (ER22-2933) approves some changes NV Energy proposed to discourage speculative interconnection projects and allow projects that are ready to move forward with construction to get through the line faster. The utility has seen the number of requests to connect to its grid spike, and recently, 42% of them have either gone into default, been withdrawn, or have interconnection agreements under suspension.

To cut back on the speculative projects, NV Energy proposed increasing deposit requirements; eliminating the use of a “Preliminary Plan of Development” (a document used by the Bureau of Land Management when firms seek to build on federal land) as a form of site control; and setting a withdrawal penalty to hold remaining customers harmless from restudy costs. It also would create a graduated deposit structure based on project size, ranging from $75,000 for up to 50 MW; $150,000 for 50 to 200 MW; and to $250,000 for 200 MW or greater.

FERC approved the stricter site control requirements, including raising the deposit in lieu of site control from $50,000 to $250,000. Those rules will increase the likelihood that only commercially viable projects will have a place in the queue, FERC said.

The commission rejected the withdrawal penalties NV Energy proposed because it found that requiring such customers to cover restudy costs would prove too burdensome. Other utilities have withdrawal penalties, but they are more limited, FERC said.

FERC also rejected NV Energy’s proposal to require interconnection customers who suspend their agreements to pay for restudies of lower-queued projects. Because suspended projects still have the option to move forward, FERC ruled it would be “inefficient for [NV Energy] to conduct a restudy based on the assumption that a suspending interconnection customer is going to withdraw from the queue.”

The commission also rejected a rule that would have let Nevada Power assign the cost of network upgrades that were only triggered by one project in a cluster to that specific project. FERC found the language was not specific enough.

In discussing that rule, the commission also noted that it launched the second show cause proceeding against Nevada Power because its tariff does not include how the utility allocates the costs of network upgrades among interconnection customers in a cluster.

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Treasury Updates EV Tax Credit Vehicle Classifications

Figuring out whether a new electric vehicle qualifies for one of the Inflation Reduction Act’s $7,500 tax credits got a little easier on Friday as the U.S. Treasury Department updated its guidelines to base vehicle classifications on the model information listed on the car’s price sticker.

Under the IRA, EVs classified as SUVs or pickup trucks are only eligible for the tax credit if their manufacturer’s suggested retail price is $80,000 or less. The MSRP cap for sedans and other passenger vehicles is $55,000.

In its previous guidelines, released at the end of 2022, Treasury had based these classifications on EPA’s Corporate Average Fuel Economy (CAFE) standard, which sets fleetwide averages for fuel efficiency. The information on vehicle price stickers is based on EPA’s Fuel Economy Labeling standard, which is calculated from a model’s fuel savings over a five-year period.

In some cases, the vehicle classification based on the CAFE standard was different from the classification on the automaker’s price sticker ― also available on EPA’s fueleconomy.gov website ― causing confusion and uncertainty for both consumers and auto dealers.

For example, Treasury initially classified the Ford Mustang Mach-E SUV as a sedan, limiting the availability of tax credits to consumers buying a model with an MSRP $55,000 or less. Under this classification, only two of the Mach-E’s four 2023 models, the Select and Premium, would have qualified for the tax credit.

The update reclassifies the car as an SUV, putting all four of its 2023 models ― top price, $63,995 ― well below the $80,000 MSRP price cap for SUVs.

Chris Smith, Ford’s chief government affairs officer, welcomed the update. “We recognize that the Treasury Department has a huge task in front of them in implementing the Inflation Reduction Act. We sincerely appreciate their consideration and hard work to make sure that more customers are able to access clean vehicle tax credits under the [IRA],” he said.

General Motors and Tesla faced similar limits on some of their models, specifically GM’s Cadillac Lyriq SUV and Tesla’s Model Y.

GM lobbied the department for changes, as reported by The Street. The automaker argued that “in determining how vehicles should be classified, Treasury should leverage existing U.S. government definitions and practices. … This drives consistency across existing federal policy and clarity for consumers.”

A statement from the automaker on Friday noted that the change “will allow crossover vehicles that share similar features to be treated consistently,” according to The Street.

Tesla had already cut prices on its Model Y in January, The Verge reported. But the company raised prices on both Model Y configurations ― the Long Range and Performance ― hours after Treasury issued its update.

Domestic Content Delay 

The updated guidelines on vehicle classification clears up some of the confusion about the EV tax credits. But Treasury’s delay in issuing critical guidelines for the IRA’s domestic content requirements remains a point of ongoing controversy.

The law required Treasury to issue these guidelines by Dec. 31, 2022; however, Friday’s announcement reiterated the department’s plan to release them in March. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)

As originally written in the IRA, to qualify for the full $7,500 tax credit, an EV’s battery must contain a certain percentage of critical minerals sourced in North America or from a country with which the U.S. has a free-trade agreement. A certain percentage of other battery components must also be sourced in North America.

The domestic content requirements start this year at 40% for critical minerals and 50% for battery components, ramping up in subsequent years.

If one of the domestic content requirements is not met, a consumer may only get half the credit. While delaying the guidelines on domestic content, Treasury is allowing EV buyers to claim the full $7,500 credit.

European automakers and government officials have widely criticized the requirements, labeling them as protectionist and likely to cause a “subsidy war.”

Speaking at the Washington Auto Show last month in D.C., EU Ambassador Stavros Lambrinidis warned that with both the union and U.S. putting billions into transportation decarbonization, “the biggest mistake that governments can do is to get into a subsidy war.”

“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” he said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.” (See Tracking the Contradictions of the US EV Market at the DC Auto Show.)

Sen. Joe Manchin (D-W.Va.) has also criticized the delay, introducing a bill that would require the department to implement the guidelines immediately and make them retroactive to Jan. 1. As chair of the Senate Energy and Natural Resources Committee, Manchin has consistently argued that the IRA’s domestic content requirements are aimed at building out a domestic supply chain and cutting U.S. dependence on China for critical mineral processing and battery component manufacturing.

“We’re moving rapidly into the EV markets — and I think, recklessly — as we were going into that before we were able to supply [domestic production] and be held captive by China,” he said during a Senate floor debate on Jan. 26. (See IRA’s EV Tax Credits Spark Senate Debate.)

The bill has yet to receive a committee hearing or a vote in the Senate.

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ERCOT Briefs: Week of Jan. 30, 2023

Ice Storm Hammers Texas; 400K Customer Outages Reported

ERCOT easily met demand last week as icy weather swept through the state and created local distribution outages affecting as many as 400,000 customers at one point.

The grid operator’s load never averaged more than the 65.56 GW it did during the early evening hours of Jan. 31, when the storm swept through the northern half of state. Demand peaked at 73.96 GW during the December winter storm, a 16-GW increase from ERCOT’s previous high for the month.

Most of the outages were centered on Austin and Northeast Texas, where trees succumbed to the icy accumulation in what locals referred to as an “oakpocalypse.” Some observers pointed to lax vegetation management and opposition to tree-trimming measures as the primary reason for the outages.

Texas Forecast (WeatherBell) Alt FI.jpgThe National Weather Service’s forecast for icy conditions in Texas. | WeatherBell

 

Austin Energy, the city’s municipal utility, had more than 163,000 customer outages at one point. By Sunday morning, it had reduced that total to 44,000, meaning some customers had been without power for 102 hours, longer than they were during the deadly 2021 winter storm.

Oncor, which serves much of North Texas, said Saturday it had restored power to the “vast majority” of its customers. The utility reported more than 140,000 customer outages Thursday morning.

Texas still had more than 65,000 customer outages Sunday morning, according to poweroutage.us.

Texas Gov. Greg Abbott said ERCOT maintained “ample supply” during the week and reminded his Twitter audience that outages were caused by “local issues.” On Saturday, he declared disaster conditions for seven counties affected by the storm.

Calpine to Develop Gas Peaker

Calpine said Friday it will begin developing a 425-MW peaking facility at an existing power plant site following the Texas Public Utility Commission’s recent adoption of a framework intended to incent new generation.

The PUC last month agreed on the principles necessary to replace ERCOT’s energy-only market with a performance credit mechanism (PCM). The design rewards generators with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities, or exchanged between them and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

“The PCM framework adopted last week by the [PUC] sends a strong signal of support for maintaining a reliable grid in [Texas] through market-based mechanisms rather than government mandates,” Calpine tweeted.

The company is a member of Texas Competitive Power Advocates, which promised to build 4.6 GW of additional capacity if the PCM is adopted.

“We are encouraged that the PUC is acting to ensure Texas maintains a reliable power supply through market-based mechanisms rather than government handouts,” Calpine said in a press release. “Regulatory certainty on PCM will be critical as Calpine continues to move this project forward.”

The peaker will be built next to the Freestone Energy Center, a 794-MW combined cycle gas plant between Dallas and Houston. Calpine must secure an air permit from the Texas Commission on Environmental Quality; a spokesman said the project’s front-end development will take 12 to 18 months.

61-MW Gas Plant to Retire

Blue Cube Operations, a wholly owned subsidiary of Dow Chemical (NYSE:DOW), notified ERCOT on Friday that it plans to decommission and retire a gas-fired plant south of Houston on July 4.

The combined cycle steam turbine has a 61-MW summer seasonal net max sustainable rating and a 58-MW minimum rating. The unit was commissioned in 1982 and is paired with a Dow cogeneration facility.

ERCOT normally conducts a reliability-impact analysis before approving a resource’s suspension of operations. It said in a market notice last month that it has not designated any generation facility as necessary to avoid an adverse reliability impact in the planning horizon of more than one year.

ERCOT.com Adds 6-day Forecast

ERCOT on Friday unveiled a new six-day forecast on its supply-and-demand dashboard as part of its continued effort to increase transparency into grid operations. The dashboard displays the system’s current capacity and demand using real-time data from hourly forecasts and other sources.

The forecasts can be found from the Grid and Market Conditions page on ERCOT’s website.

“While the supply and demand forecasts may change, as weather forecasts do, the dashboard provides a general ‘heads-up’ on the trends based on currently known information,” Dan Woodfin, vice president of system operations, said in a release.

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Report: IRA Makes Renewables Cheaper than Virtually All US Coal Plants

If money were the only object, most coal plants providing power to the U.S. grid could be replaced today with regional or local renewable energy made cheaper by tax credits and other funding in the Inflation Reduction Act, according to a new study from industry analysts Energy Innovation.

Based on 2021 costs for operating 210 coal plants across the U.S., the new Coal Cost Crossover 3.0 report found that all but one of those plants “are more expensive to run than replacing their generation capacity with either new solar or wind.”

“It costs more to continue to run coal than it would be to build entirely new wind and solar resources,” said Michelle Solomon, an Energy Innovation policy analyst and lead author on the report.

Many U.S. utilities are already planning to close their remaining coal plants by 2035, the timeline President Biden has set for the U.S. grid to be powered 100% by clean electricity. Energy Innovation’s previous Coal Cost Crossover 2.0 report, issued in May 2021, found that 80% of the 235 plants then in operation were more expensive to run than new solar or wind.

With its more dramatic results, the new report does not push for any accelerated timelines, but “it tells every utility in the country that they need to take a hard look at every single coal plant,” Solomon said. For “every single coal plant, the energy is more expensive than renewables.”

The report also argues for the added benefits of “local” renewables, defined as solar, wind or storage sited within a 30-mile radius of a closed or soon-to-close coal plant. These include the potential jobs and tax revenues for communities as well as the potential for shorter interconnection times.

Both economics and the environment are driving the phaseout of coal in the U.S. In the last decade, the share of U.S. electricity produced by the dirtiest fossil fuel has plummeted from 50% to 21.9%, as coal has been replaced by natural gas and renewables, according to the U.S. Energy Information Administration.

But even at that lower level, coal still accounts for 60% of greenhouse gas emissions from the U.S. electric power sector and 20% of emissions from the nation’s energy consumption overall.

Looking ahead, EIA says, “23% of the 200,568 MW of coal-fired capacity currently operating in the United States has reported plans to retire by the end of 2029.”

Those plants are in 24 states, including several that have not set targets for utilities to provide a specific percentage of their power from renewable or other clean energy sources, EIA says.

Energy Innovation sees the IRA as providing new economic momentum to take more coal offline. Both solar and wind owners can now choose between a 30% investment tax credit, more of a capacity-based incentive, or a performance-based 2.6-cent/kWh production tax credit, providing they pay workers prevailing wage and offer registered apprenticeships.

The law’s bonus incentives for locating new renewable projects close to “energy communities” that have been affected by the closure of coal mines or coal-fired power plants could further cut costs, while driving “up to $589 billion in clean energy investment” in these areas, the report says.

Solar Investment by State (Energy Innovation) Alt FI.jpgStates across the country could see billions of dollars in new investments by replacing coal plants with solar, according to Energy Innovation. | Energy Innovation

Money saved from coal plant closures could also be used to take advantage of the IRA’s energy storage investment tax credit, also 30%, to finance up to 137 GW of four-hour duration storage, which could replace 62% of the coal fleet’s 220 GW of nameplate capacity, the report said.

Still another big plus is that new local solar or wind projects could use existing power lines, cutting interconnection time and costs and reducing the need for new transmission and distribution lines, the report says.

“The combined impacts of energy community, labor and domestic content bonuses reshape solar economics in coal communities,” the report says. “The median cost of new solar in these communities is about $24/MWh with low variance, while the median marginal cost of coal is $36/MWh with higher variance.”

In this context, Solomon said, “variance” means “the coal plant costs vary more than solar costs.”

Stranded Assets and Reliability

But Michelle Bloodworth — president and CEO of America’s Power, a coal industry trade association — called the report “misleading because it does not account for all the costs and challenges associated with replacing the coal fleet with wind and solar.”

Replacing coal with renewables could cost at least $1 trillion and another $300 billion for the new transmission that would be needed, Bloodworth said in an email to RTO Insider. “Just as important, the report fails to consider the value of reliability, fuel diversity, fuel security and high-capacity value of the coal fleet, none of which can be matched by wind or solar.”

Solomon countered that Energy Innovation’s calculation of the cost of renewables, based on computer models developed by the National Renewable Energy Laboratory, does account for the all-in capital investments that will be required. The report also recognizes that the early closure of coal plants can leave utilities with millions in unpaid debt on their balance sheets and embedded in the higher rates their customers may have to pay as a result.

The IRA provides two potential options here, the report says. The law’s Energy Infrastructure Reinvestment program provides low-interest loan guarantees to utilities replacing old energy infrastructure with new projects that “avoid, reduce, utilize, or sequester air pollutants or anthropogenic emissions of greenhouse gases,” according to the Department of Energy.

The program is administered by DOE’s Loan Programs Office which, under Director Jigar Shah, has already set rigorous guidelines for applications. During a recent interview, Shah said the office takes 12 to 18 months to process a typical loan application.

For electric cooperatives, which may be particularly dependent on coal for their electricity supply, the IRA also provides $9.7 billion in loans and grants for the purchase of renewables or other zero-emissions energy systems. The Rural Utilities Service at the Department of Agriculture is administering this program and has recently finished a series of stakeholder roundtables to gather input on its implementation.

Bloodworth’s concerns about reliability are a more complex issue that Energy Innovation acknowledges as a major challenge for utilities and grid operators moving from coal to renewables. Delaware’s 445.5-MW Indian River Generating Station, owned by NRG Energy, is a case in point, the report says. Though it was scheduled to close in June 2022, PJM requested it stay online through 2026 to ensure system reliability while transmission upgrades were made.

The RTO has “an established 90-day process to review generator retirement requests and their potential effects on the transmission system … to be sure reliability is not impacted,” according to Jeffrey Shields, media relations manager for PJM. “This does not have anything to do with what kind of generator it is; it is a matter of how the system will be impacted without the particular generator providing power in a certain area.”

In the case of Indian River, continuing to run the plant “was the only real solution to address immediate reliability needs until a long-term solution is built,” Shields said in an email. “Longer-term replacement generation could certainly include solar, offshore wind or hybrid renewable units paired with storage.”

While the plant is still online, it is run under a reliability-must-run agreement, which means it is run only in situations where system reliability cannot be provided by other sources; for example, in a “capacity emergency when … scheduled reserves are not sufficient,” according to Shields.

Delaware ratepayers are paying an estimated $6.45/month extra on their electric bills, according to the Delaware News Journal, which called the plant “one of the state’s top polluters.”

Energy Innovation also said Indian River was “the eighth most expensive plant we analyzed due to low capacity factor and high estimated fuel costs.”

“Local replacement of this plant [with wind or solar] could assuage reliability concerns by providing generation and capacity needs at the same location on the grid,” the report says. “Our local analysis finds that 246 MW of storage could be funded via savings,” which could provide more than half of the plant’s capacity.

The Takeaway

Making such diversified portfolios of renewables a core element of regular resource planning is one of Energy Innovation’s recommendations for utilities, grid operators and regulators going forward. Both local and “regional” siting is also recommended, as are continuing efforts to improve and streamline interconnection processes.

Specifically, Energy Innovation calls on grid operators to “improve methods to assess reliability and resource adequacy reflecting the reliability value of renewable portfolios and valuing the reliability attributes of a high-renewables grid.”

“PJM has already begun this process,” Shields said. “We have adopted the effective load-carrying capability rating method to better reflect the reliability capacity value of renewables; and we will be making an additional filing at FERC to make sure that capacity matches up with the existing Capacity Interconnection Rights.”

Renewable projects that are able to use a retiring coal plant’s interconnection rights also “may reduce or eliminate the amount of network upgrades required for [a] new interconnection” Shields said. Fewer network upgrades could help to move a project up in the queue under PJM’s new first-ready, first-served approach to interconnection, he said.

The takeaway here, while hopeful, is that long interconnection queues and the need for transmission upgrades and expansion are systemic problems that will continue to slow the transition to clean energy as the IRA’s incentives and regulators’ efforts at change work their way through a risk-averse, reliability-focused industry.

But the Energy Innovation report makes clear, among the many challenges an accelerated phaseout of coal could raise, the increasingly lower cost of renewables, combined with local siting could be critical drivers for finding solutions faster.