Emily Chen, an analyst with FERC’s Office of Energy Market Regulation, gave a briefing on Orders 1920 and 1977 to members of the NYISO Management Committee on June 11 during a joint meeting with the ISO’s Board of Directors.
Order 1920 requires transmission planners to use a 20-year horizon to identify long-term needs and the facilities to meet them. Long-term planning must occur at least once every five years using at least three plausible scenarios with the best available data and incorporating factors such as retirements, policy goals and corporate commitments.
“We also require that you consider at least seven benefits to evaluate these regional proposals, including production, cost savings, or mitigation of extreme weather and unexpected system conditions,” Chen said.
She noted that the order had been published in the Federal Register just that day, and it will go into effect Aug. 12.
The rule also requires transmission providers to propose a default method of cost allocation to pay for long-term regional facilities and to hold a six-month engagement period before submitting their compliance filings.
Order 1977 updates the process FERC uses when it is called upon to exercise its siting authority to include a Landowner Bill of Rights and a codified Applicant Code of Conduct for applicants to demonstrate good faith effort to engage with landowners in the permitting process. It also directs applicants to develop engagement plans to environmental justice communities and federally recognized tribes. The order was published May 29 and is effective July 29.
Project Prioritization Process
Kevin Pytel, director of product and project management for NYISO, presented the proposed internal project prioritization for 2025 and outlined changes to the process since last year.
“This process is not perfect, we know that, and we try to make it better every year,” Pytel said.
NYISO had 53 proposed market projects this year; of those, eight were continuing projects. They include implementing five-minute transaction scheduling and ancillary service shortage pricing.
The primary changes were to how NYISO handles “continuing” projects, which are those that were approved in a prior year that have progressed to the functional requirements specification, software design, development completion or deployment stages.
Stakeholders had requested that the ISO revise the timeline for stakeholders to decide whether to continue with a project; they now have until June, pushed back from March.
“The hope is that by moving this back three months, we will have a more healthy discussion and be able to come to a resolution quicker on which projects should be considered ‘continuing,’” Pytel said.
The ISO also shifted the stakeholder scoring survey from June to July, which it said will allow it to develop a project set for budgeting purposes by early August.
The Budget and Priorities Working Group will decide on the continuing projects at its meeting June 24; NYISO will also provide its own project scores at the meeting. The survey will be distributed July 3, with a deadline of July 14. The ISO will present the results to the working group July 31.
NYISO’s internally facing enterprise projects that do not involve market rule changes are not subject to stakeholder approval.
Rate Schedule 1 Allocation of the NYISO Budget
Chris Russell, senior manager of customer settlements for NYISO, reminded the committee of an upcoming vote to determine whether a new cost-of-service study should be conducted to evaluate the Rate Schedule 1 allocation between withdrawals and injections.
Rate Schedule 1 is used by the ISO to collect its operating costs from members. The 2024 rate is $1.281/MWh, with 72% from withdrawals and 28% from injections.
The current allocation was set by the committee in July 2011. It was originally scheduled to be effective for January 2012 to December 2016, but in 2016, the committee voted to decline conducting a study and has done so annually every third quarter through 2023.
Russell said market participants have indicated that a study is necessary in the future because of the evolving market. Last year, the committee voted to waive the study by an overwhelming majority of 91.22%. (See NYISO Management Committee Briefs: July 26, 2023.)
The vote will take place at the committee’s July 31 meeting.
SPP’s Board of Directors added its approval June 12 to a proposed tariff revision that establishes a cost-allocation framework for projects in the Joint Targeted Interconnection Queue (JTIQ) with MISO.
The revision request (RR620) addresses chronic transmission issues on the RTO’s seam with MISO related to generator interconnection requests and implements cost-allocation policies already approved by SPP’s state regulators. It also memorializes and defines how the JTIQ process will be implemented and applied once executed.
Combined with earlier endorsements from stakeholders June 7 and state regulators June 10, RR620’s approval ends a process that began nearly four years ago after repeated fruitless attempts to find interregional projects both RTOs could agree on.
SPP CFO David Kelley, who has assumed new responsibilities since the work began, told the board, “This feels like we are near the end of a really long marathon. It’s been a good journey.”
The trek began with a thawing of relations between the two RTOs and their CEOs and, Kelley said, “a challenge to both SPP and MISO staff to go and work out a solution to problems that were shared by both RTOs.”
The grid operators have identified five projects along their seam that can help unlock new generation and resolve congestion issues in the absence of interregional projects.
After being awarded a $464 million grant from the U.S. Department of Energy, the RTOs revised their original direct-billing approach for JTIQ projects to one that assigns 100% of the portfolio’s engineering and construction costs for interconnection requests that meet certain criteria. Those costs are estimated at between $1.6 billion and $1.8 billion before applying the DOE funds. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects, DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
“The more complicated piece of this would be associated with the funding and the handling of money from interconnection customers in both RTOs, as well as the transmission owners in both RTOs,” Kelley said. “That’s something that has never been done before, and it took a significant amount of time to figure those things out.”
The Members Committee’s advisory vote passed 17-2, with two abstentions. EDP Renewables and the Advanced Power Alliance (APA) both voted against the measure.
EDP’s David Mindham said that while his independent power producer sector supports transmission buildout and the JTIQ projects, the process itself represents a failure of planning in the two regions. He said a lack of coordinated assumptions and models has led to a “dysfunctional planning system that is broken.”
“Generators want this transmission to be built … and we’re willing to pay for it,” Mindham said. “But in order to do that, the entities paying for this transmission are being asked to compromise on a lot of other issues and a lot of additional things that have bad precedent nationally for us, and we just can’t support that today.”
Kelley reassured Mindham and the APA’s Steve Gaw that the framework’s structure is specific to the projects in the current portfolio and that their objections could be considered for the next round.
“We fully understand that should there be another round of [JTIQ projects], we’re going to have these conversations and justify either something different or something else that is viable going forward,” Kelley said.
The Regional State Committee unanimously approved the tariff revision June 10, and the Markets and Operations Policy Committee endorsed it June 7 with 89% approval.
SPP will coordinate the FERC filing with MISO once its neighbor gains approval of its tariff revision. It will seek board approval of the JTIQ portfolio if the commission accepts the tariff change and updates to its joint operating agreement with MISO.
FERC has authorized an exception to MISO’s interconnection rights transfer process, allowing two Xcel Energy subsidiaries to cooperate on a replacement of a coal-fired plant with a solar farm.
FERC said Xcel’s Northern States Wisconsin is free to substitute about 650 MW of new solar and potential storage facilities for Northern States Minnesota’s 591-MW Allen S. King Power Plant, which is scheduled to be powered down in 2028. The project would use the King plant’s point of interconnection (ER24-1719).
Xcel requested the waiver of MISO’s ordinary interconnection rules because it plans to hand over MISO interconnection permissions from one Northern States Power affiliate to another. The King plant is near the Minnesota-Wisconsin state line.
Ordinarily, MISO’s generating facility replacement rules prevent owners of retiring generator from transferring their facilities and interconnection rights to someone else from a year before they submit a replacement request up until the replacement generation reached commercial operation.
Xcel plans to be coal-free no later than 2034 and said this transfer is a piece of the puzzle. It said pursuing an expedited process using a different interconnection customer under MISO’s generator replacement process is preferable to submitting the project for study in the interconnection queue, which takes years to complete.
Xcel said it investigated alternatives to Northern States Wisconsin developing the solar facilities, including having Northern States Minnesota lead the project. However, it said Northern States Minnesota would be considered an out-of-state developer on the project, which requires approval from the Public Service Commission of Wisconsin.
FERC said its approval was based in part on the fact that Xcel first explored alternatives and concluded they would “present tariff obstacles or other significant complexities and challenges.”
The commission said the transfer doesn’t introduce queue-jumping concerns because the waiver encompasses “two wholly owned subsidiaries that operate a single integrated system” and doesn’t involve “unaffiliated entities outside of the interconnection queue.”
The waiver, however, elicited a caution from Commissioner Allison Clements, who said the order exemplifies the “increasingly strained reasoning underpinning the transferability restrictions in MISO’s (and other transmission providers’) generator replacement rules.” She called for a “fulsome evaluation” of generator replacement rules because of their “piecemeal proliferation” across the country.
“I concur because the effect of granting this waiver is that a brownfield site of existing generation on the transmission system can be expeditiously reused. I believe that outcome is consistent with the purpose of MISO’s generator replacement rules, and I acknowledge that fast-tracking the interconnection of new generation at previously studied sites may yield efficiencies and cost savings,” Clements nevertheless wrote in a concurrence to the order.
But Clements suggested MISO’s transfer restrictions today may show undue preference to owners of existing generation. She said at this point, it appears MISO’s transfer rules require only the party assuming interconnection rights to be an affiliate of the original owner to bypass the queue and the cost responsibility of the original network upgrades.
MISO’s generator replacement requests are poised to increase as members turn off the lights at their aging, baseload plants.
Clements ended by urging the commission to take a fresh look at generator replacement processes and their “nonsensical transferability restrictions” that FERC “must contort around to permit rational commercial arrangements.”
Several renewable energy developers have indicated they will oppose ERCOT stakeholders’ approval of a controversial rule change for inverter-based resources (IBRs) when the issue goes to a vote before the Board of Directors later this month.
Invenergy Energy Management, NextEra Energy Resources, Southern Power, Avangrid Renewables and Clearway Renew — the ad hoc “joint commenters” who have argued against the change — on June 10 filed a recommendation to oppose, urging the board to reject the revision to the Nodal Operating Guide (NOGRR245) during its June 17-18 meetings.
ERCOT’s Technical Advisory Committee endorsed the rule change June 7 after months of trading and reviewing comments with staff. It would impose voltage ride-through requirements on IBRs, aligning ERCOT’s protocols with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid. (See ERCOT TAC Endorses Rule for Inverter-based Resources.)
The committee inserted gray-box language with potential modifications that wouldn’t become effective until March 2025. The language would enable entities to meet the applicable ride-through requirements when they have not yet added a “technically feasible” change. The revisions are aimed at those entities for which upgrade costs are less than 40% of the full, in-kind replacement cost of a plant’s inverters or turbines and converters.
The joint commenters agreed there is a sense of urgency to impose the standards and make them effective for IBRs. However, they urged the board to ensure that the ride-through standards “do not have the unintended consequences of harming reliability by eliminating existing generation and harming future investment in infrastructure in the ERCOT market.”
The commenters said TAC attempted to defer issues around hardware changes by placing them in the gray-box language, but that the action did not accomplish anything.
“The gray box simply indicates that hardware changes contemplated by ERCOT would be required unless a new NOGRR modifies such requirement before the gray box becomes effective,” the commenters wrote. They asked that the language be deleted and that required hardware modifications for existing IBRs be bifurcated from the NOGRR and addressed after further study of the reliability need for the requirements.
NOGRR245’s TAC-approved version has “fatal flaws,” they said. “It imposes arbitrary costs on existing generation [IBRs] and unlawfully gives ERCOT … authority to indefinitely shutter existing operational IBRs.”
‘Unresolved Issues’
“While I appreciate that both the joint commenters and TAC wanted to decouple hardware changes from everything else, there are still a lot of unresolved issues,” Eric Goff, representing the commenters, said in an email to RTO Insider.
During the June 7 conference call, Goff recommended that TAC members vote against the motion. He said that while the main intention is in “good spirit,” the six to nine months allowed to work on hardware issues won’t solve any problems.
“That’s due to the [Public Utility Commission of Texas’] procedural rules,” he told TAC. “If the joint commenters believe that the proposals here are not lawful or bad policy, we have 35 days to appeal an ERCOT action. We would be forced to appeal this or lose the right to appeal it, so it would result in this issue not getting six to nine months of time in the ERCOT stakeholder process, but rather in a contested case with the commission.”
Goff also said the NOGRR includes “inappropriate” changes to technical requirements that have yet to be approved.
The joint commenters face long odds in seeing the board reject NOGRR245. ENGIE’s Bob Helton pointed out during the TAC call that striking the gray-box language would lose ERCOT’s support for the change.
“I would assume that means [ERCOT] is going to challenge that at the board. I’ve got a pretty good idea of where we would end up. … The board would likely go with ERCOT on the appeal,” Helton said.
The ERCOT board remanded the NOGRR back to TAC in April, directing that the language — approved by the committee over staff’s objections — be modified to address staff’s reliability concerns. (See ERCOT Board of Directors Briefs: April 22-23, 2024.)
A pair of IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the “Odessa disturbances,” added urgency to eventually passing the measures. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Representatives of the New England Power Generators Association (NEPGA) and Competitive Power Ventures (CPV) offered amendments to ISO-NE’s proposed changes to the financial assurance provisions for the Forward Capacity Market at a joint meeting of the NEPOOL Markets Committee and Budget and Finance Subcommittee on June 11.
ISO-NE has raised concerns that its financial assurance policy — intended to ensure that generators can pay penalties associated with failing to meet their capacity supply obligations (CSOs) — does not adequately protect against the risks of generators defaulting.
To address these concerns, the RTO has proposed to rely on a “corporate liquidity assessment” to evaluate whether generators will be required to provide additional financial assurance.
The proposed amendments presented at the meeting focused on ways to reduce pool-wide default risks, with the hope that reducing the overall risks would enable ISO-NE to ease the financial assurance requirements for generators.
NEPGA’s Bruce Anderson said allowing generators to sell monthly CSOs closer to each period would help mitigate the risk of equipment failures leading to unmet obligations. He noted that the last opportunity to sell CSOs is more than a month in advance of each monthly period.
“Allowing for bilateral trading closer in time to the relevant month will decrease the risk of default for a market participant that may not be able to perform,” Anderson said.
NEPGA has also proposed to increase the payback period for Pay-for-Performance penalties, saying this would similarly reduce the overall risk of defaults. He highlighted recently approved tariff changes at PJM “allowing for longer payoff periods of up to nine months.”
CPV’s Joel Gordon echoed the potential of increasing the opportunities for generators to sell their obligations. He said ISO-NE could consider a rule to enable it to terminate a CSO if a generator defaults on a penalty, or it could create a special status for defaulting generators.
“There are market design solutions that would significantly reduce the potential exposure that should be explored,” Gordon said, emphasizing the need to “address the underlying cause first.”
ISO-NE said it plans to respond to the proposals in July and is targeting an initial vote on the finance assurance changes in August.
TerraPower on June 11 broke ground on its Natrium reactor demonstration project in Wyoming, making it the first advanced reactor to enter construction.
TerraPower was founded by billionaire Bill Gates and the project is supported by a long-term contract with PacifiCorp, which is part of fellow billionaire Warren Buffett’s Berkshire Hathaway business empire.
“I’m proud of all the partners and people who helped get the most advanced nuclear project in the world built in Kemmerer, Wyo.,” Gates said in a statement. “I believe that TerraPower’s next-generation nuclear energy will power the future of our nation — and the world.”
Construction is expected to take five years and at its peak will employ 1,600 workers. Once the plant is operational, TerraPower expects it will support 250 permanent employees.
The Natrium reactor will be a fully functioning commercial power plant, which is being built at the site of a retiring coal-fired power plant in Kemmerer.
The 345-MW reactor uses sodium-cooling technology with a molten salt-based energy storage system that can boost its overall output to 500 MW when needed, which is enough to power 400,000 homes. The energy storage capability allows the project to help balance with renewable power, which has long been an issue with conventional nuclear plants that that lack ramping flexibility.
The company’s construction permit application is still pending at the Nuclear Regulatory Commission, but it was able to start construction on non-nuclear facilities while nuclear construction awaits regulatory approval.
The NRC announced last week that it was advancing its consideration of the project and noted that if it approves construction, TerraPower would have to submit another application to actually operate the power plant.
“This is a challenging yet exciting time in the energy industry,” PacifiCorp CEO Cindy Crane said in a statement. “In an era of rapid change, the need for reliable, affordable and dispatchable energy will remain a constant. Innovative technologies like the Natrium project will enhance our ability to serve our customers, meet growing demand and ensure a reliable and resilient energy future.”
Engineering firm Bechtel is building the facility, and company President Craig Albert said in a statement that the project will launch a new approach to nuclear construction that is meant to be safer, cleaner and faster. The company has built 150 nuclear plants around the world over the past 70 years.
“Working together, the combination of advanced technology and streamlined constructability has the potential to diversify the U.S. power generation industry,” Albert said. “The option of deploying smaller advanced nuclear plants that can work in concert with other clean energy sources will help speed our progress toward net-zero emissions.”
Constellation’s Dominguez Comments on State of the Industry
Speaking on a Reuters webinar June 10, Joseph Dominguez, CEO of Constellation Energy, which owns and operates one of the largest nuclear fleets in the country, said it’s still an open question which technology will dominate the future of the industry. Dominguez said the existing fleet of reactors could run until 2060 or beyond, but that would require major investments and Constellation is also focused on expanding nuclear production.
“We are expanding the output of our plants,” Dominguez said. “As we change over equipment, we tend to get better materials, better efficiencies and all sorts of things, generators, pumps, everything that allows us to increase the output of the machines and put on the grid almost immediately, at least in power terms — over a handful of years, new firm, clean energy. And then we’re also investigating the next generation of small modular reactors or large-scale nuclear plants.”
Some firm clean power is going to be necessary to reach net-zero goals, and nuclear faces competition from other technologies, including natural gas-fired generation with carbon capture and storage, which Constellation is also looking into, he added.
While the company recently bought NRG’s share of the South Texas Project, Dominguez said other opportunities to buy existing nuclear plants are not on the table because their owners recognize the value of those assets, focusing Constellation on organic growth through capacity uprates, the possibility of restarting its Three Mile Island plant in Pennsylvania, and eventually the potential for building new plants.
“Over the last 10 years, [the industry] only brought on two nuclear units,” Dominguez said, referring to Southern Co.’s Plant Vogtle expansion. “And some reports indicate that those have been as much as $20 billion apiece to build. So, the ability to restart a unit at a fraction of those costs, to create an environment where you can do all the state-of-the-art upgrades to the unit to allow it to be able to run for decades more — that’s an incredibly valuable opportunity for America.”
The theory with small modular reactors is that much of the equipment would be manufactured at a central facility and then transported to the power plant’s location, which is how the industry builds gas-fired and renewable power plants, Dominguez said.
“The way we think about it right now is we’ve got to see these technologies evolve, we’ve got to see folks prove out the competency,” he added. “I think they’ll do that in the next five or six years. And then we’ll select the technologies that best suit our needs, and our customers’ needs.”
DTE Energy said it will build a large battery energy storage system on the site of a coal-fired plant it is demolishing near Detroit.
With a capacity of 220 MW and 880 MWh, the Trenton Channel Energy Center is expected to be the largest standalone battery storage site in the Great Lakes region when completed in 2026.
Company officials said the project will bring the state closer to the MI Healthy Climate Plan goals outlined by Michigan Gov. Gretchen Whitmer (D), who joined them for a ceremonial groundbreaking at the riverfront site June 10.
“DTE’s new Trenton Channel Energy Center will help us strengthen our grid and produce more clean power when it’s less costly and store it for later when we need it,” she said in a prepared statement.
DTE CEO Jerry Norcia said in a news release the new battery facility will support the utility’s CleanVision Integrated Resource Plan and help move the state closer to its energy storage target. It is the largest of several energy storage projects DTE has in development.
A rendering shows the battery energy storage system planned to replace the Trenton Channel plant. | DTE Energy
DTE said the Inflation Reduction Act is providing an important financial boost for the Trenton Channel project — $140 million in tax incentives.
The original Trenton Channel Power Plant dated to 1924, and a companion plant running at higher steam conditions was built in 1950. The “low-side” plant was decommissioned in the 1970s, and its boiler house was demolished.
DTE’s annual fuel mix report compares its own statistics with the five-state regional average and shows mixed results for 2022, the last year in which Trenton Channel and St. Clair were fired up.
DTE has relied on coal for 54.16% of its generation vs. 41.8% for the region; its nitrogen oxide emissions per MWh of power generated were 50% higher than the region, and its sulfur dioxide emissions per MWh were 128% higher.
But DTE also generated 13.1% of its electricity with renewable sources — mostly wind — compared with a regional average of just 6.8%. DTE’s carbon dioxide emissions per MWh were 13.5% higher than the regional average.
Demolition of the Trenton Channel Power Plant has begun.
The dual 563-foot smokestacks — local landmarks known as The Witches’ Socks or The Candy Canes for their red and white bands — were brought down with explosives March 15, and the boiler house is scheduled to meet the same fate at sunrise June 21.
The plant was not only a landmark for generations of area residents, but also a literal and figurative powerhouse for the area’s economy, with a nameplate capacity as high as 1,060 MW, plus a sizeable workforce and local tax impact.
DTE said the battery plant will generate tax revenue for the community to continue the coal plant’s legacy.
ISO-NE’s Order 2023 compliance filing received mixed comments from a range of clean energy stakeholders last week, drawing support from several large trade associations along with protests from multiple companies.
Order 2023 is intended to reduce wait times and costs associated with interconnection by mandating that transmission providers implement first-ready, first-served cluster study processes with defined timelines. (See FERC Updates Interconnection Queue Process with Order 2023.)
In comments supporting ISO-NE’s filing, Advanced Energy United, American Clean Power Association, Natural Resources Defense Council and Solar Energy Industries Association jointly praised the RTO’s adoption of several stakeholder amendments to its proposal.
“Throughout this process and right up to the final vote, there was extremely robust stakeholder engagement in the compliance proceeding,” the groups wrote. “Ultimately, from more than two dozen stakeholder amendments, ISO-NE adopted four priority stakeholder proposals identified by parties representing interconnection customers in part or in full in some form.
“While future reforms beyond Order No. 2023 will be needed to ensure a fully functional and efficient interconnection process in New England, ISO-NE’s Order No. 2023 reforms will mark an important first step in improving existing processes,” the groups added.
ISO-NE has committed to continuing work to improve interconnection, writing in its filing that it “will continue its engagement with stakeholders both to ensure successful implementation at the outset and to assess potential improvements going forward.”
The clean energy groups expressed interest in additional efforts to further reduce the overall cluster study timeline, provide more information and process transparency to interconnection customers and add flexibility to alter projects during the interconnection process to limit costs.
RENEW Northeast also supported the filing, specifically applauding ISO-NE’s proposal for studying storage resources.
Order 2023 directs RTOs to let storage developers dictate the system load at which they would charge, while requiring control technologies to prevent charging beyond this load. ISO-NE has proposed a variation in which it would study storage resources at “peak shoulder load” and rely on security-constrained economic dispatch to prevent storage “from being dispatched at load levels higher than the peak shoulder load under which the facility was studied.”
RENEW Northeast wrote that the approach “will afford energy storage the flexibility to optimize its operations according to real-time grid reliability conditions rather than under limits established during the interconnection study process that will likely become less relevant over time as the grid topography changes.”
Calls for Shorter Study Timelines, Expanded Use of Surety Bonds
New Leaf Energy also applauded the proposed storage methodology, along with ISO-NE’s proposal to continue work on late-stage interconnection studies that are projected to be complete by the end of August.
The company echoed the need for additional work to improve interconnection in the region, writing that “the success of the new interconnection process relies, in part, on the timely evaluation of how the new process is working and continuous improvement thereof.”
It recommended that ISO-NE establish an interconnection working group as a formalized setting to continue working on interconnection improvements.
Meanwhile, BlueWave called on FERC to require ISO-NE to follow the original timelines proposed in the order and increase the flexibility for interconnection customers to make changes to their request amid the interconnection process.
While Order 2023 puts a 150-day deadline on each cluster study and an additional 150-day deadline on cluster restudies, ISO-NE has proposed a 270-day deadline for cluster studies and a 90-day deadline for restudies.
“Protracted study timelines are one of the reasons for increased project costs and failures,” BlueWave wrote. “Short study timelines would also result in less queue backlog, fewer restudies and fewer requests for modifications.”
Longroad Energy argued that ISO-NE should expand the eligibility of surety bonds to meet the financial requirements within the interconnection process. ISO-NE has proposed to accept surety bonds only for commercial readiness deposit beginning in 2025.
“Surety bonds are generally easier and less expensive to procure than other accepted forms of financial security,” the renewable developer wrote, adding that CAISO “already accepts surety bonds for generator interconnection customers.”
Glenvale Solar took issue with ISO-NE’s proposed variation regarding study deposits and application fees, writing that the RTO’s proposal of uniform study deposits and application fees is “unduly burdensome and discriminatory to developers of smaller resources.”
The company called on FERC to require the RTO to follow the tiered approach outlined in Order 2023.
The National Highway Traffic Safety Administration on June 7 issued final Corporate Average Fuel Economy (CAFE) standards for U.S. passenger cars and light- and heavy-duty pickups for model years 2027 to 2031, with the goal of cutting gasoline consumption by 70 billion gallons and carbon dioxide emissions by 710 million metric tons by 2050.
The CAFE standard regulates how far a vehicle must be able to travel on a gallon of gas and represents the “maximum feasible level that the agency determines vehicle manufacturers can achieve in each [model year], in order to improve energy conservation,” the final rule says.
The rule sets regular 2% increases in fuel efficiency for passenger cars ― sedans and SUVs ― per year between the 2027 and 2031 model years, rising from 60 miles per gallon in 2027 to 65.1 mpg in 2031, the same as set in the proposed CAFE standards NHTSA issued in July 2023.
But the final standards for light- and heavy-duty pickups are less stringent than the proposed rules. A 2% fuel efficiency increase for light-duty pickups will not go into effect until 2029, starting at 42.6 mpg in 2027 and 2028, then rising to 43.5 mpg in 2029 and hitting 45.2 mpg in 2031. (See NHTSA Proposes 66.4-mpg Fuel Efficiency for Passenger Cars by 2032.)
The current CAFE standards are 48.7 mpg for passenger cars and 35.2 mpg for light-duty pickups, according to NHTSA, and are set to rise to 58.1 mpg and 41.5 mpg, respectively, in 2026.
The CAFE standard for heavy-duty pickup trucks and vans ― weighing between 8,501 and 14,000 pounds ― is measured in the gallons required to drive 100 miles. The new standards cover the 2030 to 2035 model years and are slightly less rigorous than those in the proposed rule. For example, the 2030 standard in the final rule is 4.503 gallons per 100 miles versus 4.427 gallons in the proposed rule.
The NHTSA notes “real-world fuel economy is generally 20 to 30% lower than the estimated required CAFE level” and that some automakers are “over-complying” with the standards due to electric vehicles in their fleets achieving higher anticipated levels of fuel efficiency than required. The potential “achieved” 2031 efficiency for passenger cars could be 70.8 mpg versus the 65.1 mpg that is required.
But the NHTSA says some manufacturers are not complying with existing CAFE standards for light trucks and are choosing to pay resulting penalties. According to the manufacturers, “they cannot stop manufacturing large fuel inefficient light trucks while also transitioning to manufacturing electric vehicles,” and the NHTSA says it will no longer require them to pay penalties.
The final rule also stresses that the standards are “footprint target curves for passenger cars and light trucks … [which] means that the ultimate fleet-wide levels will vary depending on the mix of vehicles that industry produces for sale in those model years.”
But the NHTSA said in its announcement that it “does not consider electric and other alternative fuels when setting standards; manufacturers may use all available technologies ― including advanced internal combustion engines, hybrid technologies and electric vehicles ― for compliance.”
Administration officials framed the final standards as a win-win for consumers economically and environmentally.
“Not only will these new standards save Americans money at the pump every time they fill up, they will also decrease harmful pollution and make America less reliant on foreign oil,” Transportation Secretary Pete Buttigieg said in the NHTSA press release.
Buttigieg estimated $600 savings on gasoline over the lifetime of a vehicle.
“When Congress established the Corporate Average Fuel Economy program in the 1970s, the average vehicle got about 13 miles to the gallon,” NHTSA Deputy Administrator Sophie Shulman said. “These new fuel economy standards will save our nation billions of dollars, help reduce our dependence on fossil fuels and make our air cleaner for everyone. Americans will enjoy the benefits of this rule for decades to come.”
EPA vs. CAFE
Based on 2022 figures from EPA, the transportation sector pumps out the largest portion of U.S. greenhouse gases ― 28% ― with light-duty vehicles accounting for 57% of that total.
While President Joe Biden wants 50% of all new car sales to be electric by 2030, the impact of the CAFE standards on transportation electrification is an open question.
The final standards were developed to complement EPA’s recent update to limits on vehicle tailpipe emissions, which EPA Administrator Michael Regan hailed as “the strongest vehicle pollution technology standard ever finalized in the United States.”
The EPA rule could also cut total CO2 emissions by 7.2 billion MT by 2054, more than 10 times the estimated reductions for the NHTSA standard.
The NHTSA takes a more incremental view, stating that “although the vehicle fleet is undergoing a significant transformation now and in the coming years, for reasons other than the CAFE standards, … a significant percentage of the on-road (and new) vehicle fleet may remain propelled by internal combustion engines (ICEs) through 2031.”
Rather, NHTSA argues, “The final standards will encourage manufacturers producing those ICE vehicles during the standard-setting time frame to achieve significant fuel economy, improve energy security, and reduce harmful pollution by a large amount.”
Just days before the release of the NHTSA rule, Toyota, Subaru and Mazda made a joint announcement that they had each committed to developing new ICEs that are smaller and more energy efficient and will use alternative fuels ― such as synthetic and biofuels and liquid hydrogen ― to cut their carbon emissions to zero.
John Bozzella, CEO of the Alliance for Automotive Innovation, noted the alignment between the EPA and NHTSA standards. “The left hand knew what the right hand was doing,” he said, in astatement on the organization’s website.
But Bozzella also questioned whether the U.S. will need CAFE standards in the future “in a world rapidly moving toward electrification.”
”CAFE’s a relic of the 1970s ― a policy to promote energy conservation and energy independence by making internal combustion vehicles more efficient,” he said. “But those vehicles are already very efficient. And EVs? They don’t combust anything. They don’t even have a tailpipe!”
Stakeholders Endorse Revisions to CIR Transfer Issue Charge
VALLEY FORGE, Pa. — The PJM Planning Committee last week endorsed revising an issue charge focused on how capacity interconnection rights (CIRs) may be transferred from a deactivating generator to a new resource.
The issue charge seeks to solve the misalignment between the transfer process, which is tied to phases of the interconnection queue, and recent changes to the interconnection process. (See “Stakeholders Discuss Change to CIR Transfer Issue Charge,” PJM PC/TEAC Briefs: April 30, 2024.)
The endorsed change rewrites the out-of-scope language to prohibit changes to the process for transferring CIRs to replacement resources interconnecting to the same substation as the deactivating generator but at a different voltage level. It previously prohibited changes for when the replacement located at a different point of interconnection.
The revisions also shift the working group from the Interconnection Process Subcommittee to the PC to accommodate the wider scope. The issue charge was cosponsored by East Kentucky Power Cooperative and Elevate Renewables.
CIFP Manual Revisions Endorsed
Stakeholders endorsed a slate of manual revisions codifying PJM’s new approach to risk modeling and accreditation drafted through the Critical Issue Fast Path (CIFP) process last year and approved by FERC in January. (See “First Read on CIFP Manual Revisions,” PJM PC/TEAC Briefs: April 30, 2024.)
The changes include how PJM will use its marginal effective load-carrying capability (ELCC) framework for accrediting all generation resources, the simulation of resource outputs and the definition of the capacity emergency transfer objective (CETO), which sets the import capability needs to meet reliability objectives. The revisions also include several calculations used in accreditation and for setting capacity procurement targets through the Reserve Requirement Study (RRS).
Manuals 20, 21 and 21A would be replaced with Manuals 20A and 21B beginning with the 2025/26 delivery year, while Manual 14B would remain with language changes. The Markets and Reliability Committee is set to consider endorsement of changes on June 27 alongside a rewrite of Manual 18 to effectuate changes on the markets side. (See “Stakeholders Endorse Manual Revisions to Implement CIFP Changes to Capacity Market,” PJM MIC Briefs: May 1, 2024.)
Preliminary ELCC Class Ratings
PJM presented a preliminary set of ELCC class ratings projected through the 2034/35 delivery year that show declining values for renewable and storage resources and fairly stable or increasing ratings for fossil generation.
Offshore wind is hit particularly hard, with its class rating expected to go from 61% in 2026 to 20% in 2034. Onshore wind is projected to fall from 35% to 15%.
PJM presented preliminary effective load-carrying capability (ELCC) ratings for several capacity resource classes, which showed wind ratings decreasing through 2034. | PJM
PJM’s Patricio Rocha Garrido said the decline in wind generation ratings was driven largely by the hours of risk being increasingly concentrated on days when wind performance is projected to be low. Much of that data is derived from the 2014 polar vortex on Jan. 7 and 8, as well as low performance hours on Dec. 26, 2022, during Winter Storm Elliott.
As the amount of wind generation on the grid increases, Rocha Garrido said, the resource class is able to meet the need on a wider number of days. That in turn concentrates the risk that remains onto winter days with low wind performance.
Solar ratings similarly are being driven down by increased winter risk matching up poorly with times of peak solar availability. Tracking solar has a rating of 11% in 2026 dropping, to 4% in 2034, while fixed solar falls from 7% to 3%.
The longer duration of winter events also also a factor for declining ratings of shorter-term storage resources. Four-hour storage falls from 56% to 38% over the years analyzed, while six-, eight- and 10-hour storage see less significant drops.
While both coal and nuclear generation saw modest declines in their ELCC ratings, gas-fired resources saw upticks owing to risk patterns swaying toward days when they have stronger performance. Combustion turbines fared particularly well, increasing from 61% to 78%.
PJM spokesperson Jeff Shields said the increased gas generation ratings are from increased winter performance since the 2014 polar vortex and the pattern of risk shifting to days when other resources do not perform as well.
“The gas CT ratings increase because the risk shifts to winter days with poor wind performance in which the gas CT performance is not as low as during days such as the first polar vortex. Therefore, you can argue that the increase is driven by risk shifts that are caused by better gas CT performance, and other resources — wind, in particular — performing worse,” he said.
Rocha Garrido said the assumptions for the projections included using the 2025/26 delivery year assumed resource portfolio as a basepoint and modeling retirements and new entry using a vendor forecast. That includes growth in the wind, solar, four-hour storage and solar-storage hybrid classes, as well as coal generation deactivations.
PJM Pushes Pause on LTRTP to Focus on 1920
PJM plans to hold off on advancing its long-term regional transmission planning (LTRTP) proposal and shift its focus to its compliance filing for FERC Order 1920, which requires RTOs to develop scenario-based planning processes on a 20-year horizon. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)
The PC endorsed the LTRTP approach in March, but deliberations were deferred at the MRC in April to see how it measured up against the commission’s long-awaited order. (See “Stakeholders Defer Vote on Long-term Planning Proposal,” PJM MRC Briefs: April 25, 2024.)
PJM’s Jason Connell laid out several differences between the LTRTP design developed over the past year and Order 1920’s requirements, which include at least one extreme weather scenario, “plausible” and “diverse” scenarios, and a wider range of planning factors. While the LTRTP would implement a 15-year planning horizon, the order requires at least 20 years, and the two reliability and policy scenarios PJM proposed fall short of the minimum of three scenarios the commission required.
“There is quite a bit of deviation between what we proposed and the order,” Connell said.
Presenting the Natural Resources Defense Council’s perspective on the differences, Senior Advocate Tom Rutigliano said the first year of PJM’s proposed LTRTP timeline involved building scenarios, work that could be done in parallel with preparing the compliance filing. Waiting until compliance is approved by FERC likely would result in delaying implementation until the fourth quarter of 2026. Laying some of the groundwork in scenario design ahead of time could shave a year off implementation and begin addressing PJM’s long-term resource adequacy concerns faster, he argued.
“This needs to start sooner, so what we’ve got here is work that can be done in parallel,” Rutigliano said.
Connell said PJM’s goal is to move quickly and bring manual revisions to stakeholders within a few months detailing how it will initiate the assumptions phase of a larger long-term planning effort. The revisions also may include starting on the analysis phase as well while the compliance filing is prepared and pending at the commission.
Transmission Expansion Advisory Committee
NJ BPU Pausing 2nd SAA Competitive Window for Offshore Transmission
The New Jersey Board of Public Utilities has suspended the second State Agreement Approach (SAA) competitive transmission solicitation window, which PJM was planning to administer in July.
Ryann Reagan, wholesale market policy specialist for the BPU, told the Transmission Expansion Advisory Committee that the board’s timeline no longer aligned with the 2024 Regional Transmission Expansion Plan (RTEP) cycle. The amount up in the air with regional transmission planning and offshore wind also contributed to the decision, she said, pointing to the board’s work updating the state’s Energy Master Plan and Offshore Wind Strategic Plan.
Reagan said it’s hard to see where the state’s offshore wind goals could align with PJM’s planning processes until there is more clarity around the LTRTP and Order 1920.
The board intends to move forward with its fourth and fifth solicitations for offshore wind generation, with awards likely prior to the transmission planning being completed.
Deactivation Request Update
Two generators have filed for deactivation over the past month, PJM’s Michael Herman told the TEAC.
J-Power USA Generation is seeking to bring nine gas-fired turbines in the ComEd zone offline in June 2025, while AES submitted a deactivation request for a 5-MW battery located at its Warrior Run cogeneration plant.
PJM also is in the process of studying a deactivation request for Cogentrix’s Elgin generator, which has four gas turbines amounting to 483 MW. Reliability analysis is set to begin in the third quarter of this year, Herman said.
IEC Remains on Hold
PJM’s Nick Dumitriu said the RTO’s annual re-evaluation of market efficiency projects recommended leaving Transource Energy’s Independence Energy Connection (IEC) project on suspension because of poor cost-benefit results and possible reliability violations. The PJM board voted to suspend the project on Sept. 22, 2021. (See “Transource Update,” PJM PC/TEAC Briefs: Oct. 5, 2021.)
The two-pronged project seeks to alleviate congestion on the AP South Interface by building about 20 miles of lines between a new Furnace Run substation in York County, Pa., and Harford County, Md. The western portion would consist of a 230-kV double-circuit transmission line running 28.8 miles from Franklin County, Pa., into Washington County, Md.
Dumitriu said the project would reduce congestion on AP South by $84.97 million by 2033, along with reducing congestion by about $41 million on a series of other constraints, but a new $341.72 million constraint would be introduced on the 230-kV Ringgold-Frostown Junction line.
PJM’s Tim Horger said an update on the project’s future is planned for next month.
Supplemental Projects
American Electric Power proposed a $155.7 million project for a new service request to serve 1,100 MW of load in New Carlisle, Ind., expected to come online in December 2026.
The project would consist of two new 345-kV substations, Larrison Drive and New Prairie, cut into the Elderberry-Dumont and Dumont-Olive Bypass lines. End work also would be conducted on the Sorenson, Elderberry and Dumont substations.
PPL presented a new service request expected to interconnect 240 MW in 2026 and grow to 1,980 MW by 2033. The customer, located in Hazleton, Pa., would be served by a 230-kV source.
PECO Energy presented a $36 million project to rebuild its 6.24-mile, 230-kV Planebrook-Bradford line, which the utility said is nearing end of its life at 96 years old.
The utility also proposed a $17 million project to rebuild its nearly 100-year-old, 69-kV Tacony substation and install new equipment to upgrade it to 230 kV. Inspection of the site has found that equipment is in poor condition and cannot be repaired.
Duke Energy Ohio & Kentucky proposed a $7.8 million project to replace nine 345-kV oil-operated breakers at its Woodsdale substation because of maintenance issues. The project would install gas-filled circuit breakers, replace 17 switches and replace all bus conductor.
Duke also presented a new service request for a customer near Mount Orab, Ohio, seeking to interconnect 2,000 MW by 2029.
FirstEnergy presented a $9.8 million project to convert its 230-kV Milesburg substation, located in the APS zone, from a straight bus to a four-breaker ring bus. It said maintaining the existing configuration elevates outage risks for 3,116 customers with 107.6 MW of load if the facility experiences a single stuck breaker contingency.
Dominion Energy presented several projects to interconnect data center load in Northern Virginia totaling $57 million.
A new 230-kV Sloan Drive substation would be built for $30 million, which includes building two 230-kV lines to the future Bermuda Hundred substation. The substation has an projected in-service date of Dec. 31, 2027, and would serve more than 100 MW of data center load.
The utility proposed cutting into the 230-kV Techpark Place-White Oak line to build a new “Decoy Airfield” substation serving 100 MW of data center load. The new substation would cost an estimated $12 million to build with an in service date of Jan. 1, 2026. A $15 million project would tap the 230-kV ICI-Allied line to connect to the new Bermuda Hundred facility.
