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December 28, 2024

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FERC Directs Additional Compliance for Tri-State on Exit Fees

FERC ordered Tri-State Generation and Transmission Association to rework two filings involving departing members in orders issued March 29. 

One order was a specific agreement on United Power’s departure from the wholesale member-owned cooperative (ER24-1145), while the other regarded what costs future departing members would have to cover (ER21-2818). 

Tri-State provides wholesale power and transmission service to 42 members in Colorado, Nebraska, New Mexico and Wyoming. United is a Colorado co-op that has taken service from Tri-State under a wholesale electric service contract (WESC), but it gave official notice it wanted to leave in April 2022, to be effective May 1, 2024. 

The broader departure fee case dates back to September 2021, when Tri-State first filed revisions, which were set for hearings and led to another order in December 2023. (See FERC Picks ‘Balance Sheet Approach’ Exit Fee for Tri-State Members.) The order issued last week directs another compliance filing to fix some aspects of the proposed exit fee. 

United told FERC that the latest withdrawal proposal from Tri-State would charge it $627.7 million, while it calculated a fee of $464.5 million. The largest reason for the $163 million gap is the $148 million United said Tri-State failed to account for in the co-op purchase of non-networked transmission and distribution facilities. 

FERC found the arguments in the case from both United and Tri-State would be better addressed in the broader compliance case but accepted the withdrawal agreement subject to some additional issues being resolved. 

The $627.7 million fee is based on a contract termination penalty of $709.5 million, minus $81.9 million in patronage capital that United had put up but no longer will be used now that it is leaving. Tri-State will have to file an updated amount with the right patronage capital amount and regulatory liabilities credit, which are being developed in the ongoing ER21-2818 docket. 

The commission accepted the withdrawal agreement, subject to a compliance filing due in 14 days, which will allow United to leave Tri-State’s service.

Tri-State also will have to make a compliance filing on the broader contract termination payment (CTP) rules within 14 days, but those rules will apply only in total to firms that leave the co-op’s service after 2025. FERC also set up hearing and settlement procedures for some aspects of the rule. 

FERC accepted Tri-State’s proposal to provide each member with a potential CTP every year that reflects their pro rata allocation of power purchase agreements in addition to their pro rata share of its debt. Tri-State also won approval for its proposal to enter into withdrawal negotiations within 180 days of getting a request, but the association will have to make clear that none of those procedures are required by entities leaving this year or next, which already have started to withdraw. 

The commission found that Tri-State partly complied with its requirements to pay back departing members’ patronage capital, either as a discounted lump sum or over time as it is retired in the normal course of business. But its proposal failed to account for any accrual or retirement of patronage capital that occurs between when a member signals a notice to leave and actually leaves service. 

Tri-State has members in both the Eastern and Western interconnections, and while those out West likely face higher CTPs than patronage capital amounts, that is not the case in the East. Tri-State proposed never having to pay a departing member if its patronage capital were higher than its CTP, but FERC ordered it on compliance to pay out a lump sum should such firms request it. 

Tri-State also was required to change its transmission crediting mechanism for departing members, basing it on their pro rata share of the full amount of its transmission debt and paying them back with full interest. 

The compliance filing also will have to change how PPAs are treated, as Tri-State will have to show departing members their pro rata share of system capacity and associated energy when it proposes their buyout amount. That will be earlier than Tri-State initially proposed, which FERC said would help departing members make their decision. 

Tri-State also will have to update its proposed CTP to properly reflect costs of serving customers in the Western Interconnection to reflect the impact of any members departing before another, so that a departing member does not have to pay for debt Tri-State collected in an earlier CTP. 

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CAISO Can Close 2024 Interconnection Window, FERC Rules

FERC on March 29 approved CAISO’s request to forgo this year’s process for taking interconnection applications, giving the ISO more time to study last year’s record-breaking number of requests (ER24-1213).  

FERC’s order became effective March 31, just ahead of the April 1 deadline CAISO is required to meet each year to open a new interconnection window, which kicks off a two-year cluster study process.  

CAISO sought the tariff change to extend study deadlines for Cluster 14 and pause Cluster 15 because of the “unprecedented increase” in new interconnection requests received for those clusters combined with a lower percentage of interconnection customers withdrawing after Phase one of the process. (See CAISO Seeks FERC’s OK to Shut 2024 Interconnection Window.) 

The rule revision will help CAISO “avoid compliance issues, the need for waiver or exacerbating the queue’s challenges before CAISO can comply with Order No. 2023 and implement needed reforms,” the order states. “Further, CAISO contends that forgoing the 2024 interconnection request window will allow sufficient time to study existing interconnection requests.”

Stakeholder Concerns

In comments submitted to FERC, several stakeholders said closing the 2024 interconnection window would affect much-needed resource procurement and fail to address the root causes of the clogged queues.  

While the Northern California Power Agency did not oppose the move, it did note that the backlog is particularly problematic for load-serving entities that will struggle to acquire the clean resources needed to meet procurement mandates without sufficient projects coming online in a timely manner.  

The Six Cities group of Southern California municipal utilities opposed the move, saying that while CAISO remains engaged in the Interconnection Process Enhancements stakeholder initiative, delaying the request window will cause a gap in implementing necessary reforms.   

“Six Cities contend that the elimination of the 2024 interconnection request window should not be permitted to prolong the gap in making these necessary changes to the process,” the order noted.  

Six Cities also acknowledged the challenge of bringing new resources online amid the delay. FERC noted the utilities said “they have experienced considerable challenges in procuring capacity to meet reliability requirements during the past two years.” 

CAISO asked the commission to disregard those concerns due to “meaningful progress” made in its stakeholder initiative and highlighted that it will propose significant reforms to the process when the ISO submits its compliance filing for Order 2023, expected April 3.  

FERC agreed with CAISO, saying the stakeholder comments fell “outside of the scope” of the proceeding.  

“We agree with CAISO that its proposed revision will enable CAISO to work with stakeholders to develop and implement meaningful reforms for processing Cluster 15 and will avoid exacerbating the queue’s challenges,” FERC said. “Further, we find that forgoing the 2024 interconnection request window is a just and reasonable solution to prioritize the significant volume of existing interconnection requests in a timely manner.” 

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NYISO Management Committee Briefs: March 27, 2024

Survey: Customer Satisfaction down, but Still ‘Very Good’

The NYISO Management Committee was informed March 27 that the ISO received a total satisfaction and performance score of 84.7, according to the eighth annual assessment by the Siena College Research Institute. 

Siena, a New York-based pollster, independently evaluated two aspects of NYISO’s operations: customer satisfaction, which gauges the quality of consumer interactions and engagement; and assessment of performance, which determines if the ISO is “realizing [its] mission through [its] performance.” 

NYISO scored 91 in satisfaction and 75.4 in performance; the final score, 1.7 points lower than last year’s, is weighted 60% on satisfaction and 40% on performance. 

Siena Director Don Levy explained that the survey involves asking both market participants and senior executives throughout the year to “assess the degree to which NYISO is enacting its mission, including things like reliably operating the grid, administering open and competitive markets, and providing factual information.” 

NYISO achieved its highest scores the previous year, with 92.3 in satisfaction and 77.6 in performance. “That score was a historic high and was bound to decline, so now the ISO has just regressed back to where it was in previous years,” Levy said. (See NYISO Receives ‘Exceptional’ Customer Survey Scores.) 

The ISO “deserves a pat on the back” for consistently scoring high in customer satisfaction, Levy said, but he noted that it should strive to enhance its performance assessment by market participants, which declined about 5 points from last year and is “lower than it has been over the past four previous years.” 

Specifically, NYISO should focus on improving its perceived underperformance in reliably operating New York’s grid, Levy said. That metric dropped 6.8 points from last year. However, he also acknowledged that NYISO’s professionalism consistently scores above 90 points, with respondents frequently writing how the ISO is “excellent, excellent, excellent at handling all interactions.” 

Levy urged NYISO to redouble its efforts to improve communication channels and engage more directly with market participants, emphasizing that the results are not “a call to jump off a cliff” but a reminder that the ISO has merely “dropped from exceptional to just very good” and has room for improvement. 

Co-located Storage Resource Participation

The MC approved proposed tariff changes allowing energy storage resources (ESRs) co-located with a dispatchable generator behind a single point of interjection to participate in the ISO’s energy markets. 

The revisions, approved by the Business Issues Committee on March 13, broaden the list of resources that can be included in the ISO’s co-located storage resource (CSR) models and are part of the wider hybrid storage resource (HSR) effort to couple generators with ESRs and further integrate them into New York’s energy markets. (See “Co-located Storage Resources,” NYISO Business Issues Committee Briefs: March 13, 2024.) 

NYISO aims to file the proposed HSR model and the approved CSR updates in the second quarter and implement the CSR updates by year-end. However, the changes will necessitate additional modifications to comply with FERC Order 2023 that will not be developed until the ISO submits its final compliance filing. 

Capacity Accreditation

The MC also approved proposed tariff revisions intended to enhance the ISO’s capacity accreditation modeling by more accurately reflecting factors such as natural gas constraints and correlated derates essential for calculating capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs). 

Approved by the BIC last year, the revisions would ensure capacity resources receive compensation that aligns with their performance, availability and marginal contribution to reliability needs. They came after resource adequacy analyses indicated capacity accreditation models were producing inaccurate CAFs and CARCs for some resources and failing to account for metrics not represented in installed reserve margins and locational capacity requirements. 

The CAFs and CARCs for the 2024/25 capability year were respectively published Feb. 26 and Nov. 30. (See “Capacity Accreditation,” Hydrogen Getting Resource-specific Rules in NYISO Markets.) 

The revisions would also update the installed capacity (ICAP) supplier bidding requirements. Suppliers, unless exempted, must now either schedule a bilateral transaction or bid energy in the day-ahead market (DAM) with a normal upper operating limit (UOLe) at or above their ICAP equivalent of unforced capacity or notify the ISO of any outages. This would address a loophole in which existing market rules did not explicitly prevent ICAP suppliers from meeting their availability obligations by offering only a portion of their capacity in the DAM at an UOLe. 

Order 2023 Update

NYISO CEO Rich Dewey informed the MC that amendments FERC made to Order 2023 necessitate delaying the ISO’s final compliance filing beyond the originally scheduled April 3 deadline. 

Dewey said the exact submission date remains uncertain as staff “are still reviewing the details,” but a presentation scheduled for the Transmission Planning Advisory Subcommittee’s (TPAS) meeting April 1 suggests the ISO plans to submit its filing by May 1. 

FERC on March 21 modified and clarified its new generator interconnection rule and extended the compliance deadline, after rejecting multiple challenges that sought rehearing. (See FERC Upholds, Clarifies Generator Interconnection Rule.) 

Dewey assured the MC that more information about NYISO’s Order 2023 filing will be shared at the TPAS meeting, with stakeholders commenting on further revisions at the Interconnection Issues Task Force’s meeting April 15. 

Board Compensation

Dewey also reported to the MC that the ISO’s Board of Directors approved a $3,500 increase in the annual retainer for directors, to $80,000. 

The board adjusted its retainer about a year ago, raising it by $5,000 to $76,500, and will reassess the need for additional compensation changes annually instead of every three years, as had been the practice. (See “Board Compensation,” NYISO Receives ‘Exceptional’ Customer Survey Scores.) 

Dewey mentioned that the board continues to interview potential members but has not yet met to formalize any decisions, though it hopes to do so in April. 

NYPSC Confirmations

The New York State Senate confirmed Uchenna Bright and Denise Sheehan as the new commissioners at the state’s Public Service Commission on March 27. 

Uchenna Bright | E2

Gov. Kathy Hochul (D), who nominated both in late February, praised the confirmation, saying in a statement that the new “commissioners will bring unique and invaluable expertise to the PSC at a pivotal time for New York’s energy future.” These are Hochul’s first nominations to the seven-member PSC, with each commissioner serving a six-year term. 

Bright, a longtime environmental advocate, was Northeast lead for E2, a nonprofit group of business leaders that lobbies for green policies and partners with the Natural Resources Defense Council. Sheehan, a former New York Department of Environmental Conservation commissioner, was an executive vice president at Capitol Hill Management Services, an Albany-based association management company. She has also served as a senior adviser to the New York Battery and Energy Storage Technology Consortium. Their confirmation hearing was March 26. 

Denise Sheehan | NYLCV

Gavin Donohue, president of the Independent Power Producers of New York, said in a statement that Sheehan “brings a balanced point of view between safe, reliable and affordable service, and her decorated career within government and the industry speaks for itself.” Bright “will provide expertise on environmental policies with economic costs and benefits at the front of mind in a way that balances a good economy and environment,” he said. 

The New York League of Conservation Voters praised Hochul’s nominations, saying their expertise and environmental advocacy make them “welcomed additions to the PSC.” 

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SPP Files Proposed Markets+ Tariff at FERC

SPP filed its Markets+ tariff at FERC on March 29, the culmination of a more-than-yearlong collaboration with potential participants and stakeholders to draft rules and protocols for the grid operator’s day-ahead market offering in the Western Interconnection. 

The tariff was formally approved by the SPP Board of Directors last week. The language previously was endorsed by Markets+ stakeholders and a panel of independent SPP directors. (See SPP Board Approves Markets+ Phase 1 Tariff.) 

“SPP’s mission and success [depend] on working together effectively, and it’s been a privilege to work alongside our new western stakeholders to craft market policy that will create a brighter, more resilient energy future in the West,” CEO Barbara Sugg said in a statement.  

Sugg added she’s looking forward to “bringing Markets+ to life.” 

SPP requested that the commission issue an order by July 31. It also asked for an extended 31-day public comment period, and it committed to specifying a precise effective date before implementation, currently targeted for the second quarter of 2027 (ER24-1658).  

As SPP doesn’t yet have an effective date, it followed FERC precedent in setting a date of 12/31/9998 for tariff records submitted in the filing. 

The RTO’s staff worked with staff from 38 western entities that executed agreements to participate in the first phase of Markets+’s development. 

“It’s been critical to us that the development of Markets+ be driven by western stakeholders,” said Antoine Lucas, SPP’s vice president of markets and sponsor of the Markets+ program. He said SPP’s approach has resulted in a market design that would improve the grid’s reliability and affordability, enable participants to meet clean energy mandates and goals and to do so in a way that “ensures equity for every market participant.”  

SPP is competing with CAISO’s Extended Day-ahead Market (EDAM) in attracting western entities to Markets+. FERC has already approved the bulk of EDAM’s tariff, and Portland General Electric and Idaho Power recently signaled their intent to join the CAISO market. That increases EDAM participants to five members. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM and CAISO’s EDAM Scores Key Wins in Contested Northwest.)  

In a news release, SPP provided positive statements from several western stakeholders, perhaps none more important than that of the Bonneville Power Administration (BPA). The federal agency operates more than 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, lending significant weight to its decision on joining a day-ahead market. 

Rachel Dibble, BPA’s vice president of bulk marketing and a member of the Markets+ Participants Executive Committee (MPEC), told SPP she appreciated the grid operator’s “collaborative and transparent stakeholder-driven governance model” used to develop the tariff language. 

“The result is an end product that recognizes the needs and perspectives of all participants and accounts for BPA’s legal obligations,” Dibble said. 

Arizona Public Service’s Brian Cole, vice president of resource management, noted his customers’ energy needs will increase dramatically over the next few years. He said the utility is “thoughtfully exploring market options.” 

“SPP’s Markets+ provides a promising framework to serve the West with dependable, diverse and cost-competitive power supplies,” Cole said. 

Northwest & Intermountain Power Producers Coalition Executive Director Spencer Gray, a prominent voice for the independent sector, applauded the commitment and work by Markets+ participants, stakeholders and SPP staff for “improving wholesale energy markets in the West.” (See “Independents Sector Changes,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.) 

SPP and western stakeholders will continue their work to define protocols for the market’s administration while awaiting FERC’s approval of the draft tariff. 

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FERC Allows MISO Plan to Align Generator Replacement and Suspension Processes

With FERC’s blessing, MISO will synchronize its generator replacement process with its generation suspension and retirement process to give interconnection customers more flexibility when they decide to replace, retire or suspend a generating unit.  

MISO received a favorable decision on a tariff change from FERC on March 29 and now will allow owners hoping to replace their generation with the option to simultaneously request to be evaluated for retirement or suspension if their plans for a replacement facility don’t pan out (ER24-1055). 

MISO’s current generator replacement process requires an interconnection customer seeking to replace its generating facility with a new facility to submit a request for replacement at least a year before the existing facility halts commercial operations. MISO completes a replacement impact study on the new generation to figure out whether its addition will adversely impact the system and completes a reliability study to see if the system will suffer violations without the existing generation while the replacement generation is being built. If the project can proceed, MISO drafts a replacement generation interconnection agreement (GIA).  

However, that roughly yearlong process bumps up against MISO’s generation suspension and retirement requirements, which expect generation owners to make a request to retire or suspend more than a year before the generating unit idles.  

MISO said its generation owners often begin the process unsure of whether a replacement, suspension or retirement is the best decision for their generation and have only the results of MISO’s reliability and impact studies for replacement once the notification deadline to retire or suspend the unit has passed. That leaves owners who find that their replacement plan is not viable in a bind, MISO said, and beholden to a process “entirely driven by procedural timing requirements rather than engineering or economic considerations.”  

Now generation owners will be able to request a suspension/retirement equivalency study alongside their option for MISO to perform generation replacement studies. If owners elect the equivalency study at the time of their replacement request, MISO will waive the yearlong lead time for suspensions and retirement requests and require only 30 days’ notice to begin suspension/retirement studies. 

MISO said the rule change will allow generation owners whose replacement plans fall through and have elected the equivalency study to seamlessly transfer units to suspension status, “which will allow the interconnection customer to make the proper plans for the future of its unit.”  

FERC said the change should allow MISO to process suspension, retirement and replacement requests more efficiently and give interconnection customers better data to make informed business decisions.  

“We find that MISO’s proposal will integrate and harmonize its retirement and suspension processes with its generator replacement process by aligning the timeline for an interconnection customer with an existing generating facility to be considered for a suspension and/or retirement request with a replacement generating facility request,” the commission wrote.   

FERC said the revisions will allow owners more freedom to pursue suspension and retirement decisions if their replacement facility requests are denied by MISO and lessen the risk that they miss deadlines to cease operations.  

MISO also said it will apply its new process to partial replacement of generation facilities, where some interconnection rights are left over after a replacement facility is planned. In those cases, interconnection customers can make additional replacement generating facility requests for the remaining capacity of an existing generating facility up until the first GIAs are struck for some of the interconnection rights.  

The Mississippi and Arkansas public service commissions, Entergy and WEC Utilities protested the filing, arguing that MISO’s plan would deprive generator owners of their residual interconnection capability by prohibiting additional interconnection requests of already-paid-for interconnection rights after the first GIA is signed.  

FERC brushed those concerns aside, saying interconnection customers still have the opportunity to replace an existing generating facility up to the same level of interconnection service.  

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Retirements and New Faces on PJM Executive Team

PJM Vice President of Planning Ken Seiler completed a nearly 23-year career with the RTO on March 29 before retiring and handing leadership of the Planning Division to Paul McGlynn, previously the executive director of system operations. 

Seiler was joined by colleagues at PJM and across its membership for a going-away celebration following the March 20 Members Committee meeting, where McGlynn said he has benefited from the work Seiler has put into transforming the RTO’s interconnection process to run more smoothly and generally putting the planning division in a strong position. (See PJM Initiates Transitional Interconnection Queue.) 

PJM Executive Vice President of Market Services and Strategy Stu Bresler also praised Seiler’s leadership. 

“You’re leaving this organization better than you found it — you made it a better place,” Bresler said. 

Seiler will continue to be the RTO representative on the ReliabilityFirst Board of Directors through 2024. He also served on the board of PJM Environmental Information Services (EIS) through Jan. 1, when Vice President of Market Design and Economics Adam Keech assumed his position.  

Paul McGlynn, PJM | © RTO Insider LLC

Prior to heading the Planning Division, Seiler worked in the information technology and operations departments at PJM and was integral in the development of its backup control center. 

McGlynn was named Seiler’s successor in November, shifting him over from the Operations Division, where he oversaw real-time dispatch operations, near-term reliability studies, load forecasting, and the coordination of generation and transmission outages. (See PJM Restructuring Executive Team.)

This won’t be McGlynn’s first time in the Planning Division. Before his time heading operations, he was the RTO’s senior director of system planning, a role involving administering the development of the Regional Transmission Expansion Plan (RTEP).

McGlynn earned his bachelor’s degree in electrical engineering from Pennsylvania State University and a master’s in electrical engineering from Drexel University. Prior to his time at PJM, he worked for Exelon in its engineering and operations departments. 

Aftab Khan Fills New VP Position

PJM has filled its newly created position of executive vice president of operations, planning and security with the appointment of Aftab Khan, former senior vice president of engineering at Eversource Energy. He began in March after his hiring in February. 

“I am eager to help PJM take on the many challenges presented by the energy transition. PJM’s creation of this new role shows the company’s commitment to seeking comprehensive solutions that emphasize reliability and security as the system evolves,” Khan said in a February announcement of his appointment. 

Khan’s role was created in November to “have overall responsibility for grid operations, transmission planning, cybersecurity and physical security, and business continuity.”  

Khan holds a bachelor’s degree in electrical engineering from the University of Alaska, an MBA in operations and finance from Carnegie Mellon University and a master’s degree in electric power engineering from Rensselaer Polytechnic Institute, the announcement says. 

He spent 24 years working at ABB, including as president of the Power Systems Division, Saudi Arabia; senior vice president of power transformers, North America; and senior vice president of grid systems, North America. 

“We welcome the experience, expertise and leadership Aftab brings to this important new role, which was created to support grid reliability during this increasingly complex energy transition,” PJM CEO Manu Asthana said in the announcement of Khan’s appointment. 

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EPA Issues Final Standards on Heavy-duty Truck Emissions

The final standards for greenhouse gas emissions from heavy-duty trucks, issued by EPA on March 29, attempt to strike a balance between environmental concerns about diesel fumes the trucks spew into the air and the economic and physical logistics of building out a zero-emission fleet and charging network.  

Aimed at cutting 1 billion tons of GHG emissions per year — and saving $3.5 billion for truckers — the rules provide a longer runway for manufacturers to meet emission-reduction targets that are initially less stringent than the proposed standards EPA issued in April 2023. This slower phase-in is offset by tougher goals in 2031 and 2032, in many cases stricter than initially proposed.  

The standards for three of the heaviest heavy-duty vehicles will go into effect on a staggered schedule. For day-cab “tractors” ― that is, semis without a sleeping compartment ― compliance will begin in 2028. The start date for heavy “vocational” vehicles ― a category covering a range of construction, maintenance and other work vehicles ― is in 2029; for tractors with sleeping compartments, it is in 2030. 

“In consideration of the opposing concerns raised by commenters, EPA believes it is critical to balance the public health and welfare need for GHG emissions reductions over the long term with the time needed for product development and manufacturing as well as infrastructure development in the near term,” the rule says. 

These changes notwithstanding, EPA Administrator Michael Regan hailed the final rules as “the strongest greenhouse gas standards for heavy-duty vehicles in history.” 

Speaking at a prerelease press call, Regan framed the standards as tackling heavy-duty trucking’s impacts on both climate change and public health. Transportation accounts for 29% of all U.S. emissions — more than any other sector — and heavy-duty trucks make up about a quarter of that total, according to EPA. 

“An estimated 72 million Americans, often people of color or people with lower incomes, live near freight truck routes,” Regan said. “These communities are disproportionately exposed to the pollution from heavy-duty vehicles, resulting in higher rates of respiratory and cardiovascular illnesses and even premature death.” 

Both Regan and National Climate Adviser Ali Zaidi also promoted the rules as another piece of the Biden administration’s work on decarbonizing transportation and the economy, while boosting investment in the automotive industry and creating jobs. The new rules are part of EPA’s Clean Trucks Plan, which includes rules, released in 2023, limiting nitrogen oxide emissions from heavy-duty trucks, Regan said. 

Zaidi pointed to the tax credits supporting clean trucks in the Inflation Reduction Act: $40,000 for zero-emission trucks and up to $100,000 for charging and refueling stations. He also cited the recent launch of the administration’s National Zero-Emission Freight Corridor Strategy, which first will develop charging hubs and then corridors to accelerate the buildout of a zero-emission freight network nationwide. (See Feds Announce National Strategy for Zero-Emission Freight.) 

EPA is estimating that operational savings for heavy-duty zero-emission vehicle (ZEVs) ― their total cost of ownership ― will offset their higher upfront costs, which are potentially more than twice the cost of a comparable diesel truck with an internal combustion engine (ICE). 

With EPA’s estimated $3.5 billion in savings for operators, payback on heavy-duty electric vehicles could happen within two to five years, depending on the type of truck. By 2032, when the standards are fully phased in, individual owners and drivers could be saving between $3,700 and $10,500 annually on fuel and maintenance, depending on vehicle type. 

EPA has also committed to ongoing consultation with stakeholders as the standards are implemented, “to learn from their experiences and gather relevant information and data,” according to the announcement. Based on stakeholder input, EPA may issue periodic reports or guidelines or consider modifications to the standards to be made through a future rule. 

“What we are excited about is the ability to collect specific data from various entities, whether that be community groups, environmental groups or the industry … to help accentuate and possibly give us new data and information we may not have considered,” Regan said. 

What’s in the Mix?

Decoding the 1,155 pages of the EPA’s final rule is more than a little complicated. While the industry classifies trucks by weight, EPA has broken down heavy-duty trucks into more detailed categories and subcategories ― vocational and tractor; low and high roof; light, medium and heavy heavy-duty. 

The emission standards themselves are expressed in grams per ton-mile, agency jargon that does not easily translate into pounds of tailpipe carbon dioxide emissions. 

Getting a handle on the scope of the challenge ahead requires some digging. Trucking industry sources count about 13 million registered trucks on roads nationwide, 2.9 million of which are semis. As of June 2023, only about 17,500 were ZEVs, and the vast majority ― 14,000 ― were medium-duty cargo vans, the nonprofit CALSTART reported. 

The Department of Energy’s Alternative Fueling Station Locator shows the U.S. with a total of 15 DC fast-charging stations, with a total of 26 charging ports, available for the largest types of HD trucks, and most of those stations are privately owned.  

EPA’s last GHG standards for HD trucks were set in 2016. When fully phased-in, the new rules could slash emissions by 25 to 60% below the 2016 standards depending on vehicle type, according to an EPA fact sheet. 

Despite Republican complaints that EPA is trying to force Americans into EVs, the new standards do not require truck manufacturers to make — or truck drivers to buy — ZEVs. Regan has stressed that the new rules are performance-based and “technology-neutral, allowing each manufacturer to choose what set of emission-control technologies works best for them, whether that’s advanced internal combustion engines, hybrid vehicles, plug-in hybrid electric vehicles, battery electric trucks [or] hydrogen fuel cell vehicles.” 

The rules offer two scenarios of how different mixes of vehicles might be used to meet the standards and how percentages of ZEVs versus diesel trucks might change through 2032. Generally, the heavier the truck, the lower the percentage of ZEVs being predicted. 

In a scenario with only ZEVs and ICEs, light vocationals start with a mix of 17% ZEVs and 83% ICEs in 2027 but reach 60% and 40%, respectively, by 2032. A second scenario replaces ZEVs with a mix of hybrids, plug-in hybrids, and natural gas and hydrogen-powered ICEs. In this case, ICEs go from 33% in 2027 to just 1% in 2032, while hybrids go from 52% in 2027 to 40% in 2032, and hydrogen ICEs from zero to 24%. 

For long-haul trucks, the rule predicts 25% ZEVs versus 75% ICEs in 2032. In the non-ZEV scenario, ICEs account for 64% of the fleet by 2032, with hybrids at 10%, natural gas at 5% and hydrogen ICEs at 17%. 

However, the potential impact of the EPA standards is only one factor in a broader landscape of policy and market forces that could drive accelerated adoption of heavy-duty ZEVs over the next decade and beyond. 

California’s Advanced Clean Trucks (ACT) rule, now adopted by 11 other states, provides a different approach, requiring manufacturers to increase their percentages of ZEVs offered for sale in the state each year through 2035, in some cases to higher levels than those projected by EPA. 

By 2032, ACT calls for 40% ZEVs for lighter medium-duty vehicles, such as cargo and passenger vans weighing between 8,501 pounds and 14,000 pounds, rising to 55% by 2035. The goals for other medium- and heavy-duty vehicles are 60% ZEVs in 2032, ramping up to 75% in 2035, while long-haul ZEVs hit a 40% plateau for 2032 and beyond. 

Similarly, EPA projections for ZEV adoption generally lag behind the sales targets set by major truckmakers in the U.S. Daimler Truck North America has committed to a carbon-neutral fleet by 2039; Navistar has said it will reach 50% ZEV sales by 2030 and 100% by 2040; and Volvo Group North America is also going for 50% ZEV sales by 2030. 

The three companies together represent 70% of all medium- and heavy-duty trucks sold in the U.S., according to a Daimler press release. 

In January, the companies announced the formation of a new coalition called Powering America’s Commercial Transportation (PACT). The group says it will not advocate for specific technologies or policies; it instead intends to focus on educating industry stakeholders about the bottlenecks to expanding charging networks for ZEVs and looking for new solutions. 

Daimler is also a founding member of another industry initiative called Greenlane, which is building out a charging network for commercial trucking along Interstate 15 between Los Angeles and Las Vegas. Daimler is partnering with NextEra Energy Resources and BlackRock on the 280-mile corridor, which will eventually have 100 fast chargers and stations with “modern amenities designed to increase the comfort of drivers [and] resilience for high uptime and ultimately moving freight more efficiently,” according to the announcement. 

Reactions

Reactions to the new standards were mixed. 

Environmental and cleantech groups were mostly positive, though they lamented what they saw as EPA’s compromises with the trucking industry. 

“Our communities have for years been concerned about the health impacts of the thousands upon thousands upon thousands … of trucks that travel our [streets] daily,” said the Rev. Lennox Yearwood Jr., president and CEO of the Hip Hop Caucus, an environmental, economic and racial justice nonprofit. “Although we would have liked to see a more stringent program that leads to zero emissions from freight, this is a meaningful step toward achieving cleaner air for our communities.” 

“These rules could have done more,” agreed Guillermo Ortiz, clean vehicles advocate at the Natural Resources Defense Council. “Our nation needs a vision to eliminate pollution from the freight transportation system. Every wheeze, every gasp for breath in communities impacted by the movement of freight serves as a reminder of the urgency to act.” 

Ryan Gallentine, managing director at Advanced Energy United, said the new rules will provide certainty for a range of industry players — truckmakers and private and public fleet operators — to move ahead with vehicle and fleet electrification and managed charging. 

“Electric trucks and buses provide a whole new business opportunity for fleet operators, who can take advantage of charge-management technology to maximize electricity savings for their vehicles and facilities,” Gallentine said. “That makes the switch to electric vehicles a force multiplier for communities, who will not only benefit from improved air but also a more energy efficient business environment.” 

Ben Prochazka, executive director of the Electrification Coalition, made a national security argument for the rules as an “important step towards ending our nation’s dependence on oil for transportation. … Heavy-duty electrification strengthens national security by reducing our dependence on global oil markets controlled by bad actors who do not share our democratic values and protects public health, particularly in underserved communities.” 

On the industry side, the American Trucking Associations began lobbying against the rules as soon as EPA released its proposed version last April, arguing the agency should not change its existing standards. 

EPA’s “post-2030 targets remain entirely unachievable given the current state of zero-emission technology, the lack of charging infrastructure and restrictions on the power grid,” CEO Chris Spear said. “Any regulation that fails to account for the operational realities of trucking will set the industry and America’s supply chain up for failure.” 

Truckmakers acknowledged EPA’s efforts to address their concerns but also stressed the need for a quick buildout of a charging network and ongoing federal support. 

Volvo said the company “is completely aligned with EPA’s objective of speeding the transition to zero-emission vehicles. It’s important to note that this regulation represents the first time that compliance is beyond our control as a manufacturer. Customers won’t buy ZEVs unless they’re confident they have access to charging, which neither [truckmakers] nor EPA can guarantee.” 

Cynthia Williams, global director of sustainability at Ford Motor Co., said, “The EPA’s new heavy-duty emissions rule is challenging, but Ford is working aggressively to meet the moment. … We also need policymakers to pair emission standards with incentives and public investment so that we can continue to deliver on the next generation of vehicles and for our nation to lead the future of this industry.” 

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Appeals Court Upholds FERC on Gas Project Extensions

FERC on March 29 came out on top of litigation over its granting previously approved natural gas projects’ requests for an extension of their deadlines to bring the facilities online (22-1233). 

The Sierra Club challenged two such orders before a three-judge panel of the D.C. Circuit Court of Appeals: National Fuel Gas Supply’s Northern Access Pipeline in Pennsylvania, and New York and Cheniere’s plan to expand its Corpus Christi Liquefaction LNG facility in Texas. Public Citizen joined Sierra in opposing the extension for the LNG facility. 

The New York State Department of Environmental Conservation denied National Fuel’s request for a permit, which set off years of litigation in federal court and caused it to seek two extensions from FERC. The firm won the case and filed its second request with the commission in 2022, which was granted. 

Cheniere’s LNG facility ran into delays because of the economic impacts of the COVID-19 pandemic and filed with FERC to extend its in-service date from later this year to 2027. FERC granted that, agreeing that the firm could not foresee the pandemic’s impacts on the global economy when its initial plans were made. 

FERC has broad discretion to grant the extensions, which is only limited by the “arbitrary and capricious” standard of the Administrative Procedure Act. It does not have to come to the best decision in such cases, with the court’s review limited to whether the commission examined the relevant considerations and articulated a satisfactory explanation for its action that includes a rational connection between the facts and its ruling. 

“In considering the requests for extensions, FERC found that the project sponsors had demonstrated diligence in the continued pursuit of their projects,” the court said. 

The litigation with New York and the pandemic’s impact on supply chains and the economy gave good cause for the extensions, the court said. FERC’s reasoning in both cases was consistent with its earlier decisions granting extensions. 

“FERC has found a wide range of circumstances to support good cause, including legal or litigation-related barriers, as well as impacts from the COVID-19 pandemic,” the court said. 

Sierra Club and Public Citizen argued that FERC’s inquiry was too lax, saying the agency rubber-stamps requests for extensions. 

“Although it is true that FERC has denied very few extension requests, that is not surprising,” the court said. “Project sponsors invest significant time and resources to secure approval of their pipelines and related facilities, and they generally have economic incentives to promptly complete construction.” 

Project sponsors can meet the good-cause standard by demonstrating their diligence and citing factors beyond their control that have slowed their progress, the court said. Developers who would abandon a project likely would never ask for an extension. 

Sierra Club also argued that FERC should have to re-evaluate the findings underlying its original certificate order any time it considers an extension request, but the court disagreed. FERC has broad authority to take whatever actions it finds necessary to amend a certificate. 

While the commission has to account for substantial or significant changes that impact a project’s approval under the National Environmental Policy Act, it is entitled to substantial deference because that call necessarily relies on FERC’s technical expertise, the court said. 

New York passed its Climate Leadership and Community Protection Act while the Northern Access project was being developed; Sierra Club argued that constituted a major change. But FERC found that the law did not impact demand for the pipeline’s gas, which is largely going to serve customers in Canada, where that law has no impact. The court again sided with the commission. 

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FERC Accepts, Sets Hearing on ND Co-op’s Tariff Rates

FERC on March 26 accepted SPP’s proposed tariff revisions modifying Central Power Electric Cooperative’s formula rate template but suspended them for a nominal period subject to refund and established hearing and settlement procedures (ER24-254). 

The commission found the proposed revisions raised issues of material fact that are more appropriately addressed in an administrative hearing. FERC encouraged the proceeding’s parties to reach a settlement before the hearing begins. 

The tariff revisions are suspended for a nominal period, effective Jan. 1, subject to refund. 

SPP filed Central Power’s requested formula rate template with FERC last year. The cooperative asked for a base return on equity of 10.29% and a 50-basis-point adder for its SPP membership. It said incorporating the adder for its initial and continuing RTO membership, previously approved by the commission, resulted in a total ROE of 10.79%. 

The commission said the adder continues to be appropriate given Central Power’s continued SPP membership. However, it found that the ROE, inclusive of the adder, must remain within the zone of reasonableness as determined by hearing and settlement judge proceedings. 

FERC rejected protests by the Western Area Power Administration and Missouri River Energy Services that Central Power should revise the template and the formula rate protocols governing the template’s updates and how the resulting rates will be implemented each year. It said the utilities did not demonstrate how the cooperative’s unchanged template and protocols are “integral to the revisions proposed by Central Power.” 

“We also find that nothing in the interaction between Central Power’s proposed revisions” and the template’s and protocols’ elements “discussed by Missouri River and [WAPA] create an unjust and unreasonable result,” the commission wrote. 

Central Power, headquartered in North Dakota, is a wholesale generation and transmission cooperative interconnected with SPP members WAPA, Basin Electric Power Cooperative and several other utilities. 

While Central Power, a borrower from the Rural Utilities Service, is not a “public utility” under the Federal Power Act, FERC cited precedent and a federal appeals court ruling to find it appropriate to apply the act’s just-and-reasonable standard to the cooperative’s proposed formula rate revisions, which are a component of SPP’s jurisdictional rates. 

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MISO Sets Sights on 2025 Completion for New Market Platform

MISO reported it’s making steady progress on installing a new market platform by the end of next year and will debut a new day-ahead market clearing engine this spring.  

The RTO said it likely will begin using its new, day-ahead market clearing engine exclusively sometime in May. 

At a March 27 customer readiness symposium meant to prepare members for MISO’s technological advances, MISO’s Arijit Bhowmik said the RTO is nearing the completion of parallel operations of the day-ahead clearing engine. MISO has said once it has its new clearing engine up and running smoothly, it can retire the legacy clearing engine from parallel operations. 

The grid operator was forced to push back the launch of the day-ahead market clearing engine to early 2024 instead of late 2023 due to delays. (See “Market Platform Replacement to Spill over into 2025,” MISO Board Week Briefs: Dec. 6-8, 2022.)  

MISO is slated to finish its market platform replacement completely by the end of 2025. It previously had ambitions to wrap up the project by the end of 2024, though it frequently cautioned the timeline could run longer. The RTO began the process of swapping out its outdated market platform for a new, modular platform in 2017. 

In late 2025, MISO will replace its real-time market clearing engine, which the grid operator uses every five minutes to send dispatch instructions. It also will go live in early 2025 with a new look-ahead commitment tool for generators.  

MISO completed factory acceptance testing and took delivery of its new real-time engine in 2023.  

Bhowmik said he hopes the introduction of the more nimble, modular platform can allow MISO to scale back the support hours it spends with members on the vintage platform.  

MISO has said it expects to spend $152 million on the market platform replacement, including about $14 million this year. It estimated program benefits remain steady at about $430 million. The grid operator began the market platform project with a $130 million budget and a $30 million contingency.  

Last year, MISO Director Theresa Wise said though the project now is “at the edge of” MISO’s budget plus contingencies, MISO expects the new platform to save at least a few hundred million dollars.