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November 1, 2024

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California Far Outpacing Clean Truck Targets

Truck manufacturers have been racking up zero-emission vehicle credits in advance of California’s Advanced Clean Trucks (ACT) rule taking effect with model year 2024, a new report shows.

About 7,900 zero-emission trucks from model years 2021 and 2022 have been sold in California, according to a report from the California Air Resources Board (CARB). Another 1,000 ZEV trucks are expected to be sold from those model years based on participation in the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project.

The combined total is about 60% more than the 5,500 zero-emission trucks that CARB expects manufacturers to need to meet the model year 2024 quota. And that doesn’t include zero-emission truck sales from model year 2023.

“Helping the businesses that rely on trucks to transport goods across the state switch to zero emissions is key to achieving a clean air future, and the data show that progress is well underway,” CARB Executive Officer Steven Cliff said in a statement.

Cliff said the figures indicate trucking businesses are interested in zero-emission vehicles, and manufacturers are stepping up to meet the demand.

Rivian led the way in model year 2022, with 5,286 zero-emission trucks sold in California. Ford followed with 1,686 ZEV trucks sold — out of a total of 28,606 medium- and heavy-duty vehicles delivered for sale in the state.

GM delivered 24,500 trucks for sale in model year 2022, but none of them were zero-emission, according to CARB.

In the Class 7-8 tractor category, Volvo sold 64 zero-emission vehicles from model year 2022. Paccar sold 16, followed by Daimler and Nikola Motor, with 13 each.

For model year 2022, 104,558 medium- and heavy-duty trucks were delivered for sale in California, including 7,639 zero-emission trucks, or 7.3%.

Advanced Clean Trucks, which CARB adopted in 2020, requires truck manufacturers to sell an increasing percentage of zero-emission vehicles in California starting in 2024.

The sales requirement varies based on the weight class of the truck. For model year 2024, ZEVs must account for 5% of Class 2b-3 trucks; 9% of Class 4-8 trucks; and 5% of Class 7-8 tractors. CARB said that on average, about 6% of trucks sold will need to be ZEVs in model year 2024.

Truck manufacturers may earn early credits for ZEV sales in model years 2021 through 2023, to be banked for use in later years or sold to other truck makers. The early credits are good through the 2030 model year.

Truck manufacturers that sell 500 or fewer vehicles a year in California are exempt from ACT but may opt to generate ZEV sales credits that can be banked or transferred.

Zero-emission truck sales generate credits that increase with the weight class of the vehicle. For model years 2022, truck manufacturers earned 6,414.7 credits, bringing the total for 2021 and 2022 to 7072.6 credits.

In July, CARB announced an agreement with leading truck manufacturers called the Clean Truck Partnership. (See CARB, Manufacturers Partner to Support Clean Truck Rules.)

The manufacturers agreed to meet California’s vehicle standards even if they’re challenged in court.

Under the Clean Truck Partnership agreement, truck manufacturers committed to selling as many zero-emission trucks as reasonably possible in California and other states that have adopted ACT.

The agreement came after a coalition of 19 states petitioned a federal appellate court in June to review EPA’s approval of Advanced Clean Trucks. Last month, a briefing schedule was filed in the case, with final briefs due in April.

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White House Announces Regional Tech Hubs to Spur Innovation

The White House and the Department of Commerce on Monday announced the designation of 31 “Tech Hubs” around the country, including a handful focused on the energy transition.

It marks the first phase of the Tech Hubs program, which is designed to drive regional innovation and job creation by strengthening a region’s capacity to manufacture, commercialize and deploy technology that will advance U.S. competitiveness. The 31 were picked from nearly 400 applications and are each eligible for up to $75 million in grants.

“Our Tech Hubs Program is fundamental to that mission and will supercharge innovation across the nation by spurring cutting-edge technological investments and creating 21st century job opportunities in people’s backyards,” Commerce Secretary Gina Raimondo said. “Each of these consortia will help us ensure the industries of the future — and their good-paying jobs — start, grow and remain in the United States.”

The program was authorized by the CHIPS and Science Act, which was signed into law in August 2020. The 31 hubs focus on a range of industries including semiconductors, clean energy, critical minerals, biotechnology, precision medicine, artificial intelligence and quantum computing.

The energy-related Tech Hubs include:

    • The Gulf Louisiana Offshore Wind (GLOW) Propeller, meant to grow a domestic offshore wind supply chain using Louisiana’s existing energy infrastructure, ports and shipbuilding network;
    • The Intermountain-West Nuclear Energy Tech Hub, which aims to position Idaho and Wyoming as global leaders in small modular reactors and advanced nuclear energy to contribute to a clean energy future;
    • The South Carolina Nexus for Advanced Resilient Energy, led by that state’s Department of Commerce and including Georgia, which aims to be a global leader in advanced energy by developing, testing and deploying exportable electricity technologies;
    • The South Florida Climate Resilience Tech Hub, led by the Miami Dade County Innovation and Economic Development Office, which aims to advance its global leadership in sustainable and resilient infrastructure solutions for the climate crisis; and
    • The New Energy New York (NENY) Battery Tech Hub, based out of the State University of New York Binghamton and meant to bolster battery technology development and manufacturing across the value chain.

Two others are focused on the country’s critical minerals supply chain. The Nevada Lithium Batteries and Other EV Material Loop is led by the University of Nevada, Reno, and it aims to build a self-sustaining and competitive lithium lifecycle cluster, spanning extraction, processing, manufacturing and recycling.

The University of Missouri is leading the Critical Minerals and Materials for Advanced Energy Tech Hub, which is aiming to position south-central Missouri as a global leader in critical minerals processing to provide the materials needed to support battery technology.

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NextEra’s Renewables Unit, FPL Key Performance

NextEra Energy said Tuesday its renewables subsidiary had its best origination quarter in its history, adding about 3.25 GW to its backlog.

NextEra Energy Resources’ (NEER) backlog now exceeds 21 GW, net of projects placed in service. The clean-energy unit placed a little over 1 GW of resources into service.

NEER and Florida Power & Light, the nation’s largest electric utility, added 65,000 more customers from a year earlier, helping NextEra beat Wall Street estimates.

NextEra reported third-quarter earnings of $1.219 billion ($0.60/share), compared to $1.696 billion ($0.86/share) for the same period a year ago.

“We will be disappointed if we are not able to deliver financial results at, or near the top of, our adjusted earnings per share expectations ranges in each year through 2026,” CEO John Ketchum told financial analysts during the company’s third-quarter conference call.

“The strength of both businesses … combined with our competitive advantages and strong balance sheet, positions us to continue creating long-term value,” he said.

NextEra’s share price closed at $55.12 Tuesday, a gain of $3.60 and nearly 7% on the day.

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MISO Likely to Pay $815K for NERC Violations

MISO has agreed to pay an $815,000 penalty for a pair of NERC violations committed over the summer.

MISO Vice President of Operations Renuka Chatterjee said MISO addressed the issues quickly while self-reporting them to ReliabilityFirst’s enforcement group. The grid operator agreed to ReliabilityFirst’s non-negotiable settlement proposal in late August.

Chatterjee said ReliabilityFirst determined the severity of the violations, and MISO would have faced a higher penalty if it hadn’t admitted the violations.

“MISO agreed to settle and admit the violations to minimize risk of increased penalty amount for MISO stakeholders,” Chatterjee said at an Oct. 18 Advisory Committee teleconference.

MISO said both incidents violated standard IRO-008-2, which governs operational analyses and real-time assessments.

MISO reported it discovered missing data while it was updating models in its day-ahead analysis for an unspecified day. The data is tied to contingency scenarios the RTO runs to prepare for the next operating day.

The second breach came when MISO discovered it lapsed in monitoring a 115-kV tie-line because it had been erroneously marked as external to the grid operator. MISO said it corrected the issue and has since implemented a procedure to reflect a change in seasonal ownership of the constraint.

“An after-the-fact analysis with updated ratings also showed that this non monitoring did not represent a system operating limit violation,” MISO added.

ReliabilityFirst has forwarded the penalty agreement to NERC for approval. The agreement then goes before FERC for authorization.

After FERC approval of the agreement, MISO will make a section 205 filing to recover the penalty from market participants. MISO said it anticipates FERC will issue an order on the settlement in late November or early December. In the anticipated timeline, MISO said it will recover the penalty sometime in the first half of 2024.

MISO said it maintained reliable operations throughout both events. The grid operator said, “at no time was there any harm to the bulk electric system.”

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NERC Board Approves Cold Weather Standards

In a special meeting Monday morning, NERC’s Board of Trustees agreed to adopt two new reliability standards for extreme cold weather, leaving approval by FERC as the last step before they become enforceable.

Trustees accepted EOP-011-4 (Emergency operations) and TOP-002-5 (Operations planning), both of which were produced by Project 2021-07 (Extreme cold weather grid operations, preparedness and coordination). NERC began the project in November 2021 to address the recommendations of the FERC-NERC joint report into the winter storms that struck Texas and the South Central U.S. that year. (See FERC, NERC Release Final Texas Storm Report.)

The new standards are part of the second phase of the project; FERC already approved two standards produced in phase 1 — EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) — in February. (See FERC Orders New Reliability Standards in Response to Uri.) With the conclusion of phase 2, the team for Project 2021-07 will move into the third and final phase to address further changes to EOP-012-1 that FERC directed this year.

EOP-011-4 updates its predecessor with requirements for transmission operators (TOPs) and balancing authorities (BAs) to update their operating plans to address emergencies arising from “the critical natural gas infrastructure loads that fuel a significant portion of … generation.”

Under the new standard, TOPs would have to prioritize critical natural gas loads in manual and automatic load shedding; they also would have to identify entities that are required to assist with load shedding, and those entities would be required to develop a load-shedding plan that prioritizes critical natural gas infrastructure loads. BAs also would be required to exclude critical natural gas infrastructure loads from their demand response programs during periods of extreme cold weather.

TOP-002-5 would require each BA to develop an operating process for its area that addresses preparations for and operations during extreme cold weather periods. The process must contain methodologies for identifying the periods in which it applies, for determining adequate reserve margins during these periods, and for developing a five-day hourly forecast that considers weather, demand, resource commitment, and capacity and energy reserve requirements.

During Monday’s meeting, Trustee Jim Piro asked Soo Jin Kim, NERC’s vice president of engineering and standards, how the team decided on the threshold for determining “what is an acceptable reserve margin calculation.” Kim replied that the team felt it was important to encourage entities to get plenty of lead time ahead of any possible events.

“I know some of the entities did push for a three-day look-ahead with regards to adequate reserve margins, [but] at the end of the day, we asked that the entities [try to] coordinate as [far] ahead as possible. It does allow for future coordination,” Kim said.

Board Chair Ken DeFontes added that he felt it “particularly important” that utilities were required to think about how their load-shedding programs might impact the natural gas system and adjust their plans to ensure those impacts are as small as possible.

Following the unanimous vote for approval, DeFontes confirmed with Kim that the third phase should be complete in the beginning of 2024.

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FERC Approves ERO 2024 Budgets

FERC last week unanimously approved the 2024 business plans and budgets for NERC, the regional entities and the Western Interconnection Regional Advisory Body (WIRAB), though Commissioner James Danly said in a concurrence that he would like to see “a significant improvement in the speed and agility” of the ERO’s response to energy reliability risks (RR23-3).

NERC’s final budget, approved by the organization’s Board of Trustees in August, stands at $113.6 million, an increase of $12.6 million (12.5%) over its 2023 budget. (See “2024 Budget Approved,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.) The RE budgets are also set to grow:

    • Midwest Reliability Organization — $24.9 million (up from $23.1 million);
    • Northeast Power Coordinating Council — $22.1 million (from $19.4 million);
    • ReliabilityFirst — $31.3 million (from $28 million);
    • SERC Reliability — $32 million (from $28.2 million);
    • Texas Reliability Entity — $19.2 million (from $17.7 million); and
    • WECC — $35.4 million (from $31.8 million).

In contrast, WIRAB’s budget for next year is set to shrink from $883,520 to $831,492.

The total assessment for the ERO is set at $216 million, comprising $97 million for NERC ($87.1 million from U.S. entities, $9.5 million from Canadian entities and $346,814 from Mexican entities), $128.3 million for the REs and $580,417 for WIRAB.

In its filing, NERC also outlined anticipated funding sources outside of the assessment, such as $10.1 million of third-party funding for the Electricity Information Sharing Analysis Center’s (E-ISAC) Cybersecurity Risk Information Sharing Program; $1.8 million in fees for users of the System Operator Certification Program; and $1.1 million in interest and investment income.

NERC’s biggest spending increases next year are expected to be in personnel (+13.4%), meeting and travel (11.5%) and operating (15.7%). The organization plans to hire an additional 14.3 full-time equivalent (FTE) positions next year, bringing its total staffing level to 251.1 FTEs.

The increased meeting and travel costs reflect “a return to pre-pandemic levels of in-person meetings and travel … while continuing to utilize the efficiencies of virtual meetings where appropriate,” NERC said. The organization attributed its raise in operating expenses to increases in spending on contractors and consultants, along with increased software license and support costs.

A significant number of the added FTEs, 4.7, are to handle the Interregional Transfer Capability Study (ITCS), which Congress ordered NERC and the regional entities to perform in this year’s Fiscal Responsibility Act. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.) The ERO is required to submit the report to FERC by Dec. 2, 2024, imposing costs on NERC and the REs that were not envisioned in their initial budget drafts.

In order to avoid raising the assessment proposed in its draft budget, NERC proposed to fund the $2.6 million required for the ITCS costs by drawing $1.3 million from the Assessment Stabilization Reserve, for non-personnel costs, and the remainder from the Operating Contingency Reserve. Drawing on the ASR in this way requires an exception under section 1107 of NERC’s Rules of Procedure; FERC granted the request.

The commission also agreed to permit an exception under section 1107 to allow NPCC and SERC to deposit penalty funds received between July 1, 2022, and June 30, 2023, amounting to $535,018 and $6.6 million, respectively, into their ASRs; and to allow MRO to use $1.2 million from its ASR and $119,026 of penalties collected before June 30, 2022, to reduce its 2024 assessments.

Finally, FERC approved WECC’s request to use up to $250,000 from the funds donated by Peak Reliability upon its dissolution in 2019 to support an expanded trial of an energy market simulation platform and the acquisition of electromagnetic transient simulation software.

In his concurrence, Danly said he is “not convinced” that the commission is “really getting value for the money [NERC is] spending to address known or emerging reliability risks.” He noted the commission’s separate order on developing standards for inverter-based resources, a reliability risk that he said “we have known about, and been actively discussing, since at least 2016.” (See FERC Orders Reliability Rules for Inverter-Based Resources.)

Despite this long debate, he said, the proposed standards would not be required to take effect until 2030. “Up to nearly 14 years is a very long time, and the reliable operation of the [power grid] remains imperiled until these risks are adequately addressed. We are as responsible for this situation as NERC,” Danly wrote, noting that the proposed 2024 budget is 12.5% higher than that for 2023, which was 13.7% higher than 2022.

“Will this increased funding actually help expedite the development and implementation of needed NERC reliability standards? Based on NERC’s recent track record, I have my doubts,” he concluded.

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NY Drills Down on Statutory Meaning of ‘Zero Emissions’

The New York Department of Public Service is once again seeking input on what exactly “zero emissions” means.

More precisely, it is trying to find an acceptable, expanded definition as the state’s statutory goals for emissions reductions appear increasingly hard to reach. And it is asking for legal interpretations as it goes through the process.

The Public Service Commission opened the contentious conversation in May when it acknowledged that favored technologies such as wind and solar might not be enough to achieve 70% renewable energy by 2030 and 100% emissions-free energy by 2040 (Case 15-E-0302).

This suggested a possible fallback on technologies opposed by many clean energy advocates, such as hydrogen, bioenergy and carbon capture.

The number and range of comments filed by the late August deadline was not surprising, given the potential impacts on the business plans of energy developers and on the health and wallets of state residents.

The Department of Public Service on Oct. 20 issued a series of follow-up questions to clarify the points made in the first round of questions.

The issue is even more salient now than when the PSC started the ball rolling in May: Developers of much of the state’s clean energy pipeline — 90 projects totaling more than 12 GW — said in June they might not be able to begin construction without more money. And the PSC voted unanimously Oct. 12 to reject their request for an inflation adjustment.

Renewable energy had been coming online slowly in New York even before this turn of events, and NYISO has been warning with growing urgency about a potential generation shortfall as fossil fuel plants are retired.

The DPS on Oct. 20 issued six new questions and asked for legal interpretations rather than policy considerations:

    • State Public Service Law and the landmark Climate Leadership and Community Protection Act of 2019 do not define “emissions” when they call for zero emissions. Should that be read as all air pollutants, just greenhouse gas emissions or something else?
    • Should the PSC read “zero emissions” and “net-zero emissions” as distinct terms, and if so, how should it characterize and apply the distinction?
    • The state Department of Conservation has counted biomass combustion emissions for electrical generation on a gross rather than net basis; should that inform the PSC as it defines zero emissions for the statewide electrical demand system?
    • What discretion does the CLCPA offer DPS staff as it specifies parameters such as which elements of the lifecycle of a given emissions source should be counted toward an emissions limit, and the threshold level at which emissions from that source are disqualifying?
    • Public Service Law designates fuel cells as a renewable energy system if they do not use a fossil fuel resource while generating electricity. What significance does this have for characterizing fuel cells that consume hydrogen, biogas, renewable natural gas or other non-fossil fuels as “zero emissions?”
    • “Statewide electrical demand system” is not defined in the CLCPA or elsewhere. What definitions does the law support, and how do they relate to electricity generated outside of the state or behind the meter?

Comments are due by Jan. 19.

A two-day technical conference on the matter is scheduled in-person and virtually Dec. 11-12.

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Overheard at Connecticut Power and Energy Society’s ‘Future of Energy’ Conference

HARTFORD, Conn. — Hartford Mayor Luke Bronin opened Connecticut Power and Energy Society’s “Future of Energy” conference with a call to speed up the pace of the energy transition, while also praising the state’s accomplishments.

“We’ve got to go so much faster if we’re going to get where we need to go,” Bronin said. “We know how much is at stake.”

Commissioner Katie Dykes of the state’s Department of Energy and Environmental Protection said climate change is stressing the state’s infrastructure, which has endured the effects of flooding from heavy and persistent rains that have bombarded the northeast this year.

Dykes said economywide decarbonization relies on decarbonizing the electric sector — which will in turn relies on the successful deployment of offshore wind — while also keeping electric rates as affordable as possible.

“There is a ceiling on what ratepayers can afford when it comes to offshore wind at this moment,” Dykes said.

For developers preparing bids for the state’s upcoming offshore wind procurement, “it’s important to keep price in mind,” Dykes said, expressing her hope some developers may be willing to take a lower profit margin to help the industry off the ground.

She expressed her hope that coordinated procurements between Connecticut, Rhode Island and Massachusetts, along with indexing provisions in the contracts to account for inflation, will help overcome the industry’s recent struggles. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.) In early October, Avangrid reached an agreement to back out of its contract with two Connecticut utilities for the 804-MW Park City Wind project, calling it “unfinanceable.” (See Park City Wind to Cancel PPAs, Exit OSW Pipeline.)

Dykes added that the state will continue to think creatively about improving the procurement process, and is considering holding regular, annual solicitations and dividing wind and related transmission procurements into “separate but synchronized” processes.

Paul Lavoie, Connecticut’s chief manufacturing officer, said offshore wind presents “a once-in-a-generation opportunity for us to stand up a new industry,” and that the state needs to increase its workforce development to prepare for the opportunity.

“The number one problem in Connecticut is the lack of a skilled and available workforce,” Lavoie said, adding this likely will remain the top issue for industry and manufacturing for the next 20 years.

He added that collaborating with neighboring states will allow each state to play to its strengths and minimize workforce shortages in any given state, citing coordinated procurements as an example.

“When it comes to the offshore wind industry, we can no longer be competitive — we have to be collaborative,” Lavoie said. “If Massachusetts has a strength, let Massachusetts have that work. If Connecticut has a strength, let Connecticut have that work.”

Lavoie also connected workforce shortages with the shortage of affordable housing in the state. “We don’t have enough places for people to live,” he said.

A local supply chain also could help insulate against future inflation increases, said Per Onnerud of Cadenza Innovation, a company that develops lithium-ion battery storage.

“Unfortunately, our supply chain right now is in China, for the lithium industry,” Onnerud said. “We need to lessen our relationship with China. We need to decouple, but we also cannot completely go cold turkey … It’s about striking a balance.”

Deputy Commissioner Robert Hotaling of the Connecticut Department of Economic and Community Development added that the state must focus on bringing education and employment opportunities to diverse and underserved communities.

“Diverse workforces drive innovation,” Hotaling said. “People from different backgrounds have different ideas, which lead to diverse solutions.”

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Phillips Addresses ‘Acting’ Status as FERC Awaits Nominees

What’s in a name?

That was the question FERC Chair — or “acting” Chair — Willie Phillips was asked at his press conference after the commission’s open meeting Oct. 19.

The FERC press release announcing Phillips’ elevation in January called him “acting chair,” but that has no legal definition under the commission’s governing statute. And the “acting” caveat was missing from the order President Joe Biden signed appointing Phillips. Phillips was confirmed by the Senate in 2021 to a term that ends June 30, 2026.

“Let me be clear: I work at the pleasure, and I serve at the pleasure, of the president,” Phillips said in response to a question about the discrepancy. “And I’m honored to serve. On January 3, 2023, I was named the chairman and the leader of this agency. Nothing has changed.”

This month, the conservative Institute for Energy Research released Biden’s order, which it obtained in response to a Freedom of Information Act request.

IER said FERC took nearly eight months to respond to its FOIA request and that it did so under a court-ordered deadline.

“It is now clear … FERC had the document all along, but for some reason did not want it to see the light of day,” IER President Thomas Pyle said in a statement. “It is also clear from the order that Commissioner Phillips is not the ‘acting’ chairman, as stated in the original FERC press release, but rather the full-fledged chairman.”

Initially, Biden had tapped former Chairman Richard Glick for another term running FERC, but that was scuttled by Senate Energy and Natural Resources Chair Joe Manchin (D-W.Va.). (See FERC’s Work in 2022 Left in Doubt by Manchin.)

Manchin and committee Republicans had criticized some of Glick’s proposals on how FERC reviews applications to build natural gas pipelines and other infrastructure. Phillips got a much warmer reception from that committee in a hearing in May. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.)

The White House told E&E News in January that Phillips would be acting chair until Biden appointed a “permanent” chair, and reiterated the “acting” designation this month.

The commission has added to the confusion: While press releases refer to Phillips only as “chairman,” his biography page lists him as “acting.”

Although appointment to FERC requires Senate confirmation, the appointment of the chair is the president’s authority alone.

At the hearing in May, Manchin told Phillips “there is no such thing as an ‘acting’ chair,” adding, “I’m glad you’ve been able to hit the ground running.”

“Once the president says you’re chairman, you’re chairman,” former FERC Chair Jon Wellinghoff said in an interview. “This ‘acting’ thing is all, you know, a big tempest in a tea pot, as they say.”

The president can rescind the chair appointment at his discretion, which happened to former Chair Neil Chatterjee late in the Trump administration.

Chatterjee said in an interview that Phillips is going to be running FERC through the end of 2024 at least, after which the commission’s leadership depends on the outcome of the next presidential election. The issue around the “acting” language had nothing to do with Phillips personally, but rather the White House seeking assurances from Manchin that he would not hold up Glick’s ultimate replacement, Chatterjee said.

Open Seats

FERC has gone more than 10 months without a replacement for Glick, and since then, Commissioner James Danly’s term expired at the end of June, though he can stay on at least until the end of the year, when Congress adjourns. While the Senate schedule has only seven weeks left and some are thinking about a three-member regulator next year, Chatterjee, who was a longtime Senate staffer, said sometimes nominations can move fast.

“Things can be very, very slow,” Chatterjee said. “But then there are times when lightning strikes, and they happen very quickly. So, I wouldn’t rule it out. If there’s momentum to do it, if it were clean, if there’s a pairing that both sides were fine with, it could go very quickly.”

In response to IER’s claims, FERC spokeswoman Mary O’Driscoll said the president’s order accurately reflects that Biden designated Phillips to lead FERC at the start of this year.

“Since he was named chairman, FERC has taken significant, bipartisan steps to enhance grid reliability, address the needs of environmental justice communities, certificate needed energy infrastructure and approve historic transmission reform,” she added. “FERC is working — as it should — to secure a more reliable and sustainable energy future for all Americans.”

After the open meeting, Phillips expressed pride in running an agency that regulates key sectors of the national economy.

“I’m proud of the fact that since I became chairman, we have done significant work to make reliability job number one,” Phillips said. “We have elevated the issue of environmental justice to be something that’s not just whispered about, but actually talked about and confronted by this agency and throughout our industry.”

Phillips also said his background growing up in rural Alabama and being the first Black man to run FERC influenced his job satisfaction. “I was just at Morehouse College … two weeks ago,” Phillips said. “And I know that this is important because people tell me it’s important to them. They see me and they know that they can do anything.”

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Settlement over PJM Elliott Penalties Receives Broad Support

A proposed settlement to reduce generators’ nonperformance penalties for the December 2022 winter storm received support Thursday from stakeholders, who urged FERC to approve it to reduce legal uncertainty (EL23-53, et al.).

A pair of Pennsylvania coal generators filed what is so far the lone protest against the settlement, which would reduce the penalties for nonperformance by nearly 32%. (See PJM OKs 32% Cut in Elliott Penalties in Proposed Settlement.)

In their objection, Chief Keystone Power and Chief Conemaugh Power argued that reducing the total penalties assessed against generators that did not meet their capacity obligations during the Winter Storm Elliott performance assessment intervals (PAIs) would deprive generators that invested in maintenance and on-site fuel of the Capacity Performance bonus payments they expected to receive under the tariff.

Under the CP construct, the $1.8 billion in penalties would be distributed to generators that exceeded their expected performance during the emergency conditions. The settlement would reduce the penalties to $1.23 billion by requiring bonus payment recipients, including the Chief companies, to return a portion of their share and resolve the 15 complaints generators filed against PJM related to the charges.

The Chief companies countered the argument made in several complaints that PJM had not followed the required steps before initiating a PAI by stating that market participants are able to access equal or superior weather and load forecasts than those that RTO dispatchers rely on and therefore should have been prepared for a potential emergency.

“Here is a settlement negotiated by PJM and a group of generating companies that failed to meet their obligations during a severe weather emergency because, among other things, they decided not to conduct necessary maintenance or procure firm gas deliveries in advance of the emergency and so were unable to generate when non-firm fuel was unavailable,” the companies argued. “The fact that many of the nonperforming companies obtained fuel but failed to operate due to mechanical failures raises questions about maintenance and diligence in winterizing programs.”

They also argue that by resolving the complaints against PJM without a full investigation, the commission might foreclose on an opportunity to learn of any faults in the RTO’s markets or generation fleet that could be improved on before they can disrupt system operations again.

If the commission were to approve the settlement, the Chief companies called for it to make the settlement binding only for those companies that were parties to the agreement.

“PJM proposes that approval of the settlement will relieve it from ‘all claims’ for its actions or inactions before, during and after the Winter Storm Elliott. That ‘release’ in conjunction with other settlement provisions is intended to preclude PJM from having to pay to performing companies the payments that are due under the tariff. While that may be appropriate for those who sign the settlement agreement, it must not apply to those that prefer to exercise their legal rights.”

Support

In its comments supporting the settlement, the Coalition of PJM Capacity Resources — a group of generators that is party to the agreement — argued that it would avoid disrupting the RTO’s markets with “unprecedented” penalties and protracted litigation that was likely to result from the complaints while still providing bonus payments to resources that had earned them.

The group said that many of the complainants sought a larger reduction, or complete rejection, of their CP penalties but agreed that avoiding years of uncertainty around the allocation of penalties and bonuses was preferable.

“If approved, this settlement will allow the parties to the Winter Storm Elliott complaints — PJM, the complainants and intervenors — to avoid the risks and burdens of time-consuming litigation so that PJM and market participants can focus their attention on capacity market reforms, maintaining reliability and encouraging investments in the PJM region,” the coalition said.

It noted that 81 parties had signed on to the agreement with their support, with “many more” indicating that they don’t oppose it, showing a belief among market participants that it is just and reasonable.

“Although the settlement was not agreed upon by all participants to the settlement negotiations, the settling parties include a broad array of market participants, including net nonperformance charge payors, net performance payment recipients, renewable resources, thermal generators, and small and large PJM market participants. This broad support across market participants is indicative that the settlement as a whole is just and reasonable,” the coalition wrote.

Several companies submitted comments stating that they do not contest the settlement in the hope that it can provide market participants with more certainty about their bonus and penalty standings.

In its comments, Avangrid said its preferred outcome would be the implementation of the full penalties and bonus payments outlined in PJM’s tariff, but it sees benefits in market certainty provided by the settlement.

“The primary driver for Avangrid choosing to be a non-contesting party is its recognition that there is value in settling disputes in a streamlined and timely manner,” the company wrote. “Additionally, Avangrid hopes in earnest that this potential value of settling these issues — such that members may focus on forward-looking, and not retroactive, initiatives — comes to fruition.”