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November 2, 2024

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New York PSC Raises Champlain Hudson Debt Ceiling to $6B

The New York Public Service Commission on Thursday authorized developers of the Champlain Hudson Power Express to take on up to $6 billion in debt to build the transmission line from Quebec to New York City.

The PSC had authorized up to $4.5 billion in debt for the project in February, but the developers asked for an increase just four months later, citing nationwide economic conditions that had changed substantially since they initially submitted their request in November 2020.

The commission also authorized the developers to exercise the rights they have negotiated with the municipalities that the line will cross in the overland portion of its 340-mile route.

CHPE is considered important to New York state’s climate goals, as it will bring as much as 1.25 GW of power generated by zero-emission Canadian hydroelectric plants to New York City, which now relies almost entirely on fossil-generated electricity.

The underground HVDC line was proposed in February 2010 and authorized by the PSC in April 2013.

The company behind the project — a partnership between Hydro-Quebec and Transmission Developers Inc. — says the regulatory review since then has taken longer than it expected. On Aug. 31, it announced it was pushing back the anticipated in-service date from fall 2025 to spring 2026 because of the length of the process, as well as supply-chain constraints for key components.

The developers said Thursday that construction will begin later this year.

The PSC vote was not unanimous. Commissioners Diane Burman and John Howard both voted against the financing petition. Commissioners David Valesky and John Maggiore voted in favor of the measure, but their support was not unqualified.

Burman was concerned about giving the developers the ability to change lenders and modify the amount and terms of the financing without prior approval by the PSC.

Howard said he is opposed not to the project but to the way it is being paid for. “There’s nothing inherently objectionable, and I find many things actually very positive about the concept of … construction of the CHPE line. What I have a problem with, again, consistently, is how we pay for it, making all ratepayers pay, and sort of abandoning the broad and long-held concept of beneficiaries pay.”

Valesky said he shared Burman’s and Howard’s concerns. “However, I did come to a different conclusion,” he said. “I did support that item in February, and I will be supporting this item today.”

Maggiore said his concern that the higher debt limit might impact ratepayers was satisfied and his other concerns with CHPE are ancillary to financing, so it was not appropriate for him to raise them at Thursday’s meeting.

The project has long been contentious. Some opponents worry about the potential for environmental damage caused by construction of the line, 60% of which will run beneath Lake Champlain and the Hudson River.

Others say the net environmental benefit of hydropower is overstated and, in the case of Hydro-Quebec’s vast hydropower infrastructure, harmful to indigenous people.

But project developers have also marshaled support from environmentalists and indigenous communities.

In a news release announcing the PSC’s decision Thursday, Chair Rory Christian said: “In addition to ensuring the safety and reliability of the transmission system, the Champlain Hudson project, and others being developed, will play a key role in our comprehensive plan to modernize our state’s transmission system so that it delivers clean energy to all New Yorkers, while advancing our climate goals and creating clean-energy jobs.”

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NYISO Proposes 10-kW Min. Capability Req for DERs in Aggregations

NYISO on Monday shared a proposal to set a 10-kW minimum capability requirement for individual distributed energy resources participating in aggregations, which it said would help support their integration in its markets.

The ISO is developing new software and internal procedures to comply with FERC Order 2222, which did not set any minimum requirements for DER deployment. But NYISO said the work generated more overhead costs to interconnect DERs.

NYISO said that its proposal, presented to the Installed Capacity Working Group, would help staff save time reviewing aggregations for interconnection: reviewing 100 1-kW DERs in an aggregation would take significantly more time than reviewing an aggregation of 10 10-kW DERs, though both would have the exact same capacity.

The ISO said the minimum requirement would enable aggregations to remain flexible and still deliver their services in a reliable and timely manner, but also allow staff to catch up on the compliance work.

It also said it would consider lowering the minimum after market deployment has been underway for some time and it has gained experience managing DER aggregations.

Stakeholders attending the meeting expressed concern about the proposal, saying it could disenfranchise entire residential market classes from being included in aggregations, and that it would not supply the experience NYISO is looking for because most initial aggregation participants will be on a larger scale (20 to 40 kW).

NYISO intends to file the proposal with FERC toward the end of 2022. Comments or questions should be sent to DER_Feedback@nyiso.com.

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University of California System Pursues Hydrogen Blending

California took tentative steps toward mixing hydrogen with natural gas this week with a large grant to the University of California, Los Angeles, to study the process and an announcement by San Diego Gas & Electric that it is seeking to establish a pilot project at the University of California, San Diego (NYSE:SRE), to blend the fuels in an existing gas system.

The California Energy Commission on Wednesday awarded UCLA nearly $5.7 million to “assess the feasibility and safety of targeted hydrogen blending in gas infrastructure to support decarbonization.” The project will study hydrogen’s effects on materials and components of the gas system under different blend levels and develop risk models.

“Blending pipeline gas with hydrogen is still in the early stages of development and use,” UC researchers wrote in their grant application. The UCLA research aims to “reduce the gap in critical knowledge to help [investor-owned gas utilities] introduce hydrogen in the current California gas pipeline network.”

The benefits could include production and storage of green hydrogen at solar arrays and wind farms, using renewable energy that might otherwise be curtailed, and decentralization of the state’s gas system, researchers said.

“The current California gas pipeline system is dependent on a few key pipelines, and a single point of failure can have catastrophic consequences” they said. “The decentralization of energy production will greatly improve the resiliency of the pipeline energy network infrastructure.”

The CEC approved the grant without discussion as part of its consent agenda.

On Monday, SDG&E said it had submitted a proposal to the California Public Utilities Commission for a demonstration project at UC San Diego to study the feasibility of injecting up to 20% hydrogen into plastic natural gas pipes.

“An isolated section of a gas line serving a UC San Diego apartment complex would use hydrogen-blended gas for common building equipment such as boilers and water heaters,” the utility said in a news release. “Hydrogen used in this study would be produced on site via a dedicated, grid-connected electrolyzer. The results of the study would help inform the development of a renewable hydrogen blending standard for California.”

SDG&E CEO Caroline Winn said in the news release that “achieving the state’s climate goals, including reaching carbon neutrality by 2045, will require a broad range of clean energy technologies. That’s why we are investing in the research, development and demonstration of emerging hydrogen innovations that have the potential to be a game changer.”

The utility said the project would fulfill a recommendation of the “Hydrogen Blending Impacts Study” commissioned by the CPUC and performed by researchers at the University of California, Riverside, that called for additional examination of hydrogen blending to ensure its safety, including demonstration projects under controlled, real-world circumstances.

The study found that hydrogen blends of up to 5% in the natural gas stream are relatively safe but that blending more hydrogen in gas pipelines can embrittle steel pipes and raise the risk of leaks. Hydrogen blends of more than 20% carry a higher risk of permeating plastic pipes, increasing the risk of ignition outside the pipeline, it said. (See Study Finds Adding More Hydrogen to Natural Gas Raises Risks.)

“The main concern with pipelines comprising of polyethylene is permeability to hydrogen, which may result in leakage of gaseous hydrogen,” it said. About 65% of distribution pipelines are made of plastics and 35% are steel, it noted.

SDG&E cited a similar demonstration project in England that found that injecting up to 20% hydrogen into a university’s natural gas network had not affected pipes or gas appliances.

UC San Diego would welcome the pilot project, Chancellor Pradeep Khosla said in the news release.

“Sustainability and public service have been a key part of the university since its founding,” Kholsa said. “That’s why we are helping to support California’s decarbonization efforts through this pilot project exploring the economical and safe use of blended hydrogen.”

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NERC RSTC Briefs: Sept. 13-14, 2022

Committee Meets for Second Time in over 2 Years

In its first in-person meeting since the start of the COVID-19 pandemic — and its second ever — NERC’s Reliability and Security Technical Committee (RSTC) gathered at the offices of the Midwest Reliability Organization in St. Paul, Minn., this week to advance action on a number of NERC’s projects.

Before Tuesday, the RSTC’s only face-to-face meeting was its first, held in Atlanta more than two and a half years ago, where the group primarily discussed its plans for taking over the business of the now defunct Operations, Planning and Critical Infrastructure Protection committees. (See RSTC Tackles Organization Issues in First Meeting.) On the first day of this week’s meeting, Chair Greg Ford, of Georgia System Operations, reflected that the committee “has come a long way” since it first came together in 2020.

“I think at that point, and over the next year or so, we were still the OC, PC and CIPC, just in a room together. And today based on the discussion it was clear to me that we have become an RSTC,” Ford said. “We’re really thinking across boundaries; we’re trying to bring a cyber connection to everything we do … [which] is what the board asked us to do. We may not be perfect, but we’re certainly getting there.”

The RSTC’s next meeting, which will be held virtually, is scheduled for Dec. 6-7. For next year’s meetings, two will be fully virtual, while the other two in March and September are planned to be in person. The locations for those meetings have not been determined yet; NERC’s Tina Buzzard said the possible cities include Phoenix, Dallas and San Diego.

SPIDER Documents Approved

Three reports from NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group came before the committee this week, with members approving all three.

First was the NERC Reliability Standards Review, which SPIDER Chair Shayan Rizvi described as a “foundation” for revising the organization’s reliability standards to account for the recent rapid growth of distributed energy resources on the bulk power system, which is expected to continue in the next few years. Work on the project began in 2020 and involved the review of 78 standards over nearly two years.

SPIDER ultimately determined that 54 standards are not likely to need action of any kind to ensure they remain relevant in light of the spread of DERs. The group recommended revising 11 standards across six families: Resource and Demand Balancing; Emergency Preparedness and Operations; Facilities Design, Connections and Maintenance; Modeling, Data and Analysis; Protection and Control; and Transmission Operations (TOP). Eleven standards were recommended for supplemental reliability guidelines — in the same categories except for TOP — and two are being considered for potential future revision, though no action is needed at this time.

The group also submitted a white paper to the committee concerning the impacts of DERs on undervoltage load shedding (UVLS) programs, which found that DERs “are not expected to significantly affect” such systems. Still, it recommended that utilities ensure resources are modeled appropriately in UVLS studies, as well as a technical report on simulating beyond positive sequence conditions using current industry tools.

The group’s representatives concluded by soliciting volunteers from the RSTC to review another white paper on the impact of battery energy storage systems on DER modeling.

LTRA Previewed

NERC staff working on the ERO’s Long-Term Reliability Assessment (LTRA) said they expect a draft version of the document to be ready for the RSTC’s review by Sept. 26, with a release scheduled by Dec. 15. The LTRA is released every year to assess North American resource adequacy in the next decade and to identify trends that could affect grid reliability and security.

Anna Lafoyiannis, chair of the Reliability Assessment Subcommittee, told attendees that the goal of this year’s assessment is “to be a little bit more concise” than in previous years and “focus on what are the most critical emerging risks … for policymakers and decision-making.” She said the report will focus on two main themes: resource adequacy and energy sufficiency, including capacity shortfalls in Ontario, MISO and California; and extreme weather risks involving insufficient flexible generation in Texas and the Northwest, along with issues with the natural gas infrastructure in New England and other areas.

In response to questions from committee members, Lafoyiannis confirmed that the LTRA will “include a list of recommendations” for policymakers and industry. She added that the RAS is hoping for feedback from the RSTC about whether “those recommendations [are] the right recommendations,” and whether they “are doable and the right priority.”

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Judge Approves Brazos Chapter 11 Exit Plan

A U.S. bankruptcy judge on Tuesday conditionally approved Brazos Electric Power Cooperative’s disclosure statement about its deal with ERCOT and its proposed exit plan from Chapter 11 bankruptcy.

The decision of Chief Judge David Jones, of the U.S. Bankruptcy Court for Southern Texas, allows Brazos — which declared bankruptcy in the wake of the February 2021 winter storm after being billed for $2.1 billion in wholesale prices — to begin soliciting votes from creditors and settle its dispute with ERCOT. The grid operator later revised the amount due to the market to $1.89 billion (21-30725).

Under the terms of the settlement, ERCOT will receive $1.4 billion. Brazos will pay $1.15 billion up front and then make annual payments to ERCOT of $13.8 million for 12 years. The cooperative will also contribute about $116 million from the sale of its generation assets to fund payments through ERCOT for market participants still short from market transactions during the week of the storm. (See ERCOT, Brazos Reach Agreement in Bankruptcy Case.)

Brazos agreed to sell its generation assets and transition to a transmission and distribution utility. It owns about 4 GW of natural gas-fired capacity.

Under the agreement, Cliff Karnei, Brazos’ general manager since 1997, and three other members of the cooperative’s senior management will leave their jobs by March 2023. In addition, Karnei and two others will be barred from working for any ERCOT market participant if they’re acting as a financial counterparty to the grid operator.

The votes and any objections are due Oct. 28. Another hearing has been scheduled for November to consider final approval of the settlement and the exit plan.

Brazos filed for bankruptcy in March 2021 after receiving the $2.1 billion invoice from ERCOT. The cooperative responded with a force majeure event letter and by disputing the charges. (See ERCOT’s Brazos Electric Declares Bankruptcy.)

The co-op then opened an adversary proceeding against ERCOT in August 2021, challenging the Texas Public Utility Commission’s emergency orders directing the grid operator to set prices at their $9,000/MWh limit to reflect the scarcity in the market. It sought to reduce the short-pay claim by at least $1.1 billion, the amount it attributed to ERCOT’s administrative adjustment.

The adversary proceeding trial began earlier this year but was suspended after several weeks to allow the parties to mediate the dispute. (See ERCOT, Brazos Agree to Mediation in Dispute.)

Gregory Power to Full-time Ops

Also on Tuesday, NRG Energy (NYSE:NRG) notified ERCOT that it plans to return its Gregory Power Partners gas-fired facility to fulltime operations, effective Oct. 1.

The company submitted a notification of change of generation resource designation for the three units and their 365 MW of capacity. The plant, located outside Corpus Christi, had been on seasonal operations from May through December. It went online in 2002.

The plant was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. NRG returned the facility to seasonal operations in 2019. (See ERCOT Approves Seasonal Plan for NRG Cogen Units.)

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Gordon van Welie Stares down Another Winter in Charge of ISO-NE

BURLINGTON, Vt. — Gordon van Welie is facing another winter full of worry as the head of ISO-NE, tasked with keeping the lights on amid the possibility that extreme weather will threaten a grid that’s straining to catch up to clean energy policy in the region.

In an interview with RTO Insider after a FERC meeting in Vermont that brought all sides of the New England energy sector into a room to talk about the region’s winter issues, van Welie shared his views on the clash between reliability and the clean energy transition. (See FERC Comes to Vermont and Leaves with a New England-sized Headache.)

“The problem is, we should absolutely build all the renewables as fast as we possibly can, hook them up to the system and then let the stuff go that we don’t want. But we’re doing it the other way around,” van Welie said. “We’re shutting stuff down before the new stuff’s built.”

The clean energy transition isn’t being conducted with “completely rational behavior” right now, he said. His call has been for a “deliberate, measured” and incremental move to get away from fossil fuels.

“That’s not the way things are playing out at the moment.”

In his more than 20 years as head of the grid operator, van Welie said he’s developed a keen understanding of the economic theories underpinning the region’s markets; the regulatory paradigms; and the politics that shape his job. It’s a far cry from his background as an engineer working on smart grid technology. And the problems he’s trying to solve now are bigger and thornier than ever.

“Sometimes I feel like we’re trying to thread a rope through a needle in this region. It’s very hard to find the solution that is going to satisfy everyone,” van Welie said.

Last winter, van Welie and his staff launched a public awareness campaign, using media interviews to warn about the thin margins on New England’s grid in the winter in the case of extended cold weather. ISO-NE is planning to do so again this year, despite accusations from some critics that the as-of-yet unfulfilled warnings of rolling outages are “fear-mongering.” (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)

“What would you do in our shoes?” van Welie asked. “You know there’s a risk, and if it goes bad, it’s going to impact 15 million people. Do you hide it and say, ‘We’ll deal with it when it comes?’ Or do you talk about it and say, ‘There’s a problem here that we need society to be aware of?’”

The grid operator is planning a few changes to its strategy this year, including to emphasize that under most circumstances, it still won’t have to dip into the most extreme operating procedures involving load shed. ISO-NE is also doing a tabletop exercise with utilities to run through the scenario of an energy shortfall.

“It’s not just about CYA [covering your ass]. It’s so that people know and can take precautions,” van Welie said. “Part of what we’re saying is that we think we’re short. And so that’s a problem for society. And I’d rather have society know that in advance than for them to find out after the fact, and say, ‘Why didn’t you tell us? We could have done something.’”

No Plans to Step down

The tenuous state of the region’s grid means that van Welie, who joined the organization in 2000 and was named its president and CEO in 2001, isn’t ready to start thinking about retiring.

“The thing I would like to do is to try and leave behind something that’s in decent shape; set it up on a solid foundation,” he said. “I don’t feel like we’re on a solid foundation now.”

Last year, van Welie laid out a four “pillar” plan to support the clean energy transition: substantial amounts of clean energy, balancing resources, energy adequacy and robust transmission.

Using a traffic light indicator to gauge progress, he said transmission is green for now, renewables and balancing resources are yellow, and energy adequacy is red.

“I’d like to get things back to yellows and greens, as opposed to reds,” van Welie said. “It’s going to take time. We might, 10 years from now, be still having the same conversation.”

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Monitor Critiques MISO’s Commitment Usage During Summer

MINNEAPOLIS — MISO presided over reliable operations at higher prices this summer, although its Independent Market Monitor said it is concerned about the RTO’s reliance on out-of-market commitments to maintain reliability.

The difference of opinion arose in Tuesday’s session of the MISO Board of Directors’ Markets Committee during MISO’s quarterly Board Week.

The RTO only called a couple of maximum generation alerts this summer during June’s early heat. That same month, MISO registered the summer’s high systemwide peak at 121 GW on June 21, topping a projected 116-GW monthly peak. The system peaked at 119 GW in July and at 112 GW in August, below expectations of 124 and 122 GW, respectively.

The operations performance came with dramatically higher costs because of soaring natural gas prices, supply chain issues for coal and slightly higher load as the COVID-19 pandemic precautions ease.

The Monitor’s David Patton said all-in summer energy prices doubled year-over-year to about $75/MWh. He said that day-ahead and real-time congestion costs doubled over last summer to more than $750 million, primarily in the footprint’s northern region where abundant wind generation struggles to flow out of the region.

Are Units Being Overcommitted? 

Patton also said MISO operators continued to overcommit generation during the summer. The grid operator said it has had a commitment success rate of about 96% during the season, an indication that it regards most of its commitments as optimal or necessary.

“MISO grades itself as an A+, but at this point we think it’s more a C+. … There’s a disconnect,” Patton said.

Patton estimated that the RTO spent about $80 million in revenue sufficiency guarantee (RSG) payments to resources during the summer. He said only about 10% of the RSG payments are necessary to dilute risk.

MISO uses overly conservative criteria to justify making additional commitments, Patton said. He asked staff to support their commitments with a sharper risk analysis that could avoid excessive commitments. He said the RTO’s operators are “squelching” the markets’ ability to incent nimble generation.

“Ultimately, we want the markets to work,” he said. “We want prices to rise under tight conditions so that fast-start resources are rewarded for the reliability they provide.”

“It is our goal to never make an out-of-market commitment. The reality is we have to make out-of-market commitments,” MISO President Clair Moeller said, adding that exact load amounts materialize in real-time, not day ahead.

Renuka Chatterjee, the grid operator’s vice president of operations, called Patton’s criticism a “healthy tension” between MISO and its Monitor. Patton added that to its credit, the RTO’s leadership is open to discussing the problem further and collaborating on a solution.

MISO, which has begun to track its solar output peaks, said it recorded an all-time high of 2.2 GW on Aug. 31, accounting for 3% of load. Its all-time wind peak remains the 23.6 GW generated on Jan. 18.

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Energy-short Europe Importing More US Shale Gas

Thierry Lepercq (Green Hydrogen Coalition) Content.jpgFounder of Hydeal Ambition Thierry Lepercq | Green Hydrogen Coalition

Europe is in a historic energy crisis, and the impact on the U.S. is not going to be good as exports of its shale gas increase, warned a Paris-based industrialist and entrepreneur Tuesday.

Thierry Lepercq — an energy entrepreneur, author and founder of HyDeal, a pro-hydrogen industrial coalition aiming to replace gas with hydrogen — said U.S. gas prices will “skyrocket” because of European demand.

“I can tell you that $150 billion right now are being invested in LNG terminals across the coast of Texas and Louisiana to ship that very cheap” shale gas, he warned in a webinar produced by the U.S.-based Green Hydrogen Coalition.

“You’ll have that arbitrage thing where in the next few years, massive amounts of natural gas are shipped from the U.S. and to go to Europe and Asia. And the prices in Europe are likely to go down, but the price in the U.S. is going to skyrocket.

“Imagine the whole of the U.S. economy with energy prices going up by 100 to 200% because of the contamination from Europe.

“The same thing is going to happen to the U.S. with maybe [a] one- or two-year delay,” he said. “The message here for the U.S. is to think big immediately. You want to go into tens of millions of dollars to upgrade hydrogen [production] very fast.”

LNG Export Terminals Approved (DOE) Content.jpgDOE and FERC have approved the construction of another 13 export terminals with a combined capacity of 25 bcfd. The first-ever exports of domestically-produced LNG from the lower-48 states occurred in February 2016. | DOE

 

Lepercq, who is also on the board of directors of a newly formed U.S.-based HyDeal coalition, said hydrogen is the only real answer.

He said most of the global oil companies are reluctant to invest the billions of dollars or euros to increase production as they did following the 1970s oil crises because they fear the investments will become stranded assets.

“There needs to be a shock therapy,” he said, referring to the governments of industrialized nations. “We’re talking about hundreds of gigawatts that need to be deployed [to produce green hydrogen] very quickly, if the U.S. wants to avert that … tragic situation, which is going to strike Europe in the next couple of months.”

Florian Knobloch (Green Hydrogen Coalition) Content.jpgGerman economist Florian Knobloch | Green Hydrogen Coalition

In the face of that dire outlook, fellow panelist Florian Knobloch, an economist based in Berlin and adviser to the German federal government, outlined a detailed strategy that Germany has developed to help finance the production of hydrogen globally, with contracts to buy it via pipeline or vessels.

German gas prices have skyrocketed 400% in the last year. Knobloch said the government has developed a plan to assist consumers and industry with soaring energy bills this winter. Those subsidies will cost 4% of GNP, he said.

“We have to be quite realistic [that] hydrogen won’t help us to come through the next two winters,” he said, adding that natural gas imports from the U.S. and elsewhere are crucial.

The government’s plan is to push for the use of hydrogen in the hard-to-abate sectors such as heavy industry, steelmaking and chemicals, and heavy transportation. He said the government does not see the value at this point of heating buildings with hydrogen.

But Germany will remain an energy importer indefinitely, he said.

“We will be relying on hydrogen imports at massive scales, which is why we are planning for actually creating these hydrogen production facilities around the globe already, because hydrogen is a new market and we can’t just wait for hydrogen production facilities to pop up around the globe.”

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Arkansas PSC’s Thomas Makes Way for His Successor

Arkansas Public Service Commission Chair Ted Thomas, a towering presence among MISO and SPP stakeholders, said his decision to step down from the state’s regulatory body and enter the private sector is simply a matter of making room for his successor.

Appointed by Gov. Asa Hutchinson in 2015, and with four years left on his term, he said that with a new governor taking office next year, it is time to move on.

“I didn’t want it to last forever,” Thomas told RTO Insider on Monday. “I had a great working relationship with Hutchinson. I thought it best to let the other person make their own choice.”

Sarah Huckabee Sanders — former White House press secretary under President Donald Trump and the daughter of former Arkansas Gov. Mike Huckabee — is a heavy favorite to win the state’s gubernatorial election in November. Hutchinson is term limited.

Thomas made his decision to resign public last week after submitting a resignation letter to Hutchinson on Sept. 9. The resignation is effective Oct. 1.

Almost always the tallest person in the room, Thomas has been heavily involved in regulatory matters over the last couple of years. In addition to serving on SPP’s Regional State Committee (RSC), several other stakeholder and regulatory groups, and the National Association of Regulatory Utility Commissioners’ Electricity Committee, he was appointed last year to FERC’s Joint Federal-State Task Force on Electric Transmission that was charged with unleashing transmission expansion to improve resilience and connect new renewable generation (AD21-15). (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.)

That work continues. Thomas expressed regret about stepping away from the task force before it completes its task.

“I’m sure there’s more to do, but we’ve talked about a lot of the issues on the front end,” he said.

“This is sad for all of us who follow utility regulation,” tweeted Matt Christiansen, general counsel at FERC. “I am not sure there’s anyone whose perspective I have been more eager to hear over the last several years than Chair Thomas’.”

“Big shoes!” added energy consultant Karl Rabago, a former Texas commissioner.

Thomas said he has enjoyed working with the grid operators and their staffs, saying it was a big part of his tenure. He named-checked staff from SPP’s Cost Allocation Working Group and the Organization of MISO States (OMS) and said he was “very lucky to get to know some of those people.”

“You’re creating value for the ratepayers” when working with RTOs,” Thomas said. “There are a lot of benefits, but it’s not easy to earn them. You have to work through the stakeholder process.”

If there’s a regret for Thomas, it might be not seeing through the SPP Improved Resource Availability Task Force that he chairs. The group is responsible for addressing recommendations following the RTO’s review of its response to the February 2021 winter storm.

“That’s very important work,” he said, noting the task force is still in the middle of its assignment.

Thomas hinted he may still be visible in future grid operator circles, but right now, he has work to do.

“I’ll run through the tape,” he said.

Arkansas PSC Commissioner Justin Tate will take Thomas’ place on the RSC, beginning with October’s meeting. Fellow Commissioner Kimberly O’Guinn will remain on the OMS, Thomas said.

The resignation came two days after Thomas colorfully recused himself from a solar energy case involving Petit Jean Electric Cooperative and other utilities over alleged unauthorized net-metering practices. He accused Petit Jean of making false criminal accusations against him and said it was “soullessly” wielding “the billy club of the monopolist” and called the utility a “litigation machine paid for by the same ‘members’ that they club.”

The utilities requested Thomas’ recusal after he made comments during a legislative committee hearing earlier this year. They said his comments on interconnection requirements reflected a “predisposition or prejudgment of key issues.”

Thomas told an Arkansas newspaper that his resignation had “nothing to do” with the case, but that “no one will believe that.”

In his recusal Thomas wrote that the utility had four times defied PSC orders to file a tariff that included statutory language to interconnect residential solar customers to the grid.

“Then, like a Saul Goodman stunt, Petit Jean’s counsel falsely accused me of criminal conduct and sought my recusal. Better call Saul!” he said, referring to the lawyer character from the TV shows “Breaking Bad” and “Better Call Saul,” in making his point.

“Solar panels have been sitting in the sun not interconnected for months and months, and a formal PSC process would be litigated and appealed for additional months, if not years,” Thomas said. “This result seems to be the monopolist’s intended purpose. I do not wish to be used as a weapon by the monopolist in the endless expensive efforts to keep people … from interconnection to the grid.

“I’m all good, man. I recuse.”

“I’m very contentious. It’s in my DNA,” Thomas said Monday. “If someone wants to throw down, let’s throw down. Perhaps I could be a better person, but if we have to rumble, let’s rumble.”

Thomas has previously served as chief deputy prosecuting attorney for Arkansas’ 20th Judicial District, an administrative law judge for the PSC, Gov. Huckabee’s budget director and a member of the Arkansas House of Representatives, where he was chairman of the State Agencies and Governmental Affairs Committee during his final term.

The Arkansas Advanced Energy Association last year honored Thomas with its Ron Bell Advanced Energy Leadership Award for outstanding contributions to the renewable power, efficiency and energy contracting industry.

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Utilities File Incident Reports in Latest California Wildfires

Pacific Gas and Electric (NYSE:PCG) and Southern California Edison (NYSE:EIX) each filed incident reports with the California Public Utilities Commission last week indicating their equipment may have been involved in the two largest fires burning statewide.

PG&E said the U.S. Forest Service placed caution tape around the base of a 60-kV transmission pole close to the ignition point of the Mosquito Fire, a 47,000-acre blaze burning mostly out of control in the Sierra Nevada foothills, 50 miles northeast of Sacramento. The fire began near the Oxbow Reservoir in Placer County, where PG&E said it recorded “electrical activity” when the fire started on Sept. 6.

“Thus far, PG&E has observed no damage or abnormal conditions to the pole or our facilities near Oxbow Reservoir [and] has not observed down conductor in the area or any vegetation related issues,” the utility said in a report Thursday to the CPUC. “Our information reflects electrical activity occurred close in time to the report time of the fire. The investigation is ongoing. This information is preliminary.”

The California Department of Forestry and Fire Protection (Cal Fire) has not reported any injuries or structural damage from the Mosquito Fire, but the blaze has caused hazardous air pollution in the nearby city of Auburn and threatened rural communities in its path.

More than 400 miles to the south, the Fairview Fire has killed two people and burned more than 28,000 acres, Cal Fire and the Riverside County Fire Department said. The blaze is 53% contained, Cal Fire reported Monday.

SCE filed a report with the CPUC on Sept. 5 saying, “Our information reflects circuit activity occurred close in time to the report time of the fire” at 3:37 p.m. that day near the city of Hemet. “The investigation is ongoing.”

September traditionally marks the start of fire season in California, as autumnal offshore breezes fan vegetation parched by dry summers. The fire season typically continues until rains begin in the late fall in the state’s Mediterranean climate.

SCE and PG&E equipment has been blamed for starting major wildfires in recent fire seasons.

The catastrophic blazes include the Camp Fire, the state’s deadliest wildfire, which was ignited by a broken PG&E transmission line in November 2018, and last year’s Dixie Fire, a nearly 1 million-acre wildland blaze started by a PG&E distribution line.

Government investigators determined that SCE power lines blown together by high winds sparked the 282,000-acre Thomas Fire in Santa Barbara and Ventura counties in December 2017. The largest fire in state history at the time, it killed a firefighter and a civilian. Mud and debris slides in its aftermath killed 21 others when heavy rains drenched fire-scarred mountain slopes, washing away homes and vehicles.