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November 5, 2024

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California PUC Partners with State Workforce Agency to Advance Green Jobs

The California Public Utilities Commission has stepped up its coordination with the state’s Workforce Development Board (CWDB) to ensure that new clean energy jobs build pathways into the middle class for the disadvantaged communities that bear a disproportionate share of climate change impacts. 

The two agencies discussed their partnership in an Oct. 17 Environmental and Social Justice High Road Workforce En Banc workshop, which included panels covering tribal workforce development, utility efforts to promote jobs in energy and more.  

The CPUC and CWDB have been working independently and together for the past several years to advance what they call “high road careers” that address climate change. In 2019, the CPUC adopted its Environmental and Social Justice Action Plan, while the CWDB in 2020 released Putting California on the High Road, a plan for integrating economic and workforce development in climate policy to meet California’s greenhouse gas emissions targets by 2030 and achieve a carbon neutral economy by 2045. Both plans emphasize labor as an investment — not a cost — that can positively affect returns on social equity and climate action.  

In 2020, CPUC and CWDB signed a Memorandum of Understanding following Democratic Gov. Gavin Newsom’s Executive Order N-79-20 to accelerate climate change mitigation and build a more sustainable and inclusive economy. The MOU aims to build a framework to ensure investments in clean energy result in high-quality jobs and greater access to career opportunities for disadvantaged Californians.  

The MOU “really focuses on the role of agencies like the CPUC as an influencer on the kinds of jobs that are created as we implement our green and climate policies and our funding programs,” Carol Zabin, senior advisor for the UC Berkeley Labor Center’s Green Economy Program, said at the workshop. “That, to me, is by far the key element that we need to focus on.”  

Zabin said about three-quarters of the jobs involved in energy efficiency and renewable energy generation work are blue-collar, which, without unions or strong labor standard requirements, tend to be “low road,” low-wage positions with poor benefits and a lack of upward mobility. One of the goals laid out in the CWDB’s 2020 report is a just transition for blue-collar workers into the climate and energy workforce.  

The MOU in Action

CPUC Executive Director Rachel Peterson described one step the agency took to advance the goals in the MOU: the 2019 rollout of the Solar on Multifamily Affordable Housing (SOMAH) Project. The program provides financial incentives for installing solar panel systems in disadvantaged communities, identified as the 25% most pollution-burdened census tracts in the state, according to CalEPA’s environmental health screening tool CalEnviroScreen. More than 35,000 tenants have benefited from the program. 

But SOMAH also provides job training opportunities, with 850 individuals participating in paid job training on solar panel installation.

The commission also emphasized its work with Pacific Gas and Electric to train line clearance tree trimmers, who prevent vegetation from obstructing electrical lines. As part of a $1.97 billion settlement for PG&E’s role in the 2017 and 2018 fires in Northern California, the CPUC ordered the utility to start a multiweek training program for pre-inspector training and certificates. PG&E also was required to create a tree crew training and certificate program in partnership with the International Brotherhood of Electrical Workers.  

Representatives from the California-Nevada Joint Apprenticeship Training Committee (JATC) Line Clearance Tree Trimmer Certification program emphasized the importance of vegetation management in wildfire prevention. Despite the tangential connection between climate-caused wildfires and those sparked by electrical lines, Dan Kallai, training coordinator with JATC, said the position was crucial to climate mitigation.  

“Line clearance tree trimmers are directly mitigating the effects of climate change and reducing the number of wildfires and associated carbon emissions,” he said. “Furthermore, they keep the power grid running safely and efficiently by preventing power outages and the costly loss of our electrical resource to ground faults.”  

The program also is succeeding in creating high road careers. In 2019, SB 247 brought vegetation management under the scope of wildfire mitigation in California, and in January 2020 the law raised tree trimmer wages to match those of electrical utility linemen apprentices, giving them “skilled labor” status. Since January 2022, more than 2,300 people have enrolled in the program.  

Collaboration with Tribal Communities

California officials also are working to create access to high road careers in green energy in the state’s tribal communities. 

“There’s so much opportunity to partner with tribes, elevate tribal perspectives and learn from tribal experiences, but we can’t do this without first acknowledging the historical elephant in the room that the state has a lot to make up for in terms of tribal wellness and government integrity,” said Christina Snider-Ashtari, tribal affairs secretary to Newsom. “How do we start to disentangle that and provide more equitable access, more equitable job creation and workforce in those areas from a Native perspective, not from the perspective of a government that is responsible for those problems?” 

Grid Alternatives, a nonprofit solar organization with a mission to advance environmental justice through access to renewable energy, is looking to address that question.  

The organization partners with tribes to finance and implement solar projects that include education, training and energy cost reductions. Since 2010, Grid Alternatives has helped 50 tribes install 7.7 MW of power across eight states. Its grant program, the Tribal Solar Accelerator Fund, has awarded $7.3 million for a variety of solar-related projects, including helping tribes own their systems, as well as providing funding for scholarships, internships and workforce development opportunities in the solar industry.  

Next Steps

While some programs already have succeeded in advancing workforce development in climate-related careers, there is more to be done to ensure the goals outlined in the MOU are achieved. The CPUC and CWDB recognize the challenge of measuring future outcomes.  

“How do we know that people have actually moved into a high road career pathway?” Peterson said. “I’d like to see three years from now, four years from now, that people have been able to take advantage of these pathways.”  

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Brad Jones, Former ERCOT, NYISO CEO, Dies at 60

Friends, co-workers and others who had known former ERCOT and NYISO CEO Brad Jones recalled his memory Nov. 9, after his sudden death the day before.

Jones, 60, passed away in Houston’s MD Anderson Cancer Center of a rare intestinal cancer with a high mortality rate. The cancer was thought to have been in remission last year when he retired from ERCOT but returned late this summer.

“He’s one of the most charismatic, selfless leaders I’ve ever had the chance to work with,” said ERCOT’s Kristi Hobbs, vice president of system planning and weatherization. “He didn’t know a stranger. Everyone was his friend. He was truly about serving others, providing them development opportunities. He always had the best interest of the market and the industry in everything he did.”

Jones had two stints at ERCOT after a distinguished career at TXU (now Vistra). He served as the ISO’s vice president of commercial operations and COO from 2013-2015. Jones left ERCOT for NYISO before retiring in 2018, only to return to ERCOT as its interim CEO following the deadly 2021 winter storm.

He is widely credited with restoring confidence in the grid operator and laying out initial steps to prevent a repeat of the disaster, which almost brought the ERCOT grid to its knees. Part of that work included a listening tour around the state to share the message with Texans.

“It was really the organization’s darkest hour,” Hobbs said, noting her reluctance to use that expression. “He was our angel that was sent to us to help us navigate through that and rebuild the faith and all the good work of that organization. We can’t think of anybody else that would have been better suited for that role to help us during that time.

Brad Jones, with Pat Wood, had many friends within the Texas electric industry. | Gulf Coast Power Association

“And for that we’ll be forever grateful,” Hobbs added. “Brad was one of my best friends and mentors.”

ERCOT recognized Jones with a memoriam section on its website, linked from the home page.

“No words can express our sadness for this loss, and our gratitude for the opportunity to have known and worked with him,” the ISO said. “Brad was a friend, a colleague, a leader and a genuinely caring person. He touched the lives and careers of many ERCOT employees and industry colleagues. He will be dearly missed.”

Mike Greene, a 46-year veteran of the ERCOT market as a TXU executive and the ISO’s board chair, knew Jones for more than 30 years. He was one of the close associates who got a call from Jones during the Dallas Cowboys’ Oct. 29 game, alerting him that Jones had little time left.

“He’s always been a very confident guy and always did a great job in whatever job he was in,” Greene said. “We all think of Brad just in the job that he did following Winter Storm Uri. He did such a great job of pulling things together and giving the industry confidence. It was just an incredible job that he did. I told him I considered him a real Texas hero for that. It was tough. It took a lot of guts, a lot of confidence and a lot of ability to get it done.”

Jones was honored by politicians, regulators and industry leaders before retiring again in October 2022. During the Gulf Coast Power Association’s spring conference in April, he was presented with the Pat Wood Power Star Award by its namesake, former PUC and FERC chair Pat Wood III.

“Brad was fearless, decisive and passionate,” Wood said. “First, he saved Texas, and then he saved ERCOT.”

“Ever since Pat Wood got this award, I wanted it,” Jones said of the honor established in 2006 to honor individuals for advancing a fair and sustainable power market. “I hoped I could do something sometime that I could earn it. I realized you can’t do it alone.”

Jones was a devoted family man and a man of faith, Greene said. He was a father of six with his wife, Lynette, but still managed to keep a work-life balance that focused on family first.

Family First

Chris Schein, a friend and co-worker of Jones for 20 years, tells the story of a recent call he received from a man who had met Jones twice, for about two hours each time. The two men, both with large families, talked about how to succeed at work while also helping manage large families.

“Always make your family your first priority. Everything else will work out,” Jones advised.

“Yes, but my work is so demanding,” the man responded.

“Yeah, but it will work out. You’ll never regret the extra time you spend with your family.”

“This guy implemented Brad’s plan in early spring and said, ‘My family and I have never been happier,’” Schein recounted. “‘I only spent a few hours with Brad, but he literally changed my life. I’ll be remembering his advice throughout my career.’”

Veteran ERCOT stakeholder Mark Dreyfus, principal at MD Energy Consulting, last year recalled visiting the West Texas native in Albany, N.Y., after he had “packed up his cowboy boots.”

“I know he was lonely for home and family,” Dreyfus said during yet another celebration for Jones. “He treated me like family and treated me to an insider’s tour of the city: well-cooked sirloin, beer pong, and a reggae show.” (See “GCPA Members Honor Jones,” Overheard at GCPA’s 37th Fall Conference.)

Brad kept his cancer to himself and only those closest to him when he was first diagnosed last year. During his last board meeting in October, while his cancer was in remission, he told one former co-worker that his target for beating the disease was Nov. 26, his birthday.

Greene recalled a lunch in Fort Worth he and several other ex-TXU employees hosted for Jones during the summer. He said Jones was feeling great and was enjoying time with his family.

“September rolls around, his cancer has returned and it’s bad. We had a 10-minute conversation the first part of October. It was very emotional,” Greene said. “During the Cowboys’ game, it was a very different conversation. He started talking in a very calm voice. It was like he was describing a project to me. He said, ‘I’m feeling good, I’ve had time to be with my family, and I’m very grateful for this time.’

“It was the darndest thing. He was totally at peace. It was amazing. The last thing I told him, ‘You’re a braver man than I am.’”

Schein said Jones was a huge fan of Teddy Roosevelt. When he got his last call from Jones, Schein said Jones remarked that his Twitter feed was full of posts on Roosevelt during the weekend because it was the latter’s birthday.

“Brad said, ‘Teddy was also 60 years old when he died. I’m going to be 60 when I die. That’s one more thing that Teddy and I shared,’” Schein said.

“I told him, ‘I really wish you had admired George Burns. He was 99 when he died.’”

Schein and Greene have worked together to establish The Brad Jones Engineering Scholarship at Texas Tech, his alma mater. The scholarship fund is intended to honor Brad’s legacy and to reward junior-level engineering students and support them in continuing “the important work in the electric industry and for Texas, now and in the future.”

“I think that’s the best way that we can honor his legacy,” Hobbs said. “He was a selfless leader. He always wanted to give back and develop others. This is the best way to honor his legacy and keep it alive.”

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FERC Conference Highlights Challenges of Evolving Grid

Combating the “unprecedented” cybersecurity threats facing the North American power grid “requires constant monitoring and vigilance,” FERC Chair Willie Phillips reminded attendees at the commission’s annual Reliability Technical Conference Nov. 9. 

“The average cost of a data breach in 2023 was $4.45 million, and the global cost of cybercrime was estimated at $8 trillion in 2022, $11 trillion in 2023 and is predicted to be more than $20 trillion in 2026,” Phillips said. “Quite simply, this is a national security issue. And these quickly evolving threats present a challenge when assessing whether security controls adequately respond to the latest cyber threats.” 

The rapidly changing cyber and physical threat landscape comprised one of the three key issues addressed at the conference, along with the reliability risks posed by extreme weather and the power grid’s changing resource mix. Participants in one morning panel, including Electricity Information Sharing and Analysis Center CEO Manny Cancel, emphasized the “unprecedented” level of danger posed to the grid by both foreign states and organized criminals. 

Manny Cancel, NERC | FERC

Cancel said the willingness of nation-state actors to target the North American grid “isn’t subject to debate,” referring to the U.S. intelligence community’s 2023 Annual Threat Assessment, which identified China, Russia, Iran and North Korea as conducting active cyber campaigns against the U.S. and its allies. China, Cancel said, is believed to have sponsored attacks against multiple U.S. critical infrastructure organizations and Asian electric utilities, while the E-ISAC has detected “Russian-linked scanning in [its] information technology and operational technology systems … searching for security gaps.” 

While the sponsorship of hostile governments has enabled greater creativity from malicious actors, they also have benefited from a growing attack surface created by the addition to the grid of new, internet-connected generation types such as wind and solar facilities, along with distributed energy resources such as rooftop solar panels. These facilities have helped enable a faster transition to a lower-emission grid but constitute a potential vulnerability for adversaries to exploit.  

“When you think about it from a pure numbers perspective, you’ll have a larger coal plant retiring that may be 300 [to] 800 MW, and obviously what’s coming online … is more. [Wind and solar facilities] tend to be smaller plants,” said SERC Reliability CEO Jason Blake. “In addition to that they’re [also] more digitized. They need additional tools to perform their functions.” 

Despite these risks, Blake said he remains “comfortable and confident” in the ability of grid operators to adapt to the evolving threats because NERC’s Critical Infrastructure Protection (CIP) standards “provide a very strong base” for grid cybersecurity. However, Blake and his fellow panelists also acknowledged there still is work to be done, particularly in updating the CIP standards to allow the use of cutting-edge technology in grid operations. Maggy Powell, a principal security industry specialist for Amazon Web Services, said CIP standards “are very device-centric” and “were written without contemplating virtualization [and] before cloud [computing] was really a thing.” 

Jonathan Tubb, director of industrial cybersecurity for Siemens Energy of North America, added that in his experience utilities are looking for “lighter weight and scalable solutions” to address the cyber needs of large-scale distributed generation. But even if these solutions are available, he said, operators may feel unable to make use of them because of compliance concerns. He urged NERC and FERC to push for changes to the CIP standards that will allow the use of flexible distributed cyber defense software. 

Robb Highlights IBR, Gas Issues

In the morning’s other panel, which focused on the grid’s changing resource mix, NERC CEO Jim Robb acknowledged the “paradoxical” fact that “although the [grid] is performing exceptionally well,” with misoperation rates and human errors down and transmission availability rising, “all of our reliability assessments show an expansion of risk, both geographically and [in] severity.” He attributed the growing risk “largely … to grid transformation,” particularly the spread of inverter-based resources like wind and solar plants. 

NERC CEO Jim Robb | FERC

While Robb said these new generation sources are “incredibly exciting technologies,” he warned that they come “with real issues.” In addition to their potential cyber vulnerability, the behavior of IBRs is not as well understood as that of older generation types, which has prevented their full integration into system models and simulations.  

Robb also acknowledged the recent release of FERC and NERC’s report on Winter Storm Elliott, which he called “very sobering.” (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) He reflected that while the “heroic” actions of gas and electric utilities kept the natural gas system from collapsing under the strain of the storm, if temperatures in the Northeast had not warmed up when they did, the grid could have “been in a real world of hurt.”  

The difficulties of gas and electric coordination during Elliott pointed out another area where work is needed, Robb said. He reiterated his support for the formation of a gas reliability organization that could create mandatory standards similar to the ERO and called for NERC and other industry stakeholders to continue working with the gas industry to improve their collaboration efforts.  

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PJM Monitor Petitions FERC to Change Capacity Performance Penalty Calculation

PJM’s Independent Market Monitor on Nov. 7 filed a complaint with FERC against the RTO arguing that its Capacity Performance (CP) construct for incentivizing generation performance during emergencies through penalties and bonuses is overly punitive and undermines reliability (EL24-12).

The Monitor told the commission the penalty rate calculation, based on the cost of new entry (CONE), should be revised to be based on the Base Residual Auction (BRA) clearing price instead. The penalty rate would be set to the clearing price per megawatt-year divided by the number of intervals in 30 hours for each interval a resource is unavailable, with an annual stop loss set at 1.5 times the resource’s annual capacity revenues.

While the capacity market overhaul PJM filed with FERC on Oct. 13 would set the stop loss at 1.5 times capacity revenues, the Monitor noted that it would base the penalty rate on CONE and argued that it would continue to expose market sellers to “excessive nonperformance penalties.” The Monitor also said the proposal ties too many changes to the Reliability Pricing Model (RPM) too quickly for the markets to properly adjust to, increasing uncertainty and the risk that unintended consequences may be introduced. (See PJM Files Capacity Market Revamp with FERC.)

“Because PJM has repeatedly failed to propose rules that would correct its flawed market design, this complaint is necessary to remove the flawed rules for penalty rates in the existing rules, adopt just and reasonable replacement rules, and maintain the existing schedule for RPM auctions,” the Monitor said.

The IMM argued that lowering CP penalties has broad stakeholder support, noting that the Members Committee endorsed an identical change to the penalty structure. PJM’s Board of Managers, however, opted to file changes only to the triggers that initiate a performance assessment interval (PAI), during which generators are subject to penalties for underperforming. While no proposals received sector-weighted support during the Stage 4 meeting of the Critical Issue Fast Path (CIFP) process Aug. 23, the Monitor said its proposal to base CP penalties on capacity revenues was the only one to receive more than 50% support. (See PJM Stakeholders Vote Against All CIFP Proposals.)

During the discussions at the Markets and Reliability Committee in May, stakeholders calculated the changes would result in a penalty rate of $394/MWh and a stop loss of $17,744/MW-year, compared to a status quo penalty of $3,177/MWh and stop loss of $142,952/MW-year, based on 2023/24 clearing prices.

Revising the penalty calculation would reduce market risk and the potential for PJM to be involved in lengthy litigation in the event major penalties are incurred in the future, while also creating market certainty for the next two delivery years in a way that is straightforward for market participants to understand, the Monitor argued. It requested its proposal go in effect for the 2025/26 delivery year, as well as the following one.

The Monitor said the high penalties have undermined the goal of the CP construct of incentivizing performance during emergencies and instead created artificial risk that resulted in increased costs for consumers without a corresponding reliability benefit.

“Abstract discussions of incentives and penalties led some to the conclusion that if high prices provide incentives at times, then even higher prices or extreme penalties are even better incentives. One of the lessons of the winter storms Uri [of February 2021] and Elliott [of December 2022], in very different market designs, is that extreme prices and penalties do not have the intended incentive effect and do have a destructive effect, in the energy market and in the capacity market,” the Monitor said.

The RTO itself has identified flaws in the penalty rate, the Monitor argued, pointing to its response to the 15 complaints that generation owners filed in the wake of $1.8 billion in penalties being assessed against market sellers because of their underperformance during Elliott. (See Settlement over PJM Elliott Penalties Receives Broad Support.)

“PJM nominally defended its actions related to determining the existence of PAI, associated penalties and acceptable excuses,” the Monitor said. “Yet PJM implicitly agreed that the combination of high penalties and unclear rules made the results of nonperformance assessments during Winter Storm Elliott unworkable when, after multiple detailed and extensive complaints were filed at the commission raising specific questions about PJM’s implementation of the PAI rules, PJM proposed to immediately begin settlement judge proceedings and, after actively participating in those proceedings, entered into and filed a settlement agreement.”

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NERC: Grid Risks Widespread in Winter Months

The winter storms of recent years are weighing on NERC leaders’ minds heading into the 2023-2024 winter season, with the ERO’s 2023 Winter Reliability Assessment warning that much of the North American continent faces elevated or high risk of energy shortfalls during extreme weather conditions. 

The assessment, released Wednesday, covers the months of December through February and was developed by subject matter experts within the ERO’s technical committees and industry groups, NERC Director of Reliability Assessment and Performance Analysis John Moura said in a media call. Moura said the report spotlights worrying trends around reliability. 

“For decades, the system has mostly been built and planned around summer peaks, the concept there being that we have higher demand during the summer period, and therefore we need to make sure we’ve got a lot of capacity to serve that demand,” Moura said. “However, what we’ve seen in … probably the last 10 years is an increased vulnerability to wintertime. That’s not because of the peak demands … but mostly because of generator outages” from cold weather. 

Natural gas-fired generation capacity contributions to the 2023-2024 winter generation mix | NERC

Moura acknowledged that the assessment was released “on the heels of” Tuesday’s publication of the final report from FERC and NERC’s joint inquiry into the winter storm that caused more than 90 GW in coincident unplanned outages over Christmas 2022, also known as Winter Storm Elliott. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) He noted that the Elliott report “reiterated some of the very same findings we’ve seen year after year during these winter impacts,” including inadequate winterization of generation plants and disruptions to fuel supply, particularly for natural gas facilities. 

Those issues appear again in the assessment, which highlights the fact that declining natural gas production during Elliott contributed “to wide-area electricity and natural gas shortages.” Mark Olson, NERC’s manager of reliability assessments, said that while “nearly all areas have adequate resources for normal peak demand,” extreme, long-duration cold weather events could lead to similar disruptions this winter, despite industry efforts to prepare for the worst. 

Multiple Regions Face Elevated Risk

NERC noted that SPP, MISO, ERCOT, PJM and parts of the SERC Reliability and Northeast Power Coordinating Council regional entities are all at elevated risk, indicating the potential for insufficient operating reserves in above-normal peak conditions. Only Canada’s Saskatchewan province was assessed as high risk, meaning energy shortfalls could occur during normal peak conditions. All other regions expect to have sufficient operating reserves for normal peak conditions. 

The report attributed the high risk in Saskatchewan — where reserve margins have fallen 8% compared to last winter — to increased peak demand projections and the retirement of a 95-MW natural gas unit, as well as planned maintenance that will leave generators out of service. NERC said that during extreme winter conditions and large generation forced outages, SaskPower — the principal electric utility in the province — might need to turn to demand response programs, power transfers from neighbors, maintenance rescheduling or short-term load interruptions. 

For MISO, the report noted that available resources have increased more than 9 GW from last winter, thanks to the addition of new wind and gas-fired generation and the extension of some older fossil fuel plants. However, NERC added that an extreme cold weather event that affects MISO’s southern areas could lead to outages at inadequately winterized generators or issues with natural gas supply. 

Three subregions of NPCC face elevated risk, according to the report: Québec; the Maritimes provinces and Northern Maine; and New England. All three subregions could see energy shortfalls during periods of peak demand; in the case of New England, the challenge is exacerbated by the need to use natural gas for both electricity generation and consumer space heating, potentially stressing the area’s limited gas delivery infrastructure. 

In PJM and SERC’s East and Central areas — which cover the Carolinas, Tennessee and portions of Georgia, Alabama, Mississippi, Missouri and Kentucky — generating resources “have changed little [since] 2022,” while forecasted peak demand has risen over the last year in the areas hit hardest by Elliott. While NERC said PJM and SERC “have adequate resources for normal winter conditions,” extreme conditions could lead to generator derates and outages. 

SPP’s anticipated reserve margin of 38.8% stands more than 30 percentage points lower than last year’s forecast, NERC said. The drop is mainly from rising demand and reduced resource capacity. Notably, the report pointed out that SPP’s “vast wind resources” could be a help or a hindrance depending on the level of wind activity. 

Winter 2023-2024 anticipated and prospective reserve margins compared to reference margin levels | NERC

Finally, in Texas, as in other regions, “robust load growth” has not been matched by corresponding growth in dispatchable resources. As a result, NERC said the risk of reserve shortages has risen since last winter, though ERCOT “is taking steps to procure additional capacity” heading into the winter months and has implemented a new firm fuel supply service to help offset lost generation capacity from limited natural gas supplies. 

NERC’s recommendations for utilities in the elevated-risk areas include reviewing seasonal operating plans and ensuring operators are trained and familiar with manual load-shedding procedures in advance of severe weather. The ERO also advised balancing authorities that short-term load forecasts may “underestimate load in extreme cold weather events” and that they should be prepared to manage potential reserve deficiencies. 

In addition, NERC recommended that reliability coordinators and balancing authorities conduct fuel surveys and prepare their operating plans for supply shortfalls. State and provincial regulators can help by “supporting requested environmental and transportation waivers as well as public appeals for electricity and natural gas conservation,” it said. 

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GSA to Invest $2B in Low-carbon Building Materials

The General Services Administration (GSA) announced Nov. 6 that it will be spending just over $2 billion in funds from the Inflation Reduction Act (IRA) on low-carbon construction materials — concrete, glass, steel and asphalt — for repairs and upgrades on more than 150 federal buildings in 39 states, D.C. and Puerto Rico.

GSA Administrator Robin Carnahan rolled out the “Buy Clean” initiative in Topeka, Kan., where the Frank Carlson Federal Building and Courthouse will be getting a $25 million facelift with new windows and doors with blast-resistant aluminum frames and insulated low-embodied carbon (LEC) glass that will reduce the building’s energy use. Sidewalks and parking areas at the building will also be updated with LEC concrete.

Project design is to begin in fiscal 2024, with construction to follow in 2025, according to GSA.

Embodied carbon emissions are those generated by a material’s production, transportation, installation, use and disposal. LEC materials “have substantially lower levels of embodied greenhouse gas emissions,” according to a GSA fact sheet. The LEC concrete, glass, steel and asphalt used for the projects announced Nov. 6 could cut the federal buildings’ greenhouse gas emissions by 41,000 metric tons and create 6,000 jobs per year for the life of the projects, a GSA press release said.

“By incorporating clean construction materials in more than 150 projects across the country, we’re helping create … the clean manufacturing industries of the future and sending a clear signal that the homegrown market for these sustainable products is here to stay,” Carnahan said in the press release.

Federal demand for LEC construction materials is potentially huge. GSA manages more than 9,600 federal buildings, covering a total of 375 million square feet, in 2,000 communities across the country, according to the administration’s website. The government’s building stock ranges from courthouses, Internal Revenue Service offices, border stations and warehouses, to data centers and laboratories.

According to GSA, the IRA provided the administration with $3.375 billion to invest in federal buildings to cut emissions and spur innovation by buying and installing LEC materials. The administration has focused on concrete, glass, steel and asphalt because they are all carbon-intensive materials that together generate close to half of all GHG emissions from U.S. manufacturing.

They also account for 98% of the construction materials the government either pays for or funds for federal infrastructure projects, GSA said.

The price tag for the current round of projects includes $384 million for asphalt, $767 million for concrete, $464 million for glass and $388 million for steel.

Senate Majority Leader Chuck Schumer (D-N.Y.) praised GSA for getting the IRA dollars “out the door.”

“This funding helps create a market for low- and zero-carbon materials, further incentivizing industrial manufacturers to take advantage of other IRA programs aimed at helping them reduce their emissions,” Schumer said. “This ecosystem of incentives approach is part of what makes the IRA so impactful and resilient.”

What is ‘Substantially Lower’?

The Buy Clean initiative was launched to support President Joe Biden’s Federal Sustainability Plan, rolled out in December 2021. The plan set a 2045 target for federal buildings to cut GHG emissions to net zero, with an interim goal of 50% by 2032 and a 2050 deadline for net-zero federal procurements.

GSA collaborated with the Department of Transportation and EPA to develop a set of “interim determinations” for designating materials like asphalt, glass, concrete and steel as low carbon. The guidelines are being tested out on 11 projects during a pilot period that began in May.

A core issue was defining the “substantially lower” emissions required for LEC materials to qualify for IRA funding. EPA defined the term “as meaning a global-warming potential that is in the best-performing 20% … when compared to similar materials/products,” according to a December 2022 letter to GSA from EPA Deputy Administrator Janet McCabe.

If materials cannot be found that meet that “Top 20%” limit, EPA then set a second level of best-performing 40%, and a third level of “better than the estimated industry average,” both of which could still qualify for IRA funding.

EPA also is “working with the construction materials manufacturing industry and [nongovernmental organizations] to help track the climate impacts of their operations and to develop a labeling program that will clearly identify lower carbon construction materials in the marketplace,” McCabe said in the GSA press release.

According to the GSA fact sheet, the administration is continuing work on the 11 pilot projects and reports that “progress is being made to source LEC materials on these projects.”

More awards could be coming in the first half of 2024, the fact sheet says, but GSA decided to announce the current round of projects “to inform the market of the breadth of our plan, and to help position U.S. manufacturers, suppliers and installers to capitalize on this exciting opportunity.”

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Pioneering NuScale Small Modular Reactor Project Canceled

NuScale Power Corp. and Utah Associated Municipal Power Systems said Nov. 8 they had agreed to terminate the Carbon Free Power Project.

They said it appeared unlikely the project would have enough subscription to continue toward deployment. They now will work with the Department of Energy to wind down the project, which would have been built at DOE’s Idaho National Laboratory.

NuScale announced the news with its third-quarter earnings after the stock market closed Nov, 8. NuScale stock, which had been trading near a 52-week low, plummeted in after-hours trading.

The CFPP was to be the first NuScale small modular reactor to begin operation in the United States, with the first of six 77 MW modules to start generating power in 2029.

In its third quarter 8-K filing with the SEC, the company said it would transfer materials intended for the CFPP project to use with another customer.

NuScale had indicated in a March earnings call that the project was 25% subscribed to but needed to reach 80%.

During the conference call Nov. 8, company leaders said the goal proved unreachable.

NuScale CEO John Hopkins quoted the wisdom of the native peoples of the Great Plains: “Once you’re on a dead horse, you dismount quickly and move on to others.”

He said he was proud of the work done on CFPP over the years.

The company said about half the cost NuScale incurred in developing CFPP is not lost money — it’s effectively development spending that informs future business.

“The progress made here will benefit ALL of our future customers,” Hopkins said. “CFPP unequivocally has been a tremendous success for NuScale.”

NuScale’s 50 MW power module in January 2020 became the first SMR design certified by the Nuclear Regulatory Commission. Its 77 MWe module has been accepted for NRC review.

In its 8-K filing, the company said Standard Power has chosen the NuScale-ENTRA1 partnership to develop two SMR-powered facilities with a total of nearly 2 GWe. It said its RoPower project in Romania is advancing to the next phase of development with a key regulatory approval. And it said production of power module forgings continues.

NuScale reported a net loss of $58.3 million on revenue of $7 million in the third quarter of 2023, up from $49.6 million and $3.2 million in the same quarter of 2022.

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EVs, Data Centers to Fuel Load Growth, Forecasting Challenges

Electric vehicles and data centers are expected to be major contributors to load growth, but each has unique challenges when it comes to load forecasting, speakers said during a WECC webinar. 

“Forecasting is as unique as the industry itself,” said Shane Lunderville, business development manager for the Grant County Public Utility District in Washington. “So if it’s electrifying vehicles, if it’s data centers, if it’s manufacturing, each one is going to be different.” 

Much has been learned since Grant County got its first data centers in the mid-2000s, Lunderville said during the Oct. 2 webinar, part of WECC’s resource adequacy discussion series. 

But technology is always changing. The use of artificial intelligence is on the rise and work patterns have shifted since the COVID-19 pandemic, he said. 

“We all have Office 365 or Google, whatever; it’s all online-based,” he said. 

Data centers say the best they can do is give a five-year outlook, Lunderville said, but transmission and infrastructure development takes much longer. 

And data centers, which run constantly, don’t provide much opportunity for demand response, he said. 

But Amanda Sargent, senior resource adequacy analyst at WECC, said data center operators who are interested in carbon-free electricity might build centers with generation resources or batteries. 

“If there’s an opportunity to incentivize them to also build some of those resources at the same time, then there may be opportunities … during peak times to call on them for demand response,” Sargent said. 

Sargent also discussed load growth from EV charging, noting that the adoption of new technology often follows an S-shaped pattern, starting out slowly and then accelerating. 

“That’s going to play a really important role in being able to have more accurate forecasts — being able to follow how high those adoption rates are going to be for the sales of new electric vehicles and other kinds of technologies that are going to increase electric demand,” Sargent said. 

Phil Jones, executive director of the Alliance for Transportation Electrification, said some forecasting of EV charging loads will be fairly easy. 

Much of EV charging takes place at homes, where it can be influenced by incentives to charge off-peak. Opportunistic charging — where an EV driver stops off at a charging station — is harder to predict, he said. 

When it comes to electric truck fleets, some fleets will charge overnight using Level 2 chargers. Jones said that charging isn’t difficult for a utility to handle. 

But other trucks will charge as they travel along corridors, using DC fast chargers that could soon be providing 1 MW of power.  

Historical data on fleet charging is currently lacking, Jones said. But fleet operators are working closely with planners on the issue. Jones pointed to an effort from the Electric Power Research Institute (EPRI) called EVs2Scale2030. 

One piece of the initiative is to develop a nationwide map showing EV loads, grid impacts, utility lead times, workforce requirements and costs. (See EPRI Launches Cross-industry Initiative to Advance EV Adoption.) 

With load growth seemingly inevitable, panelists called for allowing utilities to build infrastructure further in advance. 

“Allow more flexible and sophisticated load forecasting for loads that don’t have a lot of historical data and based on that … allow utilities to build ahead of need,” Jones said. 

WECC’s discussion series will return in February with a new name and an expanded scope. The discussions, which will be called Reliability in the West, will take place the first Wednesday of each month from 11 a.m. to noon Mountain time. 

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Analysis Group Details Methodology of ISO-NE Capacity Market Study

WESTBOROUGH, Mass. — Analysis Group outlined the methodology of its study of major changes to the structure of ISO-NE’s Forward Capacity Market (FCM) at the NEPOOL Markets Committee meeting Nov. 7. The study will consider quantitative and qualitative effects of prompt and seasonal capacity market formats.

“These options are being evaluated in light of multiple changes to the region’s electricity system and markets arising in part from state policies aimed at decarbonizing the region’s grid, as well as technological innovation that increases performance and decreases costs of new technologies,” Todd Schatzki of Analysis Group told the MC.

A prompt market would reduce the time between the capacity auction and the capacity commitment period (CCP) from three years to just a few months, while a seasonal auction would split up the CCP into distinct seasons with separate auctions.

Working on a tight timeline — with draft results expected in December — Analysis Group is tasked with studying the tradeoffs associated with both formats. The study will consider prompt and seasonal constructs both separately and together and compare them to the existing three-year forward annual market.

Analysis Group will also consider other market design factors, including how the seasons are separated within a given year, whether seasonal auctions are held simultaneously or sequentially, and whether the transition to a new capacity market will be accomplished all at once or in multiple phases.

The quantitative assessment of auction outcomes associated with various constructs will look at the 2028/29 and 2034/35 CCPs, with a resource supply that “reflects resources that have recently bid into the [Forward Capacity Auction], as well as state-legislated procurements and additional assumed resources (to meet state environmental goals).”

ISO-NE is requesting stakeholder feedback on the study by Nov. 13 and is planning to make a recommendation on a potential move to a prompt market at some point in the first quarter of 2024.

RCA Updates

Feng Zhao of ISO-NE presented updates to the RTO’s proposal for winter accreditation of oil and gas resources as part of its ongoing Resource Capacity Accreditation (RCA) project.

Under the updated proposal, “gas capacities will be modeled as an aggregated profile, and oil resources will be modeled as individually de-rated thermal units for the winter period,” Zhao said.

ISO-NE stakeholder process timeline | ISO-NE

The RCA project aims to “support a reliable, clean-energy transition by implementing methodologies that will more appropriately accredit resource contributions to resource adequacy as the resource mix transforms,” Zhao said.

The seasonal risk assessments that result from these models will then be used as resource accreditation inputs.

“The newly proposed gas and oil models better capture the characteristics of gas and oil energy limitations and historical performance in the winter period, and therefore are expected to yield a more accurate winter risk level,” Zhao added.

Retirement Rules

ISO-NE continued discussions on changes to the rules for retired resources looking to re-enter the FCM.

In August, the RTO proposed to eliminate investment requirements for retired resources seeking FCM re-entry. ISO-NE has said the requirements “could create a barrier to cost-effective and timely re-entry of FCM resources.”

Responding to stakeholder concerns about seller-side market power and cost-of-service impacts, ISO-NE is now proposing to treat certain retired resources that re-enter the FCM as existing capacity and require “clawback” provisions for resources retained by cost-of-service agreements (COSAs) that seek to re-enter the capacity market.

The changes are intended to prevent unintended incentives for resources retiring and then re-entering the FCM.

“Absent a provision requiring repayment, resources could uneconomically retire only to seek a (perceived) profitable retention agreement,” said Ryan McCarthy of ISO-NE. “If retained without a clawback provision, the resource can re-enter in a later period, benefiting from any capital expenditure compensation … received via the COSA.”

ISO-NE is targeting January for a vote by the MC on the proposal, followed by the Participants Committee in February.

IMM Quarterly Report

Summer wholesale market costs were down by 60% and energy costs were down by 64% compared to the previous summer, ISO-NE’s Internal Market Monitor found in its quarterly markets report.

The Monitor attributed this to the decline in average natural gas prices, which were 71% lower than in the summer of 2022. Average loads were also significantly lower than the previous two summers — and the lowest summer peak load since 2000 — in part because of cooler weather in the region.

The IMM also noted that nuclear generation decreased because of planned and unplanned outages, making up 17% of the region’s average output compared to 21% in the previous two summers.

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Maine Voters Reject Public Takeover of Electric Utilities

Maine voters have decisively rejected a proposal for a public takeover of the state’s for-profit electric transmission and distribution infrastructure.

The unofficial tally in the Nov. 7 referendum was approximately 70% opposed and 30% in favor with 99% of the vote tallied, multiple media reports indicated. The state had not posted official results by the close of business Nov. 8.

The proposed Pine Tree Power Co. would have been a nonprofit, consumer-owned utility focused on reliable, affordable service rather than shareholder profit.

Other mission goals included assisting the state with its climate action plan, improving internet connectivity, advancing environmental and social justice, creating transparent governance and supporting economic growth.

Another question on the referendum ballot Nov. 7 would have affected Pine Tree: A proposed requirement that any consumer-owned electric utility gain statewide voter approval to exceed $1 billion in total outstanding debt.

Voters approved that measure by a margin nearly as wide as their rejection of Pine Tree — 65% to 30% — according to unofficial results.

Rural electrification cooperatives, municipal electric districts and certain quasi-independent state entities also are subject to voter approval of debt exceeding $1 billion, under terms of the referendum.

Long-running Debate

The concept of a Maine public utility has existed for years, rooted in part in the low customer service and reliability ratings of Central Maine Power and Versant, Maine’s two investor-owned electric utilities. (For NetZero Insider’s in-depth pre-election look at the issues, see “In the Fight Over Maine’s Utilities, the Future of the State’s Energy Transition Goes to Voters.”)

But following through and creating Pine Tree has proved difficult.

In 2021, Gov. Janet Mills (D) vetoed legislation that would have directed a public takeover. Seven weeks before the 2023 referendum, she urged state residents to vote “no,” saying a takeover would result in years of litigation and create paralysis amid the urgent need to prepare the grid for the clean energy transition.

Also, she said, Pine Tree would debut with up to $13.5 billion in debt amid potentially high interest rates.

The parent companies of CMP and Versant spent heavily to sway public opinion against Pine Tree.

Arguing in favor of Pine Tree was an array of grassroots organizations focusing not just on high rates and poor performance under the current ownership but on the chance to address environmental and social concerns through public ownership.

Late Nov. 7, the group Pine Tree Power conceded defeat on the ballot measure, but not on the underlying issues. It said:

“Central Maine Power and Versant’s parent companies poured almost $40 million … into misleading voters rather than fixing their worst-in-the-nation service. They made clear that their priority will always be enriching their shareholders, not serving their customers. Thousands of Mainers are ready for public power. While we couldn’t overcome being outspent 37:1, we started a critically important conversation that does not end today. Our grassroots movement educated thousands about the savings, reliability and climate benefits of consumer-owned utilities.”

Before the election, Pine Tree proponents said utility takeovers often take more than one attempt to achieve and said they would continue to press the issue in Maine if voters did not approve it this time.

Yet another of the eight questions on Tuesday’s ballot will have direct bearing on any future effort. By a huge ratio — 86% to 14% by unofficial tally — voters approved a ban on foreign governments and their entities spending money to influence elections or referendums in Maine.

Versant is owned by Enmax, a private corporation whose sole shareholder is the city of Calgary, Alberta. CMP is part of Avangrid, which is part of Spanish utility Iberdrola. “Maine not Spain” has been a recurring slogan in debate over Pine Tree, but the largest shareholder of Iberdrola is not Spain — it is Qatar, through its sovereign wealth fund.

Proposed Structure

Under the wording of the referendum, seven of Pine Tree’s 13 board members would have been elected and six would have been designated experts.

Starting Jan. 1, 2025, the state Public Utilities Commission would have directed takeover of any utility that met the criteria laid out by the referendum.

Upon takeover, Pine Tree Power would have had to retain the utility’s employees and would have been liable for property taxes on its infrastructure. It would have been exempt from state income tax, however, and its debt also would have been exempt from state taxes.

The new company would have had to cover all of its expenses with rates and charges — it would not have had access state funds and its debt would not have been a state liability.

In her Sept. 20 message urging residents to vote down the takeover proposal, Mills said she is committed to improving utilities’ quality of service and holding them accountable for it. But she challenged Pine Tree as a means of accomplishing this and pointed to its proposed structure.

“Question 3 creates a governing board of elected individuals — in other words, politicians — with no particular credentials,” Mills said. “Electing people only injects a level of politics and partisanship into the delivery of our electricity. That’s the last thing we need, and, hey, I’m talking as a politician.

“And what would this governing board of politicians be in charge of? Well, they would be required to contract with an operator to run the transmission and utility’s assets. An operator that has ‘familiarity with the systems to be administered.’ So, somebody who looks a lot like CMP and Versant. So, what we are really talking about here is adding a layer of bureaucracy and politics and partisanship over the existing structure of CMP and Versant and I just don’t see how this improves anything.”