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November 14, 2024

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FERC Dives into Reliability Implications of EPA’s Power Plant Rule

FERC commissioners and the industry and state witnesses before them at the commission’s annual reliability technical conference Nov. 9 were split on whether EPA’s latest greenhouse gas rule for power plants can be implemented reliably and affordably.

Chair Willie Phillips opened up the afternoon’s panels focused on EPA’s proposal under Clean Air Act Section 111(d) by noting that FERC’s first job is to maintain reliability. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

“For half a century, EPA has set and enforced the emission standards that apply to every power plant in the nation,” Phillips said. “We remind ourselves again, at the outset of this conference, that our piece of the electric power puzzle is defined by the Federal Power Act. We do not build, certificate or authorize the construction or retirement of power resources. That responsibility lies with the states. We also do not have the authority to second-guess EPA’s regulatory choices.”

FERC’s task was to better understand how the rule would impact the grid going forward, with the knowledge that predicting future outcomes is a “fraught task,” he added.

Joseph Goffman, principal deputy assistant administrator for EPA’s Office of Air and Radiation, laid out the details of the rule, which he noted was still under development and would likely change before it is finalized.

“The proposed carbon pollution standards are in fact crucial to addressing the urgent need to reduce climate-destabilizing carbon dioxide pollution from the power sector,” Goffman said, “and an important part of the agency’s broader efforts to address the multiple health and environmental impacts of the power sector, while supporting the continued delivery of reliable and affordable electricity.”

The proposal includes varying compliance levels for coal and gas plants that depend on how long they plan to keep running and how often they are actually dispatched by grid operators, Goffman said. The rules will allow the industry to keep building uncontrolled combustion turbines needed to meet peak demand, while the only coal plants facing the strictest requirements are those that keep running past 2040.

The rule will also be implemented by states’ environmental agencies, and they will have some flexibility to make the rules workable. EPA is also proposing a transparent exemption process for units critical to reliability that cannot comply with the rule — as it did for the Mercury and Air Toxics Standards (MATS) a decade ago, Goffman said.

“I like to think about us as being maybe in the fifth inning of this process,” Goffman said. “We haven’t even gone to the bullpen yet. So, there’s a lot of work that we still understand that we must do on the path to finalizing these rules. And we are committed to engaging with reliability stakeholders as we develop the final rule.”

The last half of the game will involve EPA iteratively refining its rule and turning to FERC, state regulators, the industry, grid operators and others to get their expert opinions on any changes, he added.

The rule would require the longest-lived and most used fossil power plants starting in the 2030s to use carbon capture and storage (CCS), or clean hydrogen at scales that have yet to be proven for either technology. Their lack of viability has been a common criticism, and Phillips asked Goffman to address it.

EPA has designated those technologies as the “best system of emission reduction,” but states will ultimately get to pick the strategies that work for them. Both CCS and clean hydrogen have significant federal backing under the Inflation Reduction Act as well, Goffman said.

“We’ve had reports from various RTOs, in fact, almost all of them, that they’ve had unexpected retirement rates that they didn’t anticipate,” said Commissioner James Danly. Coupled with the difficulty of fully using all the incentives from the IRA and issues around interconnection, it is likely that law will not fully spur the massive growth in new clean energy some have predicted, he argued. Thus, the process of replacing the emitting plants with new clean capacity will not be as robust as EPA might think.

FERC Commissioner James Danly questions EPA Assistant Administrator Joseph Goffman at Thursday’s technical conference. | FERC

“You’ve laid out a lot of issues that I think we are going to have to address in terms of how we account for potential retirements,” Goffman replied.

Even without EPA’s rule, those issues are going to be facing FERC as the industry is transitioning away from fossil fuel to renewables and other cleaner resources because of other policies and market forces, said Commissioner Allison Clements.

“We face the need for markets to evolve to send the right signals to provide resources with the revenue certainty and to provide services we need,” Clements said. “That’s within FERC’s jurisdiction and is in need of change before we even get to this policy.”

Finalizing compliance with Order 2023 will help on that front, and FERC could also take up issues around retirement notifications to help remedy that issue, she added.

Less Room for Error

PJM released a paper early this year, before EPA released its proposal, projecting it would see 40,000 MW of retirements by the end of 2030, but it has already seen some announced retirements since then that it was not expecting, so the actual numbers could be bigger, said Mike Bryson, the RTO’s senior vice president of operations.

“We look at certainly the impact of the IRA, which I appreciate has a lot of stimulus in there,” Bryson said. “But we also look at the Ørsted announcement about Ocean Wind 1 and Ocean Wind 2 — 7,500 megawatts, which was supposed to be replacement megawatts.” (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

While PJM’s markets worked to help reliably transition its fleet from the MATS rule, which led to significant retirements of coal plants, its markets are different now. The reserve margin is thinner, and there is less room for error this time around, Bryson said.

Other industry speakers were more blunt, with Eastern Kentucky Power Cooperative CEO Tony Campbell, who was testifying for the National Rural Electric Cooperative Association, calling the rule “unlawful, unworkable, beyond salvage and disastrous for grid reliability.”

“Even if we put aside the enormous cost involved, the proposed rule relies on CCS and clean hydrogen, neither of which are ready at levels and scales for a sound economy that requires certainty, and not in all regions of the country,” Campbell said. “The infrastructure needed for both technologies is not now and will not be in place at the scale to meet EPA deadlines.”

Beyond the costs, both technologies need pipeline infrastructure, which has not been easy to build for natural gas, and that at least has an established regulatory regime, he added.

Campbell was not alone in questioning the rule’s legality, but Edison Electric Institute Vice President General Counsel Emily Sanford Fisher said that issue would ultimately be decided in the coming years in the courts.

EEI’s investor-owned utility members have embraced the clean energy transition, with Fisher noting the industry has met the goals of the Clean Power Plan even though it never it went into effect, and 2022 saw emissions equal to 1984’s.

“Regardless of any final EPA regulations addressing greenhouse gas emissions from … the fossil generating fleet, the clean energy transition is not going to be easy,” Fisher said. “Challenges do not mean, however, that this transition is impossible, or that our larger goals about a resilient equitable, affordable, clean energy future should change.”

Those challenges will require working across myriad stakeholders to address them, and the industry and policymakers should be prepared for some “bumpy” progress occasionally, she added.

EPA is likely paying close attention to the legal issues around its rule, given its experience with the Clean Power Plan being overturned, noted Analysis Group Senior Adviser Susan Tierney, who had released a paper before the technical conference explaining how the industry could meet the proposed rule’s requirements reliably. It echoed arguments she made for other EPA rules issued under the Obama administration.

“In each instance in the past dozen years, the industry and other stakeholders predictively stepped up to ensure that actual reliability was not compromised,” Tierney said.

Some of the particulars this time are different than in the past, but there are also reasons to be assured that a final EPA rule will not jeopardize reliability, she added.

Colorado is well underway to deep decarbonization, pushed by state policy and being one of the few states to benefit from plentiful wind and solar without the need for massive transmission lines, said its Energy Office’s executive director, Will Toor. It expects all coal plants to be retired before EPA’s requirements kick in, while its natural gas fleet will operate at low capacity factors, balancing a growing share of wind and solar.

“We do believe that it will be important as the EPA finalizes the rules to ensure maximum flexibility for states to comply in the most cost-effective manner,” Toor said. “We urge EPA to maximize the ability of states to use trading, massive rate-based averaging and other approaches. This should include an ability for states to recognize the changing use of existing gas plants over time.”

By 2030, only one gas unit in the state is expected to approach a 20% capacity factor, which falls to 11% before the end of that decade, he added.

“I’ve got to believe that before you get investors in, a 20% capacity unit is going to be rate based, and therefore the owners are going to be guaranteed cost recovery,” said FERC Commissioner Mark Christie.

Toor answered yes, and Christie noted that no investors are going to want to build additional natural gas plants that run so rarely. But Toor said his state has found that is the cheapest way to operate the grid going forward, even including the total costs of natural gas plants.

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100% Clean Energy, Renewable Siting Bills Heading to Michigan Governor

LANSING, Mich.— Legislation requiring Michigan to meet a 100% clean energy standard by 2040 and giving state regulators siting authority for large wind and solar energy projects is headed to Gov. Gretchen Whitmer (D).  

The Michigan Legislature completed work on the siting bills, HB 5120 and HB 5121, on Nov. 8, with the Senate’s approval on a 20-18 vote with only Democrats in support.   

Last week, lawmakers — again with just Democratic support — approved a package of bills:  

    • SB 271 requires electric providers to achieve a clean energy portfolio of at least 80% and 100% in 2040. It also sets a statewide energy storage procurement target of 2,500 MW and increases the cap on distributed generation such as rooftop solar to 10%.  
    • SB 273 requires utilities to boost their energy-efficiency savings from 1% to 1.5%. 
    • SB 502 requires the PSC to consider environmental justice, climate, affordability and reliability in its decisions on utility integrated resource plans.  
    • SB 519 creates a Community and Worker Economic Transition Office in the Department of Labor and Economic Opportunity to help retrain auto, energy and construction workers who lose jobs because of the switch to electric vehicles and efforts to reduce greenhouse gas emissions.  
    • SB 277 codifies an existing state rule allowing farmers to remain enrolled in the state farmland preservation program even if they rent their land for solar farms.  

According to the Clean Energy States Alliance, Michigan will become the 16th state to legislate 100% clean energy goals.  

In 2022, Michigan got almost 23% of its electricity from nuclear power and another 9.5% from wind, solar and hydropower, according to the Energy Information Administration.  

Michigan bills

| Energy Information Administration

Whitmer issued a statement indicating she would sign the bills, which she said makes Michigan “a national leader on clean energy.”  

“These bills will help us make more clean, reliable energy right here in Michigan, creating tens of thousands of good-paying jobs, and lowering utility costs for every Michigander by an average of $145 a year,” she said. “Getting this done will also reduce our reliance on foreign fuel sources, while protecting our air, water and public health.” 

Environmental groups criticized legislators for changing the 100% deadline from 2035 and defining landfill gas and incinerated waste as renewable energy. They also criticized allowing generators to continue using natural gas-fired generation after 2040 if they include carbon capture systems. 

But clean energy advocates were generally pleased with the final products. Lisa Wozniak, executive director of the Michigan League of Conservation Voters, said the bills puts Michigan among the top of all states in pushing for energy conservation.  

Derrell Slaughter, with the Natural Resources Defense Council, said the bills will help cut energy costs for state residents after “being plagued for decades with the worst service and highest rates” in the Midwest. 

The entire package has been controversial, with Republican opponents charging that Michigan residents will face higher energy costs and less reliability. The Mackinac Center for Public Policy, a conservative think tank based in Midland, argued that even if all the energy savings requirements go into effect, they will have little effect on curbing climate change. 

Most controversial were the siting bills, with both local government organizations and agricultural interests opposing them. Local government groups argued the measures were a state overreach on local decision-making and would deny local residents any say in how local property is developed. Agricultural groups charged the measures would reduce the amount of land being used for farming. (See Mich. Energy Siting Bills Set off Opponents and Backers.) 

But disputes over permitting new wind and solar projects in primarily rural areas led lawmakers to draft the measure giving the state Public Service Commission authority over siting of solar projects of 50 MW or more, wind facilities of 100 MW or more and energy storage facilities of at least 50 MW with a discharge capacity of 200 MW or more.  

PSC Chair Dan Scripps testified Nov. 7 before a Senate committee that the siting rules must change for the state to meet its climate goals. He said the state would need up to 209,000 acres of additional wind and solar — “a big number,” he acknowledged, but only 0.55% of the state. 

There has been no indication of how opponents might try to block the package.  The Legislature did not appropriate any funding in the bills to enact the proposals, which means under Michigan’s constitution opponents could try to hold a voter referendum on the bills.  But the petition requirements — directing that a sufficient number of petition signatures be collected and certified by the state before the bills take effect — make that a tough hurdle to overcome.  

A court challenge to the constitutionality of the provisions is possible, but no group has so far suggested a suit is coming. 

Because only Democrats supported the bills, they will not go into effect immediately after they are signed by Whitmer. However, the Legislature is planning on adjourning sine die some six weeks earlier than usual, which means the bills could go into effect by February.  

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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.