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September 2, 2024

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PJM Stakeholders Endorse New Interconnection Process

PJM stakeholders overwhelmingly endorsed the RTO’s proposal for a new interconnection queue process and a related transition plan after several hours of debate and procedural motions at Wednesday’s Markets and Reliability Committee and Members Committee meetings.

The proposal, which was developed at the Interconnection Process Reform Task Force over the last year, was endorsed with a sector-weighted vote of 4.37 (87%) at the MRC and 4.52 (90%) at the MC. The new interconnection process was nearly unanimously endorsed at the January Planning Committee meeting, while the transition proposal received 91% support at the February PC. (See “New Interconnection Rules Endorsed,” PJM PC/TEAC Briefs: Jan. 11, 2022 and PJM Planning Committee Endorses ‘Fast Lane’ Criteria for Gen Projects.)

PJM said it plans to file the proposal with FERC before the end of May.

In a statement issued after Wednesday’s meetings, PJM CEO Manu Asthana thanked RTO staff and stakeholders for developing the proposal.

“These changes represent a landmark accomplishment for PJM stakeholders and staff that establishes a better process to handle the unprecedented influx of generation interconnection requests and is critical to clearing the backlog of projects,” Asthana said. “We remain committed to our strategy of facilitating decarbonization policies while preserving reliability and cost-effectiveness and will continue to work on issues raised by stakeholders during deliberations that were not part of the package.”

Jack Thomas of PJM’s Knowledge Management Center reviewed the RTO’s proposal, which includes moving away from the concept of “first come, first served” projects in the queue to a “first ready, first served” concept. PJM said the change will ensure projects that are ready to be built are prioritized instead of allowing speculative projects to fill the interconnection queue.

The number of generation projects entering the interconnection queue has nearly tripled over the last four years as more renewable projects are planned in PJM. The RTO started the year with almost 2,500 projects under study in the queue, and about 95% of the more than 220 GW is from renewables, storage or a combination of the two.

The proposal also adds language indicating that if a project doesn’t require a facility study or network upgrades it could move to the final agreement stage early, speeding up the process. The study window for projects is proposed to be 710 days, or just under two years.

PJM’s proposal includes a two-year transition to wade through the backlog of projects in the queue by prioritizing more than 1,200 projects submitted into the queue before 2021. The transition also includes a “fast lane,” which will seek to complete about 450 projects (Queues AE1 through AG1) with upgrade cost allocations up to $5 million within 18 months.

“This has really been a tremendous body of work by our staff and all of our stakeholders to come together to find consensus to some very difficult and complex issues,” said Ken Seiler, vice president of PJM’s planning department. “This is an opportunity today to control our own destiny and really represents a large step forward towards providing our region and the whole industry with more certainty.”

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CGA Requests MISO Help for Late-stage Interconnection Projects

Clean Grid Alliance is asking MISO to develop a means to see late-stage generation projects through the interconnection queue when they’re dogged by uncertain and delayed affected-system study results.

The request comes as MISO and SPP have filed to enact a new relative interconnection queue priority for generation projects that stand to affect the seams for the purposes of system impact studies, affected-system studies and cost assignments for network upgrades.

MISO and SPP’s ongoing Joint Targeted Interconnection Queue transmission planning study compelled them to pivot from a “first-come, first-served” queue priority approach to a “first-ready, first-served” method. The RTOs have a filing before FERC to apply the new prioritization (ER22-1533).

MISO is processing queue applications that were submitted in 2019 and 2020, while SPP is working on interconnection requests submitted in 2017. In some cases, MISO interconnection customers that entered the queue in 2018 are already signing generator interconnection agreements, the final step before grid access.

Andy Witmeier, MISO director of resource utilization, has said it “doesn’t make sense” for MISO interconnection customers to be held up by projects in SPP’s queue that may have entered earlier but have yet to be sited. SPP’s Neil Robertson has also said the RTOs must “evolve” beyond the instinct that whoever lines up first must finish first. (See Midwest Energy Policy Series Addresses JTIQ Projects.)

But in MISO, batches of projects that entered the queue in 2018 and 2019 were left out of the new priority. The RTO said those cycles of projects are destined for generator interconnection agreements (GIAs) before the changes have a chance to take effect.

CGA’s Rhonda Peters said those projects in the late stages of MISO’s interconnection could also use a solution from the RTO to ensure they clear the queue.

Speaking to stakeholders at the Planning Advisory Committee’s meeting Wednesday, Peters said the generation projects are approaching GIAs without “final or accurate” upgrade costs from MISO’s and SPP’s affected-system studies. She said these interconnection customers don’t have a complete enough picture of the affected-system studies or the upgrades they could be on the hook for “to commit significant capital in a GIA or other construction contracts.” She said many are considering filing GIAs unexecuted — “not an ideal solution” for either them or MISO.

CGA’s Natalie McIntire called for a way to help interconnection customers’ advanced-stage projects with uncertain affected-system studies.

“I’m not aware of other industries where you have to sign on the dotted line [while] not understanding what your costs are going to be,” McIntire said.

Both EDF Renewables and Invenergy have protested MISO and SPP’s FERC filing based in part on similar arguments. EDF said it is “often faced with having to execute a GIA 12 to 18 months before obtaining clarity on final affected-system costs.” Invenergy called the affected-system study process “broken.”

Peters said advanced-stage interconnection customers in the 2018 and 2019 cycles have already spent millions that could be passed on to ratepayers even if the projects don’t reach commercial operation. “These projects are the rule-followers and ones that have gone by the book,” she said.

If the projects don’t ultimately connect to the grid, it could impact MISO’s reliability models and resource adequacy. “As the age-old saying goes, an ounce of prevention is worth a pound of cure,” she said.

In February and again in early April, Peters tried to submit a presentation on the topic but was blocked by MISO and the stakeholder leadership of the Interconnection Process Working Group (IPWG). Several stakeholders insisted MISO add the presentation to its website and devote time to stakeholder discussion on the 2018 and 2019 projects.

Future discussions on the topic are likely to take place at IPWG meetings.

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FERC, NERC Drill down on Generators’ Winter Readiness

More than a year after the events of February 2021, in which an unprecedented winter storm nearly led to the entire collapse of the Texas Interconnection, FERC and NERC continue to gather information from utilities, generators and grid operators on maintaining electric reliability during severe cold weather.

That continued this week with a two-day joint FERC-NERC technical conference on winterizing generation. Staff heard from more than 25 stakeholders on the best practices, lessons learned and continuing challenges of generator owners’ and operators’ preparations for the winter season.

“It’s a very important discussion,” Chairman Richard Glick said, starting off the conference Wednesday. “I think people recognize what happened in Texas. … One of [the] factors was that the generating facilities, in many cases, didn’t operate very well under the cold weather that was experienced, and we need to make sure that doesn’t happen again.”

He referred to a similar event 10 years before, when an arctic cold front in Texas and New Mexico caused 1.3 million customers to lose power in early February 2011. More than 200 generating units in ERCOT experienced an outage, derate or failure to start, and a joint FERC-NERC report found that many generators had failed to adequately prepare for winter, even though extreme cold fronts hit the region every few years.

“We know for a fact that a decade before Winter Storm Uri, there was a similar issue in Texas and some of the other Southwest states,” Glick said. “A report was done. The report said, ‘We have a problem. We need to winterize these generating facilities.’ The report was put on the shelf, and nothing happened.”

During last year’s storm, dubbed by The Weather Channel as “Uri,” ERCOT ordered a total of 20,000 MW of rolling blackouts as it tried to prevent grid collapse — the largest manually controlled load shedding event in U.S. history.

More than 4.5 million people lost power for as long as four days, with numerous deaths resulting from the outages, another report by FERC, NERC and six regional entities said. Among its recommendations was to hold a tech conference “to discuss how to improve the winter readiness of generating units” before NERC reliability standards approved by FERC in August — in response to another prior cold snap in the Midwest in 2018 — become effective on April 1, 2023. (See FERC, NERC Release Final Texas Storm Report.)

“We’re not going to let that happen again, and today’s technical conference is one of the steps that we are taking to ensure that to be the case,” Glick said. “We will work with our partners at NERC and the regional entities as well. I think at the end of the day, we’re going to have a much stronger and much more reliable grid because of it.”

“I can’t stress enough how important communication is,” NERC CEO Jim Robb said in opening Day 2 of the conference Thursday. “I think one of the worst things to happen to a grid operator is to be surprised when they’re expecting resources to be there and they aren’t. … We’re hoping for a lot of insights to come out of this conference. …

“And of course, while this is focused on winter prep, we have to remember that changing climate conditions aren’t just limited to cold-weather events. We also have to be cognizant of hot-weather events and in general rethink how we plan and operate the system to deal with extreme events, which are not rare, as we’ve seen over the last several years.”

Cold Weather Preparedness Plans

The conference’s first panel consisted of utility executives discussing the measures they were taking to head off another winter catastrophe.

Most natural gas plants in Texas are outdoor facilities that require additional protection during cold fronts, they said.

Garry Waggoner, senior director of engineering services for Luminant, the main generation subsidiary of Vistra, said that following the 2011 cold front, the company began hardening its generation units against freezing by instituting measures to be completed by November of each year.

Luminant’s fleetwide measures include temporary wind breaks for critical equipment, freeze-protection circuitry monitoring and enclosing sensitive equipment in heat- and humidity-controlled boxes, he said.

Other generators said they use similar measures.

Roger Morgan, vice president of operations at NRG Energy, said that the company’s outdoor generating units in ERCOT installed wind breaks, additional insulation and roofing over essential systems susceptible to the cold and precipitation.

Precipitation, especially in the form of freezing rain, had a big impact during the storm and “probably caused a lot more grief at the plant levels than people may recognize or understand,” Morgan said.

NRG also pre-starts gas units before cold snaps to avoid icing, he said. Each generation site has a winter-readiness coordinator who reports to a regional coordinator. And after every winter, the company conducts a root-cause analysis of problems to avoid repeating them in future years, he said.

“We revise and develop mitigation plans and put those back into our procedure to make sure that we never have a repeat issue at any of our sites,” Morgan said.

Experiences and Lessons Learned

A panel on planning, engineering and technologies for weatherization offered some practical insights and suggestions for addressing cold weather events in what are typically warm climates.

“In the South, we used to use an event time of about 24 hours as a common design [standard],” said Mark Dittus, a project manager for infrastructure consulting firm Black and Veatch. “You would expect to see the freeze event during the night, but then you’d expect to go above freezing again the next day. So you only had a short period that you were worried about.”

But growing instances of “unprecedented” long-duration cold snaps are driving the firm’s clients to upgrade their systems, Dittus said.

El Paso Electric (EPE) is one of those clients. The utility, which serves about 450,000 customers in far West Texas and southeast New Mexico, dealt with the winter events of 2011 and 2021 but faced “severely different” outcomes in each, according to Kyle Olson, director of power generation and asset management at the utility.

EPE “did not do so well” during and after the 2011 storm. “We had major issues with our generation fleet, and we had days of rolling blackouts as a result,” Olson said, noting that in 2011 the majority of the EPE’s generation fleet had been built between 1957 and 1988.

In the wake of the storm, EPE worked with Black and Veatch to devise new facility design criteria rated to -10 degrees F, 2 degrees below El Paso’s all-time low temperature. The consulting firm helped the utility prioritize equipment for freeze protection based on risk to a unit’s operational ability. Top priorities included steam drum level transmitters and major control valves; further down the list were water lines used for a facility’s drinking water.

EPE has also brought on about 500 MW of new generation since 2011 and is currently adding another 228 MW, most of which is gas-fired. Olson said the utility’s newer gas-fired Montana plant is designed for minimal water use and freezing risk and can run on diesel as a backup.

The utility fared much better during the 2021 storm, in part because of its access to power from the Palo Verde nuclear plant in Arizona, which helped the utility avoid price spikes in the market. But the utility did identify one new vulnerability after the storm: inexperienced staff.

“They hadn’t gone through the training and then gone through the implementation of the freeze protection in 2011, so what they thought was good freeze protection, being a summer-peaking utility,” was inadequate, Olson said. “We found gaps where they would go by and walk past something and go, ‘That looks fine; that looks good.’”

Amanda Frazier, senior vice president of regulatory policy at Vistra, said her company “had a disappointing performance” during the 2011 storm but experienced different problems in February 2021, despite having worked with NERC, ERCOT and Texas regulators to implement recommended best practices around weatherization.

Between 2011 and 2021, Vistra retired about 4,000 MW of coal-fired generation and discontinued use of fuel oil backup at several plants because both were considered uneconomic, Frazier said. Like other Texas utilities, Vistra faced frozen coal piles and limitations on the gas system during the 2021 storm. The company has since invested $50 million to winterize its plants and is working to restore dual-fuel capability at those facilities with permitted fuel tanks.

But Frazier said weatherization of generating plants won’t be enough to head off another grid event like that stemming from Uri.

“It’s necessary, but it’s not sufficient to prevent the next winter storm event,” Frazier said. “Unique to Winter Storm Uri were gas shortages, exceptionally high gas prices and lack of incentives to invest properly in the weatherization of the gas infrastructure facilities. … So, there must be an equivalent focus on improving the reliability of that key supply chain.”

In a similar vein, Steve Metcalf, vice president of power production and delivery at Arkansas Electric Cooperative Corporation, pointed to yet another exigency that’s not within a utility’s control during cold weather events: the standards of other utilities.

Metcalf noted that while his co-op’s consumer-owners might be willing to pay more than other electricity customers to ensure winter reliability, the broader market might have higher tolerance for risk that could force his company to institute outages anyway.

“It’s not up to us whether or not we’re experiencing or required to do rolling blackouts or brownouts; it’s up to the market,” he said.

A Rare Success Story

During the third panel, FERC heard from representatives of ISO-NE, NYISO, PJM and SPP about their generators’ winter readiness procedures.

But also on the panel was Andrew Valencia, senior vice president of generation for Lower Colorado River Authority, whom FERC and NERC were “very eager to hear from,” according to Heather Polzin, of the commission’s Office of Enforcement.

While many gas plants did not operate during the 2021 storm, the Austin, Texas-based nonprofit utility’s Thomas C. Ferguson plant — a 556-MW gas-fired combined cycle facility located in the nearby city of Horseshoe Bay — “actually performed quite well” despite the many challenges staff faced, Valencia said.

The plant broke ground in 2012 and, according to Valencia, was “designed with the 2011 event in mind,” able to withstand down to 0 F and up to 40-mph winds.

But the plant was not designed to withstand below-freezing temps for extended periods of time. Valencia said that is true of most plants in Texas, even those with very low temperature ratings, so “it’s definitely a concern going forward.” Even with the plant’s performance, LCRA installed permanent wind walls and shielding around certain pieces of equipment that froze during the event, Valencia said. Though they required responses, increased staffing meant the freezing did not impact plant operations. LCRA called for Level 3 staffing — what Valencia said is called “battle stations” — in place about two days before the most severe weather hit because in 2011, the extreme cold came earlier than forecast.

One of the challenges to cold weather preparation that Valencia wanted to stress during his presentation is that a plant “can’t functionally test [its] weather-protection systems. You know we can test relays; we can test water-induction systems; we can test all of the different subsystems … [but] the only way [to test] is to actually endure some type of an event.”

Another challenge, especially in Texas, is “that the things that you do to protect your plant from extreme cold hurt your plant in extreme heat. We can go and add enclosures and things of that nature to protect us from the cold, but an enclosure around a pump or a motor during the hot summer season is going to be problematic.”

Gas-Electric Coordination Key to Resilience

In the last panel, participants discussed how last year’s winter revealed just how intertwined the gas and electric industries have become, and the pitfalls that can result when they don’t communicate their needs.

“We’ve found that training and drill exercises are critical to preparedness,” said Jessica Lucas, senior director of reliability coordination at MISO. “Experience has proven to be the best teacher, and we’ve had quite a bit of that in recent years.”

Among the lessons that MISO learned from Uri was to bring more urgency to both its weekly fuel data requests and its annual generation winterization survey. Both information requests are still voluntary, but for the latest winter, Lucas said the RTO attempted to impress on its entities the importance of supplying accurate information.

Measures to encourage cooperation with the annual survey this year included preseason conferences with major utilities. For the weekly fuel surveys, Lucas said MISO has elevated them to formal data requests. While this format is still voluntary, she said the goal is to emphasize to respondents how seriously the RTO views the situation.

Last year’s storms also brought home the fact that generators’ theoretical performance doesn’t always match their real-world functioning, said Todd Staples, president of the Texas Oil and Gas Association. He reminded participants not to take for granted the ability to respond to changing grid conditions in real time.

“Even with the best hardening of field assets, we have to keep in mind that most of these assets are unmanned. … There are more assets than there are people,” Staples said. “And so there’s going to be a production decline, depending on the severity of the weather, and it’s very important for reliability that we plan on this production decline and take the steps that are going to mitigate that.”

Representatives of the pipeline industry focused on the efforts their companies have made to work with electric utilities and regulators on predicting how loads are likely to shift in response to changing weather conditions.

“We really believe in the continued improvement of the balancing authority websites — that’s a huge asset for us as a pipeline operator,” said Frank Rozmus, vice president of gas control and facility planning at Northern Natural Gas. Rozmus said he and his team “spend possibly hours a day on the websites of the [BAs] in our footprint, making sure that we get up-to-date information, and it really assists us with our load supply forecast.”

Speakers also highlighted the role that government can play in facilitating the sharing of information across industries. Staples pointed to the Railroad Commission of Texas’ recent designation of critical load facilities as a sign that the needed collaboration, not only between industry segments but also with the public sector, is finally taking root.

“In my eight years here … I’ve never seen this level of engagement … between industries. The Railroad Commission of Texas, ERCOT, the Public Utility Commission [and] Division of Emergency Management have all been fully engaged, and private industry has been having multiple conversations,” Staples said. “And so I think we’re moving in the right direction.”

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GOP to Granholm: ‘You’re Anti-Fossil Fuels, Aren’t You?’

Energy Secretary Jennifer Granholm announced Thursday that the United States will boost its liquified natural gas (LNG) exports to 15 billion cubic feet per day by the end of the year, with most of the increase going to European allies attempting to cut their dependence on Russia’s fossil fuels.

The announcement came as Granholm parried attacks from Republican lawmakers on the House Energy and Commerce Subcommittee on Energy, criticizing President Joe Biden’s clean energy policies and his response to high gasoline prices — and the near-term need to increase natural gas and other fossil fuel production.

Granholm was on Capitol Hill ostensibly to discuss the Department of Energy’s $48.2 billion 2023 budget request, but the Energy and Commerce hearing provided yet another demonstration of the politicization and polarization of energy policy in the wake of Russia’s invasion of Ukraine and post-COVID-19 inflation.

In her opening statement, Rep. Cathy McMorris Rodgers (R-Wash.), the full committee’s ranking member, called out a recent Granholm statement that “perhaps renewable energy is the greatest peace plan this world will ever know.”

“I cannot overstate how dangerous I believe this statement is for our energy security, our national security, our future as Americans,” Rodgers said. She called on Congress and the administration to “say yes to flipping the switch on domestic production of cleaner oil and natural gas.”

Rep. Jeff Duncan (R-S.C.) was equally confrontational. His first question to Granholm was: “You’re anti-fossil fuels, aren’t you?”

Granholm replied, “I would like to transition away from unabated fossil fuels to a clean energy future.”

Rep. Fred Upton (R-Mich.) called on DOE to lead by example by “issuing waivers to streamline the permitting process for LNG export facilities and send the signal that our country will be a stable and reliable supplier of natural gas for many decades to come. Our European allies need more certainty to push back on Russia and build new import facilities and pipeline interconnections.”

Granholm and Democrats on the committee countered with arguments that clean energy would lower prices and the dependence of the U.S. and its allies on fossil fuels from Russia and critical minerals — such as lithium for energy storage batteries — from China.

COVID, Ukraine and the rising number and severity of extreme weather events “tell us that global energy security and energy independence all depend on a shift toward American-made clean energy,” Granholm said in her opening remarks. DOE is “committed to securing the clean energy supply chains needed to reduce our reliance on unabated fossil fuels and increase our energy independence.”

At the same time, Granholm said the administration and DOE are “using every tool at our disposal to increase oil supply,” citing the president’s release of 1 million barrels of oil a day from the U.S. Strategic Petroleum Reserves and DOE’s approval on Wednesday of permits allowing two LNG facilities to increase their capacity.

With the approvals, both facilities, one in Louisiana and the other in Texas, will be able to increase their combined exports by 500 million cubic feet per day, the DOE announcement said. The Texas facility is scheduled to come online in 2024; the Louisiana plant is still in development, the announcement said.

Current export levels are about 12 billion cubic feet per day, DOE said.

“We have permitted completely 30 billion cubic feet of liquefied natural gas that has not been constructed yet,” Granholm said. “Every molecule of natural gas that can be liquefied at a terminal is being liquefied and exported.”

Echoing Granholm, Rep. Frank Pallone (D-N.J.), chair of the full committee, argued that natural gas production and LNG exports are at “record highs.”

“Five decades of fossil fuel dependency have left us reliant on volatile commodities that are priced at the whim of global markets,” Pallone said. “If we truly want to lower prices and to reduce our reliance on foreign adversaries, we must invest in renewable energy and domestic supply chains here in America.”

Solar Tariffs and Supply Chain Acceleration

While Democrats on the committee mostly offered Granholm questions that allowed her talk up DOE programs and accomplishments — like Tuesday’s release of new standards for energy-efficient light bulbs — she faced some hard questions from them as well.

Rep. Scott Peters (D-Calif.) raised concerns about the Commerce Department’s investigation of potential import violations of solar manufacturers in Cambodia, Malaysia, Thailand and Vietnam, and the devastating impact the investigation is already having on the U.S. solar industry. (See SEIA Predicts Severe Fallout from Commerce Probe of Solar Imports.)

“Is the Department of Energy researching how this potential loss in solar deployment could affect energy reliability and our climate goals, and planning what steps the administration needs to take to offset the solar project losses if they decide to impose tariffs?” Peters said.

While the final decision in the case will be “adjudicative,” Granholm said DOE and the White House Office of Domestic Climate Policy share “deep concern” about the case. “It’s safe to say that there is an awful lot of effort around how to address this given that it is an adjudicative proceeding.”

Granholm also pointed to funding in the 2023 budget for a solar manufacturing accelerator that “would help to achieve what the manufacturing processes are that can be accelerated in the solar realm, in addition to research that’s necessary in advanced components. Whether it’s the use of technology, the use of integrated systems, the bottom line is, we have to accelerate,” she said.

House Appropriations Committee

Granholm had an easier time before the Subcommittee on Energy and Water Development Thursday afternoon, where both Democrats and Republicans wanted to talk about the figures and programs outlined in Granholm’s 16-page written testimony.

While both sides of the aisle chided Granholm for not providing them with a more detailed budget justification report, she said a key priority for the 2023 budget will be building on the $62 billion in energy funding contained in the Infrastructure Investment and Jobs Act (IIJA).

That “historic long-term investment … is not on its own sufficient to address the nation’s energy challenge,” Granholm said. “That’s why our request includes base-year funding to complement the infrastructure law and maximize its impact to lower costs, to make us energy secure and to provide us with reliable baseload power.”

For example, a newly created Office of the Undersecretary of Infrastructure will be getting $2.1 billion in total, for a range of programs, including:

  • $90 million for the Grid Deployment Office “to catalyze the development of new and upgraded high-capacity electricity and distribution systems nationwide.” The money will also fund two new programs to focus on improving wholesale electricity markets and removing barriers to offshore wind deployment.
  • $214 million for the Office of Clean Energy Demonstrations for a new program that will “support full-scale and commercial-scale demonstrations that address integration issues of renewable energy in the U.S. transmission and distribution grid. The office also oversees the DOE’s initiative to develop and build two advanced nuclear reactors, one in Washington and one in Wyoming.
  • $727 million for state and community energy programs “to reduce energy costs for households and businesses, deploy low-cost clean energy solutions [and] weatherize at least 50,000 homes.”

Republicans on the committee criticized what they called the budget’s skewed priorities, with defense-related spending getting minimal increases versus more substantial increases for non-defense spending.

“The request for the nuclear program is a mere $10 million,” said Rep. Michael Simpson (R-Idaho). “In contrast, the increase for energy efficiency and renewable energy … is more than $1.7 billion, or more than a 54% increase.”

Simpson also criticized the DOE’s programs on rare earth and critical minerals as “scattered and unfocused, not only with the Department of Energy, but with other agencies that have a role to play” in developing those supply chains.

Similarly, Rep. Ken Calvert (R-Calif.) voiced disappointment that “you’re requesting a mere 3.7% increase for the [National Nuclear Security Administration] compared to 17% nondefense. … That’s a hefty cut when you account for inflation. I’m not sure how anyone can justify [shortchanging] our national security, especially now.”

Calvert was particularly concerned that the DOE has fallen behind on the production of nuclear “pits,” a key component in nuclear warheads. Granholm said the Los Alamos National Laboratory was on schedule to produce 30 pits, and the Oak Ridge National Laboratory is currently being redesigned to ensure it can also meet its quota of 50 pits, though she could not say when the redesign would be complete.

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Overheard: USEA Lithium-ion Battery Supply Chain Briefing

The U.S. does not have a shortage of the critical minerals — lithium, nickel and graphite — needed for the battery storage vital to decarbonizing transportation, said Ned Mamula, an economic geologist and energy industry consultant.

“Our country has most all of these resources in abundance,” Mamula said Friday during a virtual briefing on the lithium-ion battery supply chain, hosted by the United States Energy Association (USEA).

The problem, he said, is that “we don’t produce what we can produce” because of permitting challenges, restrictions on mining on federal lands and the fact “that this country is only less than 20% mapped geologically,” so the extent of the domestic reserves of such critical minerals is still unknown.

Mamula was one of five speakers at the briefing, providing a range of perspectives on current industry conversations about the urgent need to build out a domestic supply chain for lithium and other critical minerals essential to growing the electric vehicle market in the U.S.

The core issue is well known: U.S. dependence on “adversarial countries,” primarily China and Russia, for critical minerals has put the country’s clean energy supply chains at risk.

As many others have, Mamula pointed to countries, like Australia and Canada, which have streamlined their permitting process to allow new mines to be approved in two to three years, rather than the five to 10 that is the norm in the U.S. Looking to these and other allies for short-term supply imports is an option, he said, but not a long-term plan “because some of these countries have had the same problems we do.”

Recycling and finding replacements for the critical minerals are other options, though neither can fill the gaps in the supply chain in the near term, he said. “We are wedded to these minerals for the time being, whether they’re here in this country or have to be imported.”

Efforts to extract lithium from geothermal brine, now being developed in Southern California’s Salton Sea area, are another option for supply chain development. (See 54 GWh EV Battery Plant Proposed for Lithium Valley.) While not commenting directly on the technology, Stephanie Shaw, technical executive at the Electric Power Research Institute, noted that the initiatives now underway have involved “a substantial amount of interaction with a range of stakeholders, including nearby underserved communities.”

The environmental and social aspects of these projects require the same “strong attention” as the technology, Shaw said. While U.S. permitting processes may be long, she said, they do ensure high levels of safety and minimize environmental impacts for surrounding communities.

DPA Impact Limited

For Scott Aaronson, senior vice president of security and preparedness at the Edison Electric Institute, still another strategy for dealing with supply chain shortages is to stockpile materials and equipment, as most utilities do.

“Just-in-time supply chains are terrific for efficiency; they’re not necessarily terrific for resiliency,” Aaronson said. “We have to look holistically at the supply chain and look for some redundancy. … So, to the extent lithium is a single point of failure, we need to find other opportunities to prevent that failure.”

Proactive prevention was clearly one of the drivers behind President Biden’s March 31 invocation of the Defense Production Act. The specific purpose of the declaration was to accelerate “sustainable and responsible domestic mining … and value-added processing of strategic and critical materials for the production of large-capacity batteries for the automotive, e-mobility and stationary storage sectors.”  

However, the impact of this action may be limited, said Eric Dresselhuys, CEO of ESS, which manufactures long-duration redox flow batteries. The complexity of building out the battery supply chain means “the president’s act might help transform some of the later-stage development of products, but I don’t think it’s going to have a near-term impact on mining and materials.”

The reason, he said, is that improving processing can be accomplished more quickly than mining the raw materials.

Dresselhuys believes part of the solution to battery supply chain issues will be to minimize the storage applications in which lithium is used. For example, lithium-ion batteries may not be the best fit for grid-scale storage, especially for long-duration applications, and he said developing nonlithium alternatives would “take the pressure off what we have to build with lithium.”

“We’re going to have to start to break out our use cases into distinct chunks and [determine] what are the characteristics that are most valued for those use cases,” Dresselhuys said.

This approach will not reduce the amount of lithium or battery storage needed in the near term, he said, “but we can reduce the rate of growth by not trying to put lithium to use where it’s really not appropriate or necessary [and] use alternative technologies where they’re better suited.”

ESS uses iron, salt and water in its redox flow batteries, which have a 20-year life cycle and a duration of four to 12 hours, according to the company’s website.

Another near-term option, Dresselhuys said, are lithium technologies that do not use cobalt or nickel, such as the lithium iron phosphate batteries that, according to Tesla, went into half of the EVs the company produced in the first quarter of the year.

Solid state or other technologies that “leapfrog lithium” could be a tougher sell, he said, depending on whether the cost of lithium falls, as it had before the COVID-19 pandemic, or sees more of the substantial increases of recent months.

‘Better at Technology’

At the same time, EPRI’s Shaw said, research into new battery chemistries could also provide an opportunity to “design for recycling.”

“We’re starting to think about the ability to disassemble, retrieve and retain high purity of a product from that recycled module at the end of its life at the point of design,” Shaw said. The challenge, she said, is “maintaining performance, cost and reliability against current standards for modules or improving that to retain market acceptance while continuing to reduce the mass of critical materials or increase the energy density of the module.”

Designing for recycling and similar circular economy concepts are becoming market differentiators and selling features for manufacturers and utilities, Shaw said.

But according to John Howes, principal at industry consulting firm Redland Energy Group, the biggest obstacle to building out a domestic supply chain may be lack of political will and urgency. He believes federal incentives, rather than federal mandates, may be the most effective way forward.

Dresselhuys agrees but believes the focus should be on technology, in particular “non-lithium, non-mining alternatives” and programs like the Department of Energy’s Advanced Research Projects Agency-Energy.

“We will not win the fight against China and other places if we try to out-mine them,” he said. “What we should do is continue to drive ARPA-E and other programs that are really helping to fund early-stage development for alternatives and then fund domestic manufacturing … because we’re really good at technology around here. I would argue we’re better at technology than we are at mining.”

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SEIA Predicts Severe Fallout from Commerce Probe of Solar Imports

The U.S. solar industry could lose nearly half its workforce — about 100,000 jobs — and planned installations will decline dramatically if the U.S. Commerce Department concludes that solar panels imported from four Asian countries are actually Chinese goods, the Solar Energy Industries Association (SEIA) said Tuesday.

The impact of the probe into solar panels from Cambodia, Malaysia, Thailand and Vietnam could cut the volume of solar installations forecasted to take place in 2022 and 2023 by 46%, resulting in a reduction of 24 GW of planned power, according to SEIA’s analysis of the sector. The decline could cause the U.S. to emit an additional 364 million metric tons of carbon by 2035 and jeopardize the clean energy goals of the Biden administration, the organization said in a release, as it also published the latest results.

The analysis is based on a survey of more than 700 industry companies. It provided a fresh reminder of the impact of the Commerce Department’s decision to launch an investigation March 25 into the origin of crystalline silicon photovoltaic cells imported from the four countries. The probe is scrutinizing whether the solar panels and related equipment are actually Chinese products shipped through those four countries to avoid anti-dumping and countervailing duties that would otherwise have to be paid by Chinese manufacturers. (See Solar Sector Braces for Tariff Probe Impact.)

The bleak picture offered by SEIA is the latest step in the organization’s aggressive effort to counter the investigation. On Wednesday, the effort included putting more than 50 senior solar executives on Capitol Hill to lobby government officials, an SEIA official told POLITICO.

SEIA and some solar developers say that the start of the investigation prompted manufacturers in the four countries to immediately reduce the volume of goods sent to the U.S., diverting them to other countries, out of fear that they would face retroactive U.S. tariff increases if the department concludes that circumvention took place. That has resulted in equipment shortages and delays, and price hikes, developers say.

NextEra Energy (NYSE:NEE), a major investor in wind and solar projects, told investors on an April 21 earnings call that 2.1 to 2.8 GW of the company’s solar and storage projects could be delayed until 2023 because suppliers are not shipping panels while they wait for the Commerce Department’s decision. After the statement, the company lost about 10% of its market value. (See NextEra Shares Tumble on Solar Supply Woes.)

CFO Kirk Crews said the company believes it will be “difficult” for the Commerce Department to conclude that solar panels from the four countries are circumventing tariffs, based on the department’s past analysis of the sector. For this and other reasons, the company is “optimistic” that the department will rule “favorably” and will not impose additional tariffs, he said.

“However, given that a number of suppliers are not expected to ship panels to the U.S. until the Commerce Department makes a preliminary determination as late as August, we continue to expect some of our solar and storage projects may be adversely impacted by this delay,” he said, according to a transcript of the earnings call published by Seeking Alpha.

In an earnings call Wednesday morning, Entergy (NYSE:ETR) CEO Leo Denault spoke of near-term cost and schedule pressures. “Supply chain constraints [are being] further exacerbated by the [investigation], which we expect will lead to further delays and cost increases. We are continuing to work through these constraints and are executing on our solar expansion plan.”

Future Hard Times

SEIA based its conclusions on the potential industry impact on a scenario in which the Commerce Department concludes that circumvention took place and places new tariffs of 50 to 250% on imports from the four countries.

“This case is destroying clean energy and needlessly taking down American businesses and workers in its wake,” said SEIA CEO Abigail Ross Hopper, who called the predicted job reduction “a monumental loss.”

“The Commerce Department is on track to wipe out nearly half of all solar jobs and force a surrender on the president’s climate goals,” she said.

Current Module Supply Status (SEIA) Content.jpgMore than 4/5 of survey respondents reported canceled or delayed procurement of solar panels. | SEIA

 

The survey found that 83% of respondents said that their “expected module supply has been delayed or canceled.” Slightly more than 50% of the respondents said they expect a “devastating negative impact” on their businesses from the investigation, and slightly less than 40% said they expect it to have a “severe negative impact.”

More than 200 respondents said that their “entire solar and storage workforce is at risk” because of the investigation, and 70% of respondents said that at least half of their solar and storage workforce was at risk. Eighty percent of respondents said that at least half of their current year solar pipeline is at risk.

SEIA said that even the domestic crystalline silicon module production sector had suffered from the investigation, because “nearly half of all cell imports came from the four target countries” in 2021. Cell imports have fallen since the probe began, the organization’s report said.

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DOE Plan Unlikely to Save Entergy’s Palisades Nuke

Entergy (NYSE:ETR) said during its first-quarter earnings call Wednesday that it remains on course to shut down its nuclear-powered Palisades plant in Michigan, despite the Department of Energy’s $6 billion program to prevent the early closure of nuclear generators. (See DOE Launches $6B Nuke Credit Program.)

“We’re supportive of the federal initiative to keep nuclear plants operating,” CEO Leo Denault told financial analysts. “However, we are five years into the Palisades shutdown process. There are significant technical and commercial hurdles. It’s a real heavy lift at the last hour.”

Denault said Entergy has not ordered additional fuel for Palisades Nuclear Generating Station, which is out of fuel and is scheduled to shut down at the end of May. The company has been preparing to shutter Palisades since 2017 and has not refueled the plant since 2020.

The Nuclear Regulatory Commission in December approved Entergy’s request to transfer Palisades, its nuclear trust fund and its spent fuel to Holtec Decommissioning International. The company said it will work with Holtec or any party interested in getting the Federal funding.

“This does not change our strategy. We are exiting the merchant nuclear business,” Denault said.

Shutting down nuclear plants “is just backwards,” Denault said, noting their importance in supporting the grid’s reliability and in decarbonization efforts.

New Orleans’ only Fortune 500 company reported earnings of $276 million ($1.36/share), down from 2021’s first-quarter earnings performance of $335 million ($1.66/share). Entergy said it is ahead of schedule for its 2022 objectives based on favorable weather and higher-than-expected retail sales in the quarter.

The company’s adjusted earnings of $269 million ($1.32/share) missed the Zacks Consensus Estimate of $1.38/share.

Denault said the company has 650 MW of renewable capacity in place, with another 625 MW of solar energy gaining regulatory approval and a further 725 MW of projects announced. Entergy also has 4 GW of requests for proposals out for bid, totaling more than half of its 11-GW renewable target through 2030.

Entergy’s share price closed at $120.68, a gain of 2 cents from its previous close and up from its $119.88 open.

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Western Utilities to Support SPP Market Development

Fifteen Western utilities plan to support SPP’s efforts to develop a regional day-ahead energy market so they can evaluate it against CAISO’s proposed day-ahead market, according to a joint letter provided to RTO Insider by one of the effort’s organizers.    

“Over the past several months, it has become increasingly clear that two leading options are forming for an integrated day-ahead and real-time organized market platform in the West,” the letter says. Those options are CAISO’s proposal to establish an extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM) and SPP’s planned Markets+ offering, which would include real-time and day-ahead components.

“Given the importance of a full day-ahead and real-time integrated market to the future of Western wholesale electricity markets, the Joint Entities believe that both options should be further advanced and subsequently evaluated before any commitment decision can be made,” the letter says. “Although each of us will decide on the best path forward for our customers, we believe the governance models and market design for both of these options must be sufficiently complete in order to enable each of us to make an informed decision.”

The letter says that to evaluate “two fully-formed alternatives,” the joint entities will commit to “support the further development” of the Markets+ effort by “dedicating key staff” to participate in the initiative over the next year and “working collaboratively with SPP and other stakeholders towards the design of a governance framework and conceptual market design proposal,” slated to be completed by the end of 2022.

SPP Footprint (SPP) Alt FI.jpgSPP plans a range of services in the Western Interconnection to compete with CAISO. | SPP

 

Two of the letter’s listed participants, Arizona Public Service and Powerex, already participate in the Markets+ design team.

The letter was sent to RTO Insider by Shawn Smith, managing director of energy resources at Chelan County Public Utility District in Washington.

In addition to APS, Chelan and Powerex, the joint entities listed in the letter include Avista Corp., Douglas County PUD, Eugene Water & Electric Board, Grant County PUD, NorthWestern Energy, NV Energy, Public Service Company of Colorado, Puget Sound Energy, Salt River Project, Snohomish PUD, Tacoma Power and Tucson Electric Power.

Arizona’s Salt River Project confirmed it is participating; other utilities contacted for this story did not respond.

In an email, Smith said the letter was provided to the 15 named entities on April 22 to distribute more widely to the Western electric industry as they see fit.   

Real-time transactions in the West account for 5% of the market, while day-ahead transactions make up 40% of all sales, Smith said in the email.

“This is an important decision,” he said. “The impacts to our utility may last decades. We want to see both markets developed to a point we can evaluate [them] before selecting which one is best for Chelan PUD customer-owners. This shouldn’t be a race of which option is developed first or attracts commitments first, but rather which option is better for our customers from a governance and market-design perspective.”

Chelan and at least 13 of the other joint entities are participants in the Western Power Pool’s Western Resource Adequacy Program (WRAP), which SPP is administering. Most of the joint entities also participate in the WEIM, although Chelan is not a member.

Arkansas-based SPP has been making inroads in the West lately, competing with CAISO to attract members to its real-time Western Energy Imbalance Service (WEIS) and proposing the Markets+ platform, a combination of services that stops short of full RTO membership. It also hopes to launch a Western version of its Eastern RTO, called RTO West.

SPP said April 12 that it plans to phase out the WEIS after the 14 active participants join either Markets+ or RTO West. (See SPP to Phase Out WEIS as New Market Offerings Expand.)

CAISO is planning to release an EDAM straw proposal April 28. It has fast-tracked the effort this year, trying to get a jump on SPP and draw many of its current and expected WEIM participants to the planned day-ahead market. The WEIM now has 17 participants with five more scheduled to join through 2023, eventually representing more than 80% of the West’s electric load.

CAISO cannot yet form a Western RTO because of its one-state governance, but it offers interstate market services through the WEIM and its reliability coordinator RC West, which serves 42 balancing authorities and transmission owners in the Western Interconnection.

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Connecticut Regulators Order ‘Immediate’ Phaseout of Gas Expansion Plan

The Connecticut Public Utilities Regulatory Authority on Wednesday ordered the “immediate winding down” of the state’s plan to bring new customers onto the natural gas system (21-08-24).

An investigation of the state’s gas system expansion plan (SEP) found that it “no longer furthers the state’s overall climate and energy goals” and its continuation “is no longer in the best interest of ratepayers,” the authority said.

As originally envisioned in 2013, the SEP’s purpose was to reduce energy bills amid high oil prices and help the state meet its greenhouse gas emissions reduction targets. Oil and gas prices, however, have equalized over the years, and the SEP’s projected 1.3% reduction in emissions “does not represent a significant factor toward achieving the Global Warming Solutions Act goals,” the order said.

Regulators also found that the state’s gas utilities have not met the customer conversion rates identified in the plan, making a ratepayer-subsidized program unjustified.

Chairman Marissa Gillett welcomed a Supreme Court appeal of the decision, should the gas utilities choose to file one, saying during PURA’s meeting that it would allow additional scrutiny of the companies’ conversion rates.

The SEP targeted bringing 280,000 Connecticut residents onto the gas system in 10 years, but the utilities have only met 32% of that goal, according to the order. Utilities adjusted their conversion projections down over the years, allowing them to report high conversion completions “while presumably masking the failure to achieve original projections,” the order said.

Intervenors in the SEP review proceedings asked PURA in February to consider opening a “future of gas” docket, but regulators determined that the state is already looking at the role of gas for its 2022 Comprehensive Energy Strategy. PURA added that it will consider opening a gas proceeding prior to the release of the strategy, if the right circumstances arise.

Under the order, the state’s gas utilities must stop enrolling new customers or extending SEP program incentives, unless customers have an existing contract. In addition, the companies must stop all program marketing.

In an April 6 written exception to PURA’s draft order on the SEP, Eversource Energy agreed that the “time is right” to wind down the program but asked for an equitable process that “respects the interests of customers who reasonably assumed that they had a longer time period to sign up for the SEP.” PURA did not grant Eversource’s request.

Penalty

PURA’s gas plan review sprang from a petition filed last summer by Attorney General William Tong calling for an investigation of Eversource marketing practices for SEP and “potentially deceptive marketing materials.”

After opening the investigation, PURA split the docket into two phases, allowing for one phase to look at Eversource’s marketing and a second to review all the gas companies’ SEP marketing and consider possible changes to the program.

PURA found that Eversource failed to include certain disclosures in its marketing materials and assessed a $1.8 million civil penalty.

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MISO Reassessing Hartburg-Sabine Project amid Texas ROFR Dispute

More than four years since it approved the project, MISO announced this week it will reanalyze the controversial Hartburg-Sabine Junction project in East Texas for a fresh look at its effectiveness.

Speaking at the Planning Advisory Committee’s meeting Wednesday, MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the project’s schedule delays and an “inability to construct” the line has triggered a variance analysis to consider if it is still necessary. He said MISO will re-evaluate the line’s benefit-to-cost ratio.

MISO said the planning analysis can have one of two outcomes: reassigning the project to Entergy Texas to comply with Texas state law or canceling the project because it’s no longer necessary.

The RTO included the 500-kV, $130 million Hartburg-Sabine Junction as a market efficiency project (MEP) in its 2017 Transmission Expansion Plan, selecting competitive developer NextEra Energy Transmission Midwest (NYSE:NEE) to construct most of the line. MISO expected the line to relieve congestion and provide access to lower-cost generation at a benefit-to cost ratio greater than 1.25:1.

In 2019, Texas passed a right-of-first-refusal law that allowed Entergy Texas (NYSE:ETI-P) to take over the construction of the line. The U.S. Department of Justice opposed Texas’ ROFR law as anticompetitive. NextEra filed a federal lawsuit, and the Hartburg-Sabine line remains in legal limbo with a pending appeal. Neither Entergy nor NextEra have broken ground. (See Uncertainty Deepens for Hartburg-Sabine Project.)

In 2020, Entergy issued a request for proposals for a 1.2-GW natural gas and hydrogen plant in Orange County to be in operation by 2025. The $1 billion power plant might nullify the need for the line, according to Southern Renewable Energy Association Executive Director Simon Mahan.

Based on information it receives, MISO still maintains an “on time” construction estimate for August 2023 in its quarterly project information. Stakeholders questioned the reasonableness of a 2023 in-service date given the line’s uncertain status.

Clean Grid Alliance’s Natalie McIntire asked if MISO will use its current transmission planning future scenarios — since updated to include more renewable energy, energy efficiency, electrification and decarbonization — to reassess the project.

Mahan asked whether MISO will factor Entergy’s future Texas plant into the restudy.

Pedersen said MISO will share the study scope and ensuing results at upcoming meetings of the South Technical Studies Task Force. The task force is set to meet May 11, June 8 and July 20.

Mahan also asked if a replacement project could emerge in MISO’s ongoing long-range transmission plan should Hartburg-Sabine Junction fall off as an MEP. The long-range study is set to evaluate MISO South needs in 2023.

Pedersen said an answer to that would be “speculation,” but “any project could show up.”

Hartburg-Sabine Junction is the first MEP that MISO has ever assigned to its South region.

MISO counsel Chris Supino said that should the RTO decide to cancel the project, it must go before FERC for approval.