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November 7, 2024

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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.

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Green Hydrogen Too Expensive to Replace Blue — for Now

U.S. industry produces and uses over 10 million tons of hydrogen a year, most of it “gray” hydrogen made from natural gas, spewing millions of tons of carbon dioxide into the atmosphere as part of the process.

In an all-of-government approach involving billions of dollars in research and new programs to fund technologies capturing that CO2, the Biden administration is aiming to convert gray hydrogen into so-called “blue” hydrogen. That would mark the first step in a shift away from fossil fuels and ultimately to producing “green” hydrogen through the electrolysis of water using only renewable power.

The goal, starting with heavy industry and trucking, is to cut overall U.S. CO2 emissions by 50% by 2030 while research, development and deployment of technologies to produce significant amounts of green hydrogen continues at breakneck speed.

Daniel Bresette, executive director of the DC-based Environmental and Energy Study Institute, moderated a discussion Wednesday focusing on the efforts needed to realize the administration’s goals — and the risks.

In brief remarks before the discussion, Sunita Satyapal, director of hydrogen and fuel cell technology at the U.S. Department of Energy, said federal research is heavy and ongoing.

“We have a DOE-wide strategic plan [that] you can see online. It includes multiple offices across the entire value chain, from production through end use, [including] renewables, nuclear, fossil with CCS [carbon capture and sequestration], from basic science all the way through deployments,” Satyapal said.

DOE is funding 400 active projects at over 200 companies and universities, 15 national labs, and ranging from $100 million to $400 million per year, she said. The agency’s top priorities are producing “low-cost clean hydrogen;” creating “low-cost, efficient — obviously safe” infrastructure, delivery and storage; and “enabling end use applications at scale.”

To illustrate the difficulty of producing hydrogen with electrolysis, Satyapal said producing 10 million tons of green hydrogen to match the amount of hydrogen now produced “would basically double today’s solar and wind” capacity, which also suggests the inefficiency of electrolysis as it exists today.

And it’s expensive.

“Today hydrogen is about $1.50 [per kilogram] from natural gas and over $5 from electrolysis,” she said. Other experts have put the cost of green hydrogen as much as twice that amount.

The administration is aiming to help industry develop electrolyzer technology capable of producing a kilogram of hydrogen for $1 by the end of this decade.

The research is occurring even as DOE has allocated $9.5 billion to develop regional hydrogen hubs to help industry produce more blue hydrogen by sequestering the resulting CO2 as well as electrolytic hydrogen.

During the discussion, Rachel Fakhry of the Natural Resources Defense Council argued that using electrolysis powered by today’s “fossil-heavy” grid to produce hydrogen could be even more polluting than using natural gas-based blue hydrogen.

She said “direct electrification” would be more efficient and argued that hydrogen as a combustion fuel is “generally inefficient.”

“A hydrogen fuel cell car will be less efficient than a battery electric car. Generally, a hydrogen boiler will be much less efficient than an electric heat pump, such that as a whole hydrogen pathway requires quite a lot of energy. And it’s quite inefficient when you have alternatives.

“We would need about five times more renewable electricity to heat a home with hydrogen than to heat that same home with a heat pump,” Fakhry said.

“And just imagine how much pressure on the energy system you would put by indiscriminately deploying hydrogen in applications that could be better served by direct electrification, and this will significantly complicate the task of decarbonizing our economy,” she said.

Fluctuating Prices

Alexa Thompson, an analyst with RMI, said the price of hydrogen made from natural gas is rapidly increasing at this time because the cost of the gas “has skyrocketed from the recent energy shocks caused by Russia’s invasion of Ukraine.” Quoting Bloomberg, she said the price of gray hydrogen in Europe last week had reached $6.70/kg.

“It’s unlikely though that the [$6.70] price will be permanent. But it does suggest that energy security and resiliency is another reason to favor green hydrogen production over blue,” Thompson said.

Thompson made a case for green hydrogen: “Today, the cost of green hydrogen is heavily dependent on the capital costs of both the electrolyzer and renewable energy. And both are expected to drop substantially, making those steep cost declines quite realistic.”

For example, electrolyzers that cost around $700/kW in electrical capacity today and are expected to drop to $200/kW in a few years. And because the price of renewable power varies by location, green hydrogen prices will also vary, she said.

As an example, she said green hydrogen prices in Texas, where wind power produces prodigious amounts of electricity, are about $3/kg, while prices in California are roughly $5.05/kg.

Thompson said the country needs a national clean hydrogen strategy. The billions allocated in the bipartisan infrastructure bill “are really a drop in the ocean compared to a market that could potentially be as large as $100 billion a year by 2030,” she said. To see that market develop, “we will need to see the commercial viability of green hydrogen.”

Bryan Pivovar, senior research fellow and manager at the National Renewable Energy Laboratory in Golden, Colo., heads a team working to that goal.

He said hydrogen has “unique attributes” in that it can function across different energy systems, adding that it has “the unique ability to be electrochemically converted efficiently, rather than having to be combusted.

“Hydrogen can act as a parallel infrastructure to electricity and natural gas and do a lot of the hardest sectors to decarbonize — transportation and industry,” he said.

NREL is leading a $50 million collaborative of industry, federal and academic researchers focusing on not only the technologies under development but also on how hydrogen will fit into the existing energy infrastructures, he said.

“Electrolysis specifically has the most competitive economics and basically allows you to balance the renewable generation challenges in ways that other hydrogen generation routes do not,” he said.

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Nev. Looks to Capitalize on Becoming Tx Crossroads

Nevada is poised to be at the center of a robust and interconnected transmission system in the Western U.S., but the state must move quickly, the chairman of a new task force said Tuesday.

Speed is necessary because of the extended time it takes to develop new transmission projects, said Nevada state Sen. Chris Brooks (D), who chairs the Regional Transmission Coordination Task Force. The group held its first meeting on April 26.

And Nevada faces competition from other states, Brooks noted.

“We are not alone in this,” Brooks said. “We are in a race with our neighboring states to really take full advantage of our position here in the West.”

During the 2021 session Brooks was the sponsor of Senate Bill 448, wide-ranging energy legislation that included creation of the task force. Gov. Steve Sisolak signed the bill into law in June and appointed the group’s members in December. (See Nevada Gov. Sisolak Appoints Regional Tx Task Force.)

SB 448 requires transmission providers in the state to join a regional transmission organization by Jan. 1, 2030, although providers may be able to receive a waiver of the deadline.

The task force’s work will complement that goal. The mission of the 21-member panel is to advise the governor and lawmakers on the potential costs and benefits of the state joining or forming an RTO.

The group will explore policies that would support the state entering an RTO by Jan. 1, 2030.

It will look at the siting of transmission facilities needed to reach the state’s clean energy and economic development goals.

And it will evaluate which businesses and industries could move to the state once it enters an organized, competitive regional wholesale electricity market.

The group will prepare a report to the Legislature, which is due by Nov. 30. Another meeting is scheduled on Oct. 12, and the group is expected to meet again after that to vote on a final report.

Brooks said there’s also an option for the task force to form working groups to tackle specific topics.

Member Perspectives

The group’s first meeting featured overviews of electric transmission and wholesale markets, and it also heard about Nevada’s existing transmission network and the status of projects in the pipeline.

Task force members introduced themselves and shared their perspectives on a regional transmission system.

Mona Tierney-Lloyd, head of U.S. policy for Enel North America, is the geothermal industry’s representative on the task force. Enel’s projects in Nevada include the Salt Wells geothermal plant and Stillwater, a combined solar and geothermal facility.

Tierney-Lloyd said Enel has “a very strong interest” in the creation of an RTO, which would deliver economic opportunity, boost system efficiency and increase reliability. It would also provide an avenue for developing demand-side technologies, she said. “Having a strong transmission grid is really the backbone for providing development of those resources.”

Kris Sanchez, deputy director of the Governor’s Office of Economic Development, said his office has been looking at how to ensure Nevada’s economic vitality coming out of the pandemic.

“One of the things that we recognized is that Nevada needed to start really investing in … looking at what we would need to make sure that the state was strong moving forward, and that we grow jobs in these critical industries like energy and transmission,” Sanchez said.

As a representative of the Bureau of Consumer Protection in the Office of the Attorney General, Consumer Advocate Ernest Figueroa said his goal is to maximize ratepayer benefits. Figueroa is a non-voting member of the task force.

Economic Benefits

Task force member Leslie Mujica, executive director of Las Vegas Power Professionals, a nonprofit focused on workforce development, represents the general public on the panel.

She said Nevada can become a leader in renewable energy and electrification.

“Most importantly … there are billions of dollars ready to be spent and invested in our state that will create not only high-paying jobs, but careers, long-term careers,” Mojica said.

John Seeliger, regional energy manager for Nevada Gold Mines, represents the mining industry on the task force. The mining industry is very energy-intensive, he said, and it’s looking at ways to decarbonize.

“We’re very interested in making sure we have a stable and robust transmission system,” Seeliger said.

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Dragos Warns Malware Developers Building Skills Fast

Staff at cybersecurity firm Dragos warned on Tuesday that the Pipedream malware they discovered this month represents “a threat that should be taken seriously,” with potential to disrupt industrial control systems (ICS) across a wide range of critical infrastructure sectors.

Dragos disclosed the Pipedream malware suite April 13, and the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Sam Hanson (Dragos) Content.jpgSam Hanson, Dragos | Dragos

The firm dubbed Pipedream’s developer “Chernovite,” in keeping with its policy of not attributing hacks to specific nation-states or other groups, and said it appears to be an “impact group” focused on conducting the actual cyberattack rather than gaining access to target networks. The group appears capable of operating in both information technology and operational technology networks, giving it “the potential for significant industry impact.”

In a webinar focused on the new malware, Dragos Vulnerability Analyst Sam Hanson emphasized that the Chernovite team appear to be “professionals [with] the resources on their side to improve their capabilities and industrial impact over time.” While there is no evidence Pipedream has been used in any attacks so far, its existing capabilities and the sophistication of its developers mean the danger is likely to rise over time.

Modular Structure Allows Wide Range of Targets

The version of Pipedream discovered this month targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.

However, presenters in Tuesday’s webinar warned that users should not assume they are safe because they don’t work with these two vendors. The modular nature of Pipedream means it can be easily modified to attack equipment from other manufacturers or different types of ICS hardware.

Rather than a single tool, Dragos’ researchers said Pipedream is more like a collection of utilities that an attacker “could package together or use individually.” Its many components — given code names by Dragos — include Evilscholar, which enables interaction with Schneider Electric controllers; Badomen, which interacts with Omron controllers; Mousehole, for OPC UA servers; Dusttunnel, a Microsoft Windows implant that facilitates remote interactive operations; and Lazycargo, which can be used to install an unsigned driver on a target device.

In a sample deployment scenario Dragos shared, an initial access group — likely separate from Chernovite — gains entry into an enterprise network, after which Chernovite uses Dusttunnel to establish a permanent foothold and move laterally into an OT network. Mousehole is then used to identify OPC UA servers and connected devices. The attacker can then use Evilscholar and Badomen to interact with the appropriate PLCs and disrupt the target’s operations.

Malware Teams’ Sophistication Growing

Jimmy Wylie (Dragos) Content.jpgJimmy Wylie, Dragos | Dragos

Jimmy Wylie, Dragos’ principal malware analyst, emphasized that the discovery of Pipedream’s capabilities does not mean it has been neutralized; the targeted hardware is used across the electricity, oil and gas sectors, and should be considered vulnerable without mitigating activities. Recommendations for Schneider Electric devices include changing default credentials and monitoring for new outbound connections; for Omron equipment, restricting access to certain ports and, where possible, restricting workstations from making outbound connections; and disabling OPC UA discovery to reduce the target’s “attack surface.”

In addition, Wylie warned that the new malware displayed a much greater level of sophistication than relatively “sloppy” tactics seen in the last decade, suggesting the pace of malware development is accelerating.

“This is an attack tool, and also a research utility,” Wylie said. “Pipedream combines the breadth of knowledge of Crashoverride” — the malware used to attack Ukraine’s power grid in 2017, also called Industroyer — “with the in-depth knowledge of protocols of Trisis,” which was used in a cyberattack against targets in the Middle East in 2017.

“In six years, we’ve gone from something that was sloppy and defective” — referring to Crashoverride — “to something that’s professionally made and easy to use,” he added.

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Emissions in PJM Rebound from Pandemic Lows

Carbon dioxide, nitrogen oxide and sulfur dioxide emission levels in PJM increased last year after the historic lows of 2020 during the height of the COVID-19 pandemic, according to a report released Tuesday by the RTO.

But emission rates did drop, in some cases sharply, compared to 2019 levels, continuing an overall decline since 2005, according to PJM’s annual Emission Rates Report, used by generators, state regulators and other stakeholders in planning for environmental objectives.

CO2 Emission Rates (PJM) Content.jpgMarginal carbon dioxide emission rates in PJM from 2017-present | PJM

 

The average CO2 emission rate for electric generators in PJM increased 6.6% from 2020 to 2021, going from 791 pounds/MWh to 843 pounds/MWh. That, however, was 1% lower than in 2019. The RTO attributed the increased levels last year to relaxed COVID-19 precautions and business and consumer activity returning to near pre-pandemic levels, with 2020 seeing historically low CO2 emission levels.

Since 2005, CO2 emission rates have fallen 35% across the RTO’s footprint. Emission rates for NOx and SO2 have decreased 85% and 94%, respectively, during the same period.

NOx emission rates increased 5.6% in 2021, but they were down 15.6% compared to 2019. SO2 rates increased 11.6% in 2021, but they were down 12.7% compared to 2019.

On average, combined cycle gas-fired generators accounted for 59.75% of the marginal unit — the resource that sets the LMP — time on the system In 2021. Combined cycle generators made up 64.33% of the marginal unit time in 2020.

Coal units were the second largest marginal unit in 2021, coming in at 14.15%, down from 17.53% in 2020. Wind units made up 11.04%, up from 6.75% in 2020.