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November 4, 2024

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Rhode Island Advocates Hold out Hope for Stalled Clean Energy Policies

Members of the public asked Rhode Island’s climate leaders Tuesday to elevate the policies of three stalled energy-related bills as priority actions for reducing the state’s greenhouse gas emissions.

They said that the policies, which support energy storage and renewable energy deployment, should be a part of the state’s next plan for emission reductions in the electric sector.

Top among the policy priorities was a 100% renewable energy standard (RES) bill (H.7277) that was introduced in February and held for study in March by the House Environment and Natural Resources (ENR) Committee.

Passing a 100% RES by 2030 would be “really helpful,” Greg Gerritt, former executive director of the Environment Council of Rhode Island, said during the Executive Climate Change Coordinating Council (EC4) listening session. Amy Moses, general counsel for Utilidata, echoed Gerritt’s comment, saying that the standard is “critical” for the state.

EC4 hosted the electric sector-focused event as part of a series of listening sessions this year that will inform a legislatively mandated update to the state’s 2016 GHG Emissions Reduction Plan. A 2020 executive order from former Rhode Island Gov. Gina Raimondo put the state on a path to achieving 100% renewable energy, but it has yet to be codified.

Under the existing state RES, 19% of retail electricity supply must come from renewable sources this year, and the state had reached 12% of supply in 2020, according to U.S. Energy Information Administration data.

The Rhode Island Office of Energy Resources (OER) completed a 100% renewable energy study last year that recommended advancing an RES-like mechanism along with enabling actions, such as integrated grid planning, strategic energy storage deployment and regional collaboration on wholesale markets.

Gov. Dan McKee supported the RES bill in March 10 testimony for an ENR bill hearing, saying that the state needs a “largely carbon-free electric generation portfolio” to reach net-zero emissions by 2050. While the bill also received broad support from environmental groups and residents during the hearing, the Northern Rhode Island Chamber of Commerce urged the committee to gather insights from ISO-NE before adopting a mandate to accelerate renewables on the electric grid.

ENR still has the option of considering the RES bill again before the end of the session in June.

Rooftop Solar Cap

Eliminating current size requirements for solar rooftop systems should be an RES-enabling policy in the EC4’s emission-reduction plan update, according to Hank Webster, senior policy advocate and Rhode Island director at Acadia Center.

“We would like to see incentives for prioritizing rooftop solar throughout the state and removal of the cap on rooftop solar,” he said.

The House Corporations Committee took testimony March 1 on a bill (H.7333) that would remove size limitations on net-metered systems, but the committee voted to hold it for study.

In hearing testimony, the Division of Public Utilities and Carriers said the current limit ensures that a rooftop system meets on-site energy needs and protects ratepayers from the costs of “overly large systems.” National Grid also opposed the bill in its testimony, saying that net metering should not make rooftop solar a “revenue stream” for building owners.

Homeowners, however, should have the option to build larger systems that complement neighborhood-level demand or support peak grid demand, Webster said.

Energy Storage

An energy storage bill that the Corporations Committee held for study April 12 represents another priority policy that Webster says should be in the GHG plan update.

The bill (H.8026) would set an energy storage capacity goal for the state of 500 MW by 2032 and direct OER to develop programs and associated funding mechanisms to advance system deployments.

Sunrun supported the bill in hearing testimony, saying energy storage has a “critical role” to play in building a 100% zero-carbon electric grid in the state. The Public Utilities Commission, however, said a legislatively mandated storage compensation program, as proposed in the bill, could be more expensive than current market-based solutions and warrants further study.

Webster said that the 2022 GHG plan, which is due in December, should support a pathway to understanding where energy storage resources are needed across the region and where they can feed the distribution system.

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FERC Tells PacifiCorp to Refund Premiums

FERC told PacifiCorp this week that it must repay premiums it earned on wholesale electricity sales during the August 2020 Western heat wave that forced CAISO to order rolling blackouts and pushed prices sky-high in other parts of the West (ER21-60).

PacifiCorp received premiums on top of the spot market’s average index prices at Arizona’s Palo Verde trading hub on Aug. 18-19, 2020, when CAISO was struggling to prevent more blackouts like those it ordered Aug. 14-15, and the Western grid was strained by record triple-digit temperatures. (CAISO Blames Blackouts on Inadequate Resources, CPUC.)

Palo Verde wholesale prices on the Intercontinental Exchange (ICE) reached a record $1,515/MWh on Aug. 18 and $1,750 on Aug. 19, according to data posted by the U.S. Energy Information Administration. (The average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas & Electric said in FERC filings.)

Prices outside CAISO in the West fall under the Western Electricity Coordinating Council’s (WECC) soft price cap of $1,000/MWh, which requires sellers to justify prices above the cap to FERC or to issue refunds. The process, instituted in response to the California energy crisis of 2000-01, is meant to avoid the exercise of market power.

Prices above the cap can be justified based on three frameworks — a production cost-based framework, an opportunity cost-based framework or an index-based framework — FERC said in guidance it issued in June 2021. (See FERC Offers Guidance on Exceeding Western Price Caps.)

FERC found that PacifiCorp had justified its prices on Aug. 18-19 using the index-based framework, in which a seller cites an index at a specific trading hub to justify prices that exceed WECC’s soft cap. But FERC said the utility had failed to justify premiums it received above the index prices.

PacifiCorp defended the premiums by arguing it had seven bilateral spot market sales in August 2020 that exceeded the $1,000/MWh price cap. Four were brokered day-ahead transactions, with the price set by the buyer based on the Palo Verde day-ahead ICE index, and three were “direct transactions with counterparties that contacted PacifiCorp,” the commission said.

“PacifiCorp [contended] that, to the extent the prices reflect a premium over the prevailing index price, the premium was set by the customer, and PacifiCorp had no visibility into the prevailing index price for these transactions until after the ICE day-ahead market closed,” FERC wrote. “PacifiCorp notes that it served as a price-taker, which it argues the commission has recognized addresses any concern about the legitimacy of price formation.”

The premiums, which raise the cost of wholesale electricity marginally above the index price, usually are added by customers to “secure energy during times of scarcity,” the utility said.

FERC rejected the argument that the adders were justified.

“The Palo Verde price index already reflects scarcity conditions,” it said. “PacifiCorp’s attempt to justify prices above the soft cap by arguing it was a price-taker is insufficient.”

“In these circumstances, the index-based framework only justifies prices up to the index price and … any premiums above the index must be justified in other ways, which PacifiCorp failed to do,” FERC said. “Accordingly, we find that PacifiCorp has not provided adequate justification for the premiums above the index price.”

The commission directed the utility to refund the premiums to buyers within 30 days and report back to the commission in another 30 days. The decision did not cite specific amounts of the premiums or the total amount that could be at stake.

Four of the five FERC commissioners signed the order.

Commissioner James Danly issued a dissent in which he said FERC was meddling with contracts to sell electricity at market-based rates.

“I would … not require PacifiCorp to pay refunds for the ‘premium’ amount above the price index that PacifiCorp and the willing buyers freely negotiated because no showing has been made that the public interest is seriously harmed by the contract rate,” Danly wrote.

With its decision, FERC was putting sellers in an unworkable position, he said. The commission requires wholesalers to sell electricity, or it will investigate them for withholding and market manipulation, but then it negates market-based prices, he said.

“The de facto result is that we require PacifiCorp to sell, and then we require them to sell at our preferred price,” Danly said. “No wonder there seems to be no end in sight to the supply shortage in California and, increasingly, the Western United States.”

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CISA Issues Fresh Russia Cyber Warnings

The U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) joined the FBI and National Security Agency — along with security agencies in the U.K., Australia, New Zealand and Canada — on Wednesday to release a report detailing the cyber threats against critical infrastructure that have been detected in connection with Russia’s invasion of Ukraine.

The report, “Russian State-Sponsored and Criminal Cyber Threats to Critical Infrastructure,” presented hostile cyber activities by a host of Russian government agencies, including the Federal Security Service (FSB), Foreign Intelligence Service (SVR), Main Intelligence Directorate (GRU) and Central Scientific Research Institute of Chemistry and Mechanics (TsNIIKhM). Attacks could come “as a response to the unprecedented economic costs imposed on Russia, as well as materiel support provided [to Ukraine] by the United States and U.S. allies and partners,” the report said.

Veteran Cyber Units Hard at Work

Each Russian agency has been linked to previous cyber incidents: Just last month the Justice Department announced it had indicted agents of TsNIIKhM and the FSB for a series of cyberattacks against the global energy industry. (See DOJ Reveals Indictments Against Russian Energy Hackers.) GRU’s Unit 74455 — which analysts have variously dubbed Sandworm, Electrum and Voodoo Bear — is believed to have carried out attacks around the world, including against the Winter Olympics in 2018 and the Ukrainian power grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)

Industroyer, another breed of malware linked to Unit 74455 that knocked out 20% of Ukrainian capital Kyiv’s power grid in 2016, was back in the news recently after Ukraine’s Computer Emergency Response Team reported discovering a very similar attack underway last week. Like the earlier threat, the new “Industroyer2” hack appeared designed to attack the industrial control systems used by electric utilities; however, in this case the attack was stopped before any damage could be done. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Along with these officially government-linked groups, the report identified two malicious actors as “aligned” with Russia but not definitely known to be employed by its government. The first, dubbed Gamaredon or Primitive Bear, has “targeted Ukrainian organizations since at least 2013,” including multiple operations before Russia’s invasion. The other, known as Venomous Bear or Turla, “is known for its unique use of hijacked satellite internet connections” to attack NATO-aligned governments, defense contractors and “other organizations of intelligence value.”

Nominally independent cybercrime groups are another growing threat, the report said, with some gangs pledging support for Russia’s government and threatening to “retaliate against perceived attacks against Russia or materiel support for Ukraine.” Among the groups identified by code name is Wizard Spider, responsible for the Conti ransomware that has targeted more than 1,000 organizations worldwide. Other groups historically have focused more narrowly on the Ukrainian government.

Cybercrime gangs tend not to have the direct support of Russia’s government, even when based in the country; rather, law enforcement often turns a blind eye to their activities as long as they are directed against Russia’s perceived adversaries. The agencies noted that even for the groups that have promised to support Russia’s war in Ukraine, their primary motivation and mode of attack are likely to remain financial rather than participating in government hacking operations.

Warnings Becoming More Urgent

CISA has been in a “Shields Up” posture since Russia’s invasion began in February, calling for critical infrastructure operators to be vigilant for potential cyber interference. Though the agency initially said it had seen “no specific or credible cyber threats to the U.S. homeland,” it and other federal entities — including the White House — have issued more pointed warnings as the conflict wears on and Russia’s military seemed increasingly unlikely to score a clear victory on the battlefield, making a cyber escalation more probable.

“We know that malicious cyber activity is part of the Russian playbook. We also know that the Russian government is exploring options for potential cyberattacks,” CISA Director Jen Easterly said in a release. “We urge all organizations to review the guidance in this advisory as well as visit [CISA’s website] for continually updated information on how to protect yourself and your business.”

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FERC Opens Probes on Western Transmission Rate Protocols

FERC on Thursday ordered show cause proceedings on the transmission formula rate protocols of five Western utilities, saying they do not appear to provide customers and regulators the ability to challenge rates resulting from the formulas.

The commission opened proceedings under Section 206 of the Federal Power Act on the formula rate protocols of PacifiCorp (EL22-38), Idaho Power (EL22-37), Puget Sound Energy (EL22-41), Public Service Company of New Mexico (EL22-40) and Public Service Company of Colorado (EL22-39) (NASDAQ: XEL).

The commission said the companies’ rate protocols did not meet the standards it has required since a 2012 order regarding MISO’s transmission owners.

Under formula rates, the commission does not require transmission owners to make FPA Section 205 filings to update their annual transmission revenue requirements. Instead the utilities update the input data in the formulas.

“Safeguards need to be in place to ensure that the input data is correct, that calculations are performed consistent with the formula, that the costs to be recovered in the formula rate are reasonable and were prudently incurred, and that the resulting rates are just and reasonable,” FERC said.

“Formula rate protocols provide the parties paying for transmission service specific procedures for notice of, review of, and challenges to the rates that they will be charged. In order to fulfill this purpose, formula rate protocols must afford adequate transparency to affected customers, state regulators or other interested parties, as well as provide mechanisms for resolving potential disputes.”

The commission’s orders Thursday found that each of the five utilities’ protocols fell short on one or more of the following:  “(1) the scope of participation (i.e., who can participate in the information exchange); (2) the transparency of the information exchange (i.e., what information is exchanged); and (3) the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

In the 2012 MISO order, the commission ruled that the MISO’s protocols inappropriately limited who could participate in the review processes and directed MISO and the transmission owners to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general (143 FERC ¶ 61,149).

Similarly, the commission said Thursday that PacifiCorp’s protocols do not define the term “interested party” to identify who is eligible to participate. “Without such a definition, PacifiCorp’s formula rate protocols may not provide sufficient clarity and may provide PacifiCorp with the discretion to determine who is an interested party, and therefore appear to be unjust and unreasonable,” the commission said.

In the Puget Sound order, the commission said the utility’s protocols regarding challenge procedures lacked “straightforward and defined procedures” or “the level of specificity required” in the MISO standard.

It ordered each of the utilities to respond within 60 days to either show cause as to why its protocols remain just and reasonable or explain what changes it will make to remedy the commission’s concerns.

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FERC Fines NY Hydro Operator $600K for Safety Violations

FERC on Thursday ordered the former operator of an upstate New York dam to pay $600,000 in civil penalties for failing to make needed repairs over six years and retain possession of all property needed to access the facility (P-9685-034).

Ampersand Cranberry Lake Hydro has 60 days to pay the fine for violating its hydroelectric license for the Cranberry Lake Project, located in St. Lawrence County, N.Y.

The project is owned by the Oswegatchie River-Cranberry Reservoir Regulating District Corp. (OR-CRRDC), a state municipal corporation. It includes a 57,400-acre-foot reservoir contained by dam that is 195 feet long and 19 feet high.

“The dam has a high hazard potential rating, which means that a failure of the project works would result in a probable loss of human life or economic or environmental losses,” FERC said.

Under FERC rules, hydro licensees are required to maintain property rights to their projects to provide access to the land associated with a dam in order to make repairs when necessary.

“In this particular case, Ampersand didn’t maintain those access rights. And thus, if something does go wrong or might go wrong, they don’t have the ability to access the site to make repairs that are necessary,” FERC Chairman Richard Glick said in a statement Thursday. “And this particular dam is classified as having a high hazard potential, so that’s something that we take very seriously.”

Thursday’s order follows an October 2021 commission issuance directing Ampersand Cranberry Lake to explain why it should not be assessed a civil penalty for violating its hydroelectric license and a November response by the company acknowledging that it failed to retain possession of all project property, in violation of its license. (See FERC Hits NY Hydro Plant for Delayed Repairs.)

FERC granted Ampersand Cranberry a license for the project in 2015 after the company promised to complete safety work related to the facility’s fuse plug spillway in the dam’s embankment and to raise the earthen embankment crest. The company notified the commission last July that it had agreed to terminate its lease and give up access rights to the project site to settle litigation with OR-CRRDC, which sued the company in 2019 over its failure to make rent payments.

FERC said the settlement came despite its repeated warnings that terminating the lease would violate the company’s license and would not relieve it of its responsibility to complete the outstanding work on the dam.

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MISO Stakeholders Insist on Consistency in Capacity Accreditations

Stakeholders told MISO Wednesday it should use a consistent capacity accreditation process for both its conventional and non-thermal generators.

The request comes as MISO is evaluating new accreditation options for non-thermal generation. The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during tight conditions. The new accreditation is contained in a larger filing to create four seasonal capacity auctions (ER22-495). (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

At the time, MISO elected to wait to propose a new accreditation for its other, intermittent generating units.

Now, MISO is evaluating three accreditation options for non-thermal resources:

  • Expanding its effective load carrying capability (ELCC) calculation, currently in use for wind generation, to include solar generation and other intermittent resources;
  • Using an availability-based accreditation based on generator performance during “resource adequacy hours” — tight margin and emergency periods — over four historical planning years. That accreditation style is pending before FERC for MISO’s conventional resources; or
  • Employing a blend of ELCC and an availability-based accreditation.  

The blended approach would have MISO identifying seasonal risky hours in addition to running a loss of load expectation (LOLE) analysis to identify possible shortfall events. MISO said it will “develop windows of risk for each season by combining resource adequacy hours and LOLE events.” Capacity credits would be issued based on generator performance during the combined risk periods.

Stakeholders attending an April 20 Resource Adequacy Subcommittee (RASC) teleconference said they want comparability across accreditation of thermal and non-thermal resources. They said if thermal resources are going to be valued based on their historical contributions during times of system need, non-thermal resources need to be as well.

WEC Energy Group’s Chris Plante questioned why MISO considers ELCC “good enough” for intermittent resources but not for conventional resources.

“Why are we making a distinction between intermittent and conventional resources when, at the end of the day, we’re trying to determine the same thing?” he asked.

“We don’t need to have apples-to-apples, but we at least need a fruit salad. We can’t be throwing onions in,” Clean Grid Alliance’s Natalie McIntire said.

MISO staff said they’re still considering accreditation designs. The RTO plans to hold a special workshop sometime in June and set a direction on a new accreditation in July. It said it will work on a design with stakeholders through the end of the year.

During the March RASC, McIntire encouraged MISO to pursue an entire rethink of its resource adequacy construct instead of developing a new capacity accreditation for intermittent resources. Other stakeholders have also asked MISO to assess the entirety of its resource adequacy construct.

MISO’s Scott Wright told stakeholders the accreditation redesign for non-thermal resources is only a piece of the reforms MISO envisions needing as the resource mix transitions away from centralized, baseload generation.

“This is not the end or a destination,” Wright said.

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New York TOs Again Defend Local Tx Project Rights

New York transmission owners on Wednesday again rejected challenges to their new public policy category of local transmission development for purposes of cost sharing and recovery (Case No. 20-E-0197).

The NYTOs, including state investor-owned utilities, the New York Power Authority (NYPA) and the Long Island Power Authority, told state regulators that LS Power, the Alliance for Clean Energy (ACE-NY), and New York City were mistaken in their concern with the NYTOs’ proposed cost sharing and recovery agreement (CSRA) for so-called phase 2 projects.

Phase 1 projects are traditional utility investments that address system reliability or resilience issues, while phase 2 projects are investments made primarily to satisfy requirements of the Climate Leadership and Community Protection Act (CLCPA).

The NYTOs in January had urged the Public Service Commission to reject LS Power’s argument that costs of local transmission can only be allocated under the NYISO tariff’s Order No. 1000 processes and that any regional cost allocation is preempted by FERC’s exclusive jurisdiction over transmission. (See New York TOs Defend New Public Policy Tx Category.)

This month, the NYTOs rejected LS Power’s insistence that phase 2 projects must go through NYISO’s public policy transmission planning process: “Transmission projects identified through each NYTO’s local planning process have never been subject to the NYISO PPTPP or its competitive solicitation process and are properly within each NYTO’s planning authority.”

Forcing project development through the ISO would only serve to address bulk power transmission facility needs, not local system capacity shortfalls, the NYTOs said.

Under Order No. 1000, regional transmission facilities are those that must be regionally planned, competitively selected and eligible for regional cost allocation.

ACE-NY and the City

ACE-NY asked the PSC to establish a cost containment mechanism for phase 2 projects, a request the NYTOs said should be rejected as being outside the scope of the proceeding.

The NYTOs said they balanced competing interests in developing a voluntary CSRA under the basic premise that incurred costs of projects approved by the commission would be recoverable.

Regulators will use the cost recovery mechanism for only those projects approved as meeting the statutory objectives under the CLCPA, including a pre-determined rate of return and capital structure, the NYTOs said. The CSRA, they added, does not provide for pre-approval of all project costs. In addition, the PSC and all interested parties reserve the right to contest project costs incurred by the sponsoring NYTO, and therefore it would be inappropriate to impose generic involuntary cost caps.

New York said it is concerned about inconsistency between the CSRA and the rate schedule, according to the city’s Feb. 8 comments in the proceeding. Regarding cost recovery for NYPA customers, the NYTOs contend that under the CSRA, NYPA “will be allocated costs of approved transmission projects in the same manner as other [load serving entities] under rate schedule 18,” and that the rate schedule does not apply to NYPA, the city noted in its comments.

The CSRA and rate schedule, however, are correct, according to the NYTOs.

A provision of the CSRA relating to NYPA as a load-serving entity “recognizes NYPA’s customers will be responsible for CSRA-related costs to the same extent as other end-use customers in New York served by a load serving entity,” the NYTOs said.

NYPA said it will not use the CSRA or accompanying rate schedule to recover the costs of its transmission projects for the following reasons:

  • NYPA does not have a retail service area or local transmission and distribution system and therefore, under the Accelerated Renewables Act, will not be developing phase 2 projects for inclusion in the utilities’ capital plans, and
  • NYPA uses the NYPA transmission adjustment charge, which already allocates those costs state-wide, to recover its transmission embedded costs.
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Washington Looks to Boost Prospects for Winning Hydrogen Hub

Washington officials are seeking to bolster the state’s case to land one of the nation’s federally funded hydrogen hubs.

Gov. Jay Inslee and Lisa Brown, director of the Washington Department of Commerce, have been working in recent months to coordinate the state’s activities in seeking a piece of an $8 billion U.S. Department of Energy fund to create regional hydrogen hubs to produce and distribute the fuel for industrial and transportation applications.

“This is a ruthless competition nationwide. It’ll be political malpractice not to leave everything on the field,” state Sen. Reuven Carlyle (D) said at the Future of Carbon Policy Forum held at Seattle’s Space Needle last week.

Speaking at the forum, Rep. Kim Schrier (D-Wash.) said roughly 80 proposals will likely be whittled down to four to eight regional hubs, translating into $1 billion to $2 billion for each.

On Feb. 24, Inslee sent a letter to dozens of state agencies, utilities and private companies saying that Washington stands a good chance to host one of the hubs, citing the state’s extensive efforts in in combating greenhouse gas emissions.

“Washington has the lowest carbon intensive grid in the United States. The opportunity to develop truly green hydrogen and understand how it fits into a modern decarbonized economy is possible today in the state of Washington. No other region is as advanced in this area,” Inslee wrote.

He pointed to several utilities and private companies in Washington that are already delving into hydrogen production reduction or use. These include Microsoft, Amazon, PACCAR — which is building hydrogen-fueled semi-trucks — and the Port of Tacoma and Douglas County Public Utility District, which are exploring manufacturing hydrogen. Washington State University and the Pacific Northwest National Laboratory are also conducting hydrogen-related research.

The Douglas County PUD is the farthest along, building a $25 million hydrogen plant expected to go online in late 2022 or early 2023. (See Wash. PUD Breaks Ground on Hydrogen Plant.)

In an interview with NetZero Insider, the PUD’s General Manager Gary Ivory said that while no contracts have yet been signed for the output from the plant, potential customers have expressed interest in more hydrogen than the planned facility would be able to produce. Douglas County has more land set aside to expand the operation after construction of the original plant is complete.

In an April 4 letter to the same organizations addressed by Inslee’s letter, Brown wrote that the state, utilities and private companies recently created the Pacific Northwest Hydrogen Association, which is expected to coordinate hub-related efforts starting in May. In its 2022 session, the state legislature allocated $2 million to those efforts.

Lawmakers this year also passed a bill (SB 5910) establishing the Office of Renewable Fuels within the Commerce Department to support the development of renewable fuel and electrolytic hydrogen projects. (See Green Hydrogen Bill Passes Wash. Legislature.)

In her letter, Brown noted that the legislature also recently expanded the responsibilities of the state’s Energy Facilities Site Evaluation Council, giving the agency siting authority over renewable fuel projects. Lawmakers also created tax breaks for renewable energy projects if they met specific labor hiring standards, Brown wrote.

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54 GWh EV Battery Plant Proposed for Lithium Valley

Controlled Thermal Resources, a company developing a geothermal energy and lithium production facility in Southern California, has a new potential partnership with a business that plans to build an EV battery factory nearby.

A newly launched company called Statevolt intends to build a 54 GWh EV battery factory in Imperial Valley, California, according to an announcement Tuesday from company founder Lars Carlstrom. Carlstrom is founder and CEO of Italvolt, a company that’s developing an EV battery factory in Italy.

Statevolt has signed a letter of intent with Controlled Thermal Resources (CTR) in which CTR will provide lithium and geothermal power from the company’s Hell’s Kitchen Lithium and Power project, which is now under development in Imperial Valley.

Statevolt said in a release that it’s performing due diligence to find the best site for its Imperial Valley battery factory. The factory will be one of the largest in North America, the company said, with a production capacity of 54 GWh, enough for about 650,000 electric vehicles a year at full capacity.

The project is expected to cost around $4 billion. The announcement didn’t include details on project financing.

A CTR spokeswoman said Statevolt expects to start producing lithium-ion batteries at scale by 2025. She said there are no further details on lithium or power offtake at this time.

Lithium from Brine

California’s Imperial Valley is home to the Salton Sea Geothermal Field, where a number of geothermal power stations are located.

The area is also a rich source of lithium, which is in growing demand as a component of electric vehicle batteries. CTR plans to extract lithium from the geothermal brine it uses to produce renewable energy.

CTR announced in November that it had started drilling wells at the Hell’s Kitchen site. CEO Rod Colwell said at the time that CTR was on track to deliver the project’s first 50 MW of baseload renewable power in late 2023 and an estimated 20,000 tons of lithium hydroxide in 2024.

In July, General Motors (NYSE: GM) announced it will invest millions of dollars in CTR’s lithium production project, a deal that will give GM first rights to lithium produced in the first stage of the Hell’s Kitchen project. (See GM Invests Big in Calif. ‘Near Zero’ Lithium Project.)

‘Hyper-local’ Model

At Statevolt, Carlstrom described the planned partnership with CTR as a “hyper-local” sustainable business model, in which lithium and power come from local sources. The approach minimizes the environmental impact of battery production and produces a more secure supply chain, he said.

“We believe this model will offer Statevolt a significant advantage in producing lithium-ion batteries at scale, to meet booming consumer demand,” Carlstrom said in a statement.

Carlstrom’s other company, Italvolt, announced in September that it had signed a binding agreement to buy land in the municipality of Scarmagno, Italy for a 45 GWh lithium-ion battery factory.

The company said it expects to obtain building permits and start construction in the second half of this year.

Carlstrom also co-founded Britishvolt, a company aiming to build a battery factory in England. He stepped down as company chairman in late 2020 after details emerged of his tax fraud conviction in Sweden more than 20 years previously, according to news reports.

Carlstrom said at the time that he didn’t want to be a “distraction” for the company and that he had planned all along to pass on Britishvolt’s chairmanship.

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DOE Wants 60 GW of Dispatchable Geothermal Power on US Grid

The U.S. Department of Energy wants geothermal energy to provide 60 GW of firm, flexible clean energy to the U.S. grid by 2050, and it’s putting up $84 million from the Infrastructure Investment and Jobs Act (IIJA) to develop a range of nontraditional, “enhanced” geothermal systems (EGS), according to a request for information (RFI) released Tuesday.

Hitting that target would mean a 26-fold increase in the geothermal generation online in the U.S. today, DOE said.

“The U.S. has incredible, untapped geothermal potential beneath our very feet, which can be harnessed to meet our energy demands with a round-the-clock, clean renewable resource available across the country,” Energy Secretary Jennifer Granholm said in Tuesday’s announcement of the RFI. The funds from the IIJA will help “incentivize access to that resource nationwide while helping fossil communities and workers leverage existing infrastructure and skills to seamlessly transition to producing clean energy.”

The IIJA calls for the funds to be used to “demonstrate EGS in different geological settings, using a variety of development techniques and well orientations, at sites where subsurface characterization or geothermal energy integration analysis has been conducted,” the RFI says.

Following those provisions, DOE lays out four specific types of EGS projects it is looking to fund:

  • a “proximal” demonstration that is located near an existing geothermal project and uses existing infrastructure (one to four awards, of $5 million to $15 million each);
  • a “greenfield” demo on a site “with no existing geothermal development” and the potential for tapping geothermal resources closer to Earth’s surface (one to three awards of $5 million to $25 million each);
  • a super-hot, supercritical EGS project drilling potentially several miles into the ground to tap into high-pressure water over 700 degrees Fahrenheit (one to two awards of $5 million to $25 million each); and
  • an East Coast EGS project located at a site with existing wells, such as old oil or gas drilling sites (one award of $5 million to $9 million).

All the projects would have immediate or near-term potential to produce electricity or heat. The RFI envisions having an open application process for the funds, with rolling submissions stretching out over two years, and project reviews every six months.

It also asks stakeholders — developers, researchers, tribes, and community and labor groups — to provide feedback on how federal funding can have the greatest impact on covering upfront development costs, building out an inclusive workforce, and benefiting low-income and disadvantaged communities.

Two questions also focus in on supply chain issues, asking what incentives or programs might be needed to “encourage and foster U.S. manufacturing” and what key construction materials — such as iron, steel or other manufactured goods — might not be available domestically.

The RFI also notes that under federal regulations, the applicants for the DOE funding would have to match the amount of the grant, for a 50/50 split. However, DOE is hoping to reset that equation, with the department picking up 80% and awardees providing 20%, in recognition of the cost and complexity of the projects.

The deadline for responding to the RFI is May 13.

500,000 MW

The U.S. is the world leader in geothermal energy, but the country’s 93 geothermal plants located in seven Western states account for only 0.4% of national power generation, according to the Energy Information Administration.

At the same time, as Granholm stressed, geothermal represents a huge potential source of clean, dispatchable power that could balance the U.S. grid as more variable renewable energy projects come online. The U.S. Geological Survey estimates that more than 500,000 MW of EGS resources are available in the Western — about half of the current installed electric power generating capacity in the U.S.

The challenge that the DOE funding hopes to unlock is how to access those resources. While traditional geothermal produces energy by drilling into the ground to tap superheated geothermal brine through existing fractures or permeability in subsurface rock, “enhanced” geothermal uses engineered, manmade systems to tap into reservoirs located below rocks with “limited permeability,” said Lauren Boyd, DOE’s EGS program manager.

Speaking at a March webinar on DOE’s geothermal program plan for 2022-2026, Boyd said EGS requires specialized materials and tools that can be used in “very high temperature, very caustic environments. Commercializing EGS requires the manipulation of the subsurface in these environments; and so, we have the challenge of not only repeatedly controlling and enhancing permeability in general, but just doing that also at super high temperatures and depth, in corrosive environments.”