‘Monumental Progress’ for OSW in New York in 2022

Wind power development off the coast of the Northeast U.S. continued to advance in 2022.

Extensive progress outweighed setbacks that arose, as construction on the first projects began or continued and several additional gigawatts of offshore wind (OSW) inched through various stages of the planning and approval process.

On the other side of the ledger, a developer moved to cancel agreements it said were no longer viable for a 1,200-MW wind farm off the Massachusetts coast, although it said it remained interested in developing the project under other terms.

On the whole, particularly in New York, it was a “banner year” that saw “monumental progress,” said Fred Zalcman, director of the industry group New York Offshore Wind Alliance.

“Looking forward to 2023, New York needs to build on this fantastic progress by awarding new contracts, with associated economic development, that will allow New York to achieve its 9-GW target,” Zalcman said in a December news release.

He also flagged one of the chokepoints that faces New York’s leaders in their efforts to decarbonize the state: moving all those new kilowatts from generator to consumer.

“New York also needs to make some key and timely decisions on transmission investments to facilitate the significant levels of offshore wind energy that we will need beyond the 9 GW,” Zalcman said.

Here are some of the larger developments in 2022.

New York

Winning bids totaling a record $4.37 billion were submitted in a February auction of federal lease rights to six tracts totaling 488,000 acres in the New York Bight.

The 130-MW South Fork Wind became the state’s first and the nation’s second large-scale OSW project to begin construction.

The state in July opened its third OSW solicitation, this one for at least 2 GW installed capacity, on its way to a self-imposed target of 9 GW capacity by 2035.

New York laid the groundwork for the physical and human infrastructure — factories, ports and career training — needed to support all this activity and allocated $500 million in funding for it.

Nearly a year of negotiations over plans for the 924-MW Sunrise Wind resolved a dispute over its potential effect on fishers. (It is an issue that may arise elsewhere: the U.S. Bureau of Ocean Energy Management has warned of potentially significant impact on commercial and for-hire recreational fisheries from other OSW projects in the New York Bight.)

BOEM and the National Oceanic and Atmospheric Administration completed a draft strategy to protect the endangered North Atlantic right whale from OSW development efforts.

Massachusetts

In August, Massachusetts Gov. Charlie Baker signed into law “An Act Driving Clean Energy and Offshore Wind,” codifying the goal of 5.6 GW of OSW nameplate generation capacity in Massachusetts by mid-2027.

Work continued on the 800-MW Vineyard Wind, which in late 2021 became the first large-scale OSW project in the nation to start construction. 

The state in late December announced $180 million in funding to build up port infrastructure to support OSW projects.

Developers of the Commonwealth Wind and Mayflower Wind offshore projects said in October that the terms of the deals they had negotiated to sell the power from their planned wind farms were no longer tenable because of rising costs.

In December, Commonwealth moved to cancel those agreements but said it would rebid the 1.2-GW project if it was offered as part of a 2023 OSW solicitation by the state. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.) Mayflower Wind, which would provide 400 GW under the contracts in question, remained in development but the company would not comment on its plans.

Rhode Island

Rhode Island — home to the 30-MW Block Island Offshore Wind Farm, the first commercial OSW project in the U.S. — requested proposals for 600 to 1,000 MW of additional OSW.

Already in development is the 700-GW Revolution Wind, which is projected to go online in 2025 with 400 GW of power for Rhode Island and 300 GW for Connecticut.

Connecticut

In October, Avangrid pushed back by one year the target completion date of its 800-MW Park City Wind, which sits off the Massachusetts coast but will feed Connecticut’s grid. The developer said it hopes advances in technology in that year will allow it to extract more power from each turbine and improve the economics of the project. (Avangrid also pushed back Commonwealth Wind in Massachusetts for one year for the same reason.)

Maine

BOEM in August issued a Request for Interest in commercial OSW in the Gulf of Maine and received responses from five qualified developers.

Also in August, BOEM invited proposals for floating OSW turbine research in the Gulf of Maine.

New Jersey

In September, New Jersey kicked its OSW goal from 7.5 GW to 11 GW by 2040, the most of any state on the East Coast.

Three wind farms proposals totaling 3.7 GW are in some stage of review, and a port to support the projects is under construction in southwest New Jersey.

January 2, 2023October 25, 2023

CARB Eyes Another Busy Year for Climate Policy

The California Air Resources Board had a big year in 2022, adopting the Advanced Clean Cars II regulation, which bans the sale of most gas-powered cars starting in 2035.

It also approved a climate change scoping plan that sets a course for the state to reach carbon neutrality by 2045. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035; CARB Approves Plan to Reach Net Zero by 2045.)

CARB will have another busy year in 2023.

The agency is expected to approve an Advanced Clean Fleets (ACF) regulation aimed at accelerating the transition to zero-emission medium and heavy-duty trucks. The regulation’s goal is to achieve a zero-emission truck and bus fleet in California “where feasible” by 2045 and much sooner for some vehicles such as last-mile delivery and drayage trucks.

The CARB board held a hearing in October on the proposed ACF regulation, which is expected to return for final approval in early 2023.

CARB is also re-examining its low-carbon fuel standard (LCFS) with an eye toward increasing the stringency of carbon-intensity targets for 2030. The regulation sets carbon intensity benchmarks for transportation fuels, which decrease over time. Fuels with a carbon intensity less than the benchmark generate credits that can be purchased by providers of fuels that have a carbon intensity above the benchmark.

The potential increased stringency of LCFS is important as CARB’s new scoping plan sets a target of reducing GHG emissions to 48% below 1990 levels by 2030. That exceeds a statutory goal of a 40% emissions reduction by 2030.

CARB held several workshops in 2022 to discuss potential changes to LCFS. Those discussions will continue in 2023.

Also in 2023, CARB will continue working on a strategy to achieve net-zero emissions for cement used within California by 2045. The strategy, which is due by July 1, is a requirement of Senate Bill 596 passed in 2021.

And last year’s SB 905 requires CARB to establish a program to evaluate the safety and viability of carbon capture, utilization and storage technologies. Work on the program will start this year.

CARB Executive Officer Steven Cliff is expected to outline the agency’s priorities for 2023 during the January board meeting.

Another issue CARB will tackle in the new year is how the Environmental Justice Advisory Committee can continue on an ongoing basis. The EJAC was convened in 2021 to work on the 2022 scoping plan. EJAC members represent communities most heavily impacted by air pollution, including low-income or minority populations.

In the past, the EJAC’s work ended with completion of the scoping plan. But CARB Chair Liane Randolph has committed to keeping the EJAC going so the panel can advise the agency on scoping plan implementation.

CARB staff have proposed an ongoing EJAC with 11 members that would meet twice quarterly. During development of the 2022 scoping plan, the EJAC had as many as 21 members and often met two days a month. CARB staff said it’s been tough keeping up with the work required for that schedule.

But during the committee’s Nov. 30 meeting, EJAC member John Kevin Jefferson said the group will have even more work to do as the scoping plan is implemented. He suggested that CARB assign more staff to work with the committee.

“The pace needs to actually increase as opposed to decrease,” Jefferson said. “There’s a lot of work to do.”

January 2, 2023June 14, 2023

SPP Makes Moves Out of the Southwest

SPP continues to make a misnomer out of its name. The Southwest Power Pool? Really?

In October, it added Canadian utility SaskPower as its first international member.

And this July, SPP’s board, state regulators and members will gather in St. Paul, Minn., for their quarterly meetings. After all, who wants to meet in Minnesota in January?

And of course, the grid operator continues to expand its beachhead in the Western Interconnection along several different fronts.

Focusing on the RTO’s stakeholder-driven culture as a counterweight to CAISO’s market buildout efforts, staff worked closely with potential Western stakeholders to finalize its Markets+ service offering. The document lays out the market’s governance structure and resource adequacy requirements that will, as SPP says, “ensure Western customers get the products and services they need at affordable rates they help control.” (See Governance, Resource Adequacy Key to SPP’s Markets+.)

“Without you at the table, we simply cannot develop the market the West wants: one that will serve Western needs with the governance that you value so much,” CEO Barbara Sugg told Western stakeholders in a holiday email.

The grid operator says Markets+ is a conceptual bundle of services that would centralize day-ahead and real-time unit commitment and dispatch, deploy hurdle-free transmission service across its footprint and reliably integrate renewable generation for utilities that aren’t yet ready to pursue full RTO membership.

Several Western organizations have already committed to funding the first development phase of Markets+ that establishes market rules and tariff language. SPP will engage through March with those utilities that have committed to funding Phase 1; staff have projected that will cost $9.7 million and take about 21 months.

Phase 2 will include the day-ahead market’s development. Based on SPP’s experience in building the Integrated Marketplace, staff has estimated the second phase will take three years and about $130 million to complete. Staff is assuming the market will be about a 50-GW system with up to 30 balancing authorities and 90 market participants.

Sugg said SPP has also seen a “growing interest” in full-scale RTO services. Seven participants in SPP’s Western Energy Imbalance Service (WEIS) market, which the grid operator has been administering on a contract basis since February 2021, have signed onto a plan to form a Western RTO — dubbed RTO West.

SPP’s legacy RTO footprint and its western market services | SPP

Western stakeholders are currently developing the RTO’s terms, with a review scheduled to wrap up by March. It would then take another two or three years to integrate those utilities into the system. The WEIS market will also welcome Xcel Energy-Colorado, among others, in April.

A Brattle Group study for the grid operator found that a Western RTO would produce approximately $49 million in savings annually for SPP’s current and new members. The Western utilities would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s Eastern Interconnection members would benefit from $24 million in savings resulting from the expansion of the RTO’s market, transmission network and generation fleet.

SPP is also exploring a Markets+ transitional real-time balancing market, similar to the WEIS, that would launch in June 2024. A day-ahead balancing market would be developed at the same time and launch as soon as possible.

“Markets+ won’t exist in isolation,” Sugg said. “We certainly see opportunities to improve energy coordination within the East today, and we know California is a valuable trade partner in the West. Markets+ can optimize and improve the value of energy trading through carefully negotiated terms of coordination between peers across these seams.”

SPP will form a Markets+ seams committee early this year and will work closely with stakeholders to facilitate and advocate for seams coordination “that results in fair, equitable and value-added outcomes, Sugg said.

Already a NERC-certified reliability coordinator for 16 Western utilities, SPP will also provide program operator services for the Western Power Pool’s Western Resource Adequacy Program when it receives FERC approval. (See FERC IDs Deficiencies in Western RA Program.)

Meanwhile, in the East…

Sugg said SPP is well on its way to achieving many of its Aspire 2026 Strategic Plan initiatives, beyond expanding its service offerings in the West. It continues to improve and consolidate its transmission planning process, reduce the backlog in its interconnection queue, and define the grid of the future.

What the RTO was unable to do was find mutually beneficial interregional projects on its MISO seams. The grid operators’ staffs said in December they will not pursue any small projects that will relieve constrained flowgates. It was the fifth time the RTOs have come up empty after four fruitless joint studies last decade. (See MISO, SPP Unable to Find Smaller Joint Tx Projects.)

In the meantime, demand continues to grow. Staff said increased load assumptions could result in an almost $7 million over-recovery for the year. As it was, SPP set new records for summer and winter peak demand (53.2 GW on July 19 and 47.1 GW on Dec. 22). The highs were 4.2% and 7.9% increases over previous records.

Non-standard loads such as crypto miners, data centers, biofuel and alternative fuel manufacturers, and cannabis grow houses account for much of the growth. SPP said that, since June, it had received more than 7 GW of interconnection requests for the firm and non-firm load, some of which would be behind the meter.

Staff will begin the year attempting to secure approval of a mitigation strategy for load-responsible entities unable to meet the new 15% planning reserve margin (PRM). They could reduce the deficiency payment charge, extend the timeline to cure deficiencies or add mechanisms to assure capacity and make failure to meet the requirements “less costly or less punitive.”

The SPP board raised the PRM from 12% to 15%, effective Jan. 1. That left some members complaining they wouldn’t have enough time to meet the requirements. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

January 2, 2023June 14, 2023

NM Rings in New Year with Reconfigured Utility Commission

New Mexico Gov. Michelle Lujan Grisham has appointed three members to the state’s revamped Public Regulation Commission, a panel that up until late December had five elected members.

The new PRC members are Gabriel Aguilera, Brian Moore and Patrick O’Connell. The appointments were effective Jan. 1.

The switch from a five-member elected PRC to a three-member appointed commission is the result of a change to the state constitution proposed by the legislature and ratified by voters in 2020.

The governor chose the new commissioners from a pool of nine candidates selected by a seven-member nominating committee.

Gabriel Aguilera | NIPCC

Aguilera had worked for FERC since 2007, most recently serving as senior policy adviser in the commission’s Office of Energy Market Regulation Western region. He was appointed to a four-year term.

Moore served in the state House of Representatives from 2001 to 2008 representing eastern New Mexico. He served on the state’s Renewable Energy Transmission Authority Board and the governor’s Economic Recovery Council. Moore, who is president and CEO of Ranch Market supermarket in Clayton, was appointed to a two-year term.

O’Connell was the Clean Energy Program interim director at Western Resource Advocates. He worked for Public Service Company of New Mexico, New Mexico Gas Co. and the Sangre de Cristo Water Co. He was appointed to a six-year term.

Brian Moore | New Mexico Legislature

“These appointees are experienced professionals who have the skills needed to oversee an energy transition that is affordable, effective and equitable for every New Mexico community,” Lujan Grisham said in announcing the appointments on Dec. 30.

The PRC Nominating Committee accepted applications for the PRC positions through the end of September. The committee chose 15 applicants to interview. During a Dec. 2 meeting, the committee voted to forward nine of those names to the governor for consideration.

In addition to Aguilera, Moore and O’Connell, the nominating committee’s list included James Ellison, principal grid analyst at Sandia National Laboratories; Carolyn Glick, a former PRC hearing examiner; Joseph Little, the former general counsel to the Pueblo of Zia; Art O’Donnell, a former senior analyst with the CPUC; law professor Amy Stein; and Cholla Koury, chief deputy in the New Mexico Attorney General’s Office.

Since its formation in 1996, the PRC consisted of five elected members representing different regions of the state. With the change to a three-member appointed PRC, Native American advocacy groups say indigenous people are losing their voice on the PRC.

Pat OConnell (Western Resource Advocates) Content.jpg

Patrick O’Connell | Western Resource Advocates

“For our voice to be eliminated in this way is unjust,” Krystal Curley, executive director of Indigenous Lifeways, told the nominating committee on Dec. 2.

Indigenous Lifeways and two other groups — Three Sisters Collective and the New Mexico Social Justice Equity Institute — filed a petition with the New Mexico Supreme Court in September to overturn the change, saying the ballot language was misleading and voters weren’t aware they would lose the ability to elect commissioners. But after hearing arguments in the case, the court rejected the petition in November.

In announcing the PRC appointments last week, Lujan Grisham acknowledged concerns about a potential lack of Native American representation on the commission.

To address those concerns, the governor signed an executive order on Dec. 30 creating a Tribal Advisory Council to advise the PRC. Lujan Grisham will appoint the advisory council’s first set of four members by Jan. 30.

“It’s extremely important that we ensure tribal voices are heard on issues before the PRC, regardless of who is appointed to the commission now and into the future,” the governor said.

December 22, 2022

FERC Rejects Sale of AEP’s Kentucky Operations to Liberty

FERC last week rejected the sale of American Electric Power’s (NASDAQ:AEP) Kentucky operations to Algonquin Power & Utilities (NYSE:AQN) subsidiary Liberty Utilities, ruling that the companies failed to prove that the transaction would not adversely affect rates (EC22-26).

Under the agreement filed with FERC a year ago, and amended in October, AEP would sell Kentucky Power — a vertically integrated utility with 1,075 MW of generation — and Kentucky Transco to Liberty for $2.646 billion. (See AEP Accepts Lower Price for Kentucky Operations Sale.)

But the commission found that the companies’ commitment to hold customers harmless for all “transaction-related costs” for five years was not sufficient to demonstrate that the sale would not have an adverse impact. The application notes that the pledge is not a rate freeze and that Liberty would be able to seek rate changes to reflect their full costs of service.

The commission said that an “increase in rates that results from a transaction is not the equivalent of a transaction-related cost” and suggested that the applicants could have included a projection of the impact to rates following the sale.

“Applicants’ representations do not provide complete information upon which to evaluate the effect of the proposed transaction on rates,” the commission said. “To support their position, applicants could have, for example, included a comparison of rates currently in effect to a projection of rates once the proposed transaction is consummated.”

Both the Kentucky Public Service Commission and a group consisting of American Municipal Power, Blue Ridge Power Agency and Wabash Valley Power Association filed protests arguing that the application did not contain enough information to show that ratepayers would not be negatively impacted by the transaction.

The PSC itself gave its approval of the transaction in May, though it stipulated numerous conditions to protect consumers. (See PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities.)

The cooperative group argued that Liberty should be required to maintain the companies’ current return on equity of 9.85% and the maximum permitted equity component of capital structure of 55%. It also pushed for Liberty to be required to show customer benefits to justify any rate increases during the five-year hold-harmless period and for that pledge to include any cost of debt.

“Applicants further state that, to the extent such costs change as a result of the change of ownership, those changes will not impact customers through the end of 2022 and will be addressed in 2023 and in the future through the formula rate projection and true-up process in the normal course,” FERC said.

The commission dismissed the application without prejudice, meaning the companies are free to file a new application “that provides adequate information” on its effects on rates.

“If the effect of the proposed transaction on rates is adverse, applicants should propose adequate ratepayer protection or mitigation to address that adverse effect, or otherwise demonstrate specific benefits due to the proposed transaction that offset such effect,” FERC said.

Danly Concurs, but with Criticism of Commission

Though he concurred with the decision, Commissioner James Danly criticized the time FERC took to rule on the deal and for not requesting additional data or changes to mitigate any rate effects. The companies initially filed the application for the transaction in December 2021; on June 3 they requested that the commission authorize the transaction no later than June 21 to allow the deal to close on schedule in mid-2022.

“Instead, having waited six months to reach the same conclusion we had come to before — that we did not have enough information — we have merely impeded the actions that the applicants could have taken to move ahead with the proposed transaction, such as filing a new application with needed information, perhaps after consultation with commission staff,” he said.

Had the commission sought additional information, Danly said, it may have been possible to receive a satisfactory rate commitment within a few months. By requiring the companies to file a new application, the commission made it difficult for companies and investors to make business decisions, he said.

“It is nearly impossible to rationally allocate capital and conduct business responsibly when it is unclear who will own that business or when the decision regarding the disposition of jurisdictional assets will be made. When we delay these decisions, employees and leadership of both entities live under a cloud of uncertainty. Shareholders are unable to properly determine the value of their shares,” he said.

Phillips also Concurs

Commissioner Willie Phillips also issued a concurrence, saying that he would have preferred a conditional approval of the application. He noted the commission has rarely denied similar applications and has instead granted conditional authorization with market power mitigation measures.

“I recognize those cases may be distinguishable in certain respects but would have preferred to have taken that approach here by providing joint applicants with clear guidance on possible mitigation strategies such as a hold-harmless commitment on rates, not just transaction costs, or a rate freeze that assures the commission that transmission customers will not feel adverse effects from this transaction,” he wrote.

December 22, 2022December 14, 2023

Supporters See Strong Potential in SW Hydrogen Hub

Energy leaders in Arizona and Nevada have partnered on a clean hydrogen hub proposal, with advocates saying the states’ proximity to California, their copper and lithium mining, and the presence of salt caverns make them a good candidate for federal funding.

The Center for an Arizona Carbon-Neutral Economy at Arizona State University is collaborating with partners including the Nevada Governor’s Office of Energy and the Navajo Nation on the hub, called the Southwest Clean Hydrogen Innovation Network (SHINe).

SHINe submitted a concept paper to the U.S. Department of Energy in November seeking $1 billion in federal funding through the agency’s $7 billion clean hydrogen hub program, according to Ellen Stechel, executive director of the Center for an Arizona Carbon-Neutral Economy. DOE is planning to fund six to 10 hydrogen hubs.

Applicants now expect to hear any day whether the DOE will encourage them to send in full proposals, which will be due on April 7.

Abundant Sunshine

Stechel said that with the abundant sunshine in the two states, green hydrogen — made from electrolysis of water using renewable energy — could account for much of the hydrogen produced in the hub.

Arizona is also home to the Palo Verde Generating Station, the nation’s largest nuclear energy facility, raising the possibility of producing so-called pink hydrogen. Arizona Public Service (APS) and Salt River Project (SRP) are part owners of Palo Verde, and both are participants in SHINe.

Another feature of Arizona — its salt caverns — could contribute to the hub by providing space for large-scale hydrogen storage, Stechel said in an interview with NetZero Insider.

SHINe would help meet demand for hydrogen in California, a neighbor to both states.

One partner in the SHINe hub is Air Liquide, which in May opened a $250 million liquid hydrogen production and logistics infrastructure facility in North Las Vegas. The plant is the company’s largest liquid hydrogen production site in the world.

“The facility was built to meet the renewable hydrogen demands of the burgeoning California mobility market with the capacity to fuel more than 40,000 fuel cell vehicles, thereby eliminating concerns around fuel supply reliability and allowing this market to develop more quickly,” the company said in a fact sheet.

The hub could also meet growing demand for hydrogen in Arizona and Nevada. For example, the Regional Transportation Commission of Southern Nevada, a SHINe partner, is acquiring hydrogen fuel cell buses as part of its transition to a zero-emission fleet.

Arizona and Nevada play a role in transportation electrification through their lithium and copper mines. Demand is surging for both metals, which are used in electric vehicles. Arizona is the top copper-producing state in the U.S.

Stechel said a hydrogen hub has the potential to decarbonize mining operations in the states.

Industry, Utility Partners

SHINe includes more than 40 members. On the utility side, Tucson Electric Power and Southwest Gas are participants in addition to APS and SRP.

In addition to Arizona State University, academic partners are Northern Arizona University, the University of Arizona and the University of Nevada, Las Vegas.

Industry partners include Phoenix-based Nikola, which designs and manufactures battery-electric and hydrogen-fueled vehicles as well as hydrogen station infrastructure. The company announced in August three Southern California locations for its hydrogen-fueling stations, including a site serving the Port of Long Beach.

“California is a launch market for Nikola, and these stations will support key customers and advance the state’s efforts to decarbonize the transport sector,” the company said in a release.

In Nevada, the Governor’s Office of Energy was “happy to support the initiative,” GOE Director David Bobzien said. More details of Nevada’s involvement in SHINe will be worked out under the administration of incoming governor Joe Lombardo, said Bobzien, who is resigning from GOE effective Jan. 2.

“Since the passage of the Infrastructure Investment and Jobs Act, hydrogen has been an important area of interest, especially considering Air Liquide’s investments in southern Nevada and exploration of hydrogen applications in medium- and heavy-duty clean transportation and long-term storage benefitting the grid,” Bobzien said in a statement provided to NetZero Insider.

December 22, 2022

NYISO Management Committee Briefs: Dec. 21, 2022

Abbas to Join Talen Board

NYISO CEO Rich Dewey announced to the Management Committee on Wednesday that Director Gizman Abbas had accepted a position on Talen Energy’s board of directors.

Dewey said NYISO has determined that the appointment “does not present a conflict” with FERC’s rules and the ISO’s own Code of Conduct, as Talen no longer operates, nor owns any assets, in New York. But, he said, the ISO would “continue to watch and monitor the situation,” and revisit that determination should Talen move back into New York and “come up with a cure.”

Mark Reeder, representing the Alliance for Clean Energy New York, asked whether Talen had any interests in NYISO’s neighbors and if that was considered in the ISO’s determination.

The company does have interests in PJM and ISO-NE, owning several generators in Pennsylvania, New Jersey, Maryland and Massachusetts. Dewey said “it was considered, and we felt [under] a strict interpretation of the rules, it did not present a conflict.”

Capacity Accreditation

The MC voted to recommend that the Board of Directors approve proposed tariff modifications that would implement a new capacity accreditation process and market design.

Having been approved by the Business Issues Committee last week, several stakeholders again voiced their reservations about approving measures that they believed were either not fully understood or would be applied to resources unequally. (See NYISO Capacity Accreditation Implementation Worries Stakeholders.)

Michael DeSocio, director of market design at NYISO, said the ISO “remains committed” to doing the work required for capacity accreditation implementation and “acknowledges the need” to tackle portions of the project that were raised by stakeholders. DeSocio also assured the committee that these commitments would be reflected in the meeting’s minutes.

Hybrid Storage Resources

The MC voted to recommend that the board approve NYISO’s proposed tariff revisions that would integrate aggregated HSRs — multiple generators co-located with energy storage behind a single interconnection point — into the ISO’s markets.

The revisions were also approved by the BIC last week, and NYISO anticipates filing the changes with FERC in the third quarter of 2023. (See “Aggregated Hybrid Storage,” NYISO Capacity Accreditation Implementation Worries Stakeholders.)

Julia Popova, NRG energy manager of regulatory affairs and vice chair of the committee, asked why the revisions were being filed so late next year.

NYISO officials answered that they are targeting the third quarter because there are other projects that need to be implemented first, such as internal controllable lines. They also said the HSR construct would not be implemented until 2025 anyway, so there is no rush to get it to FERC.

CAC Scoping Plan

NYISO agreed to brief stakeholders on the New York Climate Action Council’s recently approved scoping plan and how it would impact the ISO’s work. (See related story, New York Climate Scoping Plan OK’d.)

Executive Vice President Emilie Nelson said NYISO is “looking through [the plan] carefully and is very, very interested in working with all stakeholders and state agencies going forward.” The ISO also “appreciates the acknowledgement within the plan that there are challenges ahead of us that we need to work together to solve.”

Reeder requested a “small,” formal presentation from NYISO about aspects of the plan that would affect its markets, though he acknowledged that the plan is just a framework that will take “at least multiple years” of legislation and agency rulemakings to implement.

December 22, 2022April 11, 2024

ERCOT Board of Directors Briefs: Dec. 19-20, 2022

Members, TAC Stripped of Responsibilities for Policy Development

ERCOT’s Board of Directors on Tuesday stripped away the right of corporate members to vote on future changes to the grid operator’s bylaws, rejecting an alternative stakeholder recommendation in the process.

The directors approved bylaw amendments, drafted by staff at the board’s direction, that remove ERCOT’s corporate members’ ability to vote “on any matter submitted to the general membership.” The amendment does allow members to comment on any such proposals and to propose amendments themselves.

The bylaw revisions take away the Technical Advisory Committee’s ability to recommend policy and procedural changes to the board. It leaves that top stakeholder group with doing little more than managing the process for changing market rules and document guides.

Stakeholders have expressed their opposition to the change since the draft amendments became public late this summer. The revisions are designed to align ERCOT’s governance with legislation, passed in the wake of the deadly 2021 winter storm, that created an independent board and removed market representatives from participating. (See ERCOT Stakeholders Wait on Bylaw Amendment Changes.)

Chris Hendrix 2022-12-20 (RTO Inisder LLC) FI.jpg

Chris Hendrix, Demand Control 2 | © RTO Insider LLC

“There’s no real avenue to meet with the board,” Demand Control 2’s Chris Hendrix told RTO Insider. “It makes it more like a PJM model or an ISO-NE model, where you have no access to the board.”

Hendrix represented the membership and six of the seven market segments (investor-owned utilities were not involved) in offering up an alternative recommendation that agreed with much of the bylaw revisions but carved out three exceptions: retaining members’ voting rights, removing staff’s language that gives the board authority to amend TAC’s procedures without a vote of its representatives and removing language that allows the directors to disband TAC.

“Keep corporate members voting because it is a corporate membership,” he said. “It’s an incentive. We pay to be a member, and that comes along with voting rights.”

Several directors pointed to revised language giving members a 21-day window to comment on any proposed changes and noted that TAC can’t be disbanded without the Public Utility Commission’s direction.

Hendrix said the changes allow the board to set TAC’s policies and procedures, which could lead to extreme measures such as meeting once a year or eventual disbandment. He said that its only “the good word of the PUC” that prevents drastic changes.

The commission in November issued a statement that helped set the stage for this week’s discussion. The commissioners agreed that ERCOT’s board is “empowered to amend its bylaws without obtaining the affirmative vote of the corporate members. It is necessary for ERCOT to amend its bylaws such that the ERCOT board of directors has the sole authority to change the bylaws, subject only to the approval of the commission.”

The statement also called for preserving market participant input in developing market functions by amending the bylaws such that the board “cannot eliminate [TAC] without specific direction from the commission.” (See “PUC Sides with ERCOT Board,” Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

“I believe the proposed bylaws changes represent something that is not dissimilar to the organizational structures that we see in the rest of the country,” PUC member Will McAdams said before the commission’s separate vote to approve the bylaw changes. “Ultimately, the commission has an appellate jurisdiction to approve all policies, and there’s an obligation on the part of stakeholders, the board and the commission under this contract … to collaborate and work through operational issues as they become apparent so that we can provide the best outcome for the public in Texas.”

Hendrix, who admitted he faced an uphill battle, said the revisions will only help ERCOT’s larger members who can afford to lobby legislators and regulators and might lead some market participants to forego memberships.

ERCOT held a 20-minute annual membership meeting following the board’s executive session, with only a handful of members present. ERCOT CEO Pablo Vegas promised a return to an in-person annual meeting next year and “better opportunities to connect with fellow corporate members, with the ERCOT board of directors … with staff, with commissioners and with other invited guests.”

“I think it’s an opportunity to really connect on the issues that are important to the industry and have an opportunity to get to know each other through that and have a higher-value discussion,” he said.

Board Chair Paul Foster also expressed desire for a “stronger engagement opportunity” next year and said the bylaw amendments represented “another milestone” in ERCOT’s changing governance structure.

“Each board director has now had time over the past year to see the TAC membership and the stakeholders in action and the role they provide in the policy development of the rules that helped run a reliable grid and a fair efficient market,” he said.

Grid Prepared for Winter Weather

Vegas reassured directors and stakeholders that the grid operator continues to expect adequate supplies and reserves in advance of sub-freezing temperatures forecast for the Christmas weekend. He said staff expects to have more than enough generation to handle a projected peak of nearly 68 GW with nearly 90 GW of capacity online. Wind and solar account for 20-22 GW of the available capacity.

During a press conference with Gov. Greg Abbott Wednesday morning, Vegas reduced the online capacity estimate to 85 GW, with wind and solar accounting for 12 GW. He was joined by PUC Chair Peter Lake, who said the ERCOT grid is “ready and reliable.”

ERCOT on Wednesday elevated a previously issued advisory for the extreme cold weather to a watch, effective Thursday morning through Monday, Dec. 26.

“Things are looking good to get through the weekend,” Vegas said.

Chris Coleman 2022-12-20 (RTO Inisder LLC) FI.jpg

ERCOT meteorologist Chris Coleman leans into his weather forecast. | © RTO Insider LLC

Chris Coleman, ERCOT’s lead meteorologist, said the cold front, part of a powerful winter storm that has settled over the Midwest, will not be as severe as the deadly 2021 winter storm that almost brought down the ERCOT grid.

“We’re several degrees warmer than that, and we will also not have the precipitation associated with it,” he said.

North Texas and the Panhandle will likely see snow, Coleman said. He predicted low temperatures of about 12 degrees F in Dallas and 17 degrees in Austin Friday morning. Freezing temperatures could extend as far as the Rio Grande Valley before conditions begin returning to normal during the weekend.

“We could see 70 degrees [next week], so there’s something encouraging to look forward to,” Coleman said.

Coleman is sticking by his winter outlook, which predicts that this winter will not be as warm as last year’s, but not as cold as 2020/21. This is the third straight winter with the La Niña system in place and will deepen Texas’ drought conditions. Coleman said 52% of the state has drought concerns, up from 46% last year.

“I think the drought will remain in place and potentially expand and worsen here over the next few months,” he said. “I don’t think we’re going to get through this winter, saying, ‘Boy, we had a lot of fun. It was just never warm.’ It’ll likely turn around here, so I’m not closing the door beyond this week on more cold opportunities.”

TAC Membership Set for 2023

A cast of familiar faces will be back for TAC next year following the board’s approval of the committee’s 2023 representatives.

The Office of Public Utility Counsel’s Nabaraj Pokharel, CenterPoint Energy’s David Mercado and Garland Power and Light’s Russell Franklin are the only new additions to the 30-person stakeholder group.

Current TAC Chair Clif Lange, with South Texas Electric Cooperative, has offered to again lead the group next year. Members will vote on leadership during their Jan. 24 meeting.

ERCOT Gets 1st Adjunct Member

The directors approved an adjunct membership for Pine Gate Renewables, a utility-scale solar and storage developer headquartered in Asheville, N.C., with five projects in its Texas pipeline. ERCOT staff said the company does not currently meet any segment requirements but will align with the independent power producers in the stakeholder process.

In other actions, the board approved:

- - Robert Black’s hire as vice president of public affairs following a short stint with AEP Texas and a 30-year political career on the Republican side of the aisle;
  - ERCOT’s 2023 methodologies for determining minimum ancillary service requirements, previously endorsed by TAC;
  - the Finance and Audit Committee’s acceptance of a system and organization control audit of ERCOT’s market settlements operations that found no reportable exceptions; and
  - the Reliability and Markets Committee’s charter, outlining its responsibility to review the grid operator’s core functions and disbanding the Credit Working Group. TAC will add the credit reporting functions to its structure.

Board Approves 10 Changes

The board approved a consent agenda that included six nodal protocol revision requests (NPRR), single changes to the Nodal Operating Guide (NOGRR), other binding documents (OBDRR) and the Resource Registration Glossary (RRGRR), and a system change request (SCR):

- - NPRR1128: Sets an ancillary service offer floor 1 cent/MW lower for fast frequency response (FFR) than for other RRS categories to allow FFR procurement up to the current limit, without proration with other RRS categories.
  - NPRR1132: Specifies that during local cold weather conditions, each qualified scheduling entity (QSE) must update its generation resources’ and energy storage resources’ current operating plans, real-time telemetry, and outage and derate reporting to reflect any limitations. It also requires each resource entity to provide resource-specific cold weather minimum temperature limits, hot weather maximum temperature limits, and alternate fuel capability information in its submitted resource registration data and update this information as necessary.
  - NPRR1138: Requires each resource entity to ensure the reactive capability curve for any intermittent renewable resource accurately reflects its reactive capability when it is not providing real power or is operating at lower levels of real power output.
  - NPRR1148: Resolves protocol gaps found during emergency contingency reserve service’s creation of its system change requirements.
  - NPRR1152: Removes the protocol requirements to submit emergency operations plans (EOPs), weatherization plans, and declarations of summer/winter weather preparedness; revises procedures for submitting declarations of natural gas pipeline coordination with natural gas generation resources; revises the list of items considered protected information to remove references to weatherization plans and add protections for information relating to weatherization activities; and revises the list of ERCOT critical energy infrastructure information to clarify language concerning EOPs and add protections for information relating to weatherization activities.
  - NPRR1154: Updates language to allow for a qualified alternate resource to be considered in calculating the availability reduction factor for the firm fuel supply service (FFSS) resource and provides a new settlement billing determinant providing the FFSS award amount per QSE per FFSS resource by hour.
  - NOGRR226: Adds provisions for transmission operator “anti-stall” automatic firm load shedding at 59.5 Hz to mitigate the risk of a total systemwide blackout.
  - OBDRR043: Aligns the operating reserve demand curve’s methodology with NPRR1148’s revisions, approved in August, in calculating the real-time reserve price adder.
  - RRGRR032: Adds data required to be shared with ERCOT as the reliability coordinator, balancing authority and transmission operator in considering cold weather limitations in its operational planning analysis, real-time monitoring, real-time assessments, and other analysis functions. The grid operator also requires this information for hot weather limitations and making this a requirement for distributed generation resources and distributed energy storage resources.
  - SCR821: Allows transmission and distribution service providers to set the voltage set point target information provided to distribution generation or distribution energy storage resources.

December 22, 2022June 14, 2023

PJM MRC/MC Briefs: Dec. 21, 2022

Markets and Reliability Committee

Two Proposals on ‘Circuit Breaker’ Fail

The PJM Markets and Reliability Committee rejected two proposals that would have created a “circuit breaker” mechanism to limit prices during extended periods of high prices.

Old Dominion Electric Cooperative, Southern Maryland Electric Cooperative and Northern Virginia Electric Cooperative had jointly proposed triggering a breaker when LMPs of at least $1,000/MWh last over the course of a 24-hour period, or $850 over a week. Prices would then be capped at $850/MWh until they remain below the cap for five consecutive business days.

The proposal would have also granted PJM the discretion to invoke the breaker based on conditions it’s observing; it would not have had the power to prevent a breaker being triggered. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)

Adrien Ford 2022-06-29 (RTO Insider LLC) FI.jpg

Adrien Ford of ODEC said the circuit breaker is intended to be used only under extraordinary circumstances when the markets have gone “haywire.” For a small load-serving entity serving 200 MW of load, she said the total annual spending under typical average prices for the PJM footprint could be eclipsed in 2.25 days should prices reach the current $5,700/MWh cap, which includes maximum cost-based offers, reserve shortages and a $2,000/MWh transmission constraint penalty factor.

“The numbers just get cartoonish very quickly, and that’s why we’re trying to put this in place,” she said.

Calpine proposed a breaker triggered by 90 nonconsecutive hours of shortage events in one delivery year and cap prices at $2,000/MWh — a threshold the company’s David “Scarp” Scarpignato said is critical to proper price formation. After one breaker had been observed in a single year, any subsequent shortage in excess of three consecutive hours would trigger an additional breaker. The proposal would not provide PJM with the power to initiate a circuit breaker unilaterally.

Prolonged periods of high pricing can cause more harm through revenue issues than provided by the benefits of price formation, Scarp said.

Consideration of the packages was postponed during the November MRC meeting to afford their sponsors additional time the attempt to reach a compromise, but Ford said those efforts were not successful. She said consensus was sought on the circuit breaker alone, as well as by combining the issue with the market seller offer cap (MSOC).

Concerns with the packages included giving PJM staff the ability to initiate a circuit breaker; the impact of uplift payments on small LSEs; the level prices would be capped at; and a lack of detail on some provisions, such as how uplift payments would be allocated.

Constellation Energy’s Jason Barker encouraged stakeholders to vote against both packages and to engage in further discourse to find a compromise in the middle.

“It’s unfortunate that we’re pushing forward with stakeholder packages that we believe are suboptimal at best,” he said.

Consumer advocates and load representatives said the impact of sustained high prices necessitates a quick solution being found.

“There needs to be something in place to protect consumers,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States, adding that it was hoped that a circuit breaker would be ready in time for the winter season.

Albert Pollard 2022-06-29 (RTO Insider LLC) FI.jpg

Albert Pollard, of the Illinois Citizens Utility Board, said the issue could lead to a future Federal Power Act Section 206 filing with FERC if a stakeholder solution is not found. He argued that it might be more advantageous to opponents of the circuit breaker proposals to accept one of the solutions on the table rather than take their chances with a solution the commission may arrive at.

“We don’t know what’s going to happen if this lands on their desk,” he said.

First Read on Proposals for Accrediting Intermittent Resources

The sponsors of five packages addressing capacity accreditation for effective load-carrying capability resources gave a first read of their proposals, with the discussion focusing on how to address capacity interconnection rights (CIRs) for existing resources in the interim until the new rules can be put in place. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)

None of the packages reached 50% support in a poll conducted by the Planning Committee in October. LS Power’s Package E received the largest share of support in an October poll, at 44%, followed by Packages D and I from PJM, which received 40% and 28%, respectively. Endorsement of a package from the PC is scheduled for Jan. 10, while the MRC and Members Committee are set to vote on Jan. 25. The proposals would also require approval from the Board of Managers, which is set to take up the issue on Feb. 1.

Tom Hoatson of LS Power said Package E is essentially PJM’s original Package A, which was withdrawn by the RTO early in the stakeholder process. It would immediately limit generators’ accreditation to their current CIR level, require those resources to re-enter the interconnection queue at the end to request higher CIRs and require that they be responsible for any transmission upgrades.

PJM’s Package D would grant existing interconnection service agreement (ISA) holders higher CIRs by conducting new deliverability tests in the 2023 Regional Transmission Expansion Plan (RTEP). Some opponents have criticized this as permitting those requests to jump the queue and causing projects in the queue to bear higher costs.

The RTO’s Package I would place existing resources’ requests for higher CIRs at the end of the interconnection queue, but conduct a transitional system capability study to allow for the generator to take advantage of headroom on the transmission system, which PJM has estimated will be available for approximately five years.

Package G, from E-Cubed Policy Associates, builds upon LS Power’s proposal and expands the deliverability testing to include more months — particularly the fall shoulder months, as there have been increasing reliability concerns at the start of the fall maintenance period. The proposal would also allow generation owners retiring their assets to request an expedited CIR review for new generation being developed on the same site using the existing interconnection point, a component not included in any of the other proposals.

“We need to understand how those shoulder periods are going to be effected,” said E-Cubed President Paul Sotkiewicz.

The most recent proposal, Package K, was introduced by LS Power during the Dec. 6 PC meeting and aims to ensure that the provisions within PJM’s Package I are actionable for the June 2023 Base Residual Auction. It both specifies that the changes are mandatory to implement in that BRA and asks that the board direct PJM to submit a filing with FERC clarifying that the Reliability Assurance Agreement establishes CIRs as the hourly upper limit for the unforced capacity accreditation.

“We recognize it would only be an indicative vote; we cannot tell the board what to do,” Hoatson said.

Ford said that in the event that either no packages are endorsed by the PC or Package I is not among the proposals voted to be brought before the MRC, ODEC would motion for it to be voted upon by the committee.

Generator Deliverability Test Modifications

PJM provided a first read of proposed manual revisions to change how generator deliverability tests are conducted to account for higher variability associated with the growth of intermittent resources on the grid. The proposal would merge the methodology for summer, winter and light-load testing; expand the light-load period; incorporate procedures for ramping of wind and solar; and harmonize dispatch procedures.

The RTO is anticipating seeking endorsement from the PC on Jan. 10, followed by returning to the MRC on Jan. 25 for endorsement. If approved, the changes would be effective immediate and implemented for the 2023 RTEP.

Other Committee Actions

The MRC also passed with no objections:

market suspension rules to clarify how PJM accounts for suspensions when market results and clearing prices cannot be determined. (See “Market Suspension,” PJM Market Implementation Committee Briefs: June 8, 2022.)
Operating Agreement revisions to grant PJM the flexibility to permit market participants to continue operating in markets under certain circumstances, including grid reliability; the ability to provide collateral; and future ability to generate revenue. The language also recognizes that certain transmission customers cannot have their service terminated without FERC approval. PJM Associate General Counsel Colleen Hicks told the committee that the OA currently has conflicting language on whether PJM has discretion currently, with some sections using “shall” and others saying that “PJM may limit” and the revisions bring the documents into alignment. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022.)

Members Committee

Election of Representatives and Vice Chair

The Members Committee approved sector whips and representatives on the Finance Committee, as well as a new vice chair, during its Wednesday meeting.

The sector whips for 2023 will be:

Electric Distributors: Lynn Horning of American Municipal Power;
End Use Customers: Greg Poulos of the Consumer Advocates of the PJM States;
Generation Owners: Calpine’s Scarp;
Other Suppliers: Brian Kauffman of Enel North America; and
Transmission Owners: John Horstmann of Dayton Power and Light.

The sitting Finance Committee representatives will be joined by Jeff Riley of AMP (Distributors) and John Brodbeck of EDP Renewables (Generation).

Following the rotating schedule of which sector nominates vice chair, the TOs had selected Exelon’s Sharon Midgley, whom the MC also elected Wednesday.

PJM CEO Manu Asthana thanked outgoing MC Chair Erik Heinle, of the D.C. Office of the People’s Counsel, for his leadership through many meetings and discussions, including a handful of contentious issues before the committee.

The Generation sector had originally selected Scarp to fill the vice chair position, following the departure of Becky Robinson of Vistra, who as vice chair was in line to become chair next year. Thus, Scarp will become chair next year.

First Read on Manual Revisions to Allow Direct MC Consideration of Issues

ODEC’s Ford provided a first read of proposed revisions to Manual 34 that would create an avenue for PJM members to make a motion for the MC to consider issues directly, without going through the typical pathway of the lower committees. The revisions would require that a motion be introduced as a problem statement and issue charge to follow the existing governance process.

December 22, 2022June 14, 2023

Future of Critical Mineral Mining is Responsible, Transparent and Green

One of the biggest roadblocks to developing a domestic supply chain for the minerals that are critical to clean energy technologies is the General Mining Act of 1872, “a legal and regulatory framework from the 19th century” still in force today, according to Tommy Beaudreau, deputy secretary at the U.S. Department of the Interior.

The 150-year-old law is “about prospecting, staking claims, as opposed to a leasing process,” Beaudreau said Wednesday during a webinar on the future of U.S. mining, sponsored by the Bipartisan Policy Center (BPC).

“One of the challenges we have is, how do we meet the needs of the clean energy economy with domestic sourcing of critical minerals, like lithium and cobalt and other materials, while managing the potential for conflict that any industrial activity, including mining, has; and all of the interests that we’re responsible for helping meet on public lands,” he said.

The Biden administration has made the building out of domestic supply chains a top priority of its push for a carbon-free electricity system by 2035 and a net-zero economy by 2050. Critical minerals — such as lithium, cobalt, nickel and uranium — are essential materials for energy storage, electric vehicles and advanced nuclear reactors, and the U.S. is “blessed with a number of these resources,” including on public land, Beaudreau said.

Tommy Beaudreau, DOI | BPC

The BPC sees the issue as bringing together key national security, economic and environmental interests, which makes mining and mining permitting reform ripe for bipartisan collaboration, said Xan Fishman, the organization’s director for energy policy and carbon management.

But major partisan flashpoints still exist, especially on permitting reform, as seen by the recent defeat of Sen. Joe Manchin’s (D-W.Va.) permitting reform bill this month. (See Manchin Permitting Bill Falls Short in Senate.)

Seeking common ground, the Interior Department launched an interagency working group on mining and mining reform in February and has since held about 20 meetings with the public and tribes, along with 30 more meetings with “individual companies, mining operators, as well as environmental [nonprofits],” Beaudreau reported. The group also received more than 20,000 public comments, he said.

Such extensive engagement is needed, Beaudreau said, to “overcome the legacy of hard-rock mining in the United States, going back to the 19th century,” when prospectors went into tribal and public lands “to exploit resources without talking to the community, certainly without benefiting the folks in whose backyard [the mining] is happening.”

The working group will be issuing a report in the first quarter of 2023, and while Beaudreau was not ready to provide specific details, he said the group has developed a set of principles. “Our goal [is] to take advantage of the opportunities we have for reliable sourcing of critical minerals here in the United States and with our partners and allies, but at the same time doing so in a way that respects local communities and tribes, is good stewardship for the environment and wildlife habitat and is responsible,” he said.

Part of the way forward could be identifying potential environmental or community concerns around any specific mining or supply chain project and “deconflicting” them, a strategy first used during the Obama administration to accelerate the development of renewable energy projects on public lands.

This approach is not currently used in mining permitting, Beaudreau said, but the upcoming report could include a similar proposal. “By doing that, we’re actually able to accelerate project development because we’ve sort of front-loaded community engagement, understanding and deconflicting,” he said.

Collaboration with tribal governments is another priority, with a focus on transparency, Beaudreau said. “We’ve developed a new system to … identify geographic areas of interest for mining, and there are cases where tribes see opportunities as well. We can create planning conversations about potential [projects] and then work with operators on consultation, both about money, but also on the back end, reclamation work and providing assurances on potential environmental impacts.”

‘Doing It the Right Way’

The need for the U.S. to break its dependence on China, Russia and other unreliable nations for critical minerals has become a given on both sides of the aisle in Congress. “If you care about the environment, or you have a social conscience, you want mining to happen in Nevada and across the U.S.,” said Tyre Gray, president of the Nevada Mining Association.

Tyre Gray, Nevada Mining Association | BPC

“We are currently sourcing the vast amount of our minerals from countries that are not doing it the right way,” Gray said during an industry panel following Beaudreau. “And we do it here the right way.”

“We really approach this from a national economic security lens,” said Abigail Wulf, vice president and director for the Center for Critical Minerals Strategy at Securing America’s Future Energy, a Washington, D.C. think tank. “We want to make sure our supply chains for the minerals of the future … can’t be used as political pawns. So, we’re focused on diversifying supply chains, and for the future of mining, we see responsible mining and transparent supply chains as really being the way to diversify supply chains.”

Echoing Gray, Wulf said, “Where critical minerals are coming from right now, it’s ostensibly difficult to compete on cost because people are degrading the environment or exploiting workers in a way that would not be tolerated if it were done in the United States or among some of our like-minded partners.”

Gray also stressed that the General Mining Act of 1972 mostly covers public land use, and mining in Nevada and other states is highly regulated under several federal and state laws, including the National Environmental Protection Act and the Clean Air Act. In Nevada alone, “there are over 20 different agencies, if you count the federal agencies, that have some level of oversight in mining,” he said.

Abigail Wulf, SAFE | BPC

“Before a single shovel hits the ground here in Nevada, you have to plan for reclamation [and] closure,” he said.

At the same time, Gray believes the industry could benefit from “Good Samaritan” legislation that would allow companies to reclaim old mining sites “to see if there’s anything of value but not necessarily take on the responsibility” for past environmental damage.

Gray also sees the EV supply chain in broad terms, not just lithium, nickel and cobalt, but copper, silver and gold, which may also be used in other clean technologies. “I don’t want to get too focused on just a certain set of minerals, but really be able to address the whole suite of minerals,” he said.

“When we’re talking about green technology … and where we’re heading in the future, talking about everything without talking about particular minerals, it’s kind of like talking about a peanut butter-and-jelly sandwich without thinking about the bread,” he said.

The Tamarack Project

Talon Metals Corp. is one of a small but growing number of companies on the front line of responsible, transparent mining. Based in Ontario, Canada, the company is focused on providing minerals for the EV and electric battery storage market.

Todd Malan, Talon Metals | BPC

The company’s Tamarack Project in Minnesota is being developed to provide high-grade nickel, as well as cobalt and copper for EV batteries, and the company has received a $114.8 million grant from the Department of Energy to help build a processing plant in North Dakota, Malan said.

“Why should the public care about high-grade [nickel]? Because high-grade means high concentration,” he said. “That means we can actually go in an underground line very selectively and surgically, grab the high-grade material, take it out in a responsible way and still make sure that we’re protecting the environment.”

The company was one of 20 receiving grants from the Infrastructure Investment and Jobs Act to build out the EV battery supply chain.

But, Wulf said, at this point, responsible mining still costs more and will need further federal support. While the IIJA and Inflation Reduction Act have a range of incentives for critical minerals and manufacturing, the missing piece is incentives for mineral exploration, she said.

Trade policy is another must-have, she said. The U.S. needs “enforceable mechanisms for that responsible mining, and so sanctionable, enforceable trade deals among our allies will be one way we can do that.”