New Jersey legislators sent a bill to the governor’s desk March 18 that would place a $250-a-year fee on zero-emissions vehicles, brushing aside criticism from environmentalists and car dealers that the fee would hinder electric vehicle sales.
The Senate voted 24-14 to approve the bill, A4011, which would revise the New Jersey Transportation Trust Fund Authority Act to increase revenue to help support state transportation infrastructure and mass transit expenses. The state Assembly voted 48-28 to support the bill, which includes an increase in the state gas tax and revises the way in which it is levied.
Gov. Phil Murphy’s (D) office did not immediately respond to an inquiry as to whether the governor would sign the bill.
Starting July 1, 2024, buyers of zero emissions vehicles would pay $250 a year to $290 a year when a vehicle is registered initially or is renewed. The fee in the first year would be $250, rising $10 a year until it reaches $290 a year in the fourth year, and stops increasing. Buyers would have to pay the fee for four years at once, for an upfront payment of more than $1,000.
Supporters see the bill as a way to increase investment in state transportation and to secure revenue from EVs and other zero-emission vehicles that otherwise might not contribute because they don’t pay the gas tax. But opponents said the fee — coupled with Gov. Murphy’s plan to make EV buyers pay state sales tax, from which they currently are exempt — would hamper EV sales. (See NJ Bill Would Levy Annual Fee on EV Ownership.)
“Clearly, the state’s aggressive EV mandates are on a collision course with our fiscal realities,” said James Brian Appleton, president of the New Jersey Coalition of Automotive Retailers.
“No one disputes the notion that EV drivers must pay their fair share to maintain roads and bridges or that some form or some amount of user fee must be paid,” he said. “Consumers will not react well to this and shrinking EV incentives. And adding more than $1,000 to the upfront purchase price of a new electric car will render the governor’s goal of 100% EV sales in New Jersey unachievable.”
Doug O’Malley, state director for Environment New Jersey, said the bill — if Murphy signs it — would give the state one of the highest EV fees in the nation. He said the bill, which was introduced March 4, has moved like “greased lightning” through the Legislature. He speculated the sponsors wanted to get it approved before the state budget season begins in earnest in the next few weeks.
“This is a real setback for EV drivers. This is essentially a $1,000 tax that could well dissuade potential EV drivers from making the switch,” he said, adding it’s an upfront fee that gas vehicle buyers don’t have to pay.
“It’s the opposite of a pay-as-you-go system,” he said. “No one pays the gas tax upfront for four years.”
Washington Post headline: “Amid explosive demand, America is running out of power.”1
The long article cobbles together charts without context, cites states with relatively high electric demand and quotes from all manner of folks.
Missing are the entities that actually know whether there is “explosive demand” and whether “America is running out of power.”
These entities are NERC and the RTOs like PJM that manage generation supply-demand and bulk transmission for most of the country.2But why ask the experts?
Explosive Demand?
Regarding “explosive demand,” please look at this NERC graph that shows forecast summer and winter peak demand annual growth rates for the next 10 years.3The lines show the compound annual growth rate (CAGR) values on the right-hand axis. Do you see the most recent 10-year growth rates of 1.0% summer and 1.2% winter? And do you see how much higher these growth rates were from 1995 to 2014? So yes, demand growth is increasing — but at a relatively small rate in absolute and relative terms.
10-year summer and winter peak demand growth and rate trends | NERC
Running out of Power?
As for America “running out of power,” here’s another NERC chart showing projected new Tier 1 and 2 generation resources over the next 10 years.4 Around 370 GW by 2033. This is a staggering amount of new generation relative to existing generation resources of 1,300 GW.5
Tier 1 and 2 planned resources projected through 2033 | NERC
Will all of it get built? No. Will the renewable (intermittent) resources have the same reliability value and load factor as dispatchable (firm) resources? No — I’ve written about their limits ad nauseum.6 Are there challenges that need to be worked through to ensure the energy transition does not degrade reliability? Yes. Crisis? No.
Georgia
Georgia is the poster child for the Post article, where the major utility there, Georgia Power, projects increased demand from various sources.7 But is there a crisis? No. Georgia Power identifies eight measures to address the increased demand, including power purchase agreements with generators in Mississippi and Florida, expanding battery storage, building additional simple-cycle combustion turbines, and expanding distributed energy resource and demand response programs.8 Where’s the fire?
Distracting from the Real Work at Hand
Articles like the Post’s distract from the real work at hand. Here are a few no-brainers I’ve flagged before:
(1) Keeping existing nuclear plants open. Thank goodness Diablo Canyon was saved, as I pleaded for eight years ago;9
(2) banning cryptocurrencies (especially “proof of work” crypto like Bitcoin), which have nothing but negative externalities like emissions, ransomware enabling, money laundering, drug smuggling and human trafficking;10
(3) rational onshore wind instead of irrational offshore wind, which costs at least twice as much per MWh;11
(4) rational grid solar instead of irrational rooftop solar, which costs five times as much per MWh;12
(5) high-voltage interconnections between Texas/ERCOT and the rest of the country;13
(6) unique emergency ratings for generation interconnection studies (and dispatch);14
(7) new (but known) technologies for increasing capacity of existing transmission lines;15
(8) not wasting money on green hydrogen electricity;16 and, dare we keep saying it,
(9) carbon pricing.17
The flip side of good public policies is bad public policies, such as premature closure of dispatchable resources (a threat that goes unaddressed in the Post article). Bad public policies can create a crisis that would be otherwise avoidable. But we shouldn’t assume we’ll foolishly create a self-inflicted crisis.
A Last Word
In my humble opinion, the damage from an article like the Post’s goes beyond distracting us from the real work at hand. It adds to the collective trauma from all the big things we already worry about, like climate change, artificial intelligence, politics and international crises.
We have plenty to worry about. Enough already.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
After nearly two decades of flat load growth, U.S. electricity demand is rising. Fast. The boost in domestic industry related to the growth of data centers and increased economywide electrification is driving operators to revise load forecasts and scramble to flag concerns about future capacity insufficiency.
They are right to be concerned: This new load is coming onto the aging grid far faster than solutions to handle that demand. New generation takes years to get through the backlogged interconnection queue; new and expanded transmission capacity even longer. We need to be using every tool in our toolbox to help meet these challenges — and energy efficiency is critical to ensuring we can do this effectively and affordably.
Bo Clayton | Bo Clayton
For at least half a century — since the 1970s U.S. energy crisis — energy efficiency has been America’s cheapest, most reliable source of energy. Even as modern, clean technologies like solar PV, wind energy and battery energy storage have tumbled down their cost curves, megawatts of efficiency remain a winning bet for states and their utilities.
A recent Lawrence Berkeley National Laboratory study confirms energy efficiency plays a significant role in many states. These energy efficiency programs range from major industrial-scale efforts to reduce consumption to hundreds of millions of residential customers around the country installing products and taking actions that, in aggregate, save a lot of energy and money.
Rather than identifying ways to promote further efficiency in its footprint, the nation’s largest grid operator — PJM — inexplicably is taking the opposite approach. PJM is pursuing imminent changes that effectively will gut energy efficiency across its region, precisely at a time when those gigawatts of capacity are needed more than ever.
PJM is seeking to bypass its standard stakeholder process to make a “quick fix” to its rules governing energy efficiency. PJM’s hasty proposal, which will be voted on at its Markets and Reliability Committee meeting March 20, essentially would invalidate a majority of states’ energy-efficiency programs by establishing an arbitrary timeline for when PJM thinks states should update their own energy-efficiency guidelines. (See PJM MIC Briefs: March 6, 2024; and PJM Seeking Expedited Approval of Energy Efficiency Changes.)
PJM didn’t bother to explain which state programs would be impacted or provide support for its concern about how states are running these programs. This is irresponsible at best and outright disrespectful of state programs and efficiency progress at worst.
In parallel, it effectively would eliminate the ability to aggregate energy efficiency through big box retailers, removing the primary means of energy efficiency participation in PJM to date. This could significantly hamper consumer adoption of energy efficiency solutions such as LED light bulbs and spray foam insulation.
Make no mistake: PJM should revisit its rules governing efficiency’s participation in the capacity market. Much has changed in the 17 years since these rules first were adopted. They are outdated and due for overhaul. But the process to do so must be transparent, inclusive and thoughtful.
PJM isn’t even planning to allow its regulator — FERC — to have a say on the changes. That leaves it up to the PJM stakeholders to push back. If you are a stakeholder, I urge you to pursue the harder but better approach: Send the issue back to lower committees for thoughtful deliberation including PJM staff, states and others with a stake in the outcome. Anything less flies in the face of PJM’s own commitment to consensus-based issue resolution, to the detriment of consumers and grid reliability. Moreover, PJM will be abdicating its place at the forefront of energy innovation.
This is not the time for PJM to erase decades of progress on energy efficiency by hastily implementing an ill-conceived rule change with far-reaching ramifications.
Bo Clayton is the CEO of American Efficient, a developer of energy efficiency resources with 10 years of operating history in PJM.
The West-Wide Governance Pathways Initiative has secured financial commitments from 24 utilities and other electricity sector organizations and expects that list to grow, the group disclosed March 15 as it identified the contributors.
The disclosure seeks to address concerns raised by some skeptics of the Pathways Initiative about who is backing the effort and whether it is being dominated by specific interests.
Those concerns stem from the fact that the effort is at the heart of a contest between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ day-ahead offering to attract participants.
Last year, energy officials from five Western states launched the Pathways Initiative to build a governance framework that could oversee a regionwide market that pointedly includes California and builds on CAISO’s Western Energy Imbalance Market (WEIM) and EDAM.
“The thing I did want to note on this is we have a fairly broad and diverse set of funding parties that have agreed to help us and also that there isn’t any super large amount of money coming from any one entity that’s trying to in any way dominate our funding,” Jim Shetler, general manager of the Balancing Authority of Northern California (BANC), said during a March 15 update call hosted by the initiative’s Launch Committee.
Shetler is co-chair of the committee’s Priority Admin Work Group, and BANC last August became the second balancing authority to announce its intention to join the EDAM after six-state utility PacifiCorp. (See BANC Moving to Join CAISO’s EDAM.)
Shetler displayed a spreadsheet listing companies that have pledged donations and their approximate funding. The top-level funders ($20,001-$30,000) include the investor-owned utilities Avista, Pacific Gas and Electric, PacifiCorp, Portland General Electric, Public Service Company of New Mexico, Puget Sound Energy and Southern California Edison.
Others in that pledge category include BANC, California Community Choice Association (CalCCA), Northern California Power Agency, Oregon-based generation and transmission cooperative PNGC Power, Seattle City Light, and Western Power Trading Forum (on behalf of AES, Calpine, Constellation, Shell and Vistra).
The next level of funders ($10,001-$20,000) includes NextEra Energy, Northwest Energy Coalition and Western Freedom, which represents companies seeking to buy emissions-free energy.
The third level of donors ($5,001-$10,000) consists of Apex Clean Energy, EDP Renewables and Turlock (Calif.) Irrigation District, while the fourth level ($1-$5,000) includes Avangrid, Invenergy, Ørsted Wind Power North America, Northwest & Intermountain Power Producers Coalition and Union of Concerned Scientists.
“Invoices have been sent out, funds are flowing in, so we’re able to pay our bills. We greatly appreciate that,” Shetler said.
These financial commitments put the Pathways Initiative at about $430,000 of an estimated $570,000 budget needed to fund Phase 1 of the effort through April, with more pledges expected, Shetler said.
The group also expects to win the $800,000 in U.S. Department of Energy grant funding it applied for in January, Shetler added. The first half of that money likely won’t arrive until June or July, potentially leaving a funding gap in late spring. Still, he said he thinks the initiative can run on its original budget until the end of June.
‘Quick Wins’
Opening the March 15 update, Launch Committee co-Chair Kathleen Staks, executive director of Western Freedom, emphasized the initiative is focused on its original mission of establishing an “independent entity” to oversee governance of a market building on CAISO’s WEIM and EDAM and containing the largest possible Western footprint.
Staks’ statements appeared to address a question raised in a thread under a LinkedIn post she published March 11 in which a commenter said that, based on information shared at the committee’s previous update, they assumed Pathways was no longer pursuing creation of a “regional organization” because it would require a change in California law.
“We have been evaluating how we get there. What are the options for that end state?” Staks said. That “includes everything from interim steps that demonstrate progress and achieve some quick wins for market development in the West, as well as a potential legislative change in California.”
CalCCA General Counsel Evelyn Kahl, co-chair of the Launch Committee’s Functions and Scope Work Group, elaborated on that “stepwise” approach to governance, which was discussed during the committee’s February update. (See Western RTO Effort Makes Gains on Funding, Legal Analysis.)
Kahl said her group, which is working with the law firm retained to examine legal issues around transforming CAISO’s governance, has made progress on Step 1 of the process — namely, identifying changes that could be done to make the WEIM/EDAM governance framework more independent of Californian control without triggering legal action.
She said the “two key features” in Step 1 would be elevating the level of authority for the WEIM Governing Body and introducing a dual filing concept at FERC in cases of disagreements over tariff changes between that body and CAISO.
Kahl said the work group expects to deliver stakeholders a “straw design” and associated paper by April 10.
“Step 2 is harder,” Kahl said. “It’s the next incremental step of augmenting market independence, and it’s going to require a lot more in-depth analysis and design. And it’s likely to require a change in law. So given the complexity of Step 2, it’s moved necessarily more slowly and deliberately.”
Kahl’s group is looking into the creation of a new regional body as a 501(c)(3) organization and in April expects to discuss with stakeholders a “narrowing” of the governance options the Launch Committee laid out in December. (See Western RTO Initiative Outlines Governance Options.)
“We’d like to emphasize that nothing you’re going to see on April 10 is going to be a final recommendation. What we plan to do is show you our work … and get your feedback on our work before we go further,” Kahl said.
Mike Florio, a former California Public Utilities Commission member who now works as a consultant, asked if there’d be an effort to amend California law during the 2024 legislative session.
“We want to make sure that we are having a very thorough stakeholder engagement process and don’t want to cut that short — and we will need to do some engagement with legislators in California” Staks said. “Without committing fully one way or another, I think the likelihood of having legislation ready to present in the 2024 legislative session is probably unlikely.”
The Launch Committee will hold its next update call April 19.
CPS Energy has notified ERCOT it plans to “indefinitely suspend operations” at three aging gas-fired units in 2025, further reducing the Texas grid’s thermal capacity.
The San Antonio municipality filed a notification of the suspension with the Texas grid operator March 13. The three steam turbines at the V.H. Braunig facility have a combined summer seasonal net maximum sustainable rating of 859 MW.
CPS Energy says the units are nearing the end of their operational lives. The first unit came online in 1966, and the other two followed in 1968 and 1970. Four smaller gas turbines at the site each have a nameplate capacity of 61 MW.
The municipality has made a concerted effort in recent years to meet the city’s climate goals and maintain reliability with a fuel mix that relies on clean energy, storage and gas resources. Its Board of Trustees approved a generation plan last year that shifts the utility away from coal power by retiring one unit at its J.K. Spruce plant by the end of 2028 and converting another to run on natural gas.
CPS Energy decommissioned two coal-fired units at its J.T. Deely plant in 2018.
ERCOT is accepting comments through April 3 as it conducts a study to determine whether the closure will lead to reliability issues.
The grid operator began the year with 15.5 GW of interconnection requests from gas resources. Most of those are for quick-starting combustion turbine or combined cycle units.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings March 20. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
As part of its consent agenda, the MRC will be asked to endorse:
B. proposed revisions to Manual 11: Energy and Ancillary Services Market Operations to conduct more regular reviews of interface pricing points. The changes would add a definition of interface pricing points, which group buses together when calculating LMPs for energy transfers between external areas and establish an annual review of power flow impacts on each interface. (See “Other Committee Business,” PJM MIC Briefs: March 6, 2024.)
C. proposed revisions to Manual 12: Balancing Operations identified through the document’s periodic review. The new language would seek to align with real-time market operations detailed in Manual 11 and add detail to hybrid resource market parameters. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)
D. proposed revisions to Manual 37: Reliability Coordination including administrative changes identified through periodic review and reflecting changes to NERC standards FAC-011 and FAC-014. (See “Periodic Review Manual Revisions Endorsed,” PJM OC Briefs: March 7, 2024.)
PJM’s Michele Greening will present proposed revisions to PJM’s governing documents endorsed by the Governing Documents Enhancements and Clarifications Subcommittee (GDECS) last month. Greening told the committee in February that most of the revisions are clarifications and corrections, though some stakeholders have argued that several changes are more significant than are typically made through the GDECS. (See “Other MRC Business,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The committee will be asked to endorse the revisions to the tariff, Reliability Assurance Agreement and Operating Agreement.
Demand Response Window (9:30-9:55)
Bruce Campbell, principal of Campbell Energy Advisors representing demand response providers, will present a quick-fix proposal to extend the availability window for DR resources by two hours during the winter to reflect expanded ability for load to respond in the evening hours and to align with changes made to PJM’s market structure following the Critical Issue Fast Path (CIFP) process. (See “Demand Response Providers Seek Expanded Availability,” PJM MRC/MC Briefs: Feb. 22, 2024.)
The committee will be asked to approve the proposed issue charge and endorse the proposed solution to key work activity 2 using the quick-fix process outlined in Manual 34, which allows an issue charge and proposed solution to be voted on concurrently.
Manual 18B: Energy Efficiency Measurement and Verification (9:55-10:45)
The committee will be asked to endorse one of the following proposed packages of revisions to Manual 18B: Energy Efficiency Measurement and Verification.
A. PJM’s Pete Langbein will present the main motion to revise how the RTO measures and verifies the capacity offered by energy efficiency resources. Prior to endorsement from the Market Implementation Committee on March 6, Langbein told stakeholders the manual revisions would clarify which basepoint EE providers should use to measure the energy savings associated with a resource and require that they possess exclusive rights to offer those savings into the capacity market and that they can demonstrate installation of more efficient equipment was completed. (See PJM MIC Briefs: March 6, 2024.)
B. CPower’s Ken Schisler will present an alternative motion offering a proposal seeking to resolve several concerns that EE providers laid out during the March MIC meeting, including the requirement that an EE installation be causally linked to the capacity market and a three-year limit on the eligibility for technical reference manuals be used to compare the energy use of new technologies against.
C. Affirmed Energy’s Luke Fishback will present an alternative motion that seeks to resolve issues with the PJM proposal, which Fishback told the MIC could result in large amounts of EE being unable to offer into future auctions.
Capacity Obligations for Forecasted Large Load Adjustments Issue Charge (10:45-11:10)
Old Dominion Electric Cooperative’s Michael Cocco will present revisions to the issue charge framing an ongoing stakeholder discussion on how capacity obligations arising from forecasted large load adjustments should be assigned to electric distribution companies. The proposal would add language to the in-scope section of the issue charge to include changes to Manual 19 to add details on how load-serving entities forecast large load additions and how those are then incorporated into PJM’s load forecasted. (See “1st Read of Proposal on Capacity Obligations Resulting from Large Load Additions,” PJM MIC Briefs: March 6, 2024.)
The committee will be asked to approve the amendments to the issue charge on first read.
Forecast Pool Requirement and Installed Reserve Margin (11:10-11:35)
PJM’s Patricio Rocha Garrido will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2025/26 delivery year to reflect changes to the RTO’s risk modeling and generation accreditation processes following FERC approval of market changes in docket ER24-99 resulting from the CIFP process. The recommended IRM is 17.8% — up from the 17.7% IRM the MRC endorsed in October — and the recommended FPR value is 0.9387, down from 1.1170. (See “Recommended Values for 2023 Reserve Requirement Study,” PJM MRC Briefs: Oct. 25, 2023.)
The committee will be asked to endorse the results upon first read. Same-day endorsement may be sought at the MC.
Members Committee
Endorsements (2:10-2:25)
Forecast Pool Requirement and Installed Reserve Margin (2:10-2:25)
PJM’s Patricio Rocha Garrido will present the updated FPR and IRM figures for the 2025/26 delivery year discussed at the MRC. The MC may be asked to endorse the results upon first read.
The 2023/24 winter season was one of NYISO’s most humdrum winters, characterized by high temperatures, low gas prices and below-average loads, according to a presentation shared with the Operating Committee on March 15.
Aaron Markham, NYISO vice president of operations, told the OC that “moderate temperatures led to moderate fuel prices for much of the season,” and the few “short-duration cold snaps” were not “super impactful.”
He added, however, that those cold snaps meant NYISO needed to burn “a fair amount of stored fuel” and saw “some gas system constraints,” but the ISO would “continue to monitor [fuel] replenishment” and study how to ensure fuel could be delivered more effectively for future peak days.
The season’s coldest period occurred around the Martin Luther King Jr. Day weekend, when load peaked at 22,754 MW on Jan. 17. It was still one of the ISO’s lowest winter peaks over the past 15 years and represents only one of three times during the month when load went above 22,000 MW, which usually occurs an average of 11 times during January.
During the Jan. 17 peak hour, New York’s load was served by an estimated supply mix of 26% natural gas, 14% oil, 17% hydropower, 20% imports from neighboring regions, 14% nuclear, 8% wind and 1% from other renewables.
Markham said one of the highlights for the winter season was the generation fleet’s “very good” performance, especially during the season’s peak load hour, when there was only about “150 MW of unavailable capacity from the day-ahead to real-time.” Additionally, intermittent production during peak days, although “still relatively low compared to the total demand,” continued to “see more contribution to meet demand.”
Markham also delivered the February operations report to the OC, saying the month “continued the trend of mild weather and no real strenuous operating conditions,” with a peak load of 20,981 MW recorded on Feb. 14.
He also mentioned that NYISO expects to “be able to manage” the April 8 solar eclipse and has asked its solar forecast vendor to ensure the eclipse’s impact on solar production is included in the next forecast delivered to the ISO. (See “NYISO Updates,” NY State Reliability Council Executive Committee Briefs: March 8, 2024.)
Thermal and hydro outages by type over peak hours in January’s winter cold snap | NYISO
Bear Ridge Solar Waiver Denial
FERC on March 14 denied Bear Ridge Solar’s waiver request for remedial relief from certain NYISO interconnection tariff requirements, effectively removing the project from the ISO’s queue (ER22-2085).
Bear Ridge aimed to develop a 100-MW solar farm in Niagara County and requested an exemption from two of NYISO’s tariff requirements because of “unforeseen events” that were “beyond its control” and led it to “substantial difficultly” in adhering to state siting processes and critical regulatory deadlines.
As a result of its “failure to comply with the regulatory milestone requirements,” Bear Ridge’s project faced withdrawal from the interconnection queue and risked the loss of a $657,000 cash security deposit necessary to cover its share of the costs for transmission upgrades determined by NYISO to be required for the project’s interconnection.
Although sympathetic to Bear Ridge’s situation, FERC said that granting the waiver would be “retroactive in nature and is prohibited by the filed-rate doctrine” in the Federal Power Act.
In a joint concurrence, Chair Willie Phillips and Commissioner Allison Clements said that although they were bound by the filed-rate doctrine, “the outcome here is neither equitable nor commercially reasonable” and is “emblematic of other waiver proceedings in which an applicant did not foresee that it would miss a deadline before it occurred.”
They acknowledged that FERC’s procedures are rigid and prevent it from granting even a modest milestone extension, which would “avoid sending the project back to the starting gate,” even though Bear Ridge satisfied the regulatory milestone at issue two months after submitting its waiver request unopposed by NYISO.
The commissioners called on transmission providers to revise their tariffs to permit FERC to waive such deadlines to allow the commission “greater flexibility in addressing sympathetic cases such as this one,” recognizing that the outcome “does not advance the goal of getting new resources online as quickly and reliably as possible” and “causes needless inefficiencies and deprives NYISO’s customers of the benefits that such a project provides.”
A lithium processing plant that could help put 800,000 electric vehicles on the road per year has received a conditional commitment for a $2.26 billion loan guarantee from the U.S. Department of Energy’s Loan Programs Office (LPO).
The plant would be in Humboldt County, on the Nevada-Oregon border, at Thacker Pass, where Lithium Americas Corp. and its Lithium Nevada Corp. subsidiary are developing a mine containing the largest proven lithium reserves in North America, according to the LPO announcement, released March 14.
The mine itself would be a shallow, open pit mine, located in a caldera, which is a collapsed volcanic crater, in this case formed millions of years ago. The processing plant would be located next to the mine.
The Thacker Pass lithium mine and processing plant will be located in the McDermitt caldera, a collapsed volcanic crater that was formed about 16 million years ago. | Lithium Americas
Lithium Americas is developing the site in two phases, with production from the first phase expected to total 40,000 metric tons (MT) of battery-quality lithium carbonate per year, according to the company website. A metric ton is 2,204 pounds. The output from Thacker Pass “could support the production of batteries for up to 800,000 electric vehicles,” LPO said.
General Motors also is investing $650 million in Thacker Pass and would receive all the lithium carbonate from the mine’s processing plant for its first 10 years, with an option to extend its contract for five more years. Another plus for GM: The output from the plant would qualify for the Inflation Reduction Act’s EV domestic content requirements and tax credits.
GM also would have a right of first bid for the lithium carbonate produced in the second phase, which Lithium Americas estimates would double output to 80,000 MT per year.
In a project update, also issued March 14, Lithium Americas reported that site preparation is complete, including “all site clearing, commissioning a water supply system, site access improvements and site infrastructure.” Bechtel is the main contractor for Thacker Pass and has entered into a labor agreement with North America’s Building Trades Unions for construction of the project.
Lithium Americas estimates Thacker Pass would create about 1,800 construction jobs and 360 permanent jobs.
The company estimates a three-year construction period, with work to begin pending the finalization of the LPO loan, which the company is anticipating for this year. According to the LPO, finalization would depend on the company achieving specific technical, legal, environmental and financial conditions.
Lithium Americas expects the mine and processing plant to reach full production in 2028. Plans for the second phase of development have yet to be announced.
Lithium Americas CEO Jonathan Evans called the LPO loan a “significant milestone” for Thacker Pass.
The mine will provide the U.S. “an incredible opportunity to lead the next chapter of global electrification in a way that both strengthens our battery supply chains and ensures that the economic benefits are directed toward American workers, companies and communities,” Evans said in the company’s announcement of the conditional commitment.
“The loan plus GM’s strategic investment will provide the vast majority of the capital necessary to fund Phase 1” at Thacker Pass, he said.
The GM Connection
President Joe Biden wants half of all light-duty vehicles sold in the U.S. to be electric by 2030, a goal that has made a swift buildout of a domestic supply chain for lithium and EV batteries a priority for government and industry, as both seek to counter China’s dominance in global markets.
The conditional commitment is the 10th the LPO has made since 2022 under its Advanced Technology Vehicles Manufacturing program, and two additional loans have been finalized during that time, according to the loan announcement.
One of the program’s earliest loans was its $465 million commitment to Tesla in 2010, which was repaid fully in May 2013.
This is the second LPO loan that would benefit GM. In 2022, the office finalized a $2.5 billion loan to Ultium Cells, the joint venture of GM and LG Energy Solution, to help build three plants ― one each in Michigan, Ohio and Tennessee ― to produce lithium-ion battery cells.
The Thacker Pass loan comes as GM has been rethinking its plans for EV production. In 2021, the company committed to sell only light-duty EVs by 2035, but in recent months, it has announced delays in planned production of certain EV models as sales continue to increase, though not at the pace the automaker originally projected.
During a January earnings call, GM CEO Mary Barra said the company’s plans for 2024 include the production and sale of 200,000 to 300,000 Chevrolet, GMC, Cadillac and BrightDrop EVs, all using Ultium batteries. BrightDrop is the company’s electric delivery van. Barra said GM also will bring back plug-in hybrid models for “select vehicles in North America.”
GM’s last plug-in hybrid was the Chevy Volt, which was discontinued in 2019. Barra hedged the company’s plans, saying GM’s ramp-up of EV production will follow customer demand.
The Thacker Pass mine has been controversial for some environmental and tribal groups, which have repeatedly but unsuccessfully gone to court to try to stop construction. The Bureau of Land Management approved the project in 2021 and reconfirmed that decision in 2023, following a court ruling that ordered the agency to perform a further evaluation.
The most recent legal challenge ended in November 2023, when a federal district court in Nevada dismissed a claim by tribal groups that the mine was near a sacred site, as reported by the Associated Press.
Environmental groups also have raised concerns about the mine’s potential use of ground water, a frequent challenge for lithium mines. However, Lithium America’s website notes the Thacker Pass open pit mine would be less than 400 feet deep, relatively shallow for an open pit mine, which could make it less likely to affect groundwater.
The project also has been designed ― and permitted by the Nevada Division of Environmental Protection ― to minimize any use of groundwater; plus, any water used on the site would be recycled at least seven times.
In addition, the company has a community benefits agreement with the Fort McDermitt Paiute and Shoshone Tribe, the closest tribe to the project, according to Lithium Americas. The company has offered job training for tribal members to prepare them for jobs at the project.
MISO discussed the second part of its long-range transmission planning (LRTP) project at a stakeholder workshop March 15, detailing how the project would help meet Midwestern transmission needs.
Tranche 2, the proposed transmission portfolio, includes a series of 765-kV lines intended to “enable a reliable and efficient transmission system while minimizing land use” as the region copes with increasing electricity demand and a changing resource mix. The project is projected to cost between $17 billion and $23 billion. (See MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV.)
“This anticipated portfolio builds on both the investment made in Tranche 1 and our existing system,” said Laura Rauch, executive director of transmission planning at MISO. Rauch added the proposal is intended to be a “least-regrets and robust step” to start solving anticipated transmission constraint issues and enable increased regional power flows.
MISO’s initial analyses indicate the transmission investments would significantly reduce thermal transmission constraints and the severity of overloads across the Midwest. The portfolio would also reduce resource curtailments throughout the region and decrease price differences between regions, MISO said.
The grid operator outlined its plans to quantify the portfolio’s potential savings from reduced losses, avoided capacity costs and decreased transmission outages, and asked for stakeholder feedback on the proposed methodology.
Tranche 2 is not intended to address all the potential regional transmission constraints, and “there is a need for additional transmission after this Tranche 2 portfolio,” Rauch said. She declined to specify the timing or targeted areas of this additional transmission.
Rauch stressed that the first phase of Tranche 2 proposal must be “independently valuable regardless of what next steps we might have.”
MISO expects the portfolio to “continue to be refined,” Rauch said. The RTO will continue to consider alternative solutions that could affect the outlined routes.
“We will make sure that we are not proposing a line that will not be valuable because of something that will be in service,” responded Rauch.
“There are legitimate questions about Grain Belt Express,” Rauch said, but added that MISO will address whether the merchant transmission project is likely to address issues similar to those met by Tranche 2 and adjust accordingly.
Some stakeholders expressed concern the portfolio is not based on the planning scenario that assumes the highest level of load growth and renewable energy penetration. MISO responded that running an additional analysis based on the more aggressive scenario would add six to nine months to the overall process, while the proposed portfolio would likely remain a good first step.
“We can’t continue to kick this can down the road; we need to start moving forward,” said Bob McKee of American Transmission.
McKee added his support for the consideration of 765-kV lines, saying stakeholders “should not be surprised that 765 is showing up on this map … it’s been two years that we’ve been talking about the possibility of 765.”
While MISO determined 765-kV lines make the most sense for Tranche 2, the RTO said it will continue to consider HVDC solutions in future proposals.
Asked whether grid-enhancing technologies (GETs) are part of the solution to the transmission constraints, Rauch said GETs are unlikely to supplant the needs of the proposed Tranche 2 lines but could complement the upgrades and help the grid operator get the most out of the infrastructure.
Federal regulators have finalized their proposed wind energy area (WEA) in the Gulf of Maine.
The zone has been trimmed, slashed and reshaped repeatedly since the U.S. Bureau of Ocean Energy Management began to gauge commercial interest in a 13.7-million-acre zone south of Maine.
After carveouts to avoid fishing and lobstering grounds, key wildlife habitats and cultural resources, the final WEA that BOEM announced March 15 totals approximately 2 million acres.
Even with the reductions, the area is believed to hold the potential for up to 32 GW of offshore wind development.
The WEA is 23 to 92 miles from land and stretches across water far too deep for wind turbines with fixed-bottom foundations, like those being built farther south along the New England coast.
Wind power development in the Gulf of Maine would rely instead on floating turbine technology that is being refined, including at the University of Maine. Maine hopes to be a leader in this new subsector and is separately pursuing BOEM approval of a research lease to place up to a dozen floating turbines closer to shore.
With the WEA finalized, BOEM will assess the potential environmental impacts of wind power development there and decide whether to proceed to leasing.
Multiple public comment periods have been opened so far, and more are yet to come. BOEM said this engagement has helped shape the WEA and will continue to be incorporated into the plans.
Maine’s governor and congressional delegation had pressed BOEM to remove a key lobster management area from the WEA. In a joint statement March 15, they said:
“We appreciate that the Bureau has heeded our concerns and the majority of the concerns of Maine’s fishing communities in its final designation of wind energy areas for the Gulf of Maine. This decision preserves vital fishing grounds and seeks to minimize potential environmental and ecological impacts to the Gulf of Maine. We look forward to reviewing the final map in detail and urge the Bureau to continue to engage with Maine’s fishing industry, coastal communities, tribal governments, and other key maritime users and stakeholders as the commercial leasing process moves forward.”
As indicated in their statement, not every stakeholder priority was entirely addressed.
The Maine Lobstermen’s Association told local media it appreciated some of the most important fishing areas being removed from the final WEA but said too many unanswered questions remained about the impact of wind power development in the Gulf of Maine.
New England for Offshore Wind said more efforts are in progress to avoid and minimize use of areas of historic and cultural significance to Maine’s tribal nations.
Maine Audubon said the announcement was an important step in the right direction, but it would pursue more wildlife safeguards.
But overall, many labor and environmental advocacy groups were pleased with the WEA.
“Maine is setting an example for the rest of the nation for responsibly developing offshore wind, balancing the needs of coastal communities and wildlife protection with the urgency to address climate change — the greatest threat facing our woods, waters, trails and coastlines,” said Jack Shapiro of the Natural Resources Council of Maine.
“BOEM’s announcement today reflects a major step forward for responsible and equitable offshore wind development in the Gulf of Maine,” said Kelt Wilska of New England for Offshore Wind. “New England is once again setting a national model for reducing potential conflicts during project construction and respecting the critical role that heritage fishing industries play in our economy.”
