Big Oil and Pure Players are Leading Smackover Lithium Project Development: The Potential is There to Move the U.S. from Producing 1% of Global Supply to 20% or More

     Jordan Blum wrote an interesting piece in Fortune Magazine about upcoming lithium sedimentary brine projects being developed in the Smackover Formation, where direct lithium extraction (DLE) will be utilized. The article gives an update and timelines on ongoing projects and the plans of developers. These developers include Big Oil companies like ExxonMobil and Chevron and pure-play companies like EnergyX and Standard Lithium, which focus on brine extraction.

     With global lithium demand rising 400% this decade to 1.5 million metric tons per year for batteries to power grids, EVs, data centers, and automation, the demand is set to stick around for a while and will likely rise even higher. The U.S. only produces 1% of global supply, mainly from a single mine, the Silver Peak Mine in Nevada. However, other sources utilizing DLE are getting closer to coming online in the Salton Sea region of California and especially in the Smackover Formation in Southern Arkansas, East Texas, and Northwest Louisiana. Smackover brine has very high concentrations of lithium. Standard Lithium believes its leased land alone can produce 150,000 metric tons per year, about 10% of current global supply. The company is expected to initiate its Southwest Arkansas Project late this year and begin construction in 2027. Below is some information about Standard Lithium's Projects.

     Another company, EnergyX, led by Elon Musk acolyte Teague Egan, might break ground on a smaller 15,000 metric tons per year project in Texas next year after finding success at its 250-ton pilot project. They have plans to expand to 50,000 metric tons per year by 2031.

     ExxonMobil holds net 400,000 acres in the Smackover lithium play and plans a pilot project for 2027. Chevron holds 125,000 acres in the play. The process is simply to drill wells, produce the brine, extract lithium and a few other components like bromine, and return about 90% of the brine to the formation. There are no evaporation ponds. It has about 1% of the land footprint compared to production in the Lithium Triangle of South America. Norway’s Equinor is another late entrant in the play, entering as a joint venture partner.

     However, some challenges remain. DLE has yet to be proven at scale. DLE can extract lithium much faster than waiting for water to evaporate and precipitate the solid lithium. China does not lead the world in lithium mining but leads it in lithium processing. DLE offers a competitive processing method. Below is Standard Lithium's schematic model for a DLE plant.

     The article mentions the Thacker Pass project in Nevada, which is a 40,000-ton open-pit clay mine, which could be completed by the end of 2027. It could potentially produce 160,000 metric tons per year when it reaches peak production. Thus, it seems fair to predict that in five years or so, the U.S. could be producing much more domestic lithium.

     Standard Lithium notes on its website that it is continuing research into producing lithium sulfide (Li2S) for next-gen solid-state battery chemistries. They are working with a partner, Telescope Innovations, to convert lithium hydroxide into lithium sulfide via a simple, low-temperature process.

 

 

 

References:

 

A ‘geologic freak’ called the Smackover may end America’s lithium dependence on China, and Big Oil is already there. Jordan Blum. Fortune. November 7, 2026. A ‘geologic freak’ called the Smackover may end America’s lithium dependence on China | Fortune

The Future of Lithium in North America. Standard Lithium. Website. Standard Lithium Ltd.

Cooperative Federalism Can Work to Support Both Economic and Environmental Goals, Argues Director of ALEC Task Force, Lora Current, in Op-Ed about EPA’s Methane Emissions Revision

     On October 27, 2026, the EPA announced a revision of the Biden Methane Emissions rule known as OOOOb/c. Trump and EPA chief Lee Zeldin announced the changes in Lubbock, Texas. A major part of the change, and one that I agree with and have long advocated for, is that producers of marginal wells be exempt or at least given a lot more time to comply. There are many marginal wells being produced by small operators in the U.S. who do not make high profits, and their costs to comply can be prohibitive. Apparently, from reading the EPA announcement, this has caused many of those small operators to shut in their marginal wells earlier than expected.

     Back in March of 2025, I wrote and compiled a post about compliance with the rule. It seemed a bit overly complicated then. While I thought the Zeldin EPA’s announcement was a bit anti-Biden, it described the rule as burdensome and unworkable. For those with marginal wells, that is likely true. However, I think that most major producers are not having any major issues with compliance.

     It’s worth noting that the rule is still in place and has simply been tweaked. The EPA provided the following summary of changes, which includes rolling back the super-emitter program, giving different compliance requirements based on well production, allowing repairs of covers and closed vent systems, adding flexibility for flame monitoring, and preferring 95% combustion flaring over requiring associated gas to go directly to sales lines. I agree with most of these aside from the flaring rollbacks. Flaring remains a serious issue in the Permian Basin and in North Dakota, where far more associated gas is flared and vented than needs to be. It is here that state rules may override federal rules in states with primacy granted by the EPA. This is where cooperative federalism comes into play. I wonder if this will result in higher flaring rates than the already high flaring rates in the Permian Basin. 

     While the EPA says that the rule changes could reduce regulatory costs by $45 billion while allowing an estimated 210 million additional barrels of oil and 1.41 trillion cubic feet of natural gas to be produced, I am skeptical that those numbers are correct and may be way off.

     Cooperative federalism is when federal agencies, such as the EPA, empower states to make rules and ensure compliance. Lora Current of the American Legislative Exchange Council (ALEC) noted in August that Zeldin’s EPA has been promoting cooperative federalism, as did previous Trump EPA leaders. There can be many advantages to ceding rulemaking and compliance to states. It makes sense for efficiency and the many regional variations in environmental issues. States are often better situated to manage environmental protection. Current wrote:

“The federal government has an important role in administering federal environmental laws, but states and local governments bring knowledge that federal regulators cannot replicate from Washington. Cooperative federalism allows each level of government to fulfill its appropriate responsibilities while giving states room to develop policies suited to their circumstances.”

     She also noted that there is a newly revitalized Local Government Advisory Committee that is set to deal with AI data center development, especially siting concerns.

     In a recent op-ed in Real Clear Energy, Current touted the usefulness of cooperative federalism in EPA’s revamped methane rules. She notes that EPA is seeking input from states and operators about how regulations can better reflect regional variations in environmental and economic conditions. She praises cooperative federalism as the best approach, and I agree. It is the most sensible approach and probably the fairest approach as well. She concludes:

“Environmental stewardship is strongest when government respects those closest to the issue, markets are allowed to work, and states retain the authority to lead.”

“That is not a retreat from environmental protection. It is a return to federalism.”

“EPA will accept public comments for 45 days following publication in the Federal Register. This provides states and stakeholders with an important opportunity to advocate for greater state flexibility and a final rule grounded in cooperative federalism.”

 

 

 

References:

 

Trump EPA Applies Federalism to Environmental Regulation in Reform of Over-the-Top Oil and Natural Gas Rules. Lora Current of ALEC via Real Clear Energy. November 7, 2026. Trump EPA Applies Federalism to Environmental Regulation in Reform of Over-the-Top Oil and Natural Gas Rules

EPA Proposes Major New Revisions to Burdensome, Unworkable Biden-era Oil and Natural Gas Regulations. October 27, 2026. U.S. EPA. EPA Proposes Major New Revisions to Burdensome, Unworkable Biden-era Oil and Natural Gas Regulations | US EPA

Restoring Federalism at the EPA. Lora Current. ALEC. August 19, 2026. Restoring Federalism at the EPA - American Legislative Exchange Council - American Legislative Exchange Council

 

Bio-CNG vs. Bio-LNG and CNG vs. LNG for Trucking: Different Advantages in Different Markets

      Bio-CNG is biomethane, which is purified biogas, compressed into pressurized cylinders. Bio-LNG trucks can carry more fuel and travel more miles between fill-ups. However, it costs more to liquefy the gas. Biomethane is liquefied via cooling to very low temperatures and stored in insulated tanks. More LNG than CNG can fit into a comparable-sized container. That means LNG fuel tanks for long-haul trucks can carry much more fuel than CNG trucks.

     According to Elastia:

“In the UK, provisional figures put bio-LNG supply at about 59,000 tonnes in 2025, up from 41,000 tonnes in 2024. Bio-CNG remained the larger market, rising from about 63,000 to 75,000 tonnes.”

     A commenter added:

“In UK road transport is about 50/50 CNG to LNG. In Germany, NL its 90% LNG.”

     In the U.S., biomethane in the form of renewable natural gas provides about 94% of the natural gas road fuel. This is mostly CNG for fleet vehicles and short deliveries.

        In the U.S., biomethane in the form of renewable natural gas provides about 94% of the natural gas road fuel. This is mostly CNG for fleet vehicles and short deliveries.

     LNG can offer advantages to ships, buses, trains, and heavy-duty vehicles, including lower fuel costs, lower pollution, and lower carbon emissions, compared to diesel.

     According to ExxonMobil:

“LNG has the greatest amount of energy per unit of mass of all conventional fuels. It packs the best punch for its weight.”

     LNG for mining vehicles and as a bunker fuel for ships is growing. ExxonMobil notes:

“In trials by a USA railway the LNG locomotive cost approximately 23% less to fuel on an energy equivalent basis compared to diesel fuel. The LNG switcher locomotive established an estimated 92% reduction in nitrogen oxides (NOx) and 76% less particulate matter (PM) compared to the baseline (uncontrolled) diesel locomotives. (Report by Patrick Couch Jon Leonard Helena Chiang, April 2010.)”

     Fleetworks compares CNG and LNG below:

     Most natural gas engines are spark-ignited. Cummins, Westport Fuel Systems, and other OEMs make the engines. A more advanced natural gas engine utilizes high-pressure direct injection (HPDI), where a small amount of diesel is injected for ignition. These engines give a more diesel-like performance. They run on 95% natural gas. Natural gas-powered transport offers significantly lower fuel prices, although prices vary by region. Lower maintenance is also a feature of natural gas engines. They may also be eligible for tax incentives. Environmentally, they offer much lower particulate matter, much lower NOx, much lower carbon emissions, and quieter operation.

     In the U.S., natural gas for transport is limited by infrastructure. According to Fleetworks, there are about 1000 CNG gas stations in the U.S. There are about 140 LNG gas stations along major transportation corridors. California, Texas, and the Northeast Corridor have the most.

     Upfront costs are a barrier for natural gas trucks, but those costs can be recouped over time in fuel savings, maintenance savings, and incentives.

“Natural gas trucks typically cost $30,000 to $80,000 more than comparable diesel trucks. This premium must be offset through fuel savings, incentives, or other operational benefits over the vehicle's lifecycle.”

     Since CNG trucks are bulkier and heavier, they are more suited to local and regional deliveries. They also require more frequent refueling. LNG trucks require specialized tanks. Both types, but especially CNG trucks, have reduced payload capacity due to the size of the tanks. CNG trucks have become a standard for waste and refuse hauling. Many of those run on biogas and biomethane (processed biogas), which in many cases is also called renewable natural gas (RNG), which comes from landfill gas collection systems. CNG trucks are being used more at ports where air quality concerns are great, and there may be more stringent requirements.

       Fleetworks estimates that the payback periods for natural gas trucks are 3-7 years. After that, the benefits of lower fuel and maintenance costs accrue. With the current very high diesel prices and low natural gas prices, those running on CNG or LNG are saving quite a lot over diesel rigs.

 

 

References:

 

 

Elastia. LinkedIn post. November 5, 2026. (22) Feed | LinkedIn

LNG for Transport. ExxonMobil. 70-lng-for-transport.pdf

Understanding Natural Gas Trucking in the Freight Industry. Fleetworks. Natural Gas Trucking Guide: CNG & LNG for Freight Carriers

 

BAAJA and Streamlining Permitting Disempowers Radical Environmental Groups, Which is Why They are Leading the Opposition: Alex Trembath Debunks Their Claims

      For decades, the more radical environmental groups have survived and prospered by opposing energy and infrastructure projects. They have succeeded in denying and delaying projects of all kinds. They have been able to do this by taking advantage of current permitting rules and through endless litigation. By exploiting these rules and finding sympathetic judges, they have succeeded in stopping and delaying pipelines, transmission projects, solar and wind farms, fossil power plants, hydroelectric projects, and many other projects. If the rules are changed to give them less leverage to affect these needed economic projects. The new rules will make permitting slightly less expensive and much faster. It will aid companies by making it easier for them to plan with more certainty.

     Yesterday, when I was driving, I heard Democratic Rep. Jared Huffman, who is set to take over as chair of the House Natural Resources Committee next year, speaking on the NPR environment show, Living on Earth. He stated that he wants to delay the Bipartisan American Affordability and Jobs Act (BAAJA) bill, set for debate this week, in order to get a deal more favorable to Democrats next year. This is a bad idea, and hopefully it won’t happen. This bill has been decades in the making and is closer than ever to a truly bipartisan solution that, frankly, benefits all parties: developers of all forms of energy, clean energy advocates, and streamlines processes that should have been streamlined a long time ago. The more radical environmental groups are pretty much the only faction that does not benefit. They have held unwarranted power for too long. Trump did a similar thing before he was re-elected with bipartisan border legislation, holding out for a better deal after he was elected. He ended up more or less bypassing Congress, with success at the border, but failure with the ICE chaos.

     Alex Trembath debunked some of the environmentalist claims about the bill in an article for the Ecomodernist. He notes that Huffman wants to gut the bill and only keep the power transmission reforms. That is a non-starter, in my opinion. Trembath notes that he and his colleagues at the Breakthrough Institute have argued for years that reforms to the National Environmental Policy Act (NEPA), the Clean Water Act (CWA), and the National Historic Preservation Act (NHPA) would benefit clean energy infrastructure. Trembath calls the environmentalists’ arguments misleading, their analysis “cockamamie,” and outright bullshit. He takes six of their arguments, ranging from absurd to more reasonable, and debunks them.

     The first claim he debunks is the absurd claim that the bill would allow Trump to build a coal plant in the Grand Canyon, put forth by Friends of the Earth. He simply notes that the National Park Service Organic Act of 1916 prevents such a thing and that air quality standards are higher in national parks than elsewhere. No one would want a coal plant there in any case.

     The ACLU apparently claims that BAAJA would allow ICE to build out an immigrant detention system far more easily. Here, Trembath simply notes that detention centers more than doubled from 134 in January 2025 to 272 in July 2026 according to the Migration Policy Institute, with only about three of them facing NEPA issues. That is a very small percentage and not statistically significant. He also takes down John Podesta’a claim that BAAJA would allow illegal permits to stand. Trembath simply states that there is a provision in the bill that addresses that and if the permits are found to be illegal, they can be revoked.

     Next, he considers Abigail Dillen’s claim that BAAJA “would bar consideration of new information and science, while significantly increasing deference to federal agencies to define the scope of their reviews.” Trembath counters:

“Reality: BAAJA codifies and specifies the timelines for environmental review, statutes of limitations, qualifications for standing in litigation, applicable interventions under judicial review, and the criteria that can be considered before issuing permits. These specifications are necessary after decades of procedural bloat, as agencies have found new ways to expand the scope of environmental review, litigants have engineered new premises under which to sue projects, and courts have pursued winding and inconsistent paths in hearing lawsuits and reviewing permits and other infrastructural legal qualifications.”

     He gives two examples: Trump holding up offshore wind development and Biden cancelling oil and gas lease sales and holding up LNG terminal development. Both would have less power to do these things under BAAJA.

     Next, he takes on Jared Huffman’s claim that “BAAJA increases both GHGs and premature deaths from air pollution.” Here, he cites studies that suggest emissions will drop under BAAJA, presumably due to clean energy projects coming online faster. He criticizes the one study Huffman cited, calling it counterfactual and saying most studies suggest lower emissions. However, I would caution that U.S. LNG demand is set to rise and power demand continues to rise due to data centers. Natural gas will be needed to feed that demand. U.S. LNG and oil are both in heavy demand around the world. That means oil & especially gas production is likely to rise in the near term, and that means higher emissions. However, the emissions gains will be partially offset by clean energy projects. Thus, I think Trembath does not make a great case here.  He does point out that natural gas can still continue to replace coal and fuel oil where applicable, in New England, for instance, thereby reducing emissions.

     Next, he takes on the Climate Justice Alliance’s claim that BAAJA would “would gut bedrock environmental laws created over half a century ago.” He writes:

“Reality: BAAJA would curtail, and in some cases consolidate, federal requirements for environmental review and community consultation under multiple regulatory statutes. This is far from a repeal or “gutting” of legacy environmental laws.”

     He notes and explains below that the big issue with NEPA is environmental review, which is procedural, not statutory.

“It’s important to remember that the specific form that federal agencies have adopted to conduct environmental reviews is a procedural development, not a statutory requirement of NEPA. These reviews have become more sprawling and unmanageable over time, vulnerable to often frivolous litigation brought by activist groups and subject to unpredictable and unconstrained judicial review. BAAJA would expand the use of Categorical Exclusions (itself a kind of environmental review) for certain classes of project, specify the criteria relevant to reviews, permit alternative reviews from states or other agencies to satisfy the review requirement, and establish deadlines for both environmental review and litigation.”

     He notes that BAAJA would also reform public engagement and consultation, an area where environmentalists routinely flood public comments airwaves with anti-project sentiments.

     Lastly, he takes on the Wilderness Society’s claim that BAAJA “would sell out our shared public lands to fossil fuel drilling, hardrock mining and AI data centers, silence public input and erode Tribal sovereignty.”

     Here, he argues that the views of tribes are varied, and many important tribal groups and voices support infrastructure projects. He also confirms that while the more radical environmental groups oppose BAAJA, many environmental groups, including the more mainstream ones, are more neutral or even support it.  

“While figures like Bill McKibben and David Bookbinder, and groups like Earthjustice and the Center for Biological Diversity, have come out guns blazing, organizations like the Natural Resources Defense Council and the League of Conservation Voters appear to be hedging their bets, criticizing the bill while refraining from formal opposition.”

     Trembath also writes that BAAJA will be reworked before it gets into a passable form and in the coming years more tweaks will be needed, especially for things like judicial and environmental reviews.

“Further reforms outside the scope of BAAJA will almost certainly be needed in the coming years, on issues ranging from further consolidation of judicial review, normalization of environmental review across agencies, and reforms to other federal statutes that are implicated in NEPA and broader environmental regulation.”

     He notes the sad facts of the past decades of empowered radical environmentalist groups wielding power to deny and delay important energy and infrastructure projects.

“Environmental regulation has become a vehicle for activist litigation and fundraising.”

     I would change that from “has become” to “has long been.” It’s time to weaken the radicals and make environmental review fairer, faster, but still keep it effective. There is no reason that cannot be done. The radical environmentalists do not have sound arguments and have been reveling in their ability to sink projects for too long. Pass BAAJA before year’s end!

 

References:

 

On Anti-BAAJA Bullshit. Debunking the Case Against Permitting Reform. Alex Trembath. The Ecomodernist.  Ovember 6, 2026.  On Anti-BAAJA Bullshit - by Alex Trembath

NYC’s Subterranean Thermal Battery Plans to Utilize Waste Heat, Passive Groundwater, and Bidirectional Borehole Energy Storage: Cools Subway Heat in Summer and Provides Water and Space Heating for Nearby Buildings in Winter

     New York City’s Manhattan is planning to decarbonize subway heating and cooling by capturing waste heat from the trains, storing it underground in groundwater aquifers, and drawing heat from the warm granite-stored water in the inter and drawing cooler water from deeper groundwater wells in summer.

     Underground subway platforms can be very hot in summer during heat waves with heat indices exceeding 132 F (55 C) and ambient air temperatures up to 15 degrees hotter than street level. This is because surfaces and tunnel masonry absorb radiant heat from braking trains, passenger crowds, and train air-conditioning exhaust. These conditions can create dangerous conditions for passengers and transit workers.

     Jay and Mimi Egg of Egg Geo have written about the details of the project. They refer to the project as a subterranean thermal battery. It seems to be a viable project that can result in better conditions for passengers and transit workers. Below, they lay out the challenges of cooling the subway platform areas and why traditional methods are not applicable:

“For mechanical engineers, MEP designers and trade executives, the traditional instinct might be to specify higher-tonnage chillers or forced-air split systems. However, in an unsealed, 100-year-old mass transit system, conventional mechanical air conditioning is a physical nonstarter. There is simply nowhere to place massive, air-cooled condensers or chiller plants in the extraordinarily congested urban landscape above.”

“Even if space could be strategically found for cooling towers, those towers pose severe public health risks due to Legionella outbreaks. As New Yorkers well know from recent summer outbreaks and fatalities, cooling towers are not the answer.”

“Furthermore, attempting to cool subway caverns by rapidly moving forced air through the tunnels is equally a nonstarter. High-velocity airflow picks up heavy steel brake dust, particulates and floor debris from subway surfaces, quickly clogging equipment fins, choking condensate pans and degrading indoor air quality. Consequently, the only physically viable answer for transit platform cooling is hydronic radiant cooling.”

 

Passive Groundwater Exchange Cooling

     Metropolitan Transportation Authority (MTA) already operates many dewatering wells and hundreds of pump rooms that continuously move groundwater at a naturally stable 55 F to 66 F (13 C to 19 C) to keep tunnel structures dry. They can also utilize this infrastructure for space cooling. Below is a model of the system and an explanation of how the passive cooling system works.

“In a passive direct-exchange configuration, cold 55 F to 60 F groundwater is drawn from a single-point dewatering well in a natural bedrock fracture and passed through a high-efficiency plate-and-frame heat exchanger to achieve hydraulic isolation. On the secondary side, a closed water-and-glycol loop circulates chilled fluid (at approximately 58 F) through ceiling-mounted hydronic radiant cooling panels installed over platform waiting areas.”

“Because platform surfaces and ceiling vaults regularly exceed 110 F (43 C), natural radiant heat transfer occurs directly between passengers, masonry surfaces and the cool overhead panels — stabilizing platform temperatures down to an 80 F to 85 F baseline without moving dusty air.”

“Once the primary groundwater stream transfers its heat across the plate heat exchanger, the thermally neutral water exits and is safely discharged to surface waterways as currently routed. On the secondary closed loop, the absorbed 90-plus F platform heat is directed into a vertical closed-loop borehole field drilled into Manhattan schist bedrock.”

“This creates a high-density borehole thermal energy storage (BTES) battery, banking the 90 F heat plume underground for winter extraction by municipal building thermal energy networks (TENs).”

     Below, they explain the advantages of the passive cooling system over alternatives. These include minimal electrical consumption from small, low-horsepower fluid-circulation pumps, instead of power-hungry compressors; no forced air movement, which means less tunnel dust, relief from summer heat, and heat storage for winter.

The Importance of Making the Geothermal System Bidirectional

     The authors also stress the important features that a bidirectional geothermal system provides, especially in preventing what is called ground thermal saturation, where fluid-to-ground temperature differentials are degraded, negatively impacting efficiency in a unidirectional cooling system. Egg Geo has retained senior hydrogeologist John Rhyner, P.G., an expert on these types of systems with extensive experience in NYC’s systems. He notes from experience that maintaining long-term subsurface energy balance requires a bidirectional system. Moving the heated groundwater out of storage in the winter to provide space and water heating for nearby buildings provides the needed bidirectionality.

     Closed-loop borehole systems have proven to be effective worldwide for passive cooling and winter heating via heat pumps. Like any heat pump, the cycle is reversible. They also note that during winter, the stored warm groundwater can also run sidewalk snowmelt loops.

     The logistics of drilling and piping have been solved in part by utilizing the Chambers Street station complex, which contains an abandoned center island platform that has been closed to passenger traffic since 1931. Here, they can operate without closing streets off or affecting trains or surface traffic. The conditions underground also require 100% electric, sonic drill rigs due to the dangers of carbon monoxide and other pollution. As they note below, drilling through the Pleistocene glacial till and alluvium can be challenging. Casing must be driven and set deep into the competent metamorphic schist bedrock for both the closed-loop well systems and the dewatering wells.

     Infrastructure to deliver the heated groundwater involves insulated underground hydronic lines. Selling the heat to nearby buildings creates a revenue stream to help sustain the project. The project benefits by meeting the city’s carbon emissions requirements. The project also takes advantage of federal tax credits of 30% to more than 40% for geothermal network installations.

     Below, they list some implications for mechanical engineers and plumbing professionals.

     This is a really interesting project, and it is likely that other cities can adopt similar projects. It should be interesting to see how well it performs. However, it is still in the early stages, with an $800,000 feasibility study currently underway to determine geothermal viability and the design phase expected in early 2027, if the project is determined to be feasible. According to New York Weekly, the geothermal wells will be drilled 500–600 ft deep beneath Chambers Street’s disused platform.

References:

 

The Subterranean Thermal Battery: Decarbonizing NYC Transit via Geothermal and Passive Groundwater Energy Networks: By harvesting waste heat, using passive groundwater exchange and managing subsurface thermodynamics, mechanical professionals are turning urban transit liabilities into clean, resilient energy infrastructure. Mimi Egg and Jay Egg. PHCP Pros. November 2, 2026. The Subterranean Thermal Battery: Decarbonizing NYC Transit via Geothermal and Passive Groundwater Energy Networks | phcppros

NYC and MTA Launch $800,000 Study to Cool Subway Platforms Using Thermal Energy at Chambers Street Station. New York Weekly. August 11, 2026. NYC Subway Thermal Energy Network Study Chambers Street 2026 - New York Weekly

Fervo May Be Overhyped: Challenges Include Parasitic Injection Loads, Water Loss, and Temperature Decline, and Their EGS Model May Struggle to Become Profitable, According to Operational and Financial Analysis by Elliot Yearsley

      I recently saw a Facebook ad from ‘Behind the Markets’ that said: “The largest energy source on Earth was found near the Grand Canyon, and Wall Street hasn’t caught on yet.” I have seen other memes hyping Fervo’s FORGE project in conjunction with the DOE as well. While Fervo has crossed some excellent milestones in its Enhanced Geothermal projects, one it has yet to cross is proven profitability. What those ads don’t say is that after the company’s IPO, shareholders have lost $10 billion since its stock price peaked in May. However, according to Elliot Yearsley, in an article for GeoExPro, Fervo may have worse problems than that going forward.

     As a clean energy technology, geothermal has significant bipartisan support. It can provide baseload energy, where applicable. Where it is applicable is where there is relatively shallow subsurface heat, or a higher geothermal gradient, and that keeps it geographically limited to the U.S. West and Southwest, generally not too close to population centers, except in California, where conventional geothermal has long been developed at high costs. Can Fervo’s EGS model, which can be produced in hot rock that is also dry rock, be competitive with conventional geothermal? Maybe and maybe not. If it could be profitable, it could expand the limited geographical area where geothermal could be developed, but it would still be mostly confined, more or less to the same regions, and would not require tapping directly into hydrothermal systems, which can create operational challenges like corrosion, induced seismicity, and drilling difficulties like lost circulation.

     Dave Waters, a geoscience consultant at Paetoro Consulting UK Ltd., noted in a LinkedIn post about EGS risks that only about 2 or 3 projects globally are producing commercially, but none has proven life-cycle commercial success. Fervo has clearly found significant technical successes, including operating in hotter rock, drilling faster, drilling cheaper, etc., but operational reliability and power production metrics are now the challenges. Fervo needs to be able to increase its cash flow organically by producing significant amounts of power and keeping it in production. It is nowhere near that point now, and despite its technical improvements, its planned projects still have high upfront costs. Waters’ post emphasizes that long-term success is an important metric for geothermal projects and considerable uncertainty will remain until more long-term analysis is available, which will take time. Simply meeting initial LCOE targets may not be enough if there are operational problems, drops in flow rate, water loss, and thermal decline that manifest over time. These unknowns keep EGS risky.  Waters writes:

“We have a handful of commercial production projects, all quite geologically different, progressing to different productions in different commercial environments, and it will be some decades before the extent of any commercial success or failure is truly, fully known.”

“LCOE of geothermal EGS, being a retrospective look at costs and rewards from a success case plant perspective, does not on its own provide a useful comparison with the LCOE of surface options that have relatively low risk of commercial failure - i.e. compared to subsurface routes with very big expenditures before any technical feasibility is or is not demonstrated. The inherently unrisked nature of LCOE calculations underestimates the relative cost of options with significant pre- (or post-) FID risk.”

     Geothermal, in general, has been annoyingly overhyped in the media. These new technologies can expand geothermal’s geographic range and improve its economics a bit, but the economics remain challenging and it sure as hell cannot compete with fossil fuels, which will remain much cheaper. Scaling geothermal will take decades, at least. Commercialization of EGS and AGS is just beginning and has yet to be proven economically viable. Technical challenges remain as well.

     Yearsley’s article in GeoExPro explores some of those challenges by examining Fervo’s models, the operations data they have released (and withheld), and the likely operational problems encountered. He examines parasitic pump loads, which are considerable with the injectors. He also explores the company’s value and financing schemes. Yearsley and Henk Kombrink pointed out in November 2024 that Fervo overstated the expected flow rate and underestimated the pressure loss between the injector and producing wells at its Project Red in Nevada. Yearsley and Kombrink predicted that the power output would be 1.3 MW rather than the 3.5 MW Fervo was touting. In an April 2026 article, they note that their suspicions were confirmed as output for the project was estimated at 1.4 MW. They missed their target due to higher thermal decline than expected and more water loss than expected. The data also suggests that pressure drop was higher than expected. Higher pressure drop means that injection pressure would have to be increased via powered pumps, resulting in higher parasitic loads on the system. Fervo blamed the issues as first-of-a-kind problems that would be overcome in their Cape Station Project. Yearsley also suggests that Fervo has not been forthcoming with all of its data.

“At Cape Station, Fervo’s self-published paper in 2024 claimed that a 30-day production test achieved “a sustained output of 8-10 MW”. But the production rate was in fact not shown by their own data to be sustained over the 30 days, or even during the brief period of data that was shown. Fervo omitted the production rate data for 29 days of the 30-day test and did not include any injection rate data.”

“They also neglected to deduct the power required for the re-injection pumps, which used about 30% of the gross power ascribed to the production well (See Appendix 1 for pump power calculations).  Critical questions of well productivity, production decline, and water loss were left unanswered at the time, and are still unanswered more than two years later. No further well test results have been shared by Fervo, a surprising omission considering that this is an unproven technology with no operating history.”

“To increase the production rate at Cape Station over Project Red, Fervo drilled longer horizontals, used two injection wells to one production well, and also significantly increased injection pressure.”

“The result was still dismally low net power produced per well drilled, much lower than conventional geothermal wells. This low well productivity is likely the main contributor to the stubbornly high development costs at Cape Station, which has apparently finally dawned on Fervo. Only days before their IPO, Fervo revealed that their capital expenditures (Capex) would be $7,000 per installed kilowatt of capacity, not the $6,000/kW that they had predicted just the year before.”

     Another issue they bring up is that they are using gross capacity rather than net capacity, failing to deduct the 30% parasitic load penalty due to reinjection. That brings their maximum possible capacity factor/utilization rate to 70%. There will still be inevitable thermal decline and some maintenance issues that will drop capacity factors further. The authors looked at a nearly perfect scenario with a capacity factor of 67% and a more realistic capacity factor of 50%. The 67% scenario was calculated to an internal rate of return of 6%, and the 50% scenario has an IRR of just 3%. They calculated the cost of capital at 7%. Thus, an IRR below 7% is below breakeven and loses money. If Fervo can drop its Capex to $5,500/kW as it hopes to do, that would give an IRR of 8% for the 67% CF scenario and an IRR of 5% for the more realistic 50% CF scenario. Thus, they conclude that even if Fervo reaches its goals, its profitability would hover near or slightly below breakeven.

     Yearsley goes on to analyze Fervo’s financing and suggests they may have to raise more money for Phase 2 of the Cape Station project. He does not believe they were accurate in saying that EGS has been proven commercial at scale. It may be at some point, but the evidence suggests that it is not now. They may have trouble raising more cash due to the lower stock price. Higher electricity prices would help their economics and could save them, but that is not guaranteed.

“To convince shareholders, investors, and lenders that they have a viable business model, Fervo will have to prove (not just speculate) that after burning through almost $3 billion so far, they will be able to vastly improve well productivity, achieve a near-perfect operating record, suffer no production shortfalls, and experience no material temperature declines or water loss. For that, they will need time. But having rushed their IPO and started the clock, they are running short of time and credibility.”

     Below are the pump power calculations Yearsley used, followed by his analysis of economic inputs.

     It will be interesting to see if they can further reduce costs, parasitic loads (which Yearsley thinks is unlikely), and the thermal decline rates that appear to be higher than for conventional geothermal.

 

 

 

References:

 

How Fervo is digging a deep financial hole: Fervo’s much-heralded success in raising money in their Initial Public Offering for their Enhanced Geothermal projects has come unravelled, with shareholders losing some $10 billion since the peak in May of this year. As bad as the collapse of their share price is, Fervo actually have bigger problems. A legacy of omissions, inaccuracies, and their own inexperience has put them in a deep financial hole that they will need time to dig out of – if at all. Elliot Yearsley. GeoExPro. November 5, 2026. How Fervo is digging a deep financial hole - GeoExpro

How do we risk the commercial success of geothermal EGS projects in 2026? LinkedIn post. Dave Waters. Post | LinkedIn

A critical look at Fervo dataset suggests lower output: Net power of enhanced geothermal project may be only a third of the number that is generally quoted. Elliot Yearsley and Henk Kombrink. GeoExPro. November 6, 2024. A critical look at Fervo dataset suggests lower output - GeoExpro

Has enhanced geothermal been proven at scale? Comments and opinion based on information released by Fervo on Project Red. Elliot Yearsley and Henk Kombrink. GeoExPro. April 23, 2026. Has enhanced geothermal been proven at scale? - GeoExpro

NOVI Labs Updates Haynesville Inventory and Economics: ‘41 Years Remaining, but Only 3.4 Below $2.50/Mcf’

      NOVI Labs recently updated its inventory and economics for the Haynesville Shale in the Louisiana Salt Basin, including a quick summary in their newsletter and via a recent webinar. The Haynesville Shale and Bossier Shale and Limestone below are Jurassic-aged natural gas reservoirs characterized by depths greater than 10,000 ft vertical, high reservoir temperatures and pressures, high production at high cost, adequate pipeline capacity, and an ideal marketing location near LNG export terminals. The Western Haynesville/Bossier region in Northeast Texas has shown very high production rates. Even with those high rates, the play is not quite as economical to produce as the Marcellus.

     NOVI notes that Haynesville drilling peaked in 2023 and dropped off in 2024 and 2025. This is likely in response to natural gas prices. The play is expected to pick up as more LNG export demand comes online in the next several years. The webinar notes that Haynesville production dropped by 11% in 2024 and rose by 2% in 2025. 

     Expand Energy is the premier Haynesville operator with the best consolidated position. Other operators, particularly Aethon and Comstock, are finding success in the Western Haynesville. Japanese LNG buyers have invested heavily in the Haynesville. They are poised to use some of that gas and resell and deliver some of it to other Asian buyers via their own marketing hub.

     As noted in the April webinar, there are 18,000 locations that can generate 25% ROR at $3.50 per mcf or higher.

     NOVI notes in its latest newsletter that came out today:

“Novi Intelligence’s latest Q4 2026 assessment identifies approximately 40.9 years of remaining inventory at the current development pace, but that runway narrows significantly when economics are considered. Just 3.4 years remain below $2.50/Mcf, increasing to 15.6 years below $3.50/Mcf. With all sub-$1.50/Mcf locations already developed and 64% of the original sub-$2.00/Mcf inventory drilled through, the basin’s lowest-cost opportunities are becoming increasingly scarce.”

     This suggests that the next few years will be the most profitable going forward for Haynesville producers. After that, higher prices will be required to keep those profits as high as they were.

 

   

References:

 

Haynesville Inventory: 41 Years Remaining, but Only 3.4 Below $2.50/Mcf. NOVI Labs Newsletter. November 6, 2026.

Meeting the Moment: Marcellus and Haynesville Inventory Amid Rising Gas Demand. Webinar, NOVI Labs. April 8, 2026. [Webinar] Meeting the Moment: Marcellus and Haynesville Inventory Amid Rising Gas Demand

Rodatherm Energy is Developing Waterless Closed-Loop Geothermal in Utah’s Wasatch Corridor Sedimentary Basin and Teaming Up with Fulcrum Point Holding’s SMR Nuclear Reactors: Modularity and the Basin’s Brackish Hydrothermal Convection Are Emphasized

  

      Rodatherm Energy Corporation was founded by Curtis Cook, who previously ran a Calgary company drilling horizontal shale wells on pads. He is using that model for what the company calls its waterless geothermal model, which is basically a closed-loop advanced geothermal system. The company is based in Salt Lake City and is planning a project in Utah’s Wasatch Corridor Sedimentary Basin. According to Utah Tech News, that model is as follows:

“…build a small, provable unit, let its revenue fund the next one, and repeat — is the organizing idea behind a new memorandum of understanding between Rodatherm and Fulcrum Point Holdings, the Salt Lake City-based energy infrastructure developer already leading Utah's nuclear buildout in Box Elder County. The companies plan to begin with a 10-megawatt geothermal site near Brigham City, with construction targeted for late in the first quarter of 2027, and scale toward 200 megawatts of capacity over time.”

     The Wasatch Corridor Basin contains deep brackish water that enables efficient heat transfer through convection. The company plans a modular approach to scaling up so they can generate some cash flow while they expand. Utah is rich in subsurface heat, which amounts to potential geothermal resources. As in other geothermal projects, some of the heat can be used for district heating and cooling.

     According to an article in Deseret News:

“Rather than relying purely on steam, Rodatherm circulates a specialized organic refrigerant through the loop. As the fluid absorbs underground heat, it vaporizes to drive a turbine and generator, then condenses through an air cooler and goes back into the system.”

“While it’s tiny on the surface, the design descends about 9,000 feet (1.7 miles) into the Earth before extending into a series of horizontal loops to maximize heat absorption before returning to the surface.”

     Cook noted:

“We go down 9,000 feet, go out two miles and come back up, and we do it six times,” he said.

     After the recent technical problems with Eavor’s closed-loop project in Germany due to hydraulic communication between loops caused by inadequate well cementing. I would expect similar concerns for this project. Drilling is also expensive and materials-intensive.

     The project is being paired with Fulcrum Point Holdings' small modular reactors (SMRs) so that it will be a hybrid geothermal and nuclear system which will provide baseload power.

     Rodatherm describes its model as a combination of convection and conduction geothermal. They utilize turboexpanders to convert vapor pressure into electricity. According to Rodatherm’s website:

“Our economics are shaped by what the system eliminates. The sealed-circuit architecture reduces operating complexity while minimizing parasitic energy losses and long-term maintenance requirements. Combined with modular pad development and established drilling practices, the system is designed to bring firm renewable electricity online in months, not years.”

     Fulcrum Point Holdings is an energy asset developer and financer. The company operates natural gas assets and seeks to add SMR capabilities. Fulcrum Point’s team has considerable experience in nuclear energy development. They are also involved with advanced manufacturing and workforce development. The area where they are developing SMRs is west of the geothermal project area. The company noted in a July 2026 press release about the collaboration:

“By combining Rodatherm’s patented Waterless Geothermal Systems™ technology and Fulcrum’s integrated development platform, we can deliver energy security that supports Utah’s long-term economic growth.”

     So far, I don’t see how this project is distinguishable from other closed-loop projects except that they plan to drill into a hydrothermal system in porous rock as opposed to dry rock. Compared to Eavor’s project in Germany, which, if it had worked as designed, would have produced 8 MW from a similar number of loops at similar vertical depths, this 10 MW project is comparable in expected output. It will be interesting to see how it develops.

References:

 

Rodatherm and Fulcrum Point Bet on Waterless Geothermal — With a Shale-Field Playbook. Mark Tullis. Tech Buzz. Utah Tech News. July 23, 2026. Rodatherm and Fulcrum Point Bet on Waterless Geothermal — With a Shale-Field Playbook - TechBuzz News

Scalable geothermal plants are coming to northern Utah: Rodatherm has slated construction to begin in early 2027. Eva Terry. Deseret News. July 23, 2026. Rodatherm to start construction on Utah geothermal plant in 2027 – Deseret News

GeoNerd Digest – 39th Edition: Rodatherm´s Closed-Loop Test Bed in Utah. Matus Gajdos. Matus Gajdos, July 14, 2026. LinkedIn. (23) GeoNerd Digest – 39th Edition: Rodatherm´s Closed-Loop Test Bed in Utah | LinkedIn

Fulcrum Point Holdings Expands Energy Partnerships Through Geothermal Collaboration with Rodatherm Energy Corporation. Fulcrum Point Holdings. July 20, 2026. News | Fulcrum Point Holdings