The Potential of Gas Lift in Low-Pressure Geothermal Wells: It Can Replace ESPs Where Applicable, According to Modeling Study

 

      Two of the most important parameters for conventional geothermal wells are temperature and flow rate. Flow rate can be seen as the rate of water production. Artificial lift, including gas lift, is commonly used to successfully increase production in oil wells. Typically, production is enhanced via electric submersible pumps (ESPs).

     Some areas that host geothermal resources, including some sedimentary basins, are not overpressured enough to sustain high flow rates. This is the case for the Molasse Basin in Germany, for instance. In those cases, ESPs are the norm for geothermal wells. ESPs are vulnerable to scaling, which is a significant problem in geothermal wells in general. High fluid flow can also damage ESPs.

     As noted below by Henk Kombrink in his GeoExPro article, gas lift involves injecting gas into the hydrothermal fluid, which lowers its density and hydrostatic pressure, allowing it to flow more easily toward and up the wellbore.

     As shown in the abstract and the graphs below, the researchers modeled several different gases, including methane, compressed air, nitrogen, and CO2. They found that all of the gases increased production significantly. Methane was slightly higher than compressed air and nitrogen, and CO2 was lowest. CO2 is also quite undesirable since it aids corrosion by about 16%, according to the study. Compressed air also aids corrosion by nearly 10%. This suggests that methane or nitrogen would be better gas candidates. Since the other gases are roughly similar in effect, I would think that the cheapest gas available near the project would be chosen for pilot projects, except for the corrosion vulnerability.

     Kombrink notes that previous gas lift projects in geothermal wells, including one that used nitrogen in Indonesia, ceased due to unfavorable economics. However, the new modeling suggests that water production rates can increase by an average of 80%, and subsequent power production rates can increase by an average of 118%. These numbers include the energy loss from running the gas injection system and, presumably, the total of parasitic loads, but as noted later, they do not include transient well processes.

     The study, published in the journal Geothermal Energy, utilized field data from a geothermal well in the Brawley Geothermal Field in California. The modeling considered parameters including fluid properties, wellbore geometry, and operational conditions. More specific parameters modeled include fluid temperature, flow rate, gas injection temperature, and thermal properties of the materials.

     The figures below from the paper show wellbore schematics, modeling workflow, and the surface equipment that would be used in the gas injection system.

     The researchers stress that they utilized a steady-state modeling approach for the study, which excludes the transient processes that routinely occur in geothermal wells, as they explain below. It is unclear how much excluding transient processes would affect real-world performance.

“The steady-state modelling approach assumes that the wellbore and surface system have reached equilibrium for each simulated condition. Transient processes like well unloading, start-up behavior, cyclic gas injection, short-term pressure fluctuations, gas lift valve dynamics, and time-dependent reservoir pressure decline are not explicitly modeled. Therefore, the results should be interpreted as quasi-steady performance estimates for specified conditions rather than predictors of transient field operation. Despite these limitations, this steady-state framework is appropriate for the objective of this study, which is to screen gas lift scenarios and quantify their relative impacts on production rate, wellhead temperature, compressor load, and net power output.”

     Some of the model assumptions, mainly for equipment efficiency, are given in the table below.

     The researchers also modeled injecting gas at different depths. They found that deeper injection depths increased the mass production rate significantly and the temperature slightly, as indicated below.

     The paper’s conclusions are summarized below. It is important to note that the greatest improvements will be found in wells with lower reservoir pressure. This is similar to artificial lift in oil wells. Finding the ideal gas injection rate is also important. Also noted is that while injecting gas at lower depths can increase production by 15%, it also requires higher injection pressures, which use power and so become more parasitic.

   

References:

 

Injecting gas in a geothermal well can double its net energy output: That is what a new published modelling study using the parameters of a Californian geothermal project suggests. Henk Kombrink, GeoExPro. September 22, 2026. Injecting gas in a geothermal well can double its net energy output - GeoExpro

Modeling of gas lift in liquid-dominated geothermal wells in Brawley field. Orkhan Khankishiyev & Hamid Karami. Geothermal Energy. Volume 14, article number 20. July 3, 2026. Modeling of gas lift in liquid-dominated geothermal wells in Brawley field | Geothermal Energy | Springer Nature Link

 

New Paper Argues That Anthropogenic Climate Change Reversed Impending Ice Age

      The idea that we could reverse an impending Ice Age has been around for a while. Climate scientist James Hansen once proposed the idea as plausible. He even suggested we could manufacture chlorofluorocarbons (CFCs) with very high global warming potential to create an atmosphere on Mars that could hold in heat via the greenhouse effect. A new paper published in Science argues that we may already have prevented an impending Ice Age.

     Scientists say we are currently living through an ice age that began 34 million years ago, with its last glacial period, marked by colder temperatures and glacial advance, ending about 11,700 years ago. Since then, we have been in an interglacial period known as the Holocene, but a resumed glacial period would be expected at any time. The study focuses on the retreat of Canada's Barnes Ice Cap, which was initiated around 95,000 years ago, reached its maximum about 20,000 years ago, reached its smallest size 3,600 years ago, and began growing again 1,600 years later, or 2000 years ago. That it began to grow again, the researchers say, is a sign of glaciation. However, the glacier is now nearing its final days as anthropogenic warming reversed its growing trend.

      According to an article about the study in Smithsonian Magazine:

“The Laurentide Ice Sheet dominated the landscape of modern-day Canada and the northern United States tens of thousands of years ago. At its peak around 20,000 years ago, it covered almost 30 percent of the continent, extending from above the Arctic Circle to what is now Illinois. The ice was more than two miles thick in some spots.”

“All that’s left of this formidable feature today is the Barnes Ice Cap. It’s a Delaware-size ice cap on central Baffin Island in Nunavut, Canada.”

     Over the past 2.6 million years, large continental ice sheets have proliferated, and our Earth system has been cycling between glacial and interglacial periods. The researchers utilized a form of beryllium in newly exposed bedrock and surrounding boulders as a proxy for exposure to the atmosphere and to cosmic rays, which means the ice had melted when exposure occurred. They also carbon-dated the recently exposed dead vegetation to figure out when it first died, corresponding to when the ice cap last expanded across that area.

     Study co-author Joerg Schaefer, a geochemist at Columbia University, noted:

“Our approach helped us see the first steps of ice-sheet growth preserved in the landscape. It gave us a rare opportunity to understand how re-glaciation begins and how the Laurentide Ice Sheet re-forms.”

     What implicates anthropogenic climate change is when the ice cap began shrinking again. It was dated to 1960, when greenhouse gas emissions from industrialization began to grow much faster in the atmosphere.

     According to Lamont-Doherty Earth Observatory, where the researchers work:

“The Barnes Ice Cap is frozen directly to its underlying bedrock. Unlike most glaciers, it does not slide, and thus preserves the vegetation that grew at earlier times when the glacier was small and was subsequently entombed by its expansion. Vegetation exposed since the glacier started retreating in 1960 can be sampled, allowing scientists to determine its age by analyzing traces of carbon-14, a harmlessly radioactive form of atmospheric carbon that collects in organisms while they live and breaks down at predictable rates after they die.”

“If you do this enough times, you can actually develop a timeline of that ice margin systematically advancing over plants. You’re actually tracking the expansion of that ice margin,” says Young.

“By combining analyses of vegetation preserved beneath the Barnes Ice Cap and smaller recently melted ice caps in the region, the researchers pieced together a climate history. The Laurentide reached its minimum dimensions about 3,000 years ago, then started re-expanding about 2,000 years ago when the climate became cold enough for ice to accumulate.”

     It is debatable when re-glaciation begins, and it can take thousands of years from that initial beginning to when large, mile-or-more-thick glaciers advance over continents. The findings validate the scientists who thought in the 1970s that a new ice age was beginning, based partly on cooler global temperatures from about 1940 to about 1970.

“By the 1960s, Earth’s climate had warmed enough that the Barnes Ice Cap lost more ice in the summer than it added in winter. The next glaciation fizzled out. According to models of the glacier’s future, it will melt completely within the next few centuries. “That will be the true very last remains of the Laurentide, disappearing for good,” Young says.

     According to Shaun Marcott, an Earth scientist at the University of Wisconsin-Madison who did not participate in the study:

“Humans are now geologic agents capable of thwarting millions of years of natural glacial cycles and offsetting Earth’s climate for hundreds of thousands of years to come.”

     The evidence appears to be pretty good that re-glaciation was initiated 2000 years ago and that shrinking of the ice sheet began around 1960. Should we adopt a different view about anthropogenic climate change if this is true? Did it protect us from the horrors of an Ice Age? If this is true, it suggests that anthropogenic climate change is indeed a powerful lever for changing the Earth system but also that it ended up being beneficial in terms of preventing an impending Ice Age. 

 

 

References:

 

Two thousand years ago, a new ice age began—but human-caused climate change recently reversed it, according to new research. Margherita Bassi, Smithsonian Magazine. October 27, 2026. Two thousand years ago, a new ice age began—but human-caused climate change recently reversed it, according to new research

An ice age was coming. Our emissions reversed it. Arden Dier with Newser.AI. Newser. October 28, 2026. An ice age was coming. Our emissions reversed it

Late Holocene reexpansion of the Laurentide Ice Sheet. Nicolás E. Young, Gifford H. Miller, Martha Raynolds, Helga Bueltmann, Scott J. Lehman, Jonathan H. Raberg, Kylie Seward, Simon L. Pendleton, John T. Andrews, Patrick J. Webber, and Joerg M. Schaefer. Science. 22 Oct 2026. Vol 394, Issue 6822. pp. 455-459. Late Holocene reexpansion of the Laurentide Ice Sheet | Science

Climate Change Stopped the Next Ice Age. Lamont-Doherty Earth Observatory. Columbia Climate School. October 22, 2026. Climate Change Stopped the Next Ice Age | Lamont-Doherty Earth Observatory

Gulf Coast Natural Gas Storage Continues Expansion to Serve LNG Export Facilities

     The Gulf Coast area of Texas, Louisiana, and Mississippi currently hosts about 1.1 TCF of natural gas storage capacity. That capacity is set to grow as new storage capacity becomes available in the future. The buildout is occurring due to more LNG export facilities coming online. When those facilities go offline for routine maintenance or unexpected shutdowns, there is a need to have significant storage capacity available.  Most Gulf Coast gas storage is in salt caverns, which offer very good storage reservoirs. The Microsoft Copilot AI summary below shows major current expansion projects.

     By the early 2030s, that new storage capacity will be needed for LNG exporters. According to RBN Energy’s Housley Carr, owners of existing salt cavern storage facilities can make new capacity available fastest by expanding existing facilities. These brownfield expansions offer better economics for gas storage developers. Those sites also often offer better pipeline connectivity and/or higher injection and withdrawal rates. He notes that there is a massive 350BCF/day of gas storage under development.

     He notes that LNG terminal operators are willing to pay for Firm Storage Services (FSS). Carr notes that a large amount of new storage will become available later this year and through 2028, and an additional 130 BCF/day may be needed in the next five years. He also points out that power generators, including AI data centers, also draw from gas storage.

“The vast majority of the new storage projects will be brownfield expansions to existing salt cavern facilities because they (1) provide the rapid injection rates that LNG terminal operators require as well as the rapid withdrawal rates that power-plant operators need, and (2) offer more favorable economics than most greenfield projects.” 

     Carr’s article covers three storage operators: Enbridge, Caliche Storage, and Enstor. Enbridge has the most storage under development at 48 BCF/day. Caliche has nearly as much, at 45 BCF/day. These are mainly brownfield expansions of existing salt cavern storage.

“Enstor, the largest privately held gas storage company in the U.S., is planning what may be the largest salt cavern expansion project in the Gulf Coast region: a 33.5-Bcf expansion at its Mississippi Hub facility in Mount Olive, MS, which will increase the site's total capacity to more than 56 Bcf.”

     Enstor’s new capacity is expected to be online in 2028. It is increasing its injection capacity by 700MMCF/day to 1.9 BCF/day. Its withdrawal capacity will remain the same at 2.4 BCF/day.

     Carr also notes that Williams is planning 19BCF salt cavern capacity expansions in Louisiana as well as a looping project that will convert 10 BCF of cushion gas to working gas inventory at a Kinder Morgan depleted reservoir gas storage facility.

 

References:

 

Long Time – Why Brownfield Projects Have an Edge in the Ongoing Gulf Coast Gas Storage Buildout. Housley Carr. RNB Energy. October 23, 2026. Long Time – Why Brownfield Projects Have an Edge in the Ongoing Gulf Coast Gas Storage Buildout | RBN Energy

Smart Energy Management Systems and Methods for Buildings and Industry

    Smart energy management has increased in importance with high energy and electricity prices. Using hardware and software to optimize energy use makes economic sense for buildings and industry. Smart energy management systems involve several different components to do this. Those different products and platforms are combined. This requires an understanding of their individual capabilities. As building electrification and industry electrification continue to grow, these systems are becoming standard for new buildings and facilities. They offer efficiency and optimization. As will be seen below, developers now have competing choices and some niche offerings for those needing them.

     According to Neil Sharp of the company Escatec, which works on design with original equipment manufacturers (OEMs) that make building automation control (BAC) systems:

“Smart energy management systems use sensors, controllers, software, and data analytics to optimise how buildings consume and conserve energy. These systems enhance building automation by dynamically adjusting lighting, HVAC, water usage, and electrical loads based on real-time data, user habits, and environmental factors.”

     Reducing energy waste and utility costs are immediate benefits. Other benefits include greater regulatory compliance, improved occupant comfort, and seamless integration of hardware and software with IoT and cloud platforms.

     Escatec’s article identifies 17 smart energy management systems for buildings and industry. These include different products and platforms considered to be effective. It provides a nice snapshot of the building energy management industry. I will summarize the 17 and mention one more.

 

1. Schneider Electric — EcoStruxure™ Building Operation (BEMS) – Schneider Electric’s building energy management system (BEMS) integrates HVAC, lighting, power, and security and has built-in analytics and energy KPI dashboards. It integrates easily with third-party devices.

“Notable features include centralised fault detection and diagnostics (FDD), a scalable app ecosystem, and lifecycle performance reporting.”

2. Siemens — Desigo CC (integrated building management) – this system involves energy, HVAC, fire, and security, and features integrated energy reporting. They note that it is suitable for complex facilities

3. Johnson Controls — Metasys® (BAS/BEMS) – this one is a widely deployed building automation system (BAS) that features lifecycle equipment analytics, submetering, and AI-assisted fault detection and diagnostics (FDD).

4. SkyFoundry — SkySpark (FDD & energy analytics) – this one is mainly an FDD and analytics platform that integrates third-party apps.

5. Honeywell — Forge Energy Management (cloud analytics) – this one is a cloud-based IoT analytics and energy management platform that provides “portfolio-level energy benchmarking, anomaly detection, and ESG/sustainability reporting outputs.”

6. BrainBox AI — Autonomous HVAC Optimisation (AI HVAC) – this one focuses on HVAC optimization. It is powered by AI and is used for predictive modeling. It has been shown to be capable of “continuous self-learning, peak demand shaving, and independently verified energy reductions of 10–25%.”

7. ABB — Ability Energy Manager (submetering and BEMS) – According to Escatec’s Sharp, this one is “an energy monitoring and management platform that provides granular submetering across electrical distribution systems, enabling load analysis, carbon tracking, and waste reduction at circuit level.” It integrates with ABB smart meters and third-party devices and provides energy consumption optimization.

8. Tridium — Niagara Framework (integration middleware) – he describes this one as “the industry's leading open software framework and IoT platform for connecting disparate building systems, including HVAC, lighting, power, and security, over a unified IP network.”

9. Eaton — Power Xpert Metering (power quality & submetering) – this one offers detailed power analysis and smart submetering. It also ties into billing. It can provide harmonic distortion analysis, peak demand alerting, and utility billing verification.

10. Danfoss — VLT HVAC Drive FC 102 (Variable Frequency Drive) – this one can optimize HVAC systems and reduce energy waste by dynamically matching motor speed to actual load demand. It can provide plug-and-play integration with most BMS controllers. It has been shown to offer a 50% reduction in the costs of fan and pump loads. It also has built-in safety functions.

11. Lutron — Quantum Lighting Control (smart lighting) – this one manages lighting. It offers daylight harvesting, occupancy sensing, and scene management across large facilities with granular zone control. One system can support over 10,000 devices. It also integrates with and interfaces with HVAC and BMS. It has documented energy reduction capabilities.

12. Signify — Interact Pro (occupancy analytics & lighting) – this one also focuses on lighting and occupancy analytics. It is cloud-based, wireless, easy to retrofit, and able to be integrated with BMS and HVAC.

13. Enel X — Demand Response Platform (load flexibility) – this one specializes in demand response and load flexibility, enabling it to provide grid services for better pricing and grid incentive payments. It works by cutting system and appliance loads where it can when needed.

14. Belimo — Energy Valve (waterside efficiency control) – Sharp describes this one as “an intelligent pressure-independent control valve with an integrated power meter that actively measures and limits hydronic coil energy consumption in real time, directly in the valve body.” This one can optimize the functions of chillers in HVAC systems, especially if there is a mismatch between actual temperatures and the chiller’s design temperatures.

15. SolarEdge — Commercial Energy Hub (solar PV + building EMS) – this one specializes in buildings powered partially by PV solar, functioning as an inverter and an energy management platform. It is equipped with “smart export control and self-consumption optimisation for large commercial and industrial installations.” It integrates with other systems and provides scalable architecture.

16. ChargePoint — EV Charging Management (EV + building load) – this one is focused on managing EV charging with building loads. It is a cloud-based network platform that features scheduling and energy cost controls. It can also support peak shaving and load balancing.

17. Optimum Energy — OptiCx® (HVAC system optimisation) – this one optimizes HVAC systems. It integrates with BMS and offers a user-friendly interface and powerful analytics.

     In the article’s conclusion, Sharp touts Escatec’s capabilities in supporting OEMs.

“Smart energy management has become a baseline market expectation for residential and commercial buildings globally. For OEMs developing BAC hardware and systems, understanding this landscape drives smarter design decisions, better integration choices, and stronger product positioning.”

“Those with strong, agile manufacturing partnerships will thrive. Whether you're producing a controller, a smart energy gateway, or an edge computing device for HVAC optimisation, the road from R&D to rollout is full of risks and complexities.”

“ESCATEC partners with BAC OEMs to bridge the gap between innovation and scalable, compliant manufacturing at every stage of the product lifecycle.”

     I came upon another company that provides energy monitoring systems. This company is Sanalife Energy, and its system is the E360, which provides power monitoring for commercial & industrial facilities. It touts its circuit-level monitoring capabilities, submetering, and alerting capabilities when there are changes in demand.

References:

 

17 smart energy management solutions you should know about. Neil Sharp. Escatec. June 18, 2026. 17 smart energy management solutions you should know about

See Every kWh & Stop Energy Waste In Real-Time. E360 by Sanalife Energy.  Electrical Power Monitoring & Submetering Solutions | E360 

EQT Buys Range for $13.7 Billion: Oil & Gas Consolidation Resumes After M&A Pause

 

     Consolidation in the natural gas sector just took a big leap again after relative calm. EQT will resume its status as the nation’s largest natural gas producer, retaking the crown from Expand Energy. Range’s very significant high-quality proven acreage will nicely complement EQT’s acreage. With combined natural gas production of 9 BCF per day, it will be a comfortable margin over Expand, which produces 7.5 BCF per day.

“This transaction brings together two of the highest-quality, longest-duration asset bases in North America and creates a company uniquely positioned for the next era of natural gas,” EQT CEO Toby Z. Rice said in a statement. “We believe this combination creates a must-own energy company capable of generating durable, through-cycle free cash flow while compounding value for shareholders for decades to come.”

     According to Salih Yilmaz, a senior oil analyst at the consultancy Bloomberg Intelligence:

“The bigger theme is consolidation: scale, concentration, and infrastructure control are becoming increasingly important in US gas, especially as LNG exports and power demand grow.”

     Below is a map showing how well Range’s acreage fits EQT’s acreage, in an analysis by Robert Polk for NOVI Labs.  

     As noted in the asset summary below, the combined company controls about 3 million acres throughout the better producing areas of Pennsylvania, West Virginia, and Ohio. EQT offers its strong Midstream value and vertically integrated position. The summary notes that Range has a higher percentage of natural gas liquids production in its portfolio than EQT, which previously was 93% dry gas weighted. This gives EQT more optionality. Another highlight is that the combined company now has 20 years of solid Marcellus inventory as well as a very significant deep Utica inventory.

     Polk further explains:

“EQT has also been THE Appalachian Basin consolidator. Including this deal, EQT has now executed major transactions in 5 out of the last 6 years: Range in 2026, Olympus in 2025, Tug Hill in 2023, Alta in 2021, and the Equitrans Midstream combination in 2024. The result is an unrivaled Appalachian Basin platform poised to execute on what the company describes as “secular power-driven natural gas demand growth.”

     The graph below shows other major natural gas producers as well as noting that “Expand still exceeds pro forma EQT on a gross operated basis.”

     RBN Energy’s Housley Carr notes that the value of the combined company exceeds $50 billion. He notes that EQT adds stellar Midstream value with 3,700 miles of infrastructure. He also notes that EQT shareholders will own about 73% of the combined company and Range shareholders will own 27%. The map below shows the core acreage of both companies along with the major pipelines.

     EQT has been pursuing natural gas power plant supply deals for hyper-scale AI data center projects and expects those projects to significantly increase local natural gas demand, which is very important for the pipeline-constrained basin assets. I noted this in a post at the end of July about EQT’s future plans.

     As noted in the graph below, EQT expects demand for Appalachian gas to skyrocket in the next four years. They recently even updated those numbers for more demand growth.

     Carr also stresses the importance of EQT’s Clarington Connector as a hub for Marcellus and Utica gas being exported out of the basin, and notes that Range’s main acreage position is nearby. EQT has also proposed the Pennsylvania Ohio West Virginia Energy Reliability Pipeline, or POWER Pipeline:

 “…which would run from an as-yet-unspecified location in southwestern Pennsylvania and/or West Virginia to the Clarington Hub. In a non-binding open season that ran from August 26 to October 26, EQT sought expression of interest for firm capacity on a pipeline with capacity of up to 1 Bcf/d that would come online by 2030.”

     Finally, Carr notes that the deal puts:

“…the combined company in an even better position to secure the long-term, large-volume gas-supply deals with power generators. And, as a bonus of sorts, these supply deals will provide EQT with an expanded opportunity to develop new gas pipelines to connect its supply either directly to new power plants or to takeaway pipelines at the Clarington Hub.”

 

 

 

References:

 

A natural gas megamerger creates America’s new No. 1 producer. Heatmap AM. October 27, 2026.

Open Range: EQT Corporation Acquires Range Resources for ~$13.7 B, Creating the US’ Largest Natural Gas Platform. Robeert Polk. NOVI Labs. October 27, 2026. Open Range: EQT Corporation Acquires Range Resources for ~$13.7 B, Creating the US’ Largest Natural Gas Platform

Roar – EQT’s Range Resources Deal to Supercharge Inventory and Boost Midstream Opportunities. Housely Carr. RBN Energy. October 27, 2026. Roar – EQT’s Range Resources Deal to Supercharge Inventory and Boost Midstream Opportunities | RBN Energy

Trump says “We’re Making a Freaking Fortune” from the Iran War’s Oil Spike, but Who is We? The Gas Pumps are Making Us Pay Them

    Here is more evidence that Trump is living in an alternate reality of sorts and making up alternate facts, or rather, in this case, an alternative interpretation of facts, referring to spiking oil company profits as somehow benefiting everyday Americans. According to reporting from Newsweek and 24/7 Wall St., Trump gave the following assessment at a rally recently.

“President Trump addressed a midterm rally at the Guardian Centers in Perry, Georgia, on Saturday, Oct. 24, and said the US is "making a freaking fortune" on oil, according to Newsweek. He said the country is making "hundreds of billions" because buyers are coming to Texas, Oklahoma and Louisiana, that advisers warned him not to mention it because people pay more at the pump, and that he doesn't "give a damn" about the criticism.

     So yeah, Big Oil is making big profits, but little America is paying significantly more. If you are poor, that rise in gas prices hurts more. Europe sometimes has an overly harsh method to curb Big Oil profits every time there are geopolitical supply disruptions, by adding so-called windfall profit taxes to those big companies. Now, I’m glad our oil & gas companies are profitable, but when it is at the public’s expense. It is an unfortunate economic situation for many. Trump knows this:

“On Oct. 14 in Bullhead City, Arizona, he said "we're making a fortune," citing Texas, Oklahoma and North Dakota, per Common Dreams. On Aug. 3, ABC7 reported, he said Chevron (NYSE:CVX) and Exxon Mobil (NYSE:XOM) "made too much money" and should give some back.”

     U.S. crude oil exports had hit records due to the global shortage but are now closer to normal.

“EIA data show US exports of crude oil and petroleum products hit a record 13,610 thousand barrels a day in April, about 13.6 million, up 15% from March's record. Crude exports reached about 5.6 million barrels a day, 21% above the prior record, per the EIA, as Strait of Hormuz disruptions sent buyers to US supply.”

     However, now those exports have dropped down to normal pre-war levels. As detailed below, the U.S. has suffered a much smaller loss of GDP than much of the rest of the world due to our productive oil industry.

“A June 23 Dallas Fed model found a 15% global oil supply disruption cuts annualized US real GDP growth by about 0.3 points. Its working paper puts fourth-quarter 2026 US output down about 0.1%, 0.2% or 0.3% for closures lasting one, two or three quarters, while rest-of-world output falls about 1.7 points annualized. Higher income for US producers partly offsets lost non-oil output. These are model estimates that leave producer gains and consumer spending unmeasured. The US has been a net oil exporter since late 2019, and oil spending fell from nearly 8% of GDP in 1980 to about 3% in 2024, per the Dallas Fed.”

“By a rough 24/7 Wall St. estimate, April's pace of about 13.6 million barrels a day annualizes to about 4.96 billion barrels. At $30 to $35 of added price per barrel, that implies about $149 billion to $174 billion a year in added export revenue. It reflects the peak month only: exports have since fallen, they mix products priced differently, and the US still imports crude.”

     Democrats in Congress are calling for a windfall profits tax for big companies. The big companies call that short-sighted. However, U.S. drivers know they are being scalped, so they are not sympathetic to the big companies nor to Trump. While I strongly agree with Trump that Iran should not have nuclear weapons and while I would love to see regime change in Iran, I think if we bomb again, we should focus on the nuclear sites as well as taking out their missile and drone capabilities as we are able.     

     Meanwhile, “we,” meaning most Americans, will continue to pay more at the pump, and oil companies will continue to profit from geopolitical disruptions as they often do. If the situation continues long enough, calls for windfall profit taxes will only increase.

 

 

References:

 

Trump says “we’re making a freaking fortune” from the Iran war’s oil spike. Here’s what the economic data actually show. AJ Tiarsmith. 24/7 Wall St. October 26, 2026. Trump says “we’re making a freaking fortune” from the Iran war’s oil spike. Here’s what the economic data actually show

Chemical Confidentiality Highest for Most Dangerous Chemicals, According to Chemical & Engineering News

        Companies that utilize chemicals and various chemical recipes often like to keep those chemicals and formulas confidential, citing proprietary commercial knowledge.  However, when those chemicals are dangerous or potentially dangerous if the public were to be exposed, then there is an argument to be made in favor of the public’s right to know. According to Chemical & Engineering News (C&EN), companies withhold information more often for dangerous chemicals, which is somewhat problematic.

     C&EN explains:

“C&EN analyzed US chemical production and import data from 2012 to 2023 under the Chemical Data Reporting (CDR) program of the Toxic Substances Control Act (TSCA) and looked at how often companies marked their yearly production volume as confidential business information (CBI). Compared with all chemicals reported under TSCA, companies withheld production volumes from the public between 6 and 21 percentage points more frequently for compounds that the EPA deemed the highest priority for safety evaluation when Congress overhauled the law in 2016.”

     The bottom line and the point of concern is that the public does not know how much of these dangerous chemicals a company is handling.

     According to Tosh Sagar, an attorney for the environmental group Earthjustice:

Routinely, companies will withhold how much of a chemical they’re using, their name, and where the plant is located as confidential information in their TSCA reporting data, Sagar says. “If you’re in one of these communities, you have no way of knowing that that stuff is about to come into your community and potentially poison you, your neighbors, your water, your air,” he says.

     Companies cite the importance of the protection of trade secrets from competitors. We saw that with fracking chemicals early on, but information became accessible later in disclosures, which have become routine.

     C&EN explains the situation further:

“This balance between the public’s right to know and industry’s right to preserve business interests has been a topic of debate since Congress overhauled TSCA, including its CBI rules, in 2016. Ten years later, some of the CBI permissions that the EPA granted to businesses are coming up for renewal. In addition, TSCA’s rule on charging companies fees for evaluating chemicals expires in September, which lawmakers see as an opportunity to rework the law again.”

“For most chemicals, companies must file CDR data if they use 11,340 kg or more per year. For chemicals that are highly toxic or have other special considerations under TSCA, this threshold drops to 1,134 kg. The TSCA top 10 list falls under the lower-threshold category. It includes chemicals such as perchloroethylene, 1,4-dioxane, methylene chloride, and N-methylpyrrolidone (NMP), which have been linked to a variety of adverse health outcomes.”

     One observation that they made is that for four of the most dangerous chemicals for which there is full data: 1-bromopropane, 1,4-dioxane, methylene chloride, and N-methylpyrrolidone (NMP), the withheld amounts of the chemicals used exceeded the reported amounts.

      C&EN goes on to explain, citing Richard Engler, director of chemistry at Bergeson & Campbell, and Maria Doa, senior director of chemical policy at the Environmental Defense Fund:

“There’s some variability in the extent to which companies claim CBI for production volume, Engler says. Companies in highly competitive sectors tend to claim all production volume as CBI, while others are less concerned and tend to not claim CBI. He also says companies might claim CBI for production volume for the 10 prioritized TSCA chemicals more often because there’s a lot of visibility on these compounds.”

“But what companies are allowed to claim as CBI, what they’re not allowed to, and what they need to justify are subject to a lot of EPA rules. There are two “can claim” CBI buckets, Doa says. “Bucket 1 is information that is presumptive CBI.” That means a company can claim CBI without having to give the EPA a reason, she says. What goes in that bucket are things like production volume, the supplier of a chemical, and the physical form of a chemical a company is using.

“In the other bucket are categories for which CBI is not presumed. For these, a company must substantiate to the EPA why that information should be withheld from the public, Doa says. Information in this bucket includes company name, location, and even the name of the chemical.”

“If you do not want your company associated with the production of something that’s listed on the public portion of the inventory, you can claim your company name as CBI, but you have to explain to EPA why that is,” she says. For example, a company must make a case to the EPA that releasing the information to the public would cause it “substantial harm to the competitive position” of the company, according to CDR filing rules (PDF). The company must show the EPA that it is taking precautions to protect this confidentiality itself, she says. “They have to show they’re not making empty claims,” Doa says.

“The EPA doesn’t explicitly define what substantial harm to the competitive position means in its guidance for companies wishing to claim CBI. “The EPA is not an expert on competitive harm,” Mark Duvall of the law firm Beveridge & Diamond says. Instead, the agency says it’s up to the CBI claimant to show this harm, he says.

     Earthjustice’s Sagar argues that this approach allows companies to claim CBI when it is not really necessary. C&EN’s Leigh Krietsch Boerner refers to the public’s right to chemical information as a balancing act. Below, she explains the Emergency Planning and Community Right-to-Know Act (EPCRA) and the Toxics Release Inventory (TRI) and how they relate to the CDR and CBI and how they differ.

“Under the Emergency Planning and Community Right-to-Know Act (EPCRA), companies storing or handling hazardous chemicals must provide safety information to local emergency responders and report any toxic chemical releases. The Toxics Release Inventory (TRI), meant to inform the public about toxic chemical releases either as waste or pollution, falls under EPCRA.”

“The information in the TRI is related to what’s in the CDR but doesn’t give the same level of insight, Engler says. The TRI has some information about what a company is storing on-site, but unlike the CDR, it doesn’t tell you how much the company is using, he says. “The TRI is telling you what comes out of a facility, but it doesn’t tell you what went in.”

     Sagar also takes issue with confidentiality being allowed for the volume of a chemical being produced, since that can have a huge impact on public safety risks. The public can possibly get information by submitting a Freedom of Information Act request to the EPA, but the EPA would have to approve it.

     The last time the TSCA rules were revamped was in 2016 and companies are typically given CBI exemptions from reporting for a ten-year period. Thus, many of these exemptions are expiring in 2026 as explained below. Some CBI claims can be renewed if approved by the EPA.

“According to data on CBI claims from the EPA, the agency fully approved about 58% of CBI requests between June 22, 2016, and Jan. 1, 2026. It denied 28% of requests and partially approved 14%.”

“If a CBI claim is granted, it comes with an expiration date, often 10 years after the company applies for CBI protection. The 2016 TSCA overhaul brought companies claiming new CBI protections, and many of them are about to expire.”

“So far, the EPA has released two lists of expiring CBI claims—one made up of claims set to run out between June 22 and July 31, and one with claims expiring by Aug. 31. Companies whose CBI claims are up for renewal have 30 days to submit new justifications to keep their CBI status.”

     If a company loses its CBI claim status, it can file an appeal, which presumably can keep the chemicals and volumes confidential for a longer period. Some members of Congress are seeking changes to TSCA, and these may affect how CBI claims are handled.

 

 

References:

 

Companies withhold info more often for dangerous chemicals, C&EN finds: Analysis of EPA data highlights difficult balance between a company’s right to confidentiality and the public’s right to know about toxic chemicals. Leigh Krietsch Boerner. July 1, 2026. Companies withhold info more often for dangerous chemicals, C&EN finds