CCS and Green Hydrogen Not Yet Mature Enough to Support Projects: Many Expected to Be Abandoned, Argues Paper with Support from Report and Some Scientists

      A new paper published in the European Association of Geoscientists and Engineers’ journal, First Break, argues that both green hydrogen and geological carbon sequestration remain immature technologies despite the proliferation of projects, and says many of the projects will never be completed. I was only able to see the paper’s abstract, which notes that current publications are:

“…routinely overstating the technological readiness of these climate mitigation remedies.”

     The paper evaluates both the technological and economic readiness of these projects. It refers to green hydrogen production as a “distant hope,” and CCS in the North Sea as “unproven.”

     They note that none of these projects is anywhere near viable without public funding and may never be. Of course, especially for CCS, which can be seen as a form of pollution abatement, there never was any hope for profitability. Green hydrogen is even less economically feasible. Thus, the economics are well known to be unfavorable.

     According to Henk Kombrink at GeoExPro, the paper’s authors,  Ruud Weijermars and Simone Pilia, both affiliated with the King Fahd University of Petroleum & Minerals in Saudi Arabia, note that the projects are effectively overhyped. Kombrink writes:

“…the authors identify what they describe as a typical example of the Gartner-style hype: an ini­tial trigger leading to a peak, followed by disillusionment and, subsequently, a “land­ing” in a phase of more modest, workable solutions.”

     The graph below shows that the number of publications per year for CCS and green hydrogen continues to grow. Based on their Gartner-style hype model, they predict that the number of publications for both technologies will soon begin to drop, showing that they are overhyped.

     Renewable energy and so-called climate solutions are quite vulnerable to being overhyped. The authors and Kombrink note that technical challenges remain for most projects.

Kombrink: “Looking at Gorgon in Australia, which keeps on being the only carbon storage project at scale, they observe continued injection challenges. They also argue that it is no surprise to see the Dutch CCS project Porthos experiencing cost overruns and project delays; the project was assigned to a government entity with­out operational experience that also lacks the contrac­tor-handling leverage that large oil companies have.”

     The Global CCS Institute recently published its Global Status of CCS 2026, which is more optimistic, but does acknowledge a deployment gap. The figures below include data and highlights from the report. According to a summary by the institute’s CEO:

“More work is still required for CCS to reach its full deployment potential and many policy and regulatory gaps, uncertain financing frameworks, insufficient markets, and public awareness  barriers remain. As countries move from climate ambition to implementation, carbon management should be explicitly integrated into NDCs, sectoral plans, finance discussions, and wider multilateral processes to help projects move from concept to operation. While the global number of operating projects and cumulative amount of experience and expertise continue to grow, we still have a long way to go.”

     Environmental activists and the scientists who support their views and approach have long been highly critical of CCS, calling it a false solution. They do have some grounds for criticism, noting the high costs and technical challenges. One of those scientists is Mark Jacobson of Stanford, who recently led the authorship of a paper in the journal Environmental Science & Technology, which compared CCS to his idea of a 100% renewable energy scenario in the form of mainly wind, water, and solar, something he has been advocating for years, which most scientists see as highly unfeasible and scientifically flawed. Of course, no one ever said CCS will be the majority of the solution to climate change, simply a tool among many tools. It can only provide some mitigation of emissions. Jacobson, who often levels harsh words against those who don’t embrace his scenarios, stresses that most CCS is used for enhanced oil recovery (EOR), which enables more oil production and thus more emissions, and said this about CCS:

“…data confirm carbon capture and direct air capture are useless opportunity costs.”

“All CC/DAC ever built for non-EOR purposes captures only 0.04% of today's CO2 emissions.”

“74.3% of all CO2 captured today from all installations built in any year is used for EOR (which releases 50-120% of the CO2 back to the air).”

“68.1% of all CO2 captured from 2026 installations is used for EOR.”

     Technically, he is not wrong. However, the world still strongly demands oil, and CCS for EOR helps produce the oil we need and so remains a viable solution for both sequestering carbon and producing oil. The authors conclude in the abstract below that

 "...policies promoting CC and SDACC should be abandoned."

References:

 

Many CCS projects may falter quietly without the promised benefits: That’s the conclusion of a study recently published in First Break. Henk Kombrink. GeoExPro. August 5, 2026. Many CCS projects may falter quietly without the promised benefits - GeoExpro

Price-Flooring Green Hydrogen Production and Geological Carbon Sequestration. Ruud Weijermars and Simone Pilia. European Association of Geoscientists and Engineers. First Break. Vol 44, Issue 4. April 2026. Price-Flooring Green Hydrogen Production and Geological Carbon Sequestration | Earthdoc

GLOBAL STATUS OF CCS 2026: SUSTAINING GLOBAL PROGRESS. Global CCS Institute. GlaSobal-Status-of-CCS-2026-report-Global-CCS-Institute.pdf

Energy, Health,and Climate Costs of Carbon-Capture and Direct-Air Capture versus100%-Wind-Water-Solar Climate Policies in149 Countries. Mark Z. Jacobson, Danning Fu, Daniel J. Sambor, and Andreas Mühlbauer. Environ.Sci.Technol.2025,59,3034−3045. 25-149-Countries-Main-Final

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