Underground Pumped Hydro Energy Storage: Chinese Researchers Evaluate Henan Province Coal Mines for Pumped Hydro Potential: Scientific Paper Review & Summary

     This research from China, published in Energies in June 2023, evaluates the use of existing coal mines in Henan Province for potential underground pumped hydro energy storage (UPHES). The study calculates the space available and the suitability for pumped hydro. This is a detailed study that develops a site selection methodology that compares and high-grades sites, mining trends, the history of underground pumped hydro, and the utilization of mined-out space are all explored.

     The paper first points out China’s large coal consumption, which makes up about 56% of the country’s primary energy consumption and 80% of its carbon emissions.

 

Figure 1. Annual coal production, consumption, and CO2 emissions from coal in China. (Data source: Our World in Data [8] and China Statistical Yearbook 2022.

 

     The authors note that there are now many closed and abandoned coal mines in China with space for underground pumped hydro energy storage (UPHES) applications. Past UPHES studies in China have focused on technological feasibility, environmental impact, and economic analysis. This paper focuses on site selection. Considerations include local geology and hydrogeology. Previous studies revealed that the permeability coefficient and horizontal distance were two factors necessary for site evaluation. Above-ground PHES projects require topography with significant elevation change, but UPHES can be developed without regard to topography.

     The authors developed a two-step site selection process. The first step involves a screening assessment that evaluates the geology and hydrogeological conditions. Step two is a comprehensive assessment that involves an analytic hierarchy process (AHP).

     The section on coal industry trends in China notes that there are predictions that China’s coal consumption for both power and industry will peak before 2030.

 

Figure 2. (a) Primary energy consumption in China by fuel type. (b) Primary energy consumption of several countries in 2021. (Data source: BP Statistical Review of World Energy).

 

Mined Underground Space Utilization

     It is predicted that by 2030, there will be 15,000 closed or abandoned coal mines in China. The space available in these mines includes deep shafts, extensive drift networks, and goaves. The utilization of underground mine space includes four main modes: energy storage, waste disposal, ecological restoration, and CO sequestration.

“Pumped storage is widely regarded as one of the most reliable, cost-effective, and mature technologies for large-scale energy storage, and it holds great promise for implementation in old coal mines. The process of coal mining naturally forms large quantities of underground caverns, which can serve as ready-made reservoirs with significant elevation differences, making them ideally suited for pumped storage. Moreover, the restored surface areas of old coal mines can be effectively repurposed as sites for wind and solar farms, ensuring a sustainable and renewable power supply for UPHES. This integration of renewable energy generation and energy storage unlocks new opportunities for the coal industry. Most UPHES projects are designed as closed-loop systems, operating independently from naturally flowing water bodies. This design allows the direct utilization of mine water as a supplement, mitigating the risk of water contamination and preserving water resources.”

     The Nassfeld power plant in Austria has long utilized UPHES. The plant has a surface water body and some excavated caverns as well as mine space. The geology of impermeable granite and gneiss, igneous and metamorphic rocks, provides good containment for water.

 

Site Selection

     As noted, economics, social, and environmental factors are important for UPHES site selection, as well as geology and hydrogeology. The presence of nearby surface wind and solar facilities to charge the system by powering the hydro pumping is another consideration.

     The step 1 screening assessment involves calculation and consideration of gross head, head-distance ratio, and water source. These data are integrated with geology and hydrogeology conditions. There are three screening indicators: geological features, mine water disasters, and minimum installed capacity. Geological features include the presence of karst geology, which is vulnerable to dissolution and would make the site unsuitable for pumped hydro. Consideration of mine water disasters includes a mine’s vulnerability to inflow greater than 600 cubic meters per hour, which indicates unacceptable hydrogeologic conditions. Such inflow can reduce power production capacity and involve more pumping, which makes economics more difficult. A minimum installed capacity of 20 MW was determined to be the cutoff for the screening assessment.

     The Step 2 comprehensive assessment involves determining the surface availability of wind and solar resources and the conditions of the local power grid, where pumped hydro could provide peak shaving services during high power demand times.

     Gross head refers to the elevation difference between the upper and lower reservoirs. Effective reservoir volume refers to the amount of water that can be stored in both reservoirs. If the surface water and groundwater are well connected and interactive, then this could lead to problems, which makes such sites unsuitable. The underground space must also be geologically stable, and the disaster potential must be low. Permeability of the surrounding rock must be considered. Hydraulic conductivity that is too high, combined with a high groundwater head can result in unsuitable conditions due to the lower reservoir filling too fast. The power regulation potential of UPHES requires the facilities to be near urban centers where power demand peak shaving is most needed. Being near urban centers also helps employment. Local support for projects can also be important.  Other considerations include the cost of energy storage, the payment potential of providing peak shaving services in the form of peak-to-valley tariff differential, maintenance and monitoring costs (some mine water is corrosive due to water chemistry), and the integrity of remaining equipment, including transportation and communications equipment and substations.  

     The analytic hierarchy process (AHP) includes weight calculations of many of the above factors to rank site suitability. This is a statistical method that involves the creation of a hierarchy, the construction of comparison matrices, and calculating priority and consistency.

“By weight calculation, indicators that have significant influences over site selection are identified, including the gross head (C11), the effective reservoir volume (C12), the local peak-to-valley tariff differential (C42), the unit cost of energy storage (C41), the stability of the underground space (C14), and the local power demand (C21). These indicators play crucial roles in determining the technical feasibility, safety, and economic viability of UPHES projects in old mines.”

     Next is a case study comparing three sites in Henan Province. The first table is data for the screening assessment, and the second table is the AHP conclusions for the comprehensive assessment.

     Henan Province has a growing number of closed and abandoned mines as coal production from that region continues to drop.

 

Estimation of Underground Space in Coal Mines

     Determining available space in mines involves estimating the volume of drifts, chambers, shafts, and goaves. Goaves are less stable since they don’t have ventilation and supporting structures. The authors show how a capacity coefficient was developed in a previous study to estimate space volume. Some of the mathematical variables in this calculation are the volume of mined coal, the determination of volume reduction due to surface subsidence, and the determination of volume reduction due to rock expansion after pressure relief.

 

UPESH Potential Estimation

     Estimating the UPHES potential of a mine site involves knowing two crucial factors: effective reservoir volume and the elevation difference of the upper and lower reservoirs.

“The effective reservoir volume and the elevation difference between the upper and lower reservoirs are two crucial factors in determining the installed capacity, power generation and economic profitability of a pumped storage power plant.”  

     Effective reservoir volume estimation must account for space that is ineffective and conditions like reverse slopes that will affect gravity feed and reduce circulating volume if there are cutoff stagnant zones. Groundwater inflow that is too high will result in filling the lower reservoir prematurely. This could reduce the amount of water available for discharge.

     The elevation difference between upper and lower reservoirs, also known as the head height, should optimally be between 200m and 800m. Henan Province mines have head heights between 300m and 1200m with an average just greater than 600m, which are considered very good.

“When the head height is less than 200 m, both the efficiency and economic benefits of the power plant significantly decrease. On the other hand, when the head height exceeds 800 m, the current Francis turbine is unable to meet the high-pressure requirements. Thus, multi-stage pumped storage power plants with intermediate storage reservoirs are regarded as an alternative.”

     If only one coal seam has been mined, then the depth to the mine from the surface constitutes the head height since the upper reservoir in that case will likely be a surface water body. In that case, it is termed a semi-underground PHES. If two or more coal seams are mined, the head height can be the elevation difference between the two seams. This is termed a fully underground PHES and is the preferred configuration. It is also much rarer, as the following table for Henan Province shows. The other tables show the potential for each scenario.  

     The final section involves estimating the decarbonization potential of UPESH projects, which depends on how much curtailed or dedicated solar and wind power is provided. UPESH projects can eliminate most curtailments, increasing emissions reduction further than just the discharging of hydro energy production, but also incorporating it into charging.

“In 2022, wind and solar power curtailment rates in Henan Province were 1.8% and 0.5%, respectively. Accordingly, the abandoned wind and solar power during the year amounted to 686.7 GWh and 102.9 GWh, respectively. The surplus power can be consumed by UPHES power plants, with about 631.7 GWh of energy successfully stored (assuming the plant efficiency of 80%). There is enough UPHES potential in existing old coal mine drifts to handle this surplus power, as mentioned above.”

“…by consuming surplus renewable energy, UPHES can reduce about 7.11 × 105 tonnes of CO2 emissions in 2025.”

     The authors note that their two-step site selection process basically adds the screening assessment to the previous process, which is basically the comprehensive assessment. By screening out unlikely candidates based on the three criteria of geological features, mine water disasters, and minimum installed capacity, which effectively characterize geological and hydrogeological conditions, effective reservoir volume, and head height, the process is streamlined and becomes more reliable and effective. The paper’s conclusion that the volume of goaves, areas of space filled with caved rock, is much higher than that of drifts and shafts suggests that if the goaf space can also be utilized, it could drastically increase the amount of UPESH potential for a given mine.

     The conclusions of the paper are given below:

 

 

References:

 

A Two-Step Site Selection Concept for Underground Pumped Hydroelectric Energy Storage and Potential Estimation of Coal Mines in Henan Province. Qianjun Chen, Zhengmeng Hou, Xuning Wu, Shengyou Zhang, Wei Sun, Yanli Fang, Lin Wu, Liangchao Huang, and Tian Zhang. Energies 2023, 16 (12), 4811, June 2023. A Two-Step Site Selection Concept for Underground Pumped Hydroelectric Energy Storage and Potential Estimation of Coal Mines in Henan Province

 

 

Electrical Submersible Pump Optimization in Gas-Rich Unconventional Oil Wells

      Electrical submersible pumps, or ESPs, are ubiquitous in oil production applications. This post is a summary of two articles in World Oil’s June 2025 issue, one by personnel from Baker Hughes about the performance and lifespan benefits of its boosted gas separator, and the other by NOV personnel about the reliability benefits of its new gas processing system. Both innovations are applicable to gas-rich oil wells that can be problematic for pumps.

 

Baker Hughes Boosted Gas Separator

     The authors from Baker Hughes note that its new boosted gas separator can:

“…enhance fluid production, improve reservoir recovery and enable operational flexibility. In turn, this enables safer, more efficient and more profitable operations.”

     When bottomhole pressure drops, gas can interfere with pump operation. This is especially problematic in oil wells with high gas-to-oil ratios (GORs). Thus, there is a need to address high Gas Volume Fraction (GVF) conditions in ESP systems. Problems include cycling, gas locking, and pump wear. The problems are most apparent in the Permian and Bakken. Baker Hughes offers what they call a system-level solution:

“…a fully integrated system that combines multiple technologies to manage gas effectively and maintain flow stability. Vortex-style gas separators use centrifugal action to separate higher-density fluids from lower-density gas, which is then vented back to the wellbore. This prevents free gas from entering the pump intake. Gas handling and multiphase pumps improve system performance by compressing the gas-liquid mixture, reducing bubble size and preventing gas lock. These multiphase helio-axial stages can effectively handle mixtures with gas volume fractions (GVFs) up to 75%, maintaining high boost pressure while increasing the fluid density delivered to the upper pump stages.”

“In a standard ESP configuration, fluid flows directly through the gas separator before entering the pump stages. In a system that incorporates a boosted gas separator, the fluid is introduced through an intake, where it is compressed by a gas handler pump before entering the separator, which enhances recirculation. The pre-compressed fluid is then routed to the gas separator, before reaching the lift pump. This process improves gas separation by diluting the gas concentration and stabilizing flow, with pressure losses in the annulus offset by inducer-generated lift.”

 

Fig. 1. Standard configuration vs. boosted gas separator, where pre-compressed gas improves separation.

 

     Another innovation now in common use is permanent magnet motors to run the ESPs, which results in vastly improved efficiency. I wrote about permanent magnet motors in oilfield applications a few months ago.

     Another design enhancement has been the use of computational fluid dynamics (CFD), which enables modeling, simulation, and validation under different configurations.

“The most notable improvements in separator efficiency were observed at liquid rates above 2,000 bpd, representing a typical 40% increase over traditional gas separators. This improved separation enables ESPs to sustain a throughput of 3,000 bpd, while achieving bottomhole pressures as low as 1,000 psi, in wells producing more than 1,000 MMscfd. As a result, drawdown and production are maximized in high-GVF unconventional environments.”

 

Fig. 3. CFD analysis shows that adding a booster pump improves gas separation and sends more liquid to the pump across all GVF levels.

 

     Baker Hughes has been field testing this boosted gas separator since October 2021, with the pump achieving 934 run days. They now have 136 ESPs in the Permian Basin and 146 in other places around the world, with the separator installed. These are installed in wells with variable production rates and variable GORs. One well showed increased production of 500Bbls per day over 60 days. The chart below shows performance improvements of the boosted gas separator over gas lift, a common method of artificial lift that injects gas into the production tubing to reduce fluid density and help bring hydrocarbons to the surface.

 

Fig. 4. This chart shows the average oil production before and after ESP installation, demonstrating that installing ESPs in these six wells increased oil production in all of them by an average 90%.

 

     A new multiphase ESP system has improved production in wells susceptible to gas slugs. Gas slugging can result from undulations in well laterals, including land the well unintentionally below the target zone and coming up into it, creating a sump effect at the beginning of the lateral. Gas slugging can lead to gas lock, frequent pump cycling, and motor overheating. The multiphase ESP system is installed in 1300 locations in the U.S. and combined with the boosted gas separator, PMMs, and an efficient gas handling pump, it can lead to significant production increases. These solutions will remain important as the amount of associated gas from oil wells continues to increase.

     The authors also note some future innovation projects:

“Innovations like the FusionPro—an advanced variable speed drive that incorporates sophisticated controls specifically designed for gassy environments—are in development, along with a boosted gas separator system for high-temperature applications and a next-generation gas separation technology, offering improved gas handling capabilities, set to launch later this year.” 

 

NOV’s Integrated Gas Processor (IGP) Improves Artificial Lift and Pump Reliability

      National Oilwell Varco, or NOV, also addresses gas interference in high GOR oil wells with its Integrated Gas Processor (IGP). The first schematic below depicts a typical ESP configuration, and the second one depicts an IGP configuration. The IGP system replaces the gas handler and the gas separator. The IGP combines those into one highly efficient unit. The traditional design can prevent operators from reducing the pump intake pressure (PIP), which can prevent pump optimization and the associated production increases.  

 

Fig. 1. A typical ESP installation includes a tandem gas separator and gas handling pump.

 

Fig. 2. The IGP replaces the gas separator and gas handler.

 

“The IGP operates differently from traditional gas handling equipment. Fluid enters a high-volume flow intake and goes into the lower module, where proprietary Contra-Helical Pump (CHP) stages compress and condition (homogenize) the gas and liquid. Unlike a traditional centrifugal pump, the CHP provides two flow paths that allow gas to flow into both the rotor and stator. The primary flow path is the helical flow, while the secondary flow path is the fluid vortex, generated within the rotor and the stator vanes. As a result, the CHP can ingest and condition a higher amount of gas, as it moves through the pump. Moreover, conditioning the gas provides buoyancy to the production fluid, increasing overall lift efficiency.”

“Then, the more homogenized gas-liquid mixture enters the center module that features a dual-chambered gas separator, which is strategically positioned to reduce gas recirculation and enhance gas separation efficiency. An inducer rotates the fluid at high speed, causing the high-density liquid to move to the outer diameter, while the low-density gas concentrates toward the inside diameter. A crossover component diverts the free gas to the exit ports and out into the annulus of the well, between the IGP and casing wall, and directs the liquid into the next stage of separation. This process repeats in the second stage of separation, further reducing the GVF {gas void fraction} and directing the fluid into the upper module.”

“Finally, the fluid enters the upper module for further compression and conditioning, before moving into the primary production pump. Both CHP and centrifugal style stages are available for the upper module.”

     The tree-module system is shown below:

 

Fig. 3. The three-module, all-in-one housing system is designed to separate and prepare the gas before entering the ESP’s primary production pump.

    

  

   Below, the authors give a case study example from the Delaware Basin, showing clear production improvements:

“The IGP exceeded the previous gas handling equipment, leading to a rapid rise in fluid production. Oil production rose 153%, from 136 bpd to 344 bpd, while gas production increased 224%, from 202 Mscfd to 654 Mscfd. Water production also increased 316%, from 417 bpd to 1,734 bpd, which led to a 14% reduction in the GLR, from 365 scf/bbl to 315 scf/bbl. Meanwhile, the PIP immediately dropped 11%, from 579 psi to 514 psi.”

 

Fig. 4. After installing the IGP, the Permian operator saw an immediate increase in production and a decrease in GLR and PIP.

    As in the Baker Hughes example, the IGP showed a marked performance improvement over gas lift. Downtime was reduced as well. As GORs continue to increase over time in the Permian Basin, these solutions will be deployed more and more. Longer laterals and undulating laterals will also benefit from these solutions.

“More than 120 IGPs have been installed in unconventional wells across the U.S., tackling the persistent challenge of gas interference. By integrating critical gas handling functions into a single, modular and optimized system, the proven IGP is poised to drive a new era of enhanced production, as well as substantial improvements in operational safety, efficiency and reliability.”

 

 

    

References:

 

Boosted gas separator enhances ESP performance, extends service life in gassy, unconventional wells. JOSEPH MCMANUS, MOHAMMAD MASADEH and OSCAR PADILLA, Baker Hughes. World Oil. June 2025. Boosted gas separator enhances ESP performance, extends service life in gassy, unconventional wells 

New gas processing system enhances electrical submersible pump reliability. AMES RHYS-DAVIES and JESSICA STUMP, NOV. World Oil. June 2025. New gas processing system enhances electrical submersible pump reliability 

 

Unpacking the Hype: A Deep Dive into the Energy Industry’s Lofty Natural Gas and Electricity Demand Projection: Webinar by Natural Gas Intelligence and Yes Energy: September 23, 2025. Summary & Review

          The first part of the webinar dealt with natural gas prices, exploring regional differences and the reasons for them. Appalachian pricing has already hit the threshold of $1.50, that, if sustained, which it was not, can trigger curtailments. It is slightly above the threshold now, but is expected to come up as colder weather approaches in October. Waha in West Texas is another region with a chronic natural gas supply glut. Henry Hub gas prices have remained around $3.00 with some temporary rises last winter.

     Appalachian gas production hit record levels at 37 BCF/day, and West Texas hit records of 28 BCF/day. Haynesville gas production growth is expected, being targeted for LNG exports. The Permian will be a supplier as well. New Haynesville connected pipelines and expansions are coming online, with more to come online in 2026. 

     She notes 2TCF of storage withdrawal last winter. Gas storage is projected to reach fullness – over 3.9 TCF this season. Forecasts call for precipitation in the Pacific Northwest, which means hydropower capabilities may be restored.

     Gas storage capacity has remained stable for the past couple of decades. LNG growth will be the biggest contributor to natural gas growth, much higher than AI data center gas demand growth.

     California has two seasonal bumps in gas consumption due to winter heating demand and summer cooling demand. Different regions have different natural gas volatility profiles. New gas infrastructure should alleviate Waha Hub bottlenecks. The graph below compares gas power burn and solar generation throughout the year. The seasonal nature of both gas power burn and solar generation is displayed. Solar generation is clearly growing on the grid.

     The graphs below show forecast demand by category. Demand is increasing now, and those increases are expected to grow considerably. Data center load growth is modeled based on announced projects. He notes that under construction means ground has been broken and the facility will be online in a few years. Data centers and crypto are lumped together as large, flexible loads. The crypto growth rate is similar to the data center growth rate. It is expected to double in 2027. Crypto loads can respond very quickly to market and price signals as well as requirements to shed load during demand peaks.

     There will be 20.5GW of data center load under construction by 2027, which means ground will be broken for those projects. 

     7.7 GW of the new data center load is expected to be for crypto-mining facilities. Crypto capacity is set to double on the grid. This is often lumped into AI data center demand, but I think it should be treated separately since AI has great potential benefits to society, while crypto simply uses vast amounts of energy to provide transaction security and also benefits criminals and stock speculators. Of course, these loads can respond to price signals and be throttled when demand is high. As the graph below shows, about 30% of of projected data center demand is really crypto demand. 

     The graph below is the Freeport LNG facility in Louisiana, showing its major shutdowns. 

     Solar is leading capacity growth and ERCOT is adding the most capacity, including the most solar capacity. ERCOT has 77.1GW of planned capacity by 2030. Most is solar, followed by batteries. 

     There is more frequent daily cycling in ERCOT’s thermal fleet due to more solar on grid, as the slide below shows. The thermal fleet ramps down when solar comes on, with a steeper ramp-up rate when solar drops off. Solar’s fast drop-off is causing faster ramp rates. 

     In CAISO, solar is optimized when on peak, and batteries are smoothing out the curve. He made a new category called - Net load less battery discharge. 

     The last two slides show Security Constrained Economic Dispatch (SCED), defined as:

 “The real-time market evaluation of offers to produce a least-cost dispatch of online resources. SCED calculates Locational Marginal Prices (LMPs) using a two-step methodology that applies mitigation to resolve non-competitive constraints.”

     These are for ERCOT, which is n=both solar-heavy and battery-heavy.

 

Q&A

     Any data on hyperscale data centers? ERCOT has a 60-day delay in status data. His company is Live Power. There is not enough data available yet for hyperscale projects, but they are working on it. 

     Gas storage is nearly full. Are producers dropping production? When gas hits $1.50, it can trigger curtailment. Canadian natural gas prices have even entered temporary negative pricing and have averaged just $1.03/mcf in 2025.  Demand is coming with LNG, AI plans, and behind-the-meter gas projects. As usual, gas producers are also hoping for robust winter demand – I’m not! He projects that new data center demand will require 4-8BCF/day. Natural gas will be the main power for AI, especially in the near term, before 2030. He thinks that in the 2030s, there will be more risk for natural gas prices. The Haynesville is ready and can deliver higher gas volumes to the Gulf for LNG export as soon as price signals appear due to new facilities coming online. Solar is not replacing coal in ERCOT, but gas is. Now, with new load growth coming on, coal retirements will slow. Solar is a mid-day power generation champ, so that must be integrated. 

     Will Canadian gas imports be lower as they export more LNG? With more Canadian LNG exports, we may see fewer imports into the U.S. More than 10BCF/day of gas was imported from Canada during a cold snap last year. Variables include pricing and hydropower availability.  In Western Canada and the Pacific, there are often winter gas price spikes, like in the Algonquin City Gate region in the Northeast. 

     Why is solar still growing in Texas?  Price capture – batteries a little cheaper – virtual PPAs – carbon offset projects. It’s not profit. 

     How does extreme weather affect production? Up to 10BCF/day can be temporarily offline with extreme weather. Daily volatility in places like the Rockies often happens in early cold snaps. Weatherization of wells and infrastructure is needed. 

     Off-grid support and demand for data centers? Behind-the-meter – on-site solutions – not connecting to the grid. Gas is the prime choice due to price and reliability. Renewables cost more and are not reliable. Most LNG facilities are off-grid, but some are on grid. Whether data centers are pulling from the grid or not will affect power grid demand. Some switch back and forth from grid to island mode.

Oil Markets Face Uncertainty in Near Term: High Costs Led by Tariffs, Policy & Regulatory Uncertainty, and Demand Uncertainty are Factors in the U.S.

    There is quite a bit of uncertainty in global oil markets these days as OPEC+ attempts to raise output to regain more influence. However, increases have been less than planned due to some members being unable to produce more.

     Meanwhile, BP changed its earlier estimate that global oil demand will peak as soon as this year and is now saying that oil demand will increase at least till 2030, citing “rising consumption in emerging markets, slower efforts to increase energy efficiency and reduce global emissions, geopolitical tensions, and the continuing use of petrochemicals.”

     BP’s projections added about 1.4 million barrels per day of new global oil demand to 2030, from previous projections of 102 million Bbls/day to 103.4 million Bbls/day.  They also cited “lackluster” energy efficiency gains. They noted in their 2025 Energy Outlook report that if current trends continue, demand could increase by 6 million Bbls per day through 2035. They also stated that “growth in electricity use by data centers will account for ~10% of global power demand growth through 2035 and 40% of U.S. power demand growth.”

     Other geopolitical issues will potentially affect oil supply and prices. These include Ukraine’s successful efforts to curb Russian oil supply by drone bombing refineries and processing facilities. Russia said recently that it will stop some diesel fuel exports and all gasoline exports for the rest of the year to stabilize domestic supply. Europe hopes to stop importing all Russian oil by the end of the year. An agreement was reached to restart exports of Iraqi Kurdistan oil to Türkiye, which would bring about 500,000 Bbls/day to the Turkish market and to the global market. Exports from the Kurdish region have been halted for over two years.

     There is a lot of uncertainty in global and domestic U.S. oil forecasts. U.S. shale oil plays are expected to begin declining at some point, certainly by some time in the mid-2030s, as the best core areas become drilled up. Production has already dropped due to the lack of drilling to maintain it. Tsvetana Paraskova of Oilprice.com notes that Enverus Intelligence Research (EIR) is forecasting significantly higher breakevens for the U.S. as depletion of core inventory becomes a concern in the mid-2030s. They predict breakevens will rise from $70/Bbl to as much as $95/Bbl.

“North America’s dominance in supplying global oil demand growth is waning,” Alex Ljubojevic, director at EIR, said in a statement.

“Over the next decade, its contribution to consumption growth is expected to fall below 50% — a stark contrast to the previous 10 years when it supplied more than 100%,” Ljubojevic added.

     This suggests that OPEC+ is poised to regain some market share. However, in the near-term, drilling has been suppressed in the U.S., and cap-ex has been pulled back from drilling, waiting for better prices and more favorable costs to drill and produce. Some companies, such as Midland Basin leader Diamondback Energy, are saying that U.S. shale oil production has likely peaked and activity will remain suppressed.

     The latest anonymous Dallas Federal Energy Survey, which polled executives from 139 companies, paints a rather bleak picture for U.S. oil producers, especially in the near term. Most oil executives said that Trump’s energy policies have reduced their breakeven costs by less than $1 per barrel. According to Paraskova:

“The administration is pushing for $40 per barrel crude oil, and with tariffs on foreign tubular goods, [input] prices are up, and drilling is going to disappear. The oil industry is once again going to lose valuable employees,” one E&P executive commented to the survey.

     It is rather obvious that the U. S. oil industry won’t survive at $40/Bbl. One executive noted that both the Biden and Trump administrations are at fault for “breaking” the industry.

“The shale patch consolidation has been fueled by the collapse of capital availability. This consolidation, in turn, is pushing out independents and entrepreneurs who once defined the shale revolution, according to the executive.”

“In their place, a handful of giants now dominate but at the cost of enormous job loss and the destruction of the innovative, risk-taking culture that made the U.S. shale industry great.”

     Costs to drill and produce have surged, and it is bringing companies to the brink of financial viability. This is likely to drive more industry consolidation. One industry leader noted:

“The uncertainty generated by the administration’s policies has stifled all investment in the oil sector. Those who can are leaving.”

     Others have stressed that the 50% tariffs on steel and aluminum are hurting the industry bad. According to Gabriela Leon of Explicame:

“Exploration and production companies reported that costs for discovery and development doubled in Q3, while leasing expenses also spiked. Meanwhile, oilfield service companies, which had already been grappling with negative margins, warned that the sector is “bleeding” financially. The rising prices of tubular steel, heavy materials, and imported components have made drilling operations increasingly uneconomical.”

“Tariffs continue to increase production costs. We are caught in a combination of rising costs due to tariffs and downward pressure on prices from end-users,” one service company executive remarked.

“Daily changes in energy policy prevent us from winning as a country,” they said. “Investors are avoiding energy due to volatility and the risk of drastic government actions.”

“The shift in policy also worries many within the industry. While President Trump champions domestic drilling as the key to an American energy renaissance, the very policies his administration is pushing have increased costs, stymied investment, and left many operators unable to move forward. “The oil industry is going to lose valuable employees again,” one executive lamented. “Drilling is going to disappear.”

     Oilprice.com’s Irina Slav notes that Russian sanctions and pressure on China, India, the EU, and others not to buy Russian (and Iranian and Venezuelan) oil are keeping a potential glut in check and oil prices from dropping. Russia has a lot of oil and remains the world’s second biggest producer. The sanctions aim to take that oil off the market but have ended up just moving it around and hitting Russia with price caps that others take advantage of, such as India and China. She also notes that while oil demand is expected to peak soon in China, the country is currently building its oil stocks. They have been importing more crude oil than their refineries can process, putting much of it in storage. This is also affecting prices, keeping them from dropping, she says. The problem with sanctioning Russian oil deeper is that it will put upward pressure on oil prices. She also notes that all the clandestine oil trading via ship-to-ship transfers is making prediction more difficult since it creates “blind spots.” In any case, $40 oil is not plausible or desirable, although I would personally like to spend less on gasoline! However, I am willing to pay more to punish Russia. The bottom line is that predicting oil supply, demand, and prices is a tough and complex game that has many variables and wildcards.

 

  

 

References:

 

Tariffs hit US oil and gas in the third quarter: Costs double. Gabriela León. Explicame. September 25, 2025. Tariffs hit US oil and gas in the third quarter: Costs double

OPEC+ is poised to slip further below oil output target. Seher Dareen and Ahmad Ghaddar. Reuters. September 26, 2025. OPEC+ is poised to slip further below oil output target

BP sees oil demand growth until 2030, dropping view for peak demand as soon as this year. Seeking Alpha. September 25, 2025. BP sees oil demand growth until 2030, dropping view for peak demand as soon as this year

Oil slips but heads for biggest weekly gain in 3 months on geopolitical tensions. Seeking Alpha. September 26, 2025. Oil slips but heads for biggest weekly gain in 3 months on geopolitical tensions

U.S. Shale Costs to Soar to $95 per Barrel Within a Decade. Tsvetana Paraskova. Oilprice.com. September 25, 2025. U.S. Shale Costs to Soar to $95 per Barrel Within a Decade | OilPrice.com

Why Crude Refuses to Crash Despite Glut Predictions. Irina Slav. Oilprice.com. September 22, 2025. Why Crude Refuses to Crash Despite Glut Predictions | OilPrice.com