Midstream in energy transition?

Midstream opportunities in the energy transition?

The midstream industry moves molecules, especially energy-molecules, and especially in pipelines. Despite the mega-trend of electrification, there are still strong midstream opportunities in the energy transition, backstopping volatility and moving new molecules. This short note captures our top ten conclusions.

(1) Our overall outlook on the US midstream industry sees the total tonnage of molecules moved rising by 25%, from 2.6GTpa in 2023 to 3.3GTpa in 2030, and then plateauing around these levels. This illustrates that growth opportunities in gas, CCS and some hydrogen value chains outweigh declines in markets such as oil.

(2) Global gas demand doubles in our roadmap to net zero, in order to displace coal; global LNG trebles; while another under-appreciated angle is that growing applications like blue hydrogen, LNG and polymers all require more gas processing within the midstream sector as part of their value chains. Narrowing in on the US market, US gas demand rises 8% by 2030 and 12% by 2035 as captured in our US energy model.

(3) Gas will entrench as the leading backstop for renewables, and especially in the face of power grid bottlenecks, and to power AI data-centers that require reliable round-the-clock power. This will raise the capacity utilization of existing gas transmission lines.

(4) Volatility is also rising in the global energy industry, due to the inherent volatility of solar and wind. Rising volatility increases the value of midstream infrastructure, which by definition, can arbitrage the volatility by moving molecules from areas of low pricing to high pricing.

(5) The upside from tighter capacity and rising volatility primarily accrues to marketers and traders, because of the way pipeline assets are regulated (e.g., by FERC), but some upside inevitably trickles back to the regulated pipelines too, per our 13-page note here.

(6) Global oil demand does soften to 85Mbpd by 2050 in our roadmap to net zero, but the mix shift may be more sanguine for midstream companies, scaling back products that tend NOT to be delivered by pipeline (e.g., gasoline) while scaling up products that do (e.g., jet fuel, BTXs, intermediates for polymers). Looking by region, we also see continued growth through 2030 in US shale output.

(7) CO2 disposal ramps up most of any new midstream opportunities, from c40MTpa in the early-2020s to 7GTpa globally by 2050, in our roadmap to net zero, across conventional CCS, blue hydrogen, CO2-EOR and novel combustion and next-gen DAC. We think c1GTpa will be in the US. CO2 purity must be >90%, ideally >97%. This is the largest new growth opportunity for midstream companies.

(8) Costs of midstream components are quantified in our research, such as oil pipelines at $2/bbl/1,000km, oil storage at $1.5/bbl, gas pipelines at $1/mcf/1,000km, gas fractionation at $0.7/mcf, gas dehydration at $0.02/mcf, LNG transport at $1-3/mcf, CO2 pipelines at $5/ton/100km, liquefied CO2 shipping at $8/ton/1,000km, CO2 disposal at $20/ton, hydrogen blending, hydrogen transportation, hydrogen storage at $2.5/kg. Underlying components include storage tanks, pumps and compressors.

(9) Mitigating methane leaks remains a crucial priority, especially in gas gathering lines. The best opportunities are captured in our report on mitigating methane leaks and by building our more midstream infrastructure to reduce flaring, where as much as 8% of the methane may slip through the flares uncombusted.

(10) Midstream companies are screened in our work. This includes companies in US gas transmission and gas marketing, and a dozen LNG vessel owners. Gas gathering and processing emits 18 kg/boe of CO2e, across 20 major companies in gas gathering. Downstream gas distribution leaks 0.2% of methane sold, ranked across 15 major companies in gas distribution. We have also screened companies in pipeline technology and flaring reduction technologies.

US shale: outlook and forecasts?

What outlook for US shale in the energy transition? This model sets out our US shale production forecasts by basin. It covers the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rates, well productivity and type curves. US shale likely adds +1Mbpd/year of production growth from 2023-2030, albeit flatlining in 2024, then re-accelerating on higher oil prices. Our shale outlook is also summarized below.

What outlook for shale in energy transition?

Shale is a technology paradigm where well productivity has risen by 3-7x over the past decade, through ever greater digitization. Shale economics are very strong, with 20% IRRs at $50/bbl oil on shale oil (model here) or at $2.8/mcf on shale gas (model here). We think 100bn bbls of recoverable shale resources remain in the US and ultimately, liquids production could be ramped up from 10Mbpd in 2023 to 17Mbpd by 2030 (note here), and most of this will be needed as energy shortages loom.

However the US shale industry has shifted its focus towards capital discipline and ESG. US shale averages 10kg/boe on a Scope 1 upstream basis (data here), shale oil averages 25kg/boe on a full Scope 1&2 basis running up to the refinery gate (data here) and 55kg/boe on a refined basis running up to the point of combustion (data here). The spread is wide, after comparing and contrasting 425 companies here and here. The best decarbonization opportunities for shale are mitigating flaring and methane leaks followed by electrification. Ultimately, we think the best operators could reach CO2 neutrality.

The most important questions on shale are how the resource base and well productivity will trend. This has been the topic of our shale research, and our latest views are covered in our 2024 shale outlook. Historically, we have also undertaken large reviews of the pace of shale technology progress, based on technical papers (examples here and here). There are fifty variables to optimize. And we are most excited about big data techniques, fiber optics and shale-EOR.

Modelling US shale production by basin?

Our model for US shale production looks at each of the main basins, using a factor breakdown. Total production in month T1 = Total production in month T0 + new additions – base declines. To calculate new monthly additions, we multiply (a) number of rigs running (b) wells drilled per rig per month (c) wells completed per well drilled (d) initial production of newly completed wells (IP30). And to calculate the base declines, we fit a best-fit type curve onto the new additions from past months. This model has worked quite smoothly for 6-years now, including history going back to 2011 and forecasts going out through 2030.

The Permian basin is the largest US shale oil basin, with 8Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Permian basin has seen an average of 340 rigs running, drilling an average of 1.2 wells per rig per month, completing 1.06 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +850kbpd/year of new supply to global oil markets. We still see strong growth potential, and the Permian could reach 14Mbpd of total liquids production by 2030, amidst higher activity and oil prices. All of these variables can be stress-tested in the model.

The Bakken is the second largest US shale oil basin, with 1.3Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Bakken has seen an average of 40 rigs running, drilling an average of 1.9 wells per rig per month, completing 1.15 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +20kbpd/year of new supply to global oil markets. We see a decline in 2024, a recovery in 2025-26 and a plateau through 2030.

The Eagle Ford is the third largest US shale oil basin, with 1.1Mbpd of liquids production in 2023. Over the past six years from 2017-2023, the Eagle Ford has seen an average of 60 liquids-focused rigs running, drilling an average of 2.1 wells per rig per month, completing 1.22 wells for every well drilled (DUC drawdown) at an initial production rate of 680bpd (IP30 basis), but liquids production has actually declined, especially during the volatility of the COVID years. We see a decline in 2024, a recovery in 2025-26 and a plateau through 2030.

Challenges and controversies for US shale?

The main revisions to our shale production models have been because of lower activity, as capital discipline has entrenched through the shale industry. The chart below shows our forecasts for activity levels at different, prior publication dates of this model. We have compiled similar charts for all of the different variables and basins, in the ‘revisions’ tab, to show how our shale numbers have changed.

Our shale outlook for 2023-2030 sees the potential for +1Mbpd of annual production growth as the industry also generates $150-200bn per year of annual free cash flow. You can stress test input variables such as oil prices in the model.

We have also modeled the Marcellus and Haynesville shale gas plays, using the same framework, in further tabs of the data-file. Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion here, with just 20-50 additional rigs. Although recently we wonder whether the US blue hydrogen boom will absorb more gas and outcompete LNG, especially as the US Gulf Coast becomes the most powerful clean industrial hub on the planet (note here).

International shale? We have found it harder to get excited about international shale, but there is strong potential in other large hydrocarbon basins, if European shale is ever considered to rescue Europe from persistent gas shortages, and less so in China.

Please download the data-file to stress-test our US shale production forecasts by basin.

Midstream gas: pipelines have pricing power ?!

High utilization can provide hidden upside for transmission operators

FERC regulations are surprisingly interesting!! In theory, gas pipelines are not allowed to have market power. But they increasingly do have it: gas use is rising, on grid bottlenecks, volatile renewables and AI; while new pipeline investments are being hindered. So who benefits here? Answers are explored in this 13-page report.

CCS: what CO2 purity for transport and disposal?

CO2 purity required for various purposes. The highest purities are required by food, beverage, and medical purposes, as well as shipping and liquefaction. CO2 disposal has the highest variability. For any purpose the purity must still be at least 90%.

The minimum CO2 purity for CCS starts at 90%, while a typical CO2 disposal site requires 95%, CO2-EOR requires 96%, CO2 pipelines require 97% and CO2 liquefaction or shipping requires >99%. This data-file aggregates numbers from technical papers and seeks to explain CO2 purity for transport and disposal.

Our roadmap to net zero includes 7GTpa of CO2 disposal, across various technologies, from straight-run amine CCS, to DAC, CO2-EOR, blue hydrogen SMRs and ATRs, oxy-combustion, potassium carbonate, other sorbents, next-gen membranes. But what CO2 purity levels do these technologies need to meet?

Energy efficiency is the first reason that CO2 purity matters. As a very simple rule of thumb, compressing a gas stream to 80-200 bar requires 90-120 kWh/ton of compression energy. If the gas stream is only 90% CO2, then the energy costs per unit of CO2 are around 10% higher.

Or more. The reason it is necessary to compress CO2 to >80-bar is so that the CO2 will transition into a dense (super-critical) phase. The phase diagram below shows the critical point for pure CO2. But impurities require higher pressures before CO2 reaches supercriticality.

Larger pipelines are also required to move larger quantities of gas at higher pressures. This matters because larger pipelines with thicker walls have higher capex costs, per our data-file into gas pipeline costs.

The other key reason that CO2 purity matters for CCS is that if the gas stream has less than 100% CO2, then by definition, it must contain something else. Clearly, issues will arise is the ‘what else’ is toxic or hazardous (e.g., H2S, amine degradation products such as nitrosamines, NOx, SOx, etc). But even innocuous contaminants can have an impact.

Water is a key impurity that must be managed in a CO2 pipeline. If puddles of water precipitate out, then they will slowly start dissolving CO2, and greatly accelerate pipeline corrosion. CO2 + H2O -> H2CO3 (carbonic acid). H2CO3 -> 2H[+] + CO3[2-]. Fe(s) + 2H[+](aq) -> Fe[2+] (aq) + H2 (g). It is never good to dissolve your pipeline from the inside out. Furthermore, the H2 can cause further stress cracking.

Hence water is usually limited to <500ppm, ideally <50ppm. This is more of a convention than a hard rule (examples are tabulated in the data-file). Usually, as much as 4,450 ppm of water will be soluble in pure CO2 at 40◦C and 100-bar pressures. Even with 10% nitrogen impurities, this only reduces to 3,400 ppm. Some amine breakdown products, or NO2 can have a more “dramatic effect” on the width of the phase envelope.

CCS challenges: by any amines necessary?

But there is also always a margin of safety for cold spots, bends in the pipeline or in the case of depressurization. A pipeline operator has the prerogative to set whatever standards it deems necessary to protect the longevity and efficiency of its investment. Off-spec CO2 may be charged a materially higher transportation tariff if it is accepted at all.

CO2-EOR also requires a higher purity than straight-run CCS, in order to promote miscibility of the CO2 with oil in the subsurface, which will help to swell and mobilize it. This is less important for simple geological disposal.

CO2 transportation by ship or CO2 transportation by truck also requires very high purity, well above 99%, in order to liquefy the CO2, at 20 to -50◦C and 7-15 bar pressures. For example, any residual water vapor in the stream is going to freeze out and plug the system. So this requires the highest purity of CCS value chains and dedicated dehydration.

Carbon capture on ships: raising a sail?

CO2 purity for CCS will generally need to be above 95%, and ideally will be as high as possible. This favors CCS technologies that can create highly concentrated CO2 streams from exhaust gases of differing CO2 concentrations. But the limits are not overly strict, or likely to deter CCS, in our view. For more related research, please see our overview of CCS value chains.

Oil markets: rising volatility?

There have been a total of 80 oil market volatility events from 2003 to 2023, with an average magnitude of +/- 320kbpd. The largest drops in oil production were due to sanctions or unrest.

Oil markets endure 4 major volatility events per year, with a magnitude of +/- 320kbpd, on average. Their net impact detracts -100kbpd. OPEC and shale have historically buffered out the volatility, so annual oil output is 70% less volatile than renewables’ output. This 10-page note explores the numbers and the changes that lie ahead?

Energy market volatility: climate change?

Wind and solar produce power intermittently. As they ramp to provide higher shares of total grid power, they will also increase the magnitude low likelihood volatility events. This will increase the overall volatility of global energy markets.

This 14-page note predicts a staggering increase in global energy market volatility, which doubles by 2050, while extreme events that sway energy balances by +/- 2% will become 250x more frequent. A key reason is that the annual output from wind, solar and hydro all vary by +/- 3-5% each year, while wind and solar will ramp from 5.5% to 30% of all global energy. Rising volatility can be a kingmaker for midstream companies? What other implications?

US gas transmission: by company and by pipeline?

This data-file aggregates granular data into US gas transmission, by company and by pipeline, for 40 major US gas pipelines which transport 45TCF of gas per annum across 185,000 miles; and for 3,200 compressors at 640 related compressor stations.

This data-file aggregates data for 40 large US gas transmission pipelines, covering 185,000 miles, moving the US’s 95bcfd gas market. Underlying data are sources from the EPA’s FLIGHT tool.

Long-distance gas transmission is highly efficient, with just 0.008% of throughput gas thought to leak directly from the pipelines. Around 1% of the throughput gas is used to carry the remaining molecules an average of 5,000 miles from source to destination, with total CO2-equivalent emissions of 0.5 kg/mcfe. Numbers vary by pipeline and by operator.

Five midstream companies transport two-thirds of all US gas, with large inter-state networks, and associated storage and infrastructure.

The largest US gas transmission line is Williams’s Transco, which carries c15% of the nation’s gas from the Gulf Coast to New York.

The longest US gas transmission line is Berkshire Hathaway Energy’s Northern Natural Gas line, running 14,000 miles from West Texas and stretching as far North as Michigan’s Upper Peninsula.

Our outlook in the energy transition is that natural gas will emerge as the most practical and low-carbon backstop to renewables, while volatile renewable generation may create overlooked trading opportunities for companies with gas infrastructure.

In early-2024, we have updated the data-file, screening all US gas transmission by pipeline and by operator, using what are currently the latest EPA disclosures from 2022. The data-file also includes gas market volumes across 670 entities, based on Ferc 552 disclosures.

Previously, we undertook a more detailed analysis, matching up separately reported compressor stations to each pipeline (80% of the energy use and CO2e come from compressors), to plot the total CO2 intensity and methane leakage rate, line by line (see backup tabs).

US gas transmission by company is aggregated — for different pipelines and pipeline operators — in the data-file, to identify companies with low CO2 intensity despite high throughputs.

Pump costs: energy economics of electric pumps?

As pump power increases, pump costs per kWh decrease. The most significant reduction is in pump maintenance costs, while the total cost of electricity remains constant.

Total pump costs can be ballparked at $600/kW/year of power, of which 70% is electricity, 20% operations and maintenance, 10% capex/capital costs. But the numbers vary. Hence this data-file breaks down the capex costs of pumps, other pump opex, pump energy consumption and the efficiency of pumps from first principles.

This data-file captures the energy economics of electric pumps, which are used to move liquids in industrial applications, for commercial/domestic use such as within heat pumps, for demand shifting, for supercritical CO2, in geothermal applications, and in 15-20% of the world’s 1M oil wells globally (electric submersible pumps, or ESPs).

The capex costs of a pump are estimated from fifty commercial data-points, in $/kW, and a line of best fit suggests that pump costs approximately halve as pump size increases by 10x (chart below). In other words, larger pumps are less costly per kW of power.

Total pump costs, however, are usually only 5-20% capex, while the largest costs are for electricity use, at 50-90% of the total, depending on the pump size and utilization rate (chart below). All of these variables can be stress-tested in the ‘PumpModel’ tab.

The power consumption of a pump is modeled from first principles, using the formula that pump power consumption (in kW) equals flow rate (in m3/second) times back-pressure (in kPa) divided by pump efficiency (in %). The ‘PumpEnergy’ tab contains a simple and flexible calculator for pumping power (in kW).

Back-pressure on a pipeline, in turn, is the sum of static head (overcoming gravity), dynamic pressure (overcoming inertia) and head losses (calculated using the Darcy-Weisbach and Colebrook Equations from flow speed, Reynolds Numbers, pipeline diameter and pipeline surface roughness).

Energy costs of a pump are best minimized by using wider pipes with smoother internal surfaces (chart above). But these pipes will also have higher costs themselves. Hence a total systems approach is needed to find the lowest overall costs.

Electric submersible pumps in the oil and gas industry are also modelled in two further back-up tabs. A typical Electric Submersible Pump (ESP) will contribute $0.3/boe of cost and 5kg/boe of carbon, if powered by diesel, at a typical oilfield (chart below). And more at deeper wells with higher water cuts. Switching the ESP to run on renewable power, can readily reduce costs and CO2 intensity.

Electric Submersible Pump Optimisation Opportunities?

Please download the data-file to stress test the costs of electric pumps, as a function of lifetime (years), capex costs ($/kW), capital costs (%WACC), utilization rate (%), efficiency (%), flow rates (m3/hour) and other operating costs ($/kW/year).

Storage tank costs: storing oil, energy, water and chemicals?

Storage tank costs are tabulated in this data-file, averaging $100-300/m3 for storage systems of 10-10,000 m3 capacity. Costs are 2-10x higher for corrosive chemicals, cryogenic storage, or very large/small storage facilities. Some rules of thumb are outlined below with underlying data available in the Excel.

This data-file tabulates 80 data-points into the costs of storage tanks for water, oil products, chemicals, LNG, natural gas and hydrogen. In both $/m3 terms and $/ton terms.

This matters as storage tanks are used in downstream industry, materials value chains, and in several types of new energies such as redox flow batteries or pumped hydro.

We also think that some industrial facilities may be able to benefit from increasingly volatile power prices, amidst the build out of renewables, by demand shifting, which means timing their electrical loads to the times when renewables are generating. In some cases, this requires increasing the sizes of storage tanks to increase flexibility.

Volatility is also growing in the global energy system, which may allow owners of midstream infrastructure to generate excess returns in years of deep shortages, per our overview of energy market volatility.

A good rule of thumb is that the storage tank costs for storing fluid commodities will average around $100-300/m3 of capacity, at capacities of 10m3 to 10,000 m3, for relatively simple and non-hazardous commodities such as water and fuel.

Generally tank costs fall (in $/m3 terms) as tank capacities rise. Bigger tanks benefit from economies of scale, and this is visible in the chart above for all categories. Although some mega-sized terminals re-inflate.

Costs are typically 3-5x higher for corrosive chemicals that can require double tanks, stainless steel or specialized tank linings. Maybe $1,000/ton is fair here.

Costs are also typically 3-5x higher for storing cryogenic liquids, which can require specialized nickel steel and insulation.

Costs are also 2-3x higher for very small tanks (below 10m3, lacking economies of scale) or very large tanks (on the magnitude of 100,000m3, so large that they need to be stick-built rather than simply purchased as finished modular units).

LNG storage tanks thus come in as some of the most expensive storage facilities in the data-file, because they are very large and cryogenic. Higher capex may be worthwhile to install higher grade tanks that minimize boil-off and improve energy efficiency.

Large-scale hydrogen storage would likely be higher cost than LNG storage, in our view, and the median small-scale facility for cryogenic or ultra-compressed hydrogen storage is estimated to cost $8,000/m3. Please see our hydrogen storage model and broader hydrogen research.

Storage costs are lowest for underground gas storage, with a median $0.4/m3 of storage capacity. The key reason is scale. The average facility in our database can store over 1bcm of gas.

Methodology. Mainly we have aimed to capture tank costs in the data-file, while excluding the costs of their foundations, pumps, valves and installation; but the lines get a little bit blurry, especially for some of the very large tanks.

Context matters. Some of the data-points are supplier quotes, some are estimates for technical papers, and some are disclosed data-points from specific projects. Please download the data-file for the additional context.

Gas dehydration: costs and economics?

Gas dehydration costs might run to $0.02/mcf, with an energy penalty of 0.03%, to remove around 90% of the water from a wellhead gas stream using a TEG absorption unit, and satisfy downstream requirements for 4-7lb/mmcf maximum water content. This data-file captures the economics of gas dehydration, to earn a 10% IRR off $25,000/mmcfd capex.

Wellhead gas might have up to 0.2% water entrained within it (100lb/mmcf). This should ideally be reduced by 90-95%, to below 7 lb/mmcf, sometimes below 4lb/mmcf.

The main reasons for reducing the water content of natural gas are to avoid issues in downstream equipment and pipelines, such as plugging or hydrate formation. For example, as an LNG plant cools the gas stream to -160C, any water is clearly going to freeze out.

Dehydration is also necessary for other gas streams. For example, some of the recent projects that have crossed our desk are aimed at dehydrating CO2 in CCS projects, so that it does not form carbonic acid and dissolve disposal pipelines. Hydrogen may also require dehydration, downstream of a reforming unit or some electrolysis plants.

Gas dehydration most commonly takes place by absorbing the water in tri-ethylene glycol (TEG). TEG acts as a solvent for water at ambient temperatures in an absorber unit. Then the water can be stripped from the TEG solution by heating to 200ºC in a reboiler unit. Many readers will note this is effectively the same plant configuration as for post-combustion CCS using amines.

The global TEG market is worth around $800M per year, implying c500kTpa of production at $1.5-2.0/kg. TEG is made via the step-wise oligomerization of ethylene oxide.

In our base case model, gas dehydration costs $0.02/mcf to earn a c10% IRR while covering the capex of the TEG unit, using up 0.03% of the energy in the gas itself (i.e., a 0.03% energy penalty) and adding 0.03 kg/mcf to the CO2 intensity of gas.

This data-file allows for stress-testing of TEG unit capex (chart below), maintenance, electricity use, heat consumption, CO2 prices, TEG make-up costs and other opex costs.

TEG dehydration units are under increasing scrutiny due to methane emissions, including from pneumatically powered components.

Alternatives to TEG dehydration units include solid sorbents and molecular sieves. For an overview, see our note into swing adsorption.

But we think the most interesting read across from our gas dehydration model is for CCS/DAC. Using this fully mature technology, for which over 200,000 units have been installed to-date, we think the costs “per ton of water removal” still equate to $450/ton and the capex costs equate to around $5,000/Tpa. Details in the data-file.

What outlook for shale in energy transition?

Modelling US shale production by basin?

Challenges and controversies for US shale?

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