Global gas: is there enough gas for energy transition?

Global gas production is forecasted to double from 400bcfd in 2023 to 800bcfd in 2050.

Our roadmap to ‘Net Zero’ requires doubling global gas production from 400bcfd to 800bcfd, as a complement to wind, solar, nuclear and other low-carbon energy. This data-file quantifies global gas production forecasts by country, what do you have to believe about global gas reserves, and is there enough gas?

Global gas production doubled in the c30 years from 1990-2019, rising at a 2.5% CAGR, which is the same trajectory that needs to be sustained to 2050 on our long-term energy market supply-demand balances.

Amazingly, from 1990-2019, global gas reserves increased from 4,000 TCF to 7,000 TCF, for a reserve replacement ratio of 190%, although the numbers have been cyclical and have fallen below 100% in recent years (chart below).

Another fascinating feature of gas markets is their flexibility, shown by plotting monthly gas production by country over time (chart below). In the Northern Hemisphere, production runs 6% higher than the annual average in December-January and 6% lower than average in June-August, as producers consciously flex their output to meet fluctuations in demand. Gas output does not show volatility, but voluntarity!

Global gas production by month is typically 15-20bcfd higher than average in Northern Hemisphere winter months and 15-20bcfd lower in Northern Hemisphere summer months, due to variations in heating demand

On our numbers through 2050, as part of the energy transition, a reserve replacement ratio of 107% is needed, while the ‘reserve life’ (RP ratio) will likely also decline from around 50-years today to 25-years in 2050. Please download the data-file for reserve numbers and production numbers by country.

Global gas reserves and RP ratio by country, from 1980 to 2050.RP ratio is expected to decrease from roughly 40 years today to 25 years in 2050.

Onshore resource extensions are seen primarily coming from shale, with continued upside in the US, and vast new potential in the Middle East, North Africa and possibly even European shale as a way of replacing Russian gas.

Another offshore cycle is also seen to be necessary, discovering and developing an average of 45 TCF of offshore resources each year in 2023-2050. These are big numbers, equivalent to discovering a large new gas basin (e.g., an “entire Mozambique of gas”) every 3-5 years.

Global gas consumption by region and over time is also estimated in the data-file, flatlining at 150bcfd in the developed world, but rising by 2.5x in the emerging world, with the largest gains needed in India, Africa and China (chart below).

Global gas consumption by country, from 1990 to 2050. Consumption is expected to double from 400 bcfd today to 800 bcfd by 2050 due to increased consumption from emerging markets.

Global LNG demand would also need to treble to meet this ramp-up, linking to our model of global LNG supplies. Within today’s LNG market, 25% flows to Europe, 20% to Japan, and 55% to the emerging world. By 2050, the emerging world would be attracting 80% of global LNG cargoes, with the largest growth in China and India.

Global LNG imports by country, from 1990 to 2050. Imports are expected to triple from 400 MTpa in 2023 to almost 1200 MTpa by 2050. The major importers will be China, India, and other Asian countries.

Our best guesses for how a doubling of global gas production might unfold is captured in this model of global gas forecasts by country/region. On the other hand, there is no guarantee that coal-to-gas switching will occur on the needed scale for global decarbonization, especially as 2023/24 has seen emerging world countries (India, China) ramping coal instead for energy security reasons.

Gas power: does low utilization entail spare capacity?

The US has >400GW of large gas-fired power plants running at 40% average annual utilization. Could they help power new loads, e.g., 60GW of AI data-centers by 2030? This 5-page note shows why low utilization does not entail spare capacity, and in turn, estimates true gas power spare capacity available for loads such as data-centers.

How much gas power spare capacity exists within the US power grid, and could this help to power the rise of AI or the rise of EVs, without having to construct new power generation?

To answer this question, we have aggregated EIA power market data across 1,850 active US gas-fired power generation facilities.

This 5-page note summarizes our key conclusions on the first page, followed by three pages of follow-up charts.

The note covers the generation capacity growth we are forecasting for AI and other new loads; the average utilization rates of gas generation by plant size (in MW) and by state; why low annual utilization cannot simply be translated into spare capacity; and our estimates for how much true spare capacity really exists within the US’s current fleet of gas turbines.

As a general rule of thumb, a typical US gas power generation facility runs at 40% annual utilization, which translates into 60% peak monthly utilization, 80% peak daily utilization and 100% peak hourly utilization.

This research note is available for TSE written subscription clients, while the underlying data behind our assessment of gas power spare capacity are linked below for TSE full subscription clients.

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.

Our recent research into power grid bottlenecks and the rise of AI also leaves us wondering whether there will be increasing pipeline utilization ahead for the US gas transmission network. Hence we have also broken down capacity utilization by pipeline in the file (chart below).

The average US gas transmission pipeline runs at an 80% utilization rate compared to its throughput capacity in bcfd

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).

major US gas pipelines ranked

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.

Peak commodities: everything, everywhere, all at once?

Commodities needed for energy transition

This 15-page note evaluates 10 commodity disruptions since the Stone Age. Peak demand for commodities is just possible, in total tonnage terms, as part of the energy transition. But it is historically unprecedented. And our plateau in tonnage terms is a doubling in value terms, a kingmaker for gas and materials. 30 major commodities are reviewed.

Renewable-heavy grids: dividing the pie?

Renewable-heavy grids

The levelized cost of partial electricity (LCOPE) is very different from the levelized cost of total electricity (LCOTE). This 21-page note explores the distinction. It suggests renewables will peak at 30-60% of power grids? And gas is well-placed as a back-up, set to surprise, by entrenching at 30-50% of renewables-heavy grids?

Density of gases: by pressure and temperature?

Density of gases

The density of gases matters in turbines, compressors, for energy transport and energy storage. Hence this data-file models the density of gases from first principles, using the Ideal Gas Equations and the Clausius-Clapeyron Equation. High energy density is shown for methane, less so for hydrogen and ammonia. CO2, nitrogen, argon and water are also captured.

The Ideal Gas Law states that PV = nRT, where P is pressure in Pascals, V is volume in m3, n is the number of mols, R is the Universal Gas Constant (in J/mol-K) and T is absolute temperature in Kelvin.

The Density of a Gas can be calculated as a function of pressure and temperature, simply by re-arranging the Ideal Gas Law, where Density ρ = P x Molecular Weight / RT. Our favored units are in kg/m3.

Density of methane in kg/m3 and kWh/m3

The Density of Methane (natural gas) can thus be derived from first principles in the chart below, using a molar mass of 16 g/mol, and then flexing the temperature and pressure. This shows how methane at 1 bar of pressure and 20ºC has a density of 0.67 kg/m3. LNG at -163ºC is 625x denser at 422 kg/m3. And CNG at 200-bar has a density of 180kg/m3.

Density of gases
Density of methane, LNG and CNG according to pressure and temperature

The Energy Density of Methane can thus be calculated by multiplying the density (in kg/m3) by the enthalpy of combustion in kJ/kg, and then juggling the energy units. A nice round number: the primary energy density of methane is 10 kWh/m3 at 1-bar and 20ºC, increasing with compression and liquefaction. CNG at 200-300 bar has around 30-60% of the energy density of gasoline, in kWh/m3 terms.

The energy density of methane is 10kWh/m3 as a nice rounded rule-of-thumb.

Clausius-Clapeyron: gas liquefaction?

Methane liquefies into LNG at -162ºC under 1-bar of pressure. The boiling points of other gases range from water at 100ºC, ammonia at -33ºC, CO2 at -78ºC, argon at -186ºC, nitrogen at -196ºC to hydrogen at -259ºC. This is all at 1-bar of pressure.

However, liquefaction temperatures rise with pressure, as can be derived from the Clausius-Clapeyron equation, and shown in the chart below. At 10-20 bar of pressure, you can liquefy methane into ‘pressurized LNG’ at just -105 – 123ºC, which can sometimes improve the efficiency of LNG transport. This can also help cryogenic air separation.

Density of gases
Boiling Points of Different Gases According to the Clausius Clapeyron Relationship

Density of CO2: strange properties?

The Density of CO2 is 1.87 kg/m3 at 20ºC and 1-bar of pressure, which is 45% denser than air (chart below). But CO2 is a strange gas. It cannot exist as a liquid below 5.2 bar of pressure, sublimating directly to a solid. CO2 can also be liquefied purely by compression, with a boiling point of 20-80ºC at 30-100 bar of pressure.

Density of Gas
Density of CO2 according to pressure and temperature in kg per m3

Hence often the disposal pipeline in a CCS or blue hydrogen value chain may often be pumping a liquid, rather than flowing a gas. And finally, these properties of CO2 open the door to surprisingly low cost CO2 transport by truck or in ships. This is all just physics.

Super-critical fluids: fourth state of matter?

There is also a fourth density state for all of the gases in the data-file. Above their critical temperature and critical pressure, fluids ‘become super-critical’. Sometimes this is described as ‘having properties like both a gas and liquid’. Mathematically, it means density starts rising more rapidly than would be predicted by the Ideal Gas Equations.

Super-critical gases behave unpredictably. Their thermodynamic parameters cannot be derived from simple formulae, but rather need to be read from data-tables and/or tested experimentally. This is why the engineering of supercritical systems tends to involve supercomputers.

Examples of super-critical gases? Steam becomes supercritical above 218-bar and 374ºC. CO2 becomes supercritical about 73-bar and 32ºC. Thus CO2 power cycles inevitably endure supercriticality.

Energy density of hydrogen lags other fuels?

The Density of Hydrogen is 0.08 kg/m3 at 20ºC and 1-bar of pressure, which is very low, mainly because of H2’s low molar mass of just 2g/mol. Methane, for example, is 8x denser. CO2 is 20x denser. In energy terms, gasoline is 3,000x denser per m3.

Hence hydrogen transportation and storage requires demanding compression or liquefaction. Tanks of a hydrogen vehicle might have a very high pressure of 700-bar, to reach a 40kg/m3 (the same density can be achieved by compressing methane to just 50-bar!). Liquefied hydrogen has a density around 70kg/m3 (LNG is 6x denser).

The density of hydrogen is just 0.08 kg/m3 at 20ºC of temperature and 1-bar of pressure

The energy density of hydrogen, in kWh/m3 also follows from these equations. At 1-bar and 20ºC, methane contains 3x more energy per m3 than hydrogen. Under cryogenic conditions, it contains 2x more energy. Under super-critical and ultra-compressed conditions, it contains 4x more.

The energy density of hydrogen is 50-75% lower than natural gas, even after compression/liquefaction

Data into the energy density of gases?

Similar energy density challenges constrain the use of ammonia as a fuel, as tabulated in the data-file, contrasted with other fuels, and discussed in our research note here.

This data-file allows density charts — in kg/m3 and in kWh/m3 — to be calculated for any gas, using the Ideal Gas Laws and the Clausius-Clapeyron equations. The data-file currently includes methane, CO2, nitrogen, ammonia, argon, water and hydrogen.

Gas dehydration: costs and economics?

Gas dehydration costs

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.

Gas dehydration costs
Capex costs of a TEG unit van vary widely but a good base case might be $25,000 per mmcfd of throughput

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.

Gas fractionation: NGL economics?

Gas fractionation

Gas fractionation separates out methane from NGLs such as ethane, propane and butane. A full separation uses up almost 1% of the input gas energy and 4% of the NGL energy. The costs of gas fractionation require a gas processing spread of $0.7/mcf for a 10% IRR off $2/mcf input gas, or in turn, an average NGL sales price of $350/ton. Costs of gas fractionation vary and can be stress tested in this model.

Wellhead gas is mainly composed of methane, it also contains propane, butane, C5s and C6+ fractions, which are entrained in the gas. These condensates or natural gas liquids (NGLs) can be removed by first dehydrating the gas, then, cryogenically cooling it, to ‘drop out’ all of the NGL fractions in a demethanizer (chart below). (For more details, we have written an overview of cryogenics)

The NGLs may then be heat exchanged with steam or warm oils, to warm them back up, and fractionate out the components: with ethane evaporating first in the de-ethanizer (boiling point is -89 °C), next propane in the depropanizer (boiling point is -42ºC) and butane next in a debutanizer (-1ºC). There may be separate stages to separate n-butanes from i-butanes.

Gas fractionation
Input Gas is split into dry gas and NGLs in a demethanizer then the NGLs are fractionated to yield outputs such as C2, C3, C4

The process can vary. Some facilities only drop out mixed NGLs, which are then shipped onwards. Others will cool the gas to separate out C3+, but will leave the ethane entrained, due to limited ethane uses outside of ethane crackers. You can flex these options in the data-file. But our base case captures a full separation of all NGL fractions.

Energy costs of full natural gas fractionation will come to 113kWh/ton of input gas (using up 1% of its energy content) and 600kWh/ton of NGLs (using up 4% of its energy content).

Capex costs of full natural gas fractionation can be estimated with the simple rule of thumb of around $1M/mmcfd of demethanizer capacity plus $5M/kbpd of NGL fractionation capacity. This is based on past projects, tabulated in the data-file.

The costs of a natural gas fractionation plant require a fractionation spread of $0.7/mcf of input gas processed, in order to separate all the NGL fractions and earn a 10% IRR. In other words, if the input gas price is $2/mcf, then the fractionation plant needs to charge a blended average of $2.7/mcfe on sales gas and the various NGL products.

What NGL prices are needed for a 10% IRR? At $2/mcf, our model requires a blended price around $350/ton, across ethane, propane, butanes, and higher fractions. Recent pricing is below, based on data from the EIA. Each $1/mcf on the gas price requires a further c$80/ton onto the required average NGL price.

Gas fractionation
Product Pricing for NGL Components

NGL fractionation is increasingly important to provide feedstocks for advanced polymers used in new energies and energy efficiency technologies. But we also see a growing role for low-carbon natural gas in the energy transition. And fractionation is usually done before natural gas is liquefied into LNG.

Leading companies operating natural gas fractionation plants are constellated around the upstream and midstream industries, while companies such as Technip, Linde, Lummus and other industrial gas companies and oil service companies supply equipment and technology for NGL fractionation plants.

European gas and power model: natural gas supply-demand?

This data-file is our European gas supply demand model. Balances are assessed in European gas and power markets from 1990 to 2030, reflecting all of our research into the energy transition. 2023-24 gas markets will look better-supplied than they truly are. We think Europe will need to source over 15bcfd of LNG through 2030. A dozen key input variables can be stress-tested in the data-file.

Europe’s gas demand averaged 45bcfd in the decade from 2012 to 2021, of which c30% was consumed in industry, c30% in residential heating, c10% in commercial heating, c25% in electricity generation, and smaller quantities in T&D and transportation (chart below). Gas demand is disaggregated across a dozen different industries in the data-file.

European gas demand fell back below 40bcfd in 2022. We think that one half of the decline can be attributed to a particularly warm winter, and will naturally come back with more normal winter weather. And total demand will run sideways through 2030.

Gas demand in the European power market is actually seen rising from 11bcfd in 2021 to 13bcfd by 2030, as the electrification of heat and vehicles raise overall demand, while decarbonization ambitions are also likely to phase down 2.5x more CO2 intensive coal (chart below).

Europe’s indigenous gas supply looks increasingly pathetic. We will likely fall below 7bcfd of domestic gas production in 2023, down from a peak of 24bcfd, 20-years ago. Even amidst the supply disruptions of 2022, there is no sign yet that Europe is seriously considering long term supply growth. Although there is vast potential in European shale.

Europe has doubled its reliance on imports over the past 20-30 years, rising from a 40-45% share of final demand in 1990-2004, to an 80-85% share in 2021-25. Thank god for Norway, which is also the cleanest and lowest carbon gas in the world.

Recently, Russian supplies have collapsed, while our outlook sees a large pull on global LNG through 2030. We think this will support LNG prices.

Although in 2023-24, European gas markets may look better supplied than they really are, due to excess inventories, that were built up as an insurance policy in 2022. This is temporary.

The data file also contains granular data, decomposing gas demand across 8 major categories, plus 13 industrial segments, going back to 1990 (albeit some of the latest data-points are lagged); as well as 15 different supply sources, with monthly data going back a decade (chart below).

All models are wrong, but some models are useful. Hence variables that can be flexed in the model, for stress-testing purposes, include the growth rates of renewables (wind and solar), the rise of electric vehicles, the rise of heat pumps, the phase out of coal and nuclear, industrial activity, efficiency gains, LNG and hydrogen.

Please download the model to run your own scenarios. Our numbers have changed since the publication of our latest outlook for European natural gas, but if anything, we see the same trends playing out even moreso.

Biogas: the economics?

Biogas costs are broken down in this economic model, generating a 10% IRR off $180M/kboed capex, via a mixture of $16/mcfe gas sales, $60/ton waste disposal fees and $50/ton CO2 prices. High gas prices and landfill taxes can make biogas economical in select geographies. Although diseconomies of scale reward smaller projects?

Biogas is a mixture of 50-70% methane and 30-50% CO2, produced from the anaerobic digestion of organic matter, such as manure, sewage or crop residues, or other organic waste. Archaea notes that 72% of US renewable natural gas comes from landfills, 20% from livestock, 5% from organic waste and 3% from wastewater.

This economic model captures the costs of biogas production, informed by 20 case studies, covering yields, capex, opex, IRRs and sensitivities.

Biogas yields average around 4 mcf per ton of input material, although smaller plants may find it easier to source high-quality feedstocks, with greater quantities of volatile organic matter, and greater conversion of that matter into biogas (chart below).

The capex costs of biogas plants are also tabulated from the 20 case studies in this data-file. Costs vary. But good rules of thumb might be $200/Tpa of feedstocks. In energy industry terms, this is equivalent to around $180M/kboed, or around 6x the costs of offshore hydrocarbons, or around $2,500/kW-th, which again is around 2x higher than the per kW-e costs of solar or onshore wind.

Biogas production facilities need to earn around $35-40/mcfe of methane-equivalent production in order to generate a 10% IRR on their up-front capex. There are four main revenue streams: gas, waste disposal fees, CO2 prices or incentives, and the value of residual digestate, which can be used as fertilizer or bedding in agriculture.

Our base case biogas cost model sees a 10% IRR from a combination of $16/mcf methane, $60/ton disposal fees and a $50/ton CO2 incentive. However, $120/ton landfill taxes can take the methane-equivalent price down to as little as $2.5/mcf. Hence the economics depend on landfill taxes and gas prices in different countries.

Revenue breakdown at 10% IRR for biogas production depending on the price of methane, disposal fees, and carbon tax. This suggest greatly varying profitability in different geographies.

Biogas production in Europe currently comprises around 1-2% of the total gas grid, although some studies have estimated that total biogas production could reach 10-20% of total, or around 50-100bcm pa in Europe, via a “huge scale-up”.

One interesting observation from the charts above is that unlike other economic models in our library, biogas facilities may not benefit from economies of scale. Smaller facilities seem to cost less in capex terms and achieve higher yields. This suggests an opportunity for middle-markets private equity and companies with many small facilities?

Please download the data-file to stress-test biogas production costs. We are also constructive on some of the economic opportunities in landfill gas and biochar.

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