the research consultancy for energy technologies
Our natural gas research looks for opportunities in the energy transition. Specifically, natural gas is the lowest-carbon fossil fuel. Methane has a chemical formula of CH4. Thus 1mcf of methane contains 304kWh of energy, of which 46% is from combusting carbon atoms into CO2 and the other 54% is from combusting hydrogen atoms into innocuous H2O.
By contrast, fuels such as coal are effectively pure carbon, substantively all of their energy is derived from combusting carbon into CO2. Thus they are 2x more CO2 intensive per unit of energy. This is why our roadmap to net zero effectively eliminates unabated coal usage, which in turn requires ramping natural gas by 2.5x, to around 275 TCF pa in 2050.
This fuel-switching delivers almost as much decarbonization in our models as renewables themselves. Gas power is an effective back-up for times when the sun is not shining and the wind is not blowing.
This is not a free pass for the gas industry. It is also important to produce and consume gas as cleanly and efficiently as possible. This includes mitigating methane leaks, increasing the efficiency of turbine technologies (especially combined heat and power) and capturing remaining CO2, such as via CCS or blue hydrogen.
Overall our natural gas research in the energy transition does find good, pragmatic and low cost opportunities ahead for the natural gas industry.
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.
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?
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 already 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).
On our numbers through 2050, 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.
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 resource 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.
Our best guesses for how a doubling of global gas production might unfold is captured in this model of global gas production forecasts by country/region and global gas reserves.
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.
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.
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.
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.
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.
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.
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.
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 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.
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 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.
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.
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.
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.
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 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.
This data-file tabulates the five ‘Big Oil’ Super-Majors’ development capex from the mid-1990s, in headline terms (billions of dollars) and in per-barrel terms ($/boe of production). Real development capex quadrupled from $6/boe in 1995-2000 to $24/boe in 2010-15, and has since collapsed to $10/boe.
The peer group of Super-Majors comprises ExxonMobil, Chevron, BP, Shell and TOTAL, which comprise c10% of the world’s oil production and 12% of the world’s gas production. As a good rule of thumb, this group can be thought of as c10% of global production.
Development capex by region: gaining share? The US has always been the most favored destination, attracting c25% of all development capex, both offshore (e.g., Gulf of Mexico) and increasingly for short-cycle shale. However, the share of these companies’ development capex in the US has averaged around 32% in the past three years.
Development capex by region: losing share? Development projects in Africa and Europe have fallen most out of favor. Development capex in Africa peaked at $17bn in 2009, almost 25% of the group’s total development capex, and has since fallen back to $5bn per year, or 8% of the group’s total development capex.
It is somewhat terrifying to consider that the industry needed to spend an average of $15/boe (real terms) on development capex in order to hold its organic production “flattish” (including some large acquisitions in 2014-17, such as Shell buying BG).
Another scary data-point is that this peer group of Super-Majors spent $18/boe (real) on development projects in the decade from 2004-14 (which is 80% more than recent levels of spending) yet its net production declined by 1.5% per year over this timeframe.
Similar data for the Super-Majors’ exploration capex over time is tabulated here.
Under-investment across the entire energy industry may foreshadow a sustained shortage of energy, especially if 50% lower-carbon gas is intended to replace coal as part of the energy transition, per our roadmap to net zero. Hence one cannot help wondering about energy shortages, energy pragmatism and our fears of another up-cycle.
This data-file aggregates the Oil Majors’ development capex, across ExxonMobil, Chevron, BP, Shell and TOTAL disclosures, apples-to-apples, back to 1995, based on supplementary oil and gas disclosures, in the SEC’s EDGAR archives.
The flue gas of a typical combustion facility contains c7% CO2, 60ppm of NOx, 40ppm of SOx and 2ppm of particulate dusts. This is our conclusion from tabulating data across 75 large combustion facilities, mainly power generation facilities in Europe. However, the range is broad. As a rule of thumb, gas is cleanest, biomass and coal are worse, while some diesel-fired units are associated with the lowest air quality in our sample.
Sulphur oxides (SOx) cause acidification, in the air, in rain and in natural habitats. Hence limits are placed on the sulphur emissions in the exhaust gases of large power facilities. The limits are typically 50-250ppm in Europe, 120ppm in the US and 75-300ppm in China. We think European coal plants emit 20-400 ppm of SOx, with an average of 85ppm, which has been reduced by installing gas scrubber units in recent years. Emissions from natural gas plants are effectively nil.
Nitrogen Oxides (NOx) cause ground-level ozones and smogs to form, which can contribute to respiratory problems. Thus limits in the exhaust gases of large power plants are 60-130ppm in Europe, 90-120ppm in the US and 75-150ppm in China. We think the average coal plant in Europe emits NOx at 110pm. The numbers are highest for large diesel plants averaging 160ppm, high for biomass plants averaging 80ppm, and lowest for gas turbines averaging 25ppm at CCGTs.
Particulates and dusts are combustion products that become airborne and are later deposited on buildings, machinery, natural habitats or worst of all inhaled. Dusts are limited to 3-9 ppm in the emissions of large power plants in Europe, 17ppm in the US and 22ppm in China. The average coal plant emits at 9 ppm in Europe, due to the installation of electrostatic precipitators and other exhaust gas treatments. Again, biomass and diesel plants can have high particulate emissions. Gas fired power plants seem to have particulate emissions well below 1ppm.
Underlying data on different power plants are broken down in this data-file. Note that European databases report estimated SOx, NOx and particulate emissions for large combustion facilities in tons, but we have applied our own back-of-the-envelope conversion factors, to translate the data into ppm and mg/m3 emissions intensities.
A typical simple-cycle gas turbine is sized at 200MW, and achieves 38% efficiency, as super-heated gases at 1,250ºC temperature and 100-bar pressure expand to drive a turbine. The exhaust gas is still at about 600ºC. In a combined cycle gas plant, this heat can be used to produce steam that drives an additional turbine adding 100MW of power and c20% of efficiency, for a total efficiency of 58%. This data-file tabulates the operating parameters of gas turbines.
Why do gas turbines matter? Recuperated Brayton cycles are going to be a defining technology of the energy transition and a complement to renewables. The thermodynamics are explained here. The key point is that gas-fired power cycles are totally different from steam cycles. They run off a fuel that is 50% lower carbon than coal. They can realistically be 2-3x more efficient per unit of fuel. They are more flexible (data here). And they may also be easier to decarbonize directly (example here).
How does a gas turbine work? First, air is drawn into a compressor. The compression ratio is typically around 20x. The pressurized air is then heated by combusting a fuel. The result is a very hot, very high-pressure gas. This can be used to drive a turbine as it expands. For example, expanding 1 ton of gas from a turbine inlet temperature of 1,250ºC and a turbine inlet pressure of 100-bar, down to an exhaust gas temperature of 600ºC and near-ambient pressures, might see volumes increase by around 25x (chart below).
Simple cycles versus combined cycles. If the 600ºC exhaust gas is simply discharged into the atmosphere, then a typical simple cycle gas turbine will achieve 38% efficiency, converting natural gas into electricity. But there is still a lot of energy in a 600ºC exhaust stream, which can be used to evaporate water, produce high pressure steam, and then drive an entirely separate turbine. This is a combined cycle configuration. And it adds another 20% efficiency, yielding a total efficiency of 58%.
Note that the steam cycle described above, powered by the waste heat from a gas turbine, is effectively the same as the primary heat cycle used in other conventional thermal power plants (Rankine cycle). This is remarkable.
The efficiency of a simple cycle gas turbine depends primarily on the turbine inlet temperature and pressure, which in turn depend on the compression ratio. The most efficient simple cycle gas turbines hit 43% efficiency, with compression ratios of 25-30x, turbine inlet pressures of 140-180 bar and turbine inlet temperatures of 1,400-1,600ºC. It is quite hard to get hotter than this, because things start to melt. But consider, for contrast, that a steam cycle really struggles to surpass 300-500ºC.
Why does a gas turbine look like that? To achieve these high compression ratios a typical gas turbine will have 12-22 separately optimized and sequential compression stages. And to maximize power output in the turbine, it will typically have 4 turbine stages. This explains the classic cross sectional profile of a gas turbine.
How fast does a gas turbine spin? A simple cycle gas turbine typically spins at 3,000-4,000 revolutions per minute (rpm). The compressor is connected to the same shaft as the turbine. The back-work ratio imparted to the compressor is equivalent to around 40-50% of the net work driven through the turbine.
How large is a gas turbine? A typical 200MW gas turbine might take up 60 m2 and weigh 300 tons. Good rules of thumb are 0.3 m2/MW of areal footprint, and 2 tons/MW of weight. Although larger gas turbines are more compact (on a per MW basis).
What is the cost of a gas turbine? A typical gas turbine might cost $200/kWe (chart below). Larger gas turbines have lower costs per MW (chart below). However note that our model of a gas-fired power plant assumes total capex of $850/kW. In other words, total installed capital costs are typically around 4x larger than the turbine itself.
(This multiple may be worth keeping in mind amidst debate about hydrogen electrolyser costs. Some companies have been guiding to $200-300/kWe electrolyser selling prices, and some analysts noting that this realistically means around $1,000-1,200/kW fully installed costs).
Emissions from natural gas power plants are generally low. CO2 intensity is 0.3 kg/kWh from a 60% efficient combined cycle gas turbine (up to 70% below coal power plants). NOx emissions are usually below 25ppm but can be as low as 2ppm in the best models. Many new turbines are also hydrogen ready, and have been qualified for 25-75% hydrogen blending.
Flexibility of a gas fired power plant is middling to high. A typical plant can ramp up or down by 15% of its nameplate capacity per minute, turn down to c25-50% of its load, and start up from cold in 20-minutes. Different examples are tabulated in the data-file.
Our outlook for gas turbines in the energy transition is published here. Leading companies in gas turbines are profiled here. Gas turbine operating parameters are compiled for a dozen gas turbine models in this data-file, as a useful reference, mainly designs from Siemens Energy, GE, Mitsubishi-Hitachi and Ansaldo.