natural gas research

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.

Global heat pump sales by country?

Heat pumps sold in different geographies from 2012 to 2023. 2023 was the first year in this database that sales declined.

Global heat pump sales by country are tabulated in this data-file, for 14 countries/regions. Developed world heat pump sales rose at an 11% CAGR over the decade since 2012, reaching 7M units sold in 2022, but then unexpectedly fell by -10% in 2023, including YoY declines in 7 out of the 14 countries we are tracking.

How are heat pumps defined? In the broadest sense of the term, a heat pump is any small-medium sized modular device that evaporates a refrigerant against a heat source (absorbing heat), then re-releases that heat elsewhere by compressing and re-condensing the refrigerant (releasing the heat). Strictly, therefore, all air conditions are heat pumps.

However, in this data-file, we are hoping to tabulate global heat pump sales by country, defining a heat pump as a system that is largely used to transfer heat into a space or a system, and competing with other forms of boilers and heating systems.

This exercise is relatively challenging, as some regions do not report heat pump sales at all, and others report heat pumps with different definitions. For example, Australia sold an enormous 1.4M heat pumps in 2023, including air conditioners; but of this total, only c160k were linked to hot water heating systems, and therefore we have estimated true heat pump sales somewhere closer to 300k.

Across the developed world, we think that heat pump sales reached 7M in 2023, or around 6 heat pumps sold per million inhabitants, then fell back to 6M heat pumps sold in 2024, with YoY declines in 7 out of the 14 countries/regions in our data-file (the US, Canada, Italy, Spain, Sweden, other Europe, and Japan). This is another data-point warranting caution over drawing S-curves in new energies.

Europe has some of the highest heat pump sales among regions in our database, with sales of around 10 units per year per thousand inhabitants in France, and 20-30 units per year per thousand inhabitants in Northern European countries such as Norway and Sweden.

The largest category is reversible air-air units (45%), reversible air-water (30%), while only c10% of the sales in Europe have been ground-source heat pumps, based on data from the European Heat Pump Association. Projections for European heat pumps are found in our European natural gas model.

Installed heat pump stock in Europe by category. Most common is air-air heat pumps, while ground-source is the smallest group.

US residential and commercial HVAC system deployments are available from AHRI. There was a surge across gas boilers, gas water heaters, air conditioners and heat pumps in 2021, linked to higher home construction. Heat pumps rose from 30% of cooling solutions to 40% from 2013 to 2023, and rose from 15% to 23% of heating solutions (ex electric heaters, where AHRI does not report data) (chart below).

US residential and commercial HVAC system sales from 2010 to 2023.

Heat pump sales are estimated in other regions based on public data sources. Heat pumps are clearly more efficient than combustion-based heating, as they can generally convert 1 kWh of electricity into 4 kWh-th of heat transfer. However, we think that high costs and challenging practicalities may still be a hurdle for heat pumps, and rather than following an S-curve, sales may, like EVs, follow a saturation curve.

Global CCS Projects Database

Over 400 CCS projects are tracked in our global CCS projects database. The average project is 2MTpa in size, with capex of $600/Tpa, underpinning over 400MTpa of risked global CCS by 2035, up 10x from 2019 levels. The largest CO2 sources are hubs, gas processing, blue hydrogen, gas power and coal power. The most active countries are the US, UK, Canada and Europe. Project-by-project details are in the database.

An amazing acceleration has taken place in the global CCS industry in the past half decade. In 2019, there were about 30 historical CCS projects in the world, with a combined capacity of 40MTpa. Today, there are well over 400 projects in various stages of planning and construction. This is verging on being too many to count. The CCS Institute does a fantastic job of following many of the projects. We are also trying to gather details on these projects and count up their capacity.

We have attempted not to over-count the CCS projects, however. About 200 of the projects are in an early stage of planning/development and therefore need to be risked. We are using an average risking factor of 30% in our models, based on mathematical rules and subjective assessments.

We have also attempted not to double-count them. About c100 of the projects are hubs, which gather someone else’s CO2. Clearly, if I capture 1MTpa from my auto-thermal hydrogen unit, feed it into your 1MTpa CO2 pipeline, and you pass it to a third party’s 1MTpa CO2 disposal facility, then the total quantum of CCS is 1MTpa and not 3MTpa.

Our risked forecasts point underpin 325MTpa of global CCS by 2030 and 415MTpa by 2035. This would be a dizzying increase from 40MTpa in 2019. But for perspective, our roadmap to net zero requires 7GTpa of CCS by 2050, and a straight-line journey from 2024 to 2050 would therefore require 3.5GTpa of CCS by 2037. So we would need about 10x more CCS projects to enter the pipeline. New projects are being scoped out over time, and will continue layering in on top of what we have quantified in this data-file.

CCS breakdown by region? 85% of risked CCS capacity in the data-file by 2035 is seen coming from the developed world, led by the US (40%), the UK (17%), Europe (16%), Canada (11%) and Australia (4%). The UK ambitions are perhaps boldest, rising from nil today to a risked potential of 65MTpa by 2035 (the official UK target is 20-30MTpa by 2030).

CCS breakdown by disposal method? A shift from CO2-EOR to geological storage is also seen in the database. Today, 80% of all CCS is associated with EOR activity, while by 2035, 80% is seen being for geological storage.

CCS breakdown by CO2 source? The biggest change seen by 2035 is the emerged of CCS hubs, which handle 40% of risked CCS by 2035. To the extent that we are including these hubs in our risked forecasts below, it indicates that the CO2 source has not yet entirely been locked down, but will be gathered from regional emitters.

The biggest clewar source of CO2 for CCS, in tonnage terms, is still for gas processing, by 2035 although its proportionate share declines from 55% today to just c15%. The second biggest clear souce is via the rise of blue hydrogen and blue ammonia projects, which are the source for 11% of risked CCS by 2035. Ethanol projects are most numerous, but also tend to be smaller at 0.2MTpa, and thus only underpin 4% of our risked total by 2035. Note that these are all pre-combustion or non-combustion sources of CO2 and bypass the potential risk of amine degradation and emissions.

Almost 20% of risked CCS is associated with power generation, in a split of gas (8%), coal (7%), biomass (2%) and waste (1%). For more details, see our overview of CCS energy penalties. For further analysis, this is the category where we are most interested to delve deeper, perhaps with a dedicated note looking at leading case studies and whether they are proceding on time and on budget.

The full database is available for download below, or for TSE full subscription clients, in case you want to interrogate the numbers, or look into the underlying project details and riskings that we have been able to tabulate and clean up.

US gas pipeline capex over time?

US pipeline capex spending from 1996 out to 2050. We expect spending to increase greatly, much of it from new CO2 pipelines.

US gas pipeline capex ran at $12bn pa in 2023, but likely needs to treble to reach net zero by 2050, mainly to support 1GTpa of CCS. Midstream capex for natural gas, CO2 transportation and hydrogen production are forecast out to 2050 in this data-file. Numbers can be stress-tested in the model.

The US operates the most extensive gas pipeline network in the world, moving 100bcfd of natural gas through 200,000 miles of transmission lines.

To build this network, the US has spent $14bn pa over the past decade, to construct a further 10,000 miles of transmission lines, which can carry 120bcfd, at an average capex cost of $3M/mile; while another c50% of the capex is spent maintaining the existing network.

Achieving net zero by 2050 would likely require total US gas pipeline capex to treble to almost $40bn per year, mainly as CCS volumes must ramp to 1GTpa, but also as gas displaces coal in the short-medium term and US hydrogen volumes almost double from 12MTpa to 21MTpa in our hydrogen outlook.

Our forecasts for new gas pipeline capex, CCS pipeline capex and hydrogen pipeline capex are calculated, in each case, by multiplying incremental volumes x new pipeline diameter-kilometers needed per unit of volume x capex cost per diameter-kilometer.

Capex costs of US gas pipelines are informed by a comprehensive database published by the EIA, which we scrubbed and cross-plotted, providing a good estimate for capex costs in $M per meter of diameter and per km of length (chart below).

Capex costs of pipeline expansions and newbuilds depending on their lengths in 2023.

The US already contains 50 CO2 pipelines with 5,000 miles of length, implying 100-miles per line. However, the main gas transmission network consists of 30 x large lines each running 2,000 – 15,000 miles. GTpa scale CCS in the US could continue leaning on smaller regional lines, but likely also requires an interstate network, raising the mean average CCS line length to 1,250 miles by 2050. Whether the US adopts CCS simply in regional hubs, or more extensively, is thus the largest determinant of total midstream capex requirements through 2050.

Estimates for the number and diameter of pipelines needed per bcfd or per MTpa – of natural gas, CO2 and hydrogen pipelines – are derived from the engineering equations in our US gas pipeline models.

All of the numbers can be stress-tested in the model. However, a helpful broader reference file is our roadmap model for US decarbonization. Our outlook for gas pipelines in the energy transition is also informed by recent research, summarized below.

Midstream gas: pipelines have pricing power ?!

Peaker plants: finding the balance?

Gas peaker plants: the economics?

Economic returns for a gas peaker plant over 30 years.

Gas peaker plants run at low utilizations of 2-20%, during times of peak demand in power grids. A typical peaker costing $950/kW and running at 10% utilization has a levelized cost of electricity around 20c/kWh, to generate a 10% IRR with 0.5 kg/kWh of CO2 intensity. This data-file shows the economic sensitivities to volatility and utilization.

The economics of gas peaker plants are all about volatility. Hourly power prices are lognormally distributed, which means their natural logarithms are normally distributed, per other commodity prices, and upside volatility is higher than downside volatilty (chart below).

The distribution of electricity prices is lognormal. This means it has a long higher price tail that peaker plants take advantage of.

Hence a grid with 10c/kWh mean average power prices can easily host a peaker that achieves 20c/kWh average power prices 10% of the time, even assuming non-perfect alignment between generation profiles and peak pricing. This can be flexed in the model, and is informed by actual data in ERCOT, CAISO, the UK, and Australia.

Another source of income for gas peaker plants is from capacity payments, which will usually make up 0-20% of total revenues. Grid balancing authorities are required by NERC and FERC to maintain healthy reserve margins that ensure they have adequate capacity to limit major outages to just once per decade.

While we have a separate model of combined-cycle gas turbine economics, capturing plants with >50% utilization, this data-file focuses in upon the economics of gas peaker plants, by modelling out the impacts of capacity payments and upside pricing volatility.

A fascinating observation is that each 1 c/kWh increase in power grid volatility increases peaker plant cash flows by $6/kW/year. Each 1pp reduction in utilization rate lowers cash flow by $5/kW/year. Numbers can be stress-tested in the data-file.

Cash flow for a gas peaker plant depending on power price volatility and plant utilization.

Other inputs in the model are informed by our data into gas turbine parameters, gas turbine capex costs, gas prices by region, CO2 prices and tax rates. However, we think the data-file is a neat way to stress-test the levelized costs of gas peaker plants, as they are impacted primarily by utilization and electricity price volatility.

Back up: does ramping renewables displace gas?

Comparison of the same Australian gas plants in May 2014 and May 2024. The increasing share of renewables reduces the utilization of baseload gas plants and turns them into peaker plants.

This 12-page note studies the output from 10 of the largest gas power plants in Australia, at 5-minute intervals, comparing 2024 versus 2014. Ramping renewables to c30% of Australia’s electricity mix has not only entrenched gas-fired back-up generation, but actually increased the need for peakers?

Mainspring Energy: linear generator breakthrough?

Linear generator technology can convert any gaseous fuel into electricity, with c45% electrical efficiency, and >80% efficiency in CHP mode. This data-file reviews Mainspring Energy’s patents. We conclude that the company has locked up the IP for piston-seal assemblies in a linear generator with air bearings, but longevity/maintenance could be a key challenge to explore.

EtaGen was founded in 2010 by three Stanford engineers, and rebranded as Mainspring Energy in 2020. Its headquarters are in Menlo Park, California; and the company has c400 employees, having closed a $290M Series E financing in 2022.

Mainspring is commercializing a linear generator, which is low-cost, reliable, flexible and can use any clean fuel (e.g., natural gas, biogas, hydrogen, ammonia), in sizes from 230kW to multiple-MW, >45% electrical efficiency and >80% total thermal efficiency in CHP mode.

In a linear generator, the compression of fuel and air causes a uniform and flameless combustion reaction to occur, releasing the energy from the fuel, but creating no NOx emissions. The energy from combustion pushes a piston through a cylinder (or in Mainspring’s case, two pistons, through two cylinders). Stator magnets in each piston move past coils in each cylinder, inducing a current. An air spring on the other side of the cylinder is thereby compressed, and re-expands to drive the piston back to its starting point.

Illustration of the working principles of a linear generator.

The main advantages are the simplicity, which could in principle translate into lower capex, compared to the blades and precision-engineered compression and turbine stages within a gas turbine.

Higher efficiency can also be unlocked by harnessing the expansion of combustion gases directly, rather than having to convert it into rotary motion, per the loss attributions for conventional thermal generation. On the other hand, maximum efficiency will always be lower for low-temperature combustion, due to the laws of thermodynamics.

From reviewing Mainspring’s patents, we think there are three main challenges for commercializing linear generators. The main challenge is linked to longevity and maintenance.

Mainspring’s patents focus upon piston-seal assemblies, and seem to have locked up the IP for its linear generator designs. This may also be relevant to other companies aiming to commercialize linear generators, such as Hyliion in the vehicle sector.

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 power: generation by facility over time?

Energy and AI: the power and the glory?

Electric vehicles: breaking the ICE?

Global biogas production by country?

Biogas production by country from 2000 to 2023. China has now become the worlds' largest producer of biogas, though it only covers 2% of their gas demand.

Global biogas production has risen at a 10-year CAGR of 3% to reach 4.3bcfed in 2023, equivalent to 1.1% of global gas consumption. Europe accounts for half of global biogas, helped by $4-40/mcfe subsidies. This data-file aggregates global biogas production by country, plus notes into feedstock sources, uses of biogas and biomethane.

Germany has historically been the largest producer in the world, with biogas output rising to 0.8bcfd by 2015, 10% of Germany’s total gas needs, then flat-lining on the phase-back of subsidies, such as 6-25 c/kWh feed-in tariffs for biogas->power.

40-45% of Germany’s biogas feedstock is from the anaerobic digestion of crop residues (70% corn silage), 40-45% is from animal waste (80% cattle), 6% is from wastewater. 85% is produced as biogas and 15% is upgraded to biomethane. 78% is used to produce electricity. Larger listed companies include EnviTec and Verbio.

China has now overtaken Germany to become the world’s largest biogas producer, reaching 0.9bcfed in 2023, although biogas has fallen from 4% of China’s total gas use in 2013 to 2% in 2023.

The US produced 0.6bcfd of biogas in 2023, or 1% of total gas consumption, with 2,400 production sites, of which 70-80% is captured from landfills. BP acquired the US’s largest RNG producer, Archaea Energy, for $4.2bn in 2022.

Brazil arguably has most growth potential, producing 0.1bcfed, across around 1,000 production sites, 65% from agricultural wastes, and c80% is used for electricity generation.

Denmark sources the highest share of its total gas needs from biogas of any country in our database by a wide margin, at c50%. 80% is upgraded and delivered into the gas grid, encouraged by a $6.2/mcfe subsidy program for raw biogas production, and $13/mcfe for upgraded biomethane, which supports the economics in our biogas costs models.

The data-file contains underlying data into global biogas production by country, in TJ terms, in TWH terms, and in bcf of gas equivalent terms (bcfed). Backup tabs contain workings and other input data. For further data, please see our broader biogas research and biofuels research,

US gas transmission: by company and by pipeline?

Gas volumes transported in US gas pipelines as a function of their length in miles. Longer pipelines also transfer significantly more gas.

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.

Greenhouse gas emissions of US gas pipelines in kilograms of CO2 equivalent per mcf transported as a function of their total network length.

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).

Implied utilization of gas pipelines in the US. Higher capacity gas pipelines are at 80-100% utilization while smaller pipelines have more spare capacity.

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 by CO2 intensity

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.

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