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.

Gas turbines: what outlook in energy transition?

Gas turbines should be considered a key workhorse for a cleaner and more efficient global energy system. Installations will double to 100GW pa in 2024-30, and reach 140GW in 2030, surpassing their prior peak from 2003. This 16-page report outlines four key drivers in our outlook for gas turbines, and their implications.

Global gas turbines by region and over time?

Gas turbine capacity added globally from 1985 to present, and projected to 2030

Global gas turbine additions averaged 50 GW pa over the decade from 2015-2024, of which the US was 20%, Europe was 10%, Asia was 50%, LatAm was 10% and Africa was 10%. Yet global gas turbine additions could double to 100 GW pa in 2025-30. This data-file estimates global gas turbine capacity by region and over time.

25% of global electricity came from burning 150bcfd of natural gas in 2023. A typical simple-cycle gas turbine is sized at 200MW, and achieves 35-45% efficiency, as incoming air is compressed over 20 stages to 20 bar of pressure, super-heated to 1,250ºC and 100 bar of pressure, then these super-hot, super-pressurized gases expand across 4-5 stages of turbine blades, turning at 3,000 – 6,000 revolutions per minute.

This data-file estimates global gas turbine capacity by region and over time. Specifically, we have started with open source databases of all of the world’s power plants, as published by WRI and GEM. But unfortunately these databases are incomplete.

Hence, we have adjusted some of the historical data using mathematical methods, so that the bridge of capacity additions and retirements matches up with the current fleet of operating gas turbines in each region. The adjustments and workings are shown in the data-file.

Hence as of 2024, the world has 2 TW of operating as turbines, of which 30% is in the US, 15% is in Europe, 40% is in other Asia, and around 5% is in both Africa and LatAm. Numbers are available in the data-file.

Utilization rates of the world’s gas turbines provide another way to sense-check the historical data, peaking at 50% in 1999 on a global basis, then declining to 40% in 2023, due to the ramp-up of intermittent renewables, which lowers utilization rates of other power infrastructure, and causes baseload gas to run more like peakers.

Some of the most price-sensitive regions such as India and China also sharply curtailed gas plant utilization, after LNG prices spiked in the aftermath of the Fukushima nuclear disaster. Though both regions are seen re-accelerating gas utilization by 2030, to meet air quality targets, and as Qatar adds 8 x 8MTpa mega-trains to the global LNG market.

Other regions such as the US have seen utilization rates of gas turbines rise, due to improving economics of gas, linked to the rise of US shale gas, as a low cost source of baseload power, thus displacing coal, which continues in our US natural gas outlook.

Forecasts through 2030 are also given in the data-file, estimating how global gas turbines by region will evolve as part of the energy transition.

US natural gas: the stuff of dreams?

Modeling US gas supply and demand can be nightmarishly complex. Yet we have evaluated both, through 2035. This 13-page report outlines the largest drivers of demand, requires a +3% pa CAGR from the key US shale gas basins, and argues the balance of probabilities lies to the upside.

Seeing sense: digitize the downstream gas network?

Pipeline sensing to detect flows and leaks

Greater digitization of gas networks looks increasingly important, as gas, biogas, hydrogen and CCS all aim to shore up their futures. This 15-page note started as a deep-dive into the true leakage rates in downstream gas; and ended up finding opportunities in sensors and pipeline monitoring.

Gas distribution: loss rates, leakage, unaccounted gas?

What are the loss rates in gas distribution? 1-4% of all the gas that flows into downstream gas distribution networks may fail to be metered and monetized. Stated leakage rates are usually around 0.5%, but could be higher. This data-file aggregates data from Eurostat and the UK’s Joint Office of Gas Transporters.

1-4% of all of the natural gas that flows into downstream gas distribution networks may fail to be metered and monetized. This matters not just for avoiding methane leaks, but also should ideally be improved before integrating biogas or blending hydrogen, or for ensuring that similar issues do not lessen trust in CCS value chains.

In the US, the variation between gas inputs to the gas distribution network and gas that is ultimately metered by customers is designated as Lost or Unaccounted For (LAUF). LAUF gas is generally estimated at 1-4%, and one study quotes an average rate of about 2% across the nation. In the past, the American Gas Association has somewhat questionably stated LAUF is mainly a metering and accounting adjustment and [sic] “there is no correlation between LAUF and emissions”.

In the UK, the variation between gas inputs to the gas distribution network and gas that is ultimately metered by customers is split between Shrinkage (losses, mostly leaks) and other Unidentified Gas (UIG, e.g., due to theft, or pressure-temperature differences at metering sites). In gas year 2023/24, 0.6% of the gas flowed into the downstream distribution network was lost as shrinkage and 3.5% as Unidentified Gas, based on data from the UK’s Joint Office of Gas Transporters (see below).

Build-up of Unaccounted Gas in the UK. Most of it is allegedly due to theft, not leakage.

Stated loss rates in developed world distribution networks are usually around 0.5%, based on data from Eurostat, but higher LAUF/UIG rates have opened the door to gas skeptics alleging higher leakage.

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

Global CCS in the pipeline by source, up to 2035.

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.

Global CCS in the pipeline by risking factor, up to 2035.

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 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).

Global CCS in the pipeline by geography, up to 2035.

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.

Global CCS in the pipeline by category, up to 2035.

CCS breakdown by CO2 source? The biggest change seen by 2035 is the emergence 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 clear source of CO2 for CCS, in tonnage terms, is still for gas processing, although its proportionate share declines from 55% today to just c15% by 2035. The second biggest clear source 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 proceeding 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.

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