LNG: top conclusions in the energy transition?

LNG in the energy transition

Thunder Said Energy is a research firm focused on economic opportunities that drive the energy transition. Our top ten conclusions into LNG are summarized below, looking across all of our research.



(1) LNG markets treble in our energy transition roadmap, rising from 400MTpa today to 1,100MTpa by 2050, for a c4% CAGR. The main reason is to displace coal, which is 2x more CO2 intensive. This LNG growth rate is 1.5x faster than total global natural gas supply growth, which “merely doubles” from 400bcfd to 800bcfd, for a 2.5% CAGR. The world needs $20bn of new liquefaction capex per year. Our LNG outlook through 2050 is modeled here.

(2) Marginal cost is $10/mcf as a rule-of-thumb for the 2020s. This is summing up the economics across the entire value chain for gas production, gas processing, pipeline transportation, LNG liquefaction, LNG shipping and LNG regasification. The best projects work at $7/mcf. But prices will run well above marginal cost amidst under-supply.

(3) Under-supply in 2023-28 in our supply model augurs for $15-40/mcf spot global LNG prices. After adding +20MTpa of new LNG supplies each year from 2015 to 2022, we think the world will be lucky to add +10MTpa in 2023 and 2024. There is always a further risk of supply disruptions. Meanwhile, Europe’s 15bcfd of Russian gas imports, volumetrically equivalent to 110MTpa of LNG, are shifting. The best note covering our gas outlook is linked here and our European gas models are linked here.

(4) The key challenge is CO2. Liquefying natural gas at -160C requires 300-400kWh/ton of energy, depending on the LNG plant design. This results in 3-4 kg/mcf of Scope 1+2 CO2. Across the value chain, LNG will have 7-10kg/mcf of Scope 1+2 CO2. Adding the Scope 3 from combustion, we reach total CO2 intensity of 60-65kg/mcf. Coal is 130kg/mcfe. Yet it feels like we could die of energy shortages before gas critics listen to “relative CO2” reasoning and countenance long-term LNG contracts.

(5) Rising to the challenge. The LNG industry can satisfy its skeptics. This is earnestly happening. It includes measuring CO2 in LNG supply chains. Then offsetting it via nature-based CO2 removals. Or capturing CO2 from combustion, then sharing regas terminal infrastructure to liquefy it, and ship it away for disposal. We have written a full note on back-carrying CO2 here. CO2 abatement costs range from $50-125/ton, or $3.0-7.5/mcfe. This scores well on our cost curves.

(6) 2020s supply growth will be dominated by the US, which is particularly well placed to assuage gas shortages in Europe. US LNG can treble from 70MTpa in 2021 to 200MTpa by 2030. It requires an extra 17bcfd of gas (c18% total US gas supply growth), which in turn pulls on E&P activity in the Haynesville, Permian and Marcellus.

(7) Longer term supply growth will be dominated by the Middle East, which is particularly well placed to phase out China’s coal. These numbers are mind-blowing. As an idea, if China directly substituted all 4GTpa of its coal (10GTpa of CO2 emissions!), this would require 1,600 MTpa of LNG, i.e., 4x more than today’s entire global LNG market. If you read one note, to understand this topic, we would recommend this one.

(8) Smaller-scale LNG and transport upside? We have reviewed opportunities in LNG in transport, smaller-scale LNG, LNG-fueled trucks, LNG-fueled ships, eliminating methane slip, LNG fuelling stations, small fixed LNG plants, floating LNG plants. There are some interesting concepts, especially for specific applications. But we have not materially de-risked smaller-scale LNG upside in our numbers yet.

(9) Cyclical industries reward counter-cyclical behaviours, and LNG is deeply cyclical. The title chart above shows this nicely, with spurts of growth, punctuated by plateaus, once per decade. It always feels uncomfortable to sanction projects when others are not. But our view is that bravery gets rewarded. “If you build it, the demand will come”.

(10) Companies. Incumbents benefit most from under-supply in the 2020s. Upcoming projects and their sponsors are summarized in our LNG supply model. We have also screened LNG shipping companies. But the question that fascinates us most is whether upcoming project sponsors can avoid the cost inflation that marred the past cycle, with some interesting evidence from patents in our note here.




Around 45 reports and data-files into LNG have led us to these conclusions above; listed in chronological order on our LNG category page. The best way to access our PDF reports and data-files is through a subscription to TSE 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 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).

Another fascinating feature of gas markets is their flexibility, which is shown by plotting monthly gas production by country and over time (chart below). Across 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.

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.

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. 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.

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 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.

Liquefied CO2 carriers: CO2 shipping costs?

costs of liquefied CO2 carriers

This model captures the costs of liquefied CO2 carriers, i.e., a large-scale marine vessel, carrying CO2 at -50ºC temperature and 6-10 bar of pressure, as part of a CCS value chain. A good rule of thumb is seaborne CO2 shipping costs are $8/ton/1,000-miles, as a total shipping rate of $100k/day must cover the capex of a c$150M newbuild tanker.


Could the LNG industry decarbonize by shipping LNG to gas consumers, then shipping the resultant CO2 away? We recently explored this concept in a detailed research note.

This work envisaged using the same vessel to transport LNG in and CO2 away. It required building new, dedicated, dual-purpose vessels, with ‘Type C’ containment (i.e., they would need to be capable of withstanding 8-10 bar pressures of liquefied CO2, whereas by contrast, today’s fleet of LNG vessels are ‘Type B’, and are not designed to hold pressurized gases).

Using the same vessel? The great advantage is that an LNG tanker is already making a deadhead journey back to the liquefaction facility, thus incremental transportation costs may be as little as $1.3/mcfe and total CO2 abatement costs as little as $100/ton. The great disadvantage is logistical risk and inflexibility. Swapping CO2 and LNG cargoes is do-able but annoying. It also limits the vessel to operating in ‘shuttle mode’ (i.e., no real flexibility to divert cargoes). And dual-purpose ships can end up as jack of both trades, master of neither.

Liquefied CO2 carriers could harness many of the same benefits, decarbonizing LNG in geographies with no nearby CO2 disposal reservoirs; while sharing marine infrastructure with an LNG regas facility; and using the cold stream from re-gassing LNG (at -160C) to chill and liquefy CO2 (-50C). But dedicated CO2 carriers could also be optimized for CO2. And this configuration also imparts more flexibility to the LNG carriers and CO2 carriers.

This data-file captures the costs of liquefied CO2 carriers. A $100k/day total shipping cost is required to recoup the capex on a $150M CO2 carrier vessel, and generate a 10% IRR. Costs are broken down in the file, including 20 different capex estimates for large, liquefied CO2 carriers (in $M, m3 and ktons).

In our base case, the total abatement costs likely end up c$25/ton higher using dedicated CO2 carriers versus back-carrying liquefied CO2 in an LNG carrier (at an apples-to-apples transportation distance around 5,000 miles). However, the higher base case costs may be diluted by lower risk, higher flexibility, and the ability to find CO2 disposal closer-by.

Costs are most sensitive to shipping distances. Shipping liquefied CO2 might cost $8/ton within 1,000-miles (i.e., intra basin), rising to c$50/ton at 6,000 miles (trans-Atlantic). Overall, we think liquefied CO2 carriers can be part of decarbonized value chains with total CO2 abatement costs around $100-125/ton, using bridges from our broader CCS research.

A challenge remains in regulation. Carbon markets or CO2 disposal incentives in developed world countries do not currently allow for cross-border transport of CO2. And it will be important to ensure that each ton of CO2 loaded onto a liquefied CO2 carrier is properly sequestered in a well-run CO2 disposal facility.

Another debate is over the size of the CO2 carriers. Today’s CO2 carriers are mostly around 10,000m3 (11kT of CO2e), and within a range of 5,000-30,000 m3. Larger vessels will be more economical. Ideally over 50,000m3. You can stress-test vessel size in the model.

Overall, we do think there is a growing opportunity for the LNG industry to develop decarbonized value chains, using CCS and nature-based solutions. Best placed to capture the opportunity are companies with existing experience in LNG, and LNG shipping. Economics of CO2 shipping in this data-file can also be compared with LNG shipping.

Decarbonized gas: ship LNG out, take CO2 back?

Transport CO2 in LNG carriers

This note explores an option to decarbonize global LNG: (i) capture the CO2 from combusting natural gas (ii) liquefy it, including heat exchange with the LNG regas stream, then (iii) send the liquid CO2 back for disposal in the return journey of the LNG tanker. There are some logistical headaches, but no technical show-stoppers. Abatement cost is c$100/ton.

LNG shipping: company screen?

LNG shipping companies

This data-file is a screen of LNG shipping companies, quantifying who has the largest fleet of LNG carriers and the cleanest fleet of LNG carriers (i.e., low CO2 intensity). Many private companies are increasingly backed by private equity. Many public companies have dividend yields of 4-9%.


In total, there are 650 LNG carriers in operation in 2023. A dozen companies control half of the fleet and are captured in this data-file. They have an ‘average’ fleet size of 13 vessels (ranging from 6 to 70 vessels).

The CO2 intensity of the LNG carrier fleet is measured on an AER basis, at 9 grams of CO2 per deadweight ton mile travelled, which equates to 18 grams of CO2 per effective ton mile travelled (factoring in the return journey).

The lowest carbon and most efficient vessels currently being delivered are large (174,000m3+) and have two-stroke, low-speed propulsion such as MEGI (Man) and X-DF (WinGD), yielding AER CO2 intensities below 5 grams of CO2 per dwt-mile. Conversely, older vessels and steam vessels can have AER CO2 intensities above 12 grams per dwt-mile.

Another theme that stands out from the screen is the high 4-9% dividend yields of leading public LNG shipping specialists, with high-quality fleets and vessels locked-in on long-term contracts, with high-quality charterers.

A final theme that stands out is the growing involvement of private equity firms, including taking public LNG carrier companies private and investing to expand and modernize future fleets.

Please download the data-file for an overview of the LNG shipping companies and the fleets of gas carriers. Further details can be found in our broader LNG research, including the economics of LNG shipping.

Energy transition: top commodities?

Commodities needed for energy transition

This data-file summarizes our latest thesis on the top thirty commodities needed for the energy transition. We estimate that the average commodity will see demand rise by 3x and price/cost appreciate or re-inflate by 60%. The scatter is broad. Upside ranges from 2x to 30x for different metals, materials, plastics and capital goods markets.


The data-file contains a 6-20 line summaries of our view on each commodity, and ballparks numbers on the market size, future marginal cost, CO2 intensity and pricing.

As a useful summary, summarizing all of our research into energy technologies and energy transition to-date, we have also ‘ranked’ these 30 top materials and commodities, according to our long-run outlook in this data-file in the ‘Materials’ tab of the data-file.

The median average commodity sees its demand treble in the energy transition. The mean average commodity sees its demand rise 1.5x. Top quartile commodities see growth of 5-30x, although this is most often because they are smaller markets to begin with.

Although many commodities require sharp growth curves, if the world is going to reach net zero by 2050, this is not unprecedented. Some of the largest commodities are plotted below, from 1950-2050, with a weighted average growth CAGR of 2.5% per annum.

Long Run Structural Growth of Commodities Needed in Energy Transition

An apparent paradox in our energy transition roadmap, however, is that after rising at a 2.5% CAGR for the past 70-years, our aggregate models require the total tonnage off these commodities, as consumed by human civilization to move sideways from here. The main reason is phasing out higher carbon coal. This is only really realistic amidst a vast step up in solar, wind, power grids and natural gas as alternatives.

Commodities needed for energy transition
Total Tonnage of Commodities Needed in Energy Transition

Commodities needed for the energy transition and covered in this data-file include Aluminium, Ammonia, Carbon Fiber, Coal, Cobalt, Copper, Ethylene Vinyl Acetate, Fluorinated Polymers, Fluorspar, Glass Fiber, Graphite, Hydrogen, Indium, Lithium, LNG, Mass Timber, Methanol, NdFeB Rare Earths, Nickel, Oil, Polyurethanes, PV Silicon, Silicon Carbide, Silver, STATCOMs, Steel, Sulphuric Acid, Tin, Uranium, Vanadium.

Further details on each commodity can be found by browsing our supply-demand models.

Another observation is that many of the commodities that excite us most, are strictly, becoming less commoditized, as we increasingly see evidence that the ramp-up of new energies – solar, wind, lithium ion batteries, electric vehicles – calls for advanced materials that confer higher performance and longevity. This is our new age of materials thesis. Leading examples are tabulated in the data-file.

Beware volatility! Soft bottlenecks can be defined as markets that will be tightened by the desire to accelerate the energy transition ever faster. Thus their prices and margins will generally rise. Supply will be available, prices will simply have to rise. Hard bottlenecks, however, may not be surmountable at any price, and we especially think this is the case for power grids. But inverse bottlenecks are most frightening. These materials are needed for the ascent of energy transition technologies, but whose demand and pricing unexpectedly collapse, because for a few months-years, these commodities are in a position of relative over-supply, due to another material being the hard bottleneck. For example, in a research report published in January-2023, we wrote “We are wondering whether PV silicon could see this kind of pricing action in 2023, as it said that China’s fabs will ramp from 300 GW at YE22 to 540 GW at YE23, while global gas shortages are going to disrupt production of silver and FPs“. In our view, timing volatile commodity bottlenecks is one way that active managers can add value as the energy transition impacts practically every supply chain on the planet.

We will continue adding to this data-file over time, as part of our ongoing energy transition research. Please contact us any time if you are a TSE client, and you think there is a particular commodity we should be adding while tracking commodities needed for the energy transition.

Global gas: five predictions through 2030?

European gas outlook

Modelling Europe’s gas balances currently feels like grasping at straws. Yet this 10-page note makes five predictions through 2030. We have revised our views on how fast new energies ramp, which gas gets displaced first, which energy sources are no longer ‘in the firing line’, and gas pricing.

Gas diffusion: how will record prices resolve?

Displacing industrial gas demand in Europe

Dispersion in global gas prices has hit new highs in 2022. Hence this 17-page note evaluates two possible solutions. Building more LNG plants achieves 15-20% IRRs. But shuttering some of Europe’s gas-consuming industry then re-locating it in gas-rich countries can achieve 20-40% IRRs, lower net CO2 and lower risk? Both solutions should step up. What implications?

North Field: sharing the weight of the world?

North Field energy production

The North Field is now the most important conventional energy asset on the planet. It produces 4% of world energy, 20% of global LNG and aims to ramp another 50MTpa of low-carbon LNG by 2028. But what if Qatar’s exceptional reliability gets disrupted by unforeseen conflict with Iran? Without wishing to catastrophize, this 18-page note explores important tail-risks for near-term energy balances and long-term energy transition.

Copyright: Thunder Said Energy, 2019-2024.