Energy Transition Supply-Demand Models

Global energy: supply-demand model?

This global energy supply-demand model combines our supply outlooks for coal, oil, gas, LNG, wind and solar, nuclear and hydro, into a build-up of useful global energy balances in 2023-30. We fear chronic under-supply if the world decarbonizes, rising to 5% shortages in 2030. Another scenario is that emerging world countries bridge the gap by ramping coal. Numbers can be stress-tested in the model.

Useful global energy demand grew at a CAGR of +2.5% per year since 1990, and +3.0% per year since 2000. Demand would ‘want’ to grow by +2% per year through 2030, due to rising populations and rising living standards (model here). We have pencilled in +1.75% pa growth to this model to be conservative.

Combustion energy is seen flat-lining in our net zero scenario. This includes global coal use peaking at 8.4GTpa in 2024 then gently easing to 2010 levels by 2030 (model here). It includes oil demand, rising to 102Mbpd in 2024 (data here), then plateauing (model here) as OPEC and US shale (model here) offset the decline rate impacts of conventional under-investment. It includes risked LNG supplies rising +70% from 400MTpa in 2022 to almost 700MTpa by 2030 (model here). While our roadmap to net zero would need to see global gas growing at +2.5% per year through 2050 (model here), this data-file has pencilled in flat production in 2022->30, as we think that latter scenario currently looks more likely to transpire.

Renewable energy is exploding. Our model of wind and solar capacity additions is linked here and discussed here. In our roadmap to net zero, solar more than doubles from c220GW of new adds in 2022 to 500GW by 2030, while wind rises from c100GW of new adds in 2022 to 150GW by 2030.

Other variables in the model include rising energy efficiency (note here), the need for a nuclear renaissance (note here) and other variables that can be flexed.

What is wrong with this balance is that it does not balance. The assumptions pencilled into the model see an under-supply of global energy of about 3% in 2025, rising to 5% in 2030. I.e., by 2030, the world will be “half a Europe” short of energy. The first law of thermodynamics dictates that energy demand cannot exceed supplies. So what would it take to restore the balance? Well, pick your poison…

(1) Slower demand growth could re-balance the model. Very high energy prices might mute demand growth to only +1.25% per year, although this would be the slowest pace of demand growth since the Great Depression, lower even than during the oil shocks (useful data here). Unfortunately, our view is that pricing people out of the global energy system in this way is in itself an ESG catastrophe.

(2) Ramping renewables faster could re-balance the model, although it would require an average of 1 TW pa of wind and solar capacity additions each year in 2024-30, and over 2 TW pa of wind and solar additions by 2030 itself, which is 3x higher than in our roadmap to net zero (discussion here). For perspective, this +2TWpa solution requires primary energy investment to quadruple from $1trn pa to at least $4trn pa, which all needs to be financed in a world of rising rates. It means that global wind and solar projects will consume over 200MTpa of steel, which is 2x total US steel production, and yet steel would not even qualify as a ‘top ten’ bottleneck, in our wind bill of materials or solar bill of materials. This scenario also requires a 3x faster expansion of power grids and power electronics than our base case estimates (see the links). Is any of this remotely possible?

(3) Continue ramping coal? The main source of global energy demand growth is the emerging world. The emerging world is more likely to favor cheap, dirty coal. Or worse, deforestation for firewood. Thus another way to ameliorate under-supply in our global energy supply-demand balance is if global coal continues growing, reaching a new peak of 9GTpa in 2030. Unfortunately, this scenario also sees global CO2 hitting a new peak of 54GTpa in 2030.

(4) Pragmatic gas? Another means of re-balancing the global energy system is if global gas production rises at 2.5% per year, which is the number required, and that is possible, on the TSE roadmap to net zero (model here). This scenario does see global CO2 falling by 2030. The main problem here is that pragmatic natural gas investment has become stranded in no man’s land, within a Manichean duality of fantasies and crises.

(5) Some combination? The world is complex. It is unlikely that a single lever will be pulled to resolve under-supply in our global energy supply-demand balance. In 2023, we think economic weakness will mask energy under-supply, mute energy prices, and lure many decision makers into looking at spot pricing and thinking “everything is fine”. Please download the model to stress-test the numbers, and different re-balancing solutions…

Global plastic demand: breakdown by product, region and use?

Global plastic is estimated at 470MTpa in 2022, rising to 1,000MTpa by 2050. This data-file is a breakdown of global plastic demand, by product, by region and by end use, with historical data back to 1990 and our forecasts out to 2050. Our top conclusions for plastic in the energy transition are summarized below.

Global plastic demand is estimated at 470MTpa in 2022. For perspective, the 100Mbpd global oil market equates to around 5bn tons per year of crude oil, showing that plastics comprise almost 10% of total global oil demand.

Our outlook in the energy transition sees increasing demand for polymers, most likely to 1,000MTpa by 2050. Many polymers are crucial inputs for new energies. Others are used for high-grade insulation, both thermal and electrical. Others for light-weight composites, which lower the energy consumption of transportation technologies.

Global plastic demand by region. The top billion people in the developed world comprise 12% of the world’s population, but 40% of the world’s plastic demand. We see developed world plastics demand running sideways through 2050, while emerging world demand doubles from 300MTpa to 700MTpa (charts below).

Global plastic demand CAGR? Our numbers are not aggressive and include a continued deceleration in the total global demand CAGR, from 7.5% pa growth in the twenty years ending in 1980, to 6% pa in the twenty years ended 2000, to 3.3% pa in the twenty years ended 2022 and around 2.5% pa in the period ending 2050.

Global plastic consumption per capita. Our numbers include an enormous policy push against waste in the developed world, where consumption today is around 170 kg of plastics per person per year. Conversely, plastic demand in the emerging world is 75% lower and averages 40 kg pp pa today, seen rising to 90 kg pp pa by 2050.

Upside to plastics demand? What worries us about these numbers is that they require historical trends to slow down. Historically, each $k pp pa of GDP is associated with 4kg pp pa of plastic demand. But our numbers assume slowing demand in the developed world and slowing demand in the emerging world (chart below).

Please download the model to stress-test your own variations. Underlying inputs are drawn from technical papers, OECD databases and Plastics Europe. The forecasts are our own.

Plastic demand by end use is broken down in the chart below. 35% of today’s plastics are used as packaging materials, 17% as construction materials and c10% for textiles.

The strongest growth outlook is in electrical products (currently 7-9%) and light-weighting transportation. There are few alternatives to plastics in these applications. Conversely, for packaging materials, we see more muted growth, and more substitution towards bioplastics and cellulose-based products from companies such as Stora Enso.

Upside for plastics in the energy transition is especially important, with plastics used in important components of the energy transition, from EVA encapsulants in solar panels, to the resins in wind turbine blades, to strong and light-weight components in more efficient vehicles, to polyurethane insulating materials surrounding substantively all electric components, batteries and vehicles. Of particular note are fluorinated polymers, where the C-F bond is highly inert, and helps resist degradation in electric vehicle batteries.

Plastic demand by material is broken down in the chart below. Today’s market is c20% polypropylene, c15% LDPE, and other large categories with >5% shares include HDPE, PVC, PET, Polyurethanes and Polystyrenes. We think the strongest growth will be in more recyclable plastics, materials linked to the energy transition, and next-gen materials that underpin new technologies such as additive manufacturing.

Feedstock deflation is likely to be a defining theme in the energy transition, as many polymers draw inputs from the catalytic reforming of naphtha. Today, 70% of BTX reformate is blended into gasoline, but we see this being displaced by the rise of electric vehicles, with particular upside for the polyurethane value chain.

Decarbonizing plastic production is also a topic in our research. As a starting point, our ethane cracker model is linked here, and our economic model for converting olefins into polymers is here. CO2 intensity of different plastics from different facilities is tabulated here.

Plastic recycling. We also see potential for plastic-recycling technologies to displace 8-15Mbpd of potential oil demand growth (i.e., naphtha, LPGs and ethane) by 2060, compared to a business-as-usual scenario of demand growth. All of our plastic recycling research is linked here. After a challenging pathway to de-risking this technology, we see front-runners emerging, such as Agilyx, Alterra and Plastic Energy.

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 coal production: supply outlook in energy transition?

Global coal production likely hit a new all-time peak of 8.7GTpa in 2023, of which 7.5GTpa is thermal coal and 1.2GTpa is metallurgical. The largest countries are China (4.4GTpa), India (1GTpa), other Asia (0.7GTpa), Europe (0.5GTpa) and the US (0.5GTpa). This model explores what is required to meet our energy transition aspirations.

Coal can be the cheapest thermal energy source on the planet. In normal times, coal costs $60/ton (coal mining model here) and contains 6,250 kWh/ton of thermal energy, implying a cost of 1c/kWh-th.

Coal-fired power can thus cost 2-4c/kWh (model here) and an existing coal plant is cheaper than other levelized costs of power.

Coal is the highest-carbon fossil fuel, with an average CO2 intensity of 0.37 kg/kWh-th (data here), which is 2x more than gas (note here).

The CO2 disparity is amplified further when considering coal’s Scope 1+2 emissions, as often coal mining leaks more methane than gas itself. And Rankine steam cycles fueled by coal have efficiency drawbacks (note here) and also relatively low flexibility (data here).

Hence our Roadmap to Net Zero would need to see coal consumption flat-lining from 2022, then declining at 8% pa in the 2030s and 17% pa in the 2040s, to well below 500MTpa (which in turn is abated by CCS or nature-based solutions).

This is sheer fantasy, unless wind, solar and natural gas ramp up enormously, especially in China, India and other parts of the Emerging World. Coal-to-gas switching economics are profiled here.

Some encouraging precedent come from the US, where coal production peaked at 1GTpa in the 2010s, before shale gas ramped to 80bcfd. Thus US coal declined to 500MTpa in 2021. Although questions about the continued phase-back of US coal are now being raised, due to pipeline bottlenecks from the Marcellus, and energy crisis in Europe, requiring a substitution of Russian energy supplies (oil, coal and gas).

There is always a danger of drawing lines on charts, which simply reflect aspirations, blindly projected out to 2050. The real world may not follow a straight line of pragmatic progress, but instead fluctuate between fantasy and crisis.

During times of energy crisis, such as 2022, international coal prices have spiked to $340/ton. Remarkably, this took thermal coal prices above metallurgical coal, and even above oil on a per-btu basis. Western coal producers are screened here.

Metallurgical coal may be particularly challenging to substitute. We have reviewed the costs of green steel here. We have seen some interesting but smaller-scale options in bio-coke. We have been less excited by hydrogen or syngas from gasification of coal.

Around 1GTpa of new coal projects are in planning or under construction, of which half are in China. Chinese coal production is something of a ‘wildcard’, explored in our short note here, and often defying expectations to the upside, despite rising renewables (chart below). Helping China to decarbonize might require 300bcfd of gas (roadmap here).

India’s coal use has also doubled since 2007, rising at 6% pa. It remains “the engine of global coal demand”, according to the IEA, rising +70MTpa, to 1.1GTpa in 2022, 1.3GTpa in 2023 and 1.4GTpa in 2026.

Please download the data-file to stress-test assumptions around coal mine additions, decline rates, phase-downs and coal-to-gas switching.

US shale: outlook and forecasts?

What outlook for US shale in the energy transition? This model sets out our US shale production forecasts by basin. It covers the Permian, Bakken and Eagle Ford, as a function of the rig count, drilling productivity, completion rates, well productivity and type curves. US shale likely adds +1Mbpd/year of production growth from 2023-2030, albeit flatlining in 2024, then re-accelerating on higher oil prices. Our shale outlook is also summarized below.

What outlook for shale in energy transition?

Shale is a technology paradigm where well productivity has risen by 3-7x over the past decade, through ever greater digitization. Shale economics are very strong, with 20% IRRs at $50/bbl oil on shale oil (model here) or at $2.8/mcf on shale gas (model here). We think 100bn bbls of recoverable shale resources remain in the US and ultimately, liquids production could be ramped up from 10Mbpd in 2023 to 15Mbpd by 2030 (note here).

However the US shale industry has shifted its focus towards capital discipline and ESG. US shale averages 10kg/boe on a Scope 1 upstream basis (data here), shale oil averages 25kg/boe on a full Scope 1&2 basis running up to the refinery gate (data here) and 55kg/boe on a refined basis running up to the point of combustion (data here). The spread is wide, after comparing and contrasting 425 companies here and here. The best decarbonization opportunities for shale are mitigating flaring and methane leaks followed by electrification. Ultimately, we think the best operators could reach CO2 neutrality.

The most important questions on shale are how the resource base and well productivity will trend. This has been the topic of our shale research, and our latest views are covered in our 2024 shale outlook. Historically, we have also undertaken large reviews of the pace of shale technology progress, based on technical papers (examples here and here). There are fifty variables to optimize. And we are most excited about big data techniques, fiber optics and shale-EOR.

Modelling US shale production by basin?

Our model for US shale production looks at each of the main basins, using a factor breakdown. Total production in month T1 = Total production in month T0 + new additions – base declines. To calculate new monthly additions, we multiply (a) number of rigs running (b) wells drilled per rig per month (c) wells completed per well drilled (d) initial production of newly completed wells (IP30). And to calculate the base declines, we fit a best-fit type curve onto the new additions from past months. This model has worked quite smoothly for 6-years now, including history going back to 2011 and forecasts going out through 2030.

The Permian basin is the largest US shale oil basin, with 8Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Permian basin has seen an average of 340 rigs running, drilling an average of 1.2 wells per rig per month, completing 1.06 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +850kbpd/year of new supply to global oil markets. We still see strong growth potential, and the Permian could reach 12Mbpd of total liquids production by 2030, amidst higher activity and oil prices. All of these variables can be stress-tested in the model.

The Bakken is the second largest US shale oil basin, with 1.3Mbpd of total liquids production in 2023. Over the past six years from 2017-2023, the Bakken has seen an average of 40 rigs running, drilling an average of 1.9 wells per rig per month, completing 1.15 wells for every well drilled (DUC drawdown) at an initial production rate of 780bpd (IP30 basis), adding +20kbpd/year of new supply to global oil markets. We see a plateau through 2030.

The Eagle Ford is the third largest US shale oil basin, with 1.1Mbpd of liquids production in 2023. Over the past six years from 2017-2023, the Eagle Ford has seen an average of 60 liquids-focused rigs running, drilling an average of 2.1 wells per rig per month, completing 1.22 wells for every well drilled (DUC drawdown) at an initial production rate of 680bpd (IP30 basis), but liquids production has actually declined, especially during the volatility of the COVID years. We see a plateau through 2030.

Challenges and controversies for US shale?

The main revisions to our shale production models have been because of lower activity, as capital discipline has entrenched through the shale industry. The chart below shows our forecasts for activity levels at different, prior publication dates of this model. We have compiled similar charts for all of the different variables and basins, in the ‘revisions’ tab, to show how our shale numbers have changed.

Our shale outlook for 2023-2030 sees the potential for +1Mbpd of annual production growth as the industry also generates $150-200bn per year of annual free cash flow. You can stress test input variables such as oil prices in the model.

We have also modeled the Marcellus and Haynesville shale gas plays, using the same framework, in further tabs of the data-file. Amazingly, there is potential to underpin a 100-200MTpa US LNG expansion here, with just 20-50 additional rigs. Although recently we wonder whether the US blue hydrogen boom will absorb more gas and outcompete LNG, especially as the US Gulf Coast becomes the most powerful clean industrial hub on the planet (note here).

International shale? We have found it harder to get excited about international shale, but there is strong potential in other large hydrocarbon basins, if European shale is ever considered to rescue Europe from persistent gas shortages, and less so in China.

Please download the data-file to stress-test our US shale production forecasts by basin.

Global electricity: by source, by use, by region?

Global electricity supply-demand is disaggregated in this data-file, by source, by use, by region, from 1990 to 2050, triangulating across all of our other models in the energy transition, and culminating in over 50 fascinating charts, which can be viewed in this data-file. Global electricity demand rises 2.5x by 2050 in our outlook.

Global electricity demand stood at 30,000 TWH pa in 2023, equivalent to 37.5% of global useful energy consumption. The breakdown is 40% industrial, 25% residential, 17.5% commercial, 6% agriculture, as disaggregated by region in the data-file.

Global electricity demand surpasses 70,000 TWH by 2050, in our outlook, which effectively means that 100% of all net growth in global useful energy consumption through 2050 is electricity demand growth.

Total electricity demand is seen growing at a 3.5% CAGR through 2050, of which the largest contributors are in new energies areas such as electric vehicles, CCS and within batteries. But the largest growth in absolute terms, at +10,000 TWH pa, is in producing metals and materials for the energy transition.

Global electricity demand by end use from 1990 to 2050

Rising living standards are the biggest driver of the growth. For example, residential electricity consumption is currently 2.4 MWH pp pa in the developed world, and just 0.7 MWH pp pa in the emerging world, which still only rises to 1.4 MWH pp pa by 2050 on our numbers, or around half the level in the developed world today.

Residential electricity use per capita by country from 1990 to 2050. We project energy use to go up.

Global electricity generation grows by 2.5x by 2050, including a 15x ramp for solar, 5x for wind, 3x for gas, 2.5x for nuclear and 1.7x for hydro, while coal-fired power falls by 60%. This outlook sees wind and solar ramping to 50% of all global electricity by 2050, which is near the economic limit. These data are all broken out by region on the Generation tab.

Global electricity supply by source from 1990 to 2050

Electricity generation from gas does need to rise, even with this large renewables build-out, in order to displace coal. Our numbers have gas consumption for power generation rising from 150bcfd in 2023 to 385bcfd by 2050, which also boosts demand for gas turbines. Fuel use for coal, gas and oil, by region, and over time, are broken out on the ShareOfCommodities Tab.

Global electricity generation from natural gas by country from 1990 to 2050

The CO2 intensity of global electricity generation falls from 0.54 kg/kWh today to 0.18 kg/kWh by 2050 on these numbers, ranging from <0.1 kg/kWh in the developed world to 0.2 kg/kWh in the emerging world, and 0.3 kg/kWh in India and Africa. These numbers are on a gross basis. Capturing and offsetting the CO2 would be necessary to reach Net Zero. These calculations are shown by region and by contributor on the CO2 tab.

Global gross grid CO2 intensity by country from 1990 to 2050

Global electricity-supply-demand is broken down by source, by use, by region and over time, across the entire data-file, which draws from all of our other energy transition research and models.

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.

Global uranium supply-demand?

Uranium yellow-cake (U3-8) supply by project type from 2010 to 2023 and forward estimates to 2050 based on current project and asset lifetimes.

Our global uranium supply-demand model sees the market 5% under-supplied through 2030, including 7% market deficits at peak in 2025, as demand ramps from 165M lbs pa to 230M lbs pa in 2030. This is even after generous risking and no room for disruptions. What implications for broader power markets, decarbonization ambitions, and uranium prices?

The world’s nuclear fleet generated 2,700 TWH of electricity in 2023, consuming 165 M lbs of mined uranium (on a U3O8 yellow-cake basis). We see these numbers rising to 3,800 TWH pa of electricity and 230 M lbs pa of uranium by 2030, then to 7,000 TWH pa and 420 M lbs by 2050 as part of our Roadmap to Net Zero.

But can uranium production keep up? Global uranium production was only 150 M lbs in 2023, as nuclear utilities were over-contracted in 2012-2017, and have been drawing down inventories for the past five years. Of course, inventory draws cannot continue forever.

This uranium supply-demand model sees the market 5% under-supplied in aggregate through 2030, with the under-supply peaking at 7% of the market in 2025.

This is concerning because as things stand there will not be enough uranium mined and upgraded to ramp nuclear generation. In the short-term, this could raise power prices and demand could surprise to the upside for other round-the-clock generation sources, such as natural gas.

Uranium prices must sustainedly rise above the incentive price for developing more uranium mines. And perhaps they may sustain far above this incentive price, amidst persistent market shortages, as regional reserve margins require for nuclear plants to run, and each $10/lb on the uranium price only adds 0.05 c/kWh to the marginal cost at a nuclear power plant.

These uranium supply forecasts are based on evaluating around 100 production assets and developments, generating an outlook for each one.

Assumptions include a typical decline rate of 3% pa, 80% risking on new assets re-opening and developments that are underway, 50% risking on FEED-stage projects and 30% risking on planning-stage projects, on average throughout the model.

Uranium production by country is also disaggregated in the data-file. 40% of global output is from Kazakhstan today. Canada, which is 20% of today’s supply, doubles its output in the next decade. Growth is also seen in Namibia and Australia, which are about 10% of today’s output. The US grows most in percentage terms, rising from almost nil to almost 10 M lbs pa in the next decade.

Uranium yellow-cake (U3-8) supply by country from 2010 to 2023 and forward estimates to 2050 based on current project and asset lifetimes.

Uranium production by company is available in our screen of uranium producers, which also has more commentary on the underlying companies developing various projects.

Notes on each project in our global uranium supply-demand model can be viewed in the notes tab, and risking factors can be varied in the assets tab of the data-file.

Lithium ion battery volumes by chemistry and use?

Global lithium ion battery demand broken down by demand category and battery technology. Data from 2011 to 2023 and projected to 2030

The lithium ion battery market reached 900GWH in 2023, representing 7x growth in lithium ion battery volumes in the past half-decade since 2018, and 20x growth in the past decade since 2013. Volumes treble again by 2030. This data-file breaks down global lithium ion battery volumes by chemistry and by end use. A remarkable shift to LFP is underway, and NMC sales may even have peaked.

The lithium ion battery market reached 900GWH in 2023, representing 7x growth in the past half-decade since 2018, and 20x growth in the past decade since 2013. This data-file breaks down global lithium ion battery volumes by chemistry and by end use, by aggregating past estimates from technical papers and forecasting agencies.

Over 70% of the lithium ion battery market is for electric vehicles, followed by grid-scale energy storage, and incorporation into electronic devices.

Our forecasts for lithium ion battery sales through 2030 hinge on our outlook for electric vehicles as reflected in our global vehicle sales database, and our outlook for co-deployment of batteries with renewables, as reflected in our global power grid capex model. In turn, these forecasts impact the demand for battery materials such as lithium, graphite, nickel, cobalt and fluorinated polymers.

Cathode chemistry has shifted markedly over time, which is reflected in the data-file. Prior to 2013, the lithium ion battery market was dominated by LMO/LCO. At peak in 2019, NMC batteries had over 60% market share, and NMC incumbents were declaring victory over LFP cells, whose share, in turn, was projected to fall to zero throughout the 2020s.

Lithium ion battery costs: materials and manufacturing?

Reality has turned out quite different, due to amazing deflation in LFP batteries (see above), especially from Chinese suppliers such as CATL and BYD. China’s electric vehicles could comprise two-thirds of all global EV sales in 2024 and LFP dominates in China. If LFP continues gaining share to around 75% of lithium ion batteries by 2030, or higher, then demand for NMC cells may have peaked in 2023.

Innovator’s dilemma? It is truly remarkable to look back at technical papers published by LG Energy Solutions (larger NMC battery producer in the world) and similarly from McKinsey, back in 2019, arguing that NMC would dominate the industry in the future, and that LFP’s market share would gradually fall to zero (!), due to its inferior ionic mobility, hygroscopicity, charge-monitoring, voltage, density and [sic] longevity. These studies did not, however, clock LFPs’ lower costs.

Maybe there is a lesson here about the importance of unbiased first-principles analysis, supported by economic models, when assessing energy transition technologies. There is a danger of confirmation bias, within an ocean of possible data-points that may support pre-existing positions. But costs often turn out to be the single most important variable.

Our own first-principles analysis into the rise of LFP is re-capped below. The data-file tracks how NMC leaders from 2019m such as LGES and SK On have shifted their perspective, based on technical papers, news stories and the number of patent filings. In 2019, LG literally wrote that “NMC is the right choice… LFP should not be preferred” yet by 2024 it signed a contract to supply LFP cells to Renault’s Ampere EVs from a facility in Poland. It may take 3-5 years for LGES and SK On to catch up with CATL and BYD in LFP.

LFP batteries: cathode glow?

Lithium ion battery volumes in GWH per year, are broken down by end use, and by cathode chemistry, in this data-file, triangulating between technical papers, going back to 2011, and forecast out through 2030.

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.

What outlook for shale in energy transition?

Modelling US shale production by basin?

Challenges and controversies for US shale?

Cookies?