Cryogenic air separation is used to produce 400MTpa of oxygen, plus pure nitrogen and argon; for steel, metals, ammonia, wind-solar inputs, semi-conductors, blue hydrogen and Allam cycle oxy-combustion. Hence this 16-page report is an overview of industrial gases. How does air separation work? What costs, energy use and CO2 intensity? Who benefits amidst the energy transition?
As compressed gases expand, they will tend to cool down, via the Joule Thomson effect. We think it is helpful for energy decision-makers to understand this theme, as it underpins fridges, air conditioners, heat pumps, LNG and industrial gases.
Industrial gases comprise a market worth c$100bn per year, including 400MTpa of oxygen. And a surprisingly large number of metals, materials and decarbonization technologies use industrial gases. For example, blue hydrogen ATRs and Allam Cycle oxy-combustion are both oxygen-fired. An overview of industrial gas demand is given on pages 2-3, and demand from new energy transition technologies is reviewed on page 4.
The thermodynamic minimum energy demand to separate oxygen from air is 51 kWh/ton. But how realistic is it that real-world processes will ever reach this theoretical level? Our answer is on page 5.
Real world cryogenic processes achieve cryogenic air separation via the Reverse Brayton Cycle. We explain how this thermodynamic cycle works on page 6, and quantify real-world energy costs (in kWh/ton) from first principles on page 7.
Air Separation Unit (ASU) designs are reviewed on pages 8-9, including the key components of real-world plants, and what determines their capex (in $/Tpa).
Costs of industrial gases are discussed on pages 10-11, including our best estimates of base case IRRs (%), costs of different gases (in $/ton) and the cost drivers. Raising energy is often possible, but not always economical. And can ASUs ‘demand shift‘, backstopping renewable heavy grids like batteries, by scaling up and down to smooth out an increasingly volatile power grid?
What implications for blue hydrogen, green hydrogen, Allam Cycle oxy-combustion, direct air capture energy economics? Some important conclusions are noted on page 12.
Leading companies in industrial gases are discussed on pages 13-14. Our company screen is linked here. We wonder whether reliability, scale and quality lead to sustainably higher margins?
Power grid circuit kilometers need to rise 3-5x in the energy transition. This trend directly tightens global aluminium markets by over c20%, and global copper markets by c15%. Slow recent progress may lead to bottlenecks, then a boom? This 12-page note quantifies rising power grid metals demand, demand for circuit kilometers, and who benefits?
Power grids have recently used 5-6MTpa of aluminium (8% of demand) and 3MTpa of copper (10%), as global electricity demand has risen by +630 TWH pa globally over the past 20-years. The purpose of this report is to estimate future power grid metals demand.
How much growth for power grids? To derive our estimates, we have quantified (and multiplied) future electricity demand in TWH (page 2), power grid circuit kilometers per TWH of electricity (page 3) and tons of metals use per circuit kilometer (page 4).
Trends in the energy transition increase power grid aluminium and copper demand even further. Including utilization factors in the transmission network halving due to volatility of wind and solar (page 5), rising remoteness (page 6) and more metals-intensive electricity use, especially for electric vehiclechargers (page 7).
There is upside for metals in energy transition power grids, but we think that the growth in power cable demand is more likely to stoke aluminium than copper. Leading global copper producers and leading global aluminium producers are discussed on pages 8 and 9.
Circuit kilometers needed for power grids in the energy transition are estimated by region on page 10, and the underlying data-set is here. While demand for power grid metals rises by 15-20%, demand for power cables rises 4x. Leading cable producers are also discussed on page 10.
Will power grids present a bottleneck for the rise of wind and solar? We review some evidence on page 11, and discuss implications for rising returns at listed transmission and distribution utilities on page 12.
Electric currents create magnetic fields. Moving magnets induce electric currents. These principles underpin 95% of global electricity. Plus 50% of wind turbines and over 90% of electric vehicles use permanent magnets with Rare Earth metals. This 15-page overview of magnets covers key concepts and controversies for the energy transition.
What is a magnet? There are 650-page textbooks seeking to answer this question. Our goal in this research note is to distil all of the key concepts for magnets in the energy transition, into just 15 highly concise pages, and starting from first principles.
A magnet is a source of potential energy with potential to exert forces on moving charges. We explain the key formulae for magnetic forces on pages 2-3, covering magnetic fields (m3), magnetic flux (Webers) and magnetic flux density (Teslas).
Magnets are the basis for all electric motors and over 95% of today’s global electricity generation, via moving magnets in rotors and magnetic induction in stator arrays. Even basic units of energy, electricity and thermodynamics tie to magnetic units (pages 4-6).
Magnetic properties that matter most for practical applications are remanent magnetic flux density (Teslas), coercivity (kA/m) and maximum energy product (J/m3, or Mega-Gauss Oersteds (MGOe)). We explain these variables, and why they matter on page 7.
Electromagnets are widely used in stationary power generation and large motors, using soft metals with low coercivity and low remanent flux densities. We cover the key materials, advantages and disadvantages on page 8.
Permanent magnets using different Rare Earth materials are compared and contrasted. Their properties hinge on quantum physics. Which sounds Academic. But it is important to understand why NdFeB will be hard to displace. And we promise that pages 9-10 are surprisingly readable, despite venturing into the murky quantum realm.
Global electricity will surpass 30,000 TWH for the first time in 2023, and the CAGR for global electricity demand steps up from 2% pa to 4% pa in the energy transition. Substantively all electricity in the world is produced by magnets, and the remainder is produced by semi-conductors. Implications for magnets, and vice versa, are discussed on page 11.
Wind power uses a balance of electromagnets in doubly fed induction generators and increasingly, permanent magnets. Our key conclusions on the relative merits are on page 12.
Electric vehicle sales need to ramp up by another 20x in our roadmap to net zero. A key debate, pace Tesla, is whether efficient and long-range electric vehicles will need to continue using Rare Earth magnets containing neodymium, dysprosium, terbium, praseodymium (page 13).
Leading companies in permanent magnet value chains include recent acquisitions from large private equity firms, listed Asian pure plays, and industrial conglomerates. We have summarized some of these companies and recent industry trends on pages 14-15.
A thermal power plant converts 35-45% of the chemical energy in coal, biomass or pellets into electrical energy. So what happens to the other 55-65%? Accessing this waste heat can mean the difference between 20% and 60% energy penalties for post-combustion CCS. This 10-page note explores how much heat can be recaptured.
What are CCS energy penalties? We define CCS energy penalties as the loss of useful energy across an end-to-end CCS value chain, versus the useful energy that would have been available without using CCS. They include direct electricity use (e.g., for CO2 compression in pipelines and disposal facilities). And they include thermal loads in the amine reboiler, absorbing heat that could otherwise have driven the power cycle. We give our best estimates for all of these variables (in kWh and in percent) on pages 2-3.
How much waste heat can be harnessed? If a coal plant can meet all of its amine reboiler duty using waste heat, which would otherwise simply have condensed in a cooling tower, then its CCS energy penalties are as low as 20%. If it needs to burn extra coal to meet all of its amine reboiler duty, then CCS energy penalties are as high as 60%. So how much waste heat can be harnessed at a solid fuel power plant?
A typical thermal power plant must already be recapturing 50-70% of its theoretically available waste heat if it is achieving a thermal efficiency in the range of 30-45%. We show this by modelling a thermal power plant, first with no heat recapture on page 4, and then adding in the efficiency impacts of modern coal power plant design on pages 5-6. This allows us to quantify how much waste heat is still available in kWh/ton.
What are the CCS energy penalties for biomass power? The same discussion applies to biomass-fired power plants as to typical thermal power plants. We have adjusted for the heat content of fuels, and a few other tweaks, to quantify how much waste heat is available, in kWh/ton at a typical biomass pellet power plant (page 7).
But is this waste heat really available to defray CCS energy penalties? We consider the IRRs on additional heat exchangers, organic Rankine cycles and supplying medium-temperature water for district heating on pages 8-9. This analysis suggests that most power plants will have already grasped options for heat recovery that are practical?
CCS is increasingly being explored due to $85/ton incentives, made available under the US Inflation Reduction Act. However, we end the note on page 10, by wondering whether simple, flat $85/ton CO2 prices could have unleashed a very large amount of efficiency gains at power plants that happened to have large waste heat streams.
Investing involves being paid to take risk. And we think energy transition investing involves being paid to take ten distinct risks, which determine justified returns. This note argues that investors should consider these risk premia, which ones they will seek out, and which ones they will avoid.
Investment strategies for a fast-evolving energy transition?
Thunder Said Energy is a research firm focused on energy technologies and energy transition. Over the past 4-years, we have published over 1,000 research notes, data-files and models, to help our clients appraise different opportunities in the energy transition, across new energies, hydrocarbons and industrial decarbonization.
Energy transition is evolving very quickly. This means that many investors are continually iterating their investment strategies, stepping into new themes/sectors as they emerge, and candidly, it also means that many risks are mis-priced.
Hence we think it is helpful to consider risk premia. Which risk premia are you getting paid to take? Are you getting paid enough? Or worse, are you exposed to risk for which you are not getting paid at all?
We think there are ten risk factors, or risk premia, that determine the justified returns for energy transition investing. Sweeping statements about the global energy system are almost always over-generalizations that turn out to be wrong. Nevertheless, we will make some observations, as we define each risk factor below.
(1) Risk free rate. The risk free rate is a baseline. It is the return available with almost no risk, when investing in cash deposits and medium-term Treasuries. Our perspective is that many technologies in the energy transition will be inflationary. They will stoke inflationary feedback loops. And in turn inflation puts upwards pressure on the risk free rate. Thus rising rates should raise the bar on allocating capital across the board and investors should consider how they are being compensated. Our favorite note on this topic is here.
(2) Credit/equity risk. This risk premium compensates decision makers for the risk of capital loss inherent in owning the debt and equity of companies. It might vary from sub-1% in the senior secured credit of highly creditworthy companies, through to a c3-5% equity risk premium, and c5-10% for smaller/private companies? Our perspective is that there is great enthusiasm to invest in the energy transition. This means credit/equity risk premia for some of the most obvious energy transition stocks may be compressed. But energy transition is also going to pull on many adjacent value chains, which have non-obvious exposure to the energy transition, while their risk premia have not yet compressed. So we think it is a legitimate investment strategy to target “non-obvious” exposure to the energy transition. Our favorite note on this topic is here.
(3) Project risk. Energy transition is the world’s greatest building project. But over 90% of all construction projects take longer than expected, or cost more than expected, and the average over-run is 60%. Opportunities with more of their future value exposed to delivering large projects have higher project risk. Infrastructure investors can happily stomach 5-10% total returns as they accept project risk. This might include building out power grids, pipelines, fiber-optic cables, and PPA-backstopped wind and solar. And thus another legitimate strategy in the energy transition investing is to get paid for appraising and defraying project risks; get paid for the ability to execute projects well.
(4) Liquidity risk. This premium compensates investors against the possible inability to withdraw capital in a liquidity crunch. It is clearly higher for small private companies than publicly listed large-caps. Energy transition sub-sectors that might debatably warrant higher liquidity premia are CCS projects (50-year monitoring requirements after disposal), reforestation projects (40-100 year rotations for CO2 credit issuance) and infrastructure with very long construction times. A legitimate strategy for endowments and pension funds in the energy transition hinges on their large size and longevity, which allows them to withstand greater liquidity risk than other groups of investors. Another legitimate strategy is to earn higher returns by taking higher liquidity risk, building up a portfolio of privately owned companies with exposure to the energy transition, rather than investing in public companies that will tend to have lower liquidity risk premia.
(5) Country risk. This premium compensates investors against deteriorating economic conditions, tax-rises, regulatory penalties or cash flow losses in specific countries. This is becoming relevant for wind and solar, as many investors are increasingly willing to take country risk to achieve higher hurdle rates, and given the vast spread in different countries’ power prices and grid CO2 intensities (chart below). It is no good if only a few countries globally decarbonize. Net zero is a global ambition. And so another very legitimate strategy in the energy transition is to specialize in particular countries, where those country risks can be managed and defrayed, while driving energy transition there.
(6) Technology risk. This risk premium compensates investors for early stage technologies not working as intended, or suffering delays in commercialization, which derail the delivery of future cash flows. One observation in our research has been that some technologies at first glance seem to be mature, but on closer inspection still have material technology risks (such as green hydrogen electrolysers, post-combustion CCS). But technology risk is interesting for two reasons. First, we think that investors can command some of the highest risk premia (i.e., highest expected returns) for taking technology risk, compared to other risk premia on our list. Second, appraising technology risk is a genuine skill, possessed by some investors, a font at the wellspring of “alpha”. We enjoy appraising technology risk by reviewing patents (see below).
(7) New market risk. This risk premium compensates investors for immature markets. For example, if you produce clean ammonia, then you can sell it into existing ammonia fertilizer markets which does not carry any new market risk; or you can sell it as a clean fuel to decarbonize the shipping industry, which involves persuading the shipping industry to iron out ammonia engines, despite challenging combustion properties, prevent NOx emissions, and retrofit existing bulk carriers and container ships, which clearly does carry new market risk. Another interesting example is that in geographies with high renewables penetration, there may be some hidden market risk in reaching ever-higher renewables penetration? Our personal perspective is that new market risk is the most ‘uncompensated’ risk in the energy transition. It is pervasive across many new energies categories, many investors are exposed to this risk, and yet they are not paid for it. Although maybe another legitimate strategy in the energy transition is to collect new market risk premia while helping to create new markets?
(8) Competition risk. This risk premium compensates against unexpected losses of market share and cash generation due to new and emerging competition. It also includes the risk of your technology “getting disrupted” by a new entrant. Across our research, the area that most comes to mind is in batteries. There is always a headline swirling somewhere about a disruptive battery breakthrough that will crater demand for some incumbent material. Arguably, competition risk goes hand in hand with technology risk and new market risk. It is not enough to develop a technology that is 20% better than the incumbent if someone else develops a technology that is 40% better. Again, we think investors may not get compensated fairly for taking competition risk, while excess returns may accrue to investors that can appraise this risk well.
(9) Commodity risk. This risk premium compensates investors for the inherent volatility of commodity markets, which can have deleterious effects on valuations, liquidity, solvency, sanity (!). Consider that within the past five years, oil prices started at $80/bbl, collapsed into negative territory in Apr-2020, then recovered above $120/bbl in mid-2022. Our work has progressively gone deeper into cleaner hydrocarbons, metals, materials. Our energy transition roadmap contains bottlenecks where total global demand must rise by 3-30x. Yet our perspective is that many investors are reluctant to take commodity risk. Stated another way, commodity risk can be well-compensated. If you have the mental resiliency to ride this roller-coaster.
(10) Environmental risk. This risk premium compensates investors against tightening environmental standards, deteriorating environmental acceptance or regulations that lower future cash generation, especially in CO2 emitting value chains. It is sometimes called “stranded asset risk”. The most obvious example is investing in coal, where investors can get paid c10% dividend yields to own some of these incumbents. Our perspective is that environmental risk premia blew out to very high levels in 2019-2021, and they still remain high, especially if you believe that an era of energy shortages lies ahead (note below). Another perspective is that it feels “easier” to get paid a 5-10% environment risk in an insurance policy against future energy shortages, than to earn a 5-10% risk premium by doing the due diligence on a new and emerging technology? And finally, it is a legitimate strategy in the energy transition to own higher-carbon businesses, then improve their environmental performance, so that the market will reward these companies with lower environmental risk premia.
We have constructed over 160 economic models of specific value chains, in new energies and in decarbonizing industries. Usually, we levy a 10% hurdle rate in these models, for comparability. But the justified hurdle rate should strictly depend upon energy transition risk premia discussed above.
Please contact us if we can help you appraise any particular ideas or opportunities, to discuss their justified hurdle rates, or to discuss how these risk premia align with your own energy transition investing strategy.
The very simple spreadsheet behind today’s title chart is available here, in case you want to tweak the numbers.
The DRI+EAF steel pathway already underpins 6% of global steel output, with 50% lower CO2 than blast furnaces. But could IRA incentives encourage another boom here? Blue hydrogen can reduce CO2 intensity to 75% below blast furnaces, and unlock 20% IRRs at $550-600/ton steel? This 13-page report explores the opportunity, and who benefits.
A blue process reduces the CO2 intensity of a value chain, usually by over 50%, often over 90%, by pairing it with some form of CCS (page 2).
Most famous are blue hydrogen and blue ammonia. Both currently seem to be booming in the US, following new incentives in the Inflation Reduction Act (IRA). And we think there are five factors underpinning these booms (page 3).
What about blue steel? This 13-page report argues that the same five factors exist for ‘blue steel’ as for blue hydrogen and blue ammonia. The goal of the report is not to assess all 80 different decarbonization pathways for all 500 different types of steel. But to zoom in on a particular pathway that looks particularly interesting to us in the 2020s (page 4).
Existing markets are one of our five factors. Global steel production has risen by 10x since 1950, to 2GTpa by 2022, and demand is still rising at 2.5% per year since 2012. 70% of steel is made in blast furnaces and basic oxygen furnaces, in a pathway that emits over 2 tons of CO2 per ton of finished steel (model here) (page 5).
Technological maturity is another factor. DRI+EAF is an alternate steel-making pathway, which already underpins 120MTpa of global steel production. This is 6% of the world’s steel output (which seems like a small amount, but for comparison, it represents about 5x more production than the world’s entire global supply of copper!) (page 6).
DRI+EAF steel. What are the costs and CO2 intensity factors? We have modeled the DRI pathway converting iron ore (Fe2O3) into direct reduced iron using a syngas of H2 and CO derived from natural gas. The DRI is then flowed through to an electric arc furnace (page 7).
Costs of DRI+EAF steel are competitive with blast furnace steel, but CO2 intensity is 50% lower. The drivers of the varying CO2 intensities are discussed on page 8.
Hydrogen blending. The reducing agents in DRI are mixtures of H2 and CO, formed by reforming natural gas. But the higher the share of hydrogen, the lower the CO2, and thus there is opportunity to add merchant hydrogen to DRIs. Existing DRIs might purchase 20-60kg/ton of merchant blue hydrogen to decarbonize steel (page 9).
Interesting economics? The most important part of the report looks at the economics of DRI+EAF facilities with very heavy levels of hydrogen blending, and thus very low CO2 intensities, around 75% below blast furnace steel. We think that sourcing $1/kg blue hydrogen as a reducing agent is already cost competitive (i.e., before subsidies). But IRA incentives, high energy prices in Europe, and ultimately border taxes uplift these IRRs to around 20% (pages 10-11).
Who benefits? Greater deployment of DRIs fed by blue hydrogen would also expand the market opportunity available to the usual suspects in hydrogen value chains. But we also see interesting wheels in motion in the steel industry. Five companies are discussed on pages 12-13.
Super-alloys have exceptionally high strength and temperature resistance. They help to enable 6GTpa of decarbonization, across efficient gas turbines, jet engines (whether fueled by oil, hydrogen or e-fuels), vehicle parts, CCS, and geopolitical resiliency. Hence this 15-page report explores nickel-niobium super-alloys’ role in energy transition.
Super-alloys are blends of metals, with crystal structures that confer high strength, high temperature resistance, and/or resiliency to oxidation and corrosion. As rules-of-thumb, super-alloys can withstand 1,000MPa of stress at room temperature, and still withstand 500MPa of stress even as temperatures surpass 1,000ºC. These material properties are explained on pages 2-3.
Gas turbines and jet engines use super-alloys for greater efficiency, which is directly linked to turbine inlet temperatures, thanks to the physics of the Brayton Cycle (note here). Super-alloys are currently being developed that could improve efficiency by 5-7pp. Opportunities and implications are discussed on pages 4-5.
Pipelines, especially CCS pipelines, will blend in traces of super-alloys, so that they can flow greater volumes at higher pressures. Materials typically only comprise 10-30% of the costs of pipelines, so it makes economic sense to up-spec materials. Barlow’s Formula and other economic considerations are on pages 6-7.
Other deployments of super-alloys will enable decarbonization themes such as more efficient vehicles (page 8), clean fuels such as hydrogen or blue ammonia (page 9), and around half of the market is currently linked to aerospace and defense spending, which matters for geopolitical security? (page 10).
Super-alloys role in energy transition. How are super-alloys made, what do they cost, and what is their CO2 intensity? The note focuses upon nickel value chains and niobium. We have condensed the most important considerations onto pages 11-12.
Leading companies in super-alloys are concentrated across a handful of specialists. Some are divisions of large industrial conglomerates, and others are pure-plays. Names that stood out in our screens are summarized on pages 13-15.
Powering the internet consumed 800 TWH of electricity in 2022, as 5bn users generated 4.7 Zettabytes of traffic. Our best guess is that the energy consumption of the internet will double by 2030, including due to AI (e.g., ChatGPT), adding 1% upside to global energy demand and 2.5% to global electricity demand. This 14-page note aims to break down the numbers and their implications.
Global energy demand is a crucial debate. We expect 60% upside in useful global energy demand by 2050 (model here), while some commentators expect declines. And nearer term, we think the world could be gripped by energy shortages (note here, model here) (page 2).
Hence the energy consumption of the internet matters. In 2021, there were 4.9bn internet users globally, underpinning 3.4 Zettabytes of internet traffic. The energy footprint of the internet has most likely doubled since 2015 to 800TWH in 2022, as internet traffic has risen at a 30% CAGR (page 3).
Why does the internet consume energy? We have aimed to explain the end-to-end drivers of energy consumption, including data servers in data centers (page 4) and transmission and networking (page 5).
It is a minefield. Different studies disagree by five orders of magnitude over the energy intensity of internet processes. We offer some perspectives around why this is, and how we get comfortable making approximate estimates for the future (6-8).
Future energy demand of the internet could double by around 2030, and reach 5% of global electricity use by 2050. We spell out our models and the numbers that we have pencilled in, including for the rise of AI engines (e.g., ChatGPT) on page 10.
Uncertainty is high. When we consider how the internet has evolved in the past, and the way it might evolve in the future, it makes a mockery of the idea that future global energy demand is knowable a priori. It is a very brave policymaker that plans their future grid, the energy security of their nation, around the notion that future demand will decline (page 11).
Counterfactuals. The internet not only consumes energy. It also displaces energy. Especially oil product energy, which is electrified. Some favorite examples are quantified on page 12. And impacts on our oil models are discussed on page 13.
Company implications: another very hungry caterpillar?The energy upside for the internet is all electricity. Moreover it is high quality electricity. So once again our conclusion is that all roads lead to power electronics. A few pure-play listed equities that stood out in our work, and interesting private equity ideas, are noted on page 14.
Blue ammonia can economically decarbonize the fertilizer industry, using low-cost natural gas; with options to decarbonize combustion fuels in the future. This 12-page report covers where we see the best opportunities, as reforms to the 45Q have already kick-started a 20MTpa boom of new US projects.
The pathway to producing blue ammonia is technically ready, scalable, and has just received an enormous boost, as reformed US 45Q regulation offers $85 per ton of CO2 that is captured and sequestered. This report argues blue NH3 can economically decarbonize the global fertilizer industry, with possible options to decarbonize some fuels in the future.
Option #1 for blue ammonia is to sell this feedstock, and its derivatives, into a growing global fertilizer market. This is our favorite option, for reasons outlined on pages 4-5.
Option #2 for blue ammonia is to blend NH3 into existing burners and boilers. There is no CO2 released when NH3 is burned, but there is CO2 embedded in the production and distribution of blue ammonia. CO2 abatement costs are calculated versus oil products, coal, gas and LNG on page 6. We argue this is more of an “option” than a mass-scale decarbonization opportunity, fit for specific contexts, at specific times, per page 7.
Option #3 for blue ammonia is to displace other liquid fuels, especially as a marine fuel. We think this option is going to be more challenging, and slower to emerge, for the reasons on page 8.
Darker thoughts. The net EROEI of the global energy system has risen steadily for 300-years, to current levels around 28x, per our note here. From an EROEI perspective, investing $50bn into producing blue ammonia does not allay our fears over mounting global energy shortages (pages 9-10).
Where are the best projects? We have screened a 30MTpa global pipeline of blue ammonia projects. We propose five rules of thumb to identify the best projects (page 11). And we also discuss some leading examples from our database, including the underlying companies, both project sponsors, services, and technology providers (page 12).
Is the global energy system on the precipice of persistent shortages, and record prices, in the mid-late 2020s? We worry that cumulative under-investment in the global energy system has now surpassed $1trn since 2015, relative to our energy transition roadmap. Our top ten slides into global energy ‘macro’ are set out in this presentation.
2022 saw the joint highest energy prices on record, matching the peaks of the 1979-80 oil shock ($100/bbl Brent, $6.5/mcf Henry Hub, $40/mcf European gas, $18/mcf LNG, $385/ton Australian coal).
Our best guess is that 2023 will bring weak macro conditions, as high inflation and rising interest rates ripple through the financial system. This will temporarily mute energy demand and prices. In turn, this will result in even further under-investment.
Thus as demand recovers in the mid-late 2020s, will the recent trends result in energy shortages and record energy prices in order to destroy unsatisfiable demand?
The purpose of this ten-page presentation is to weigh up the evidence around these energy-related anxieties.
The outlook covers surprising coal upgrades, an interpretation of record oil demand, LNG tensions, wind and solar upside vs bottlenecks, combustion energy capex trends, an estimate of global energy under-investment since 2015, our latest energy supply-demand balances, debates over supply growth, and debates over demand destruction.
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