Leading aluminium producers are reviewed in this data-file, across ten companies, producing half of the world’s global output, two-thirds of its non-China output. Scale ranges 1MTpa to 7MTpa. CO2 intensity of primary aluminium production ranges from 3 tons/ton to 17 tons/ton across these companies.
This hinges on aluminium’s materials properties. It is 70% lighter than copper, and about 70% more economical, despite being 60% more resistive. It is also 65% lighter than steel.
The global aluminium market stood at 68MTpa in 2022, marginal costs of production are modeled around $3/kg, and CO2 intensity averages 10 tons of CO2 per ton of product (model here).
Half of global production comes from ten aluminium producers, screened in this data-file. China now meets 60% of all global supply, of which the two largest producers are Chalco and Hongqiao. And the other eight companies in the data-file cover two-thirds of the world’s non-China aluminium supplies.
Exposure to aluminium is quantified by company. 8 out of 10 of the companies are aluminium ‘pure plays’ with 80% exposure to aluminium, or higher, on an EBITDA basis. Rio Tinto and Vedanta have more diversified portfolios. And even within the purer-plays, Norsk Hydro is c20% hydro power generation.
CO2 intensity varies widely, from 3 tons CO2 per ton of aluminium metal production at the lowest carbon primary producers globally to 17 tons/ton at higher-carbon Chinese producers. Some sources even quote the top of the CO2 curve at 20 tons/ton.
The largest reason for varying CO2 intensities is the different CO2 intensities of underlying power grids, which explains about 14 tons/ton of the variation. The remaining 3-4 tons/ton of CO2 intensity that is not due to power grids is broken down in our aluminium model.
Among the large primary producers, our view is that the companies with the most credible decarbonization plans are Norsk Hydro, Alcoa and Rio Tinto. These companies also have lower carbon asset bases today. And decarbonization plans are noted in the data-file.
We have also tabulated each company’s geographic exposures, exposure to aluminium, employee headcount, recent revenues, share listing details and our notes.
CANSOLV CCS amine has been commercialized by Shell since 2014. This data-file aggregates data into its reboiler duties (2.4-3.2 GJ/ton), amine emissions to air (can be below 0.2ppm) and degradation rates (pretty decent, especially up to 2,500 hours). Interest in workable CCS amines has been accelerating since early-2023.
CCS has seen a huge uptick of interest in 2022, including due to the IRA. But key challenges are amine stability (note here) and energy penalties (note here), which may not be entirely workable for commoditized amines such as MEA, in our view. Hence the hunt for better amines.
CANSOLV is the brand-name for a proprietary post-combustion CCS process, being commercialized by Shell, using the amine-based solvent, DC-103, plus other amines and additives. Some sources say that DC-103 is an activated tertiary amine. It is also selective to absorbing SO2. The solvent was developed by a spin-out from Union Carbide, Cansolv Technologies Inc, which was in turn acquired by Shell in 2008.
Commercially deployed. SaskPower’s coal-fired plant at Boundary Dam has used Cansolv since 2015, under a $1.5bn and 1MTpa CCS project. Although net output at the CCS-linked unit has reduced from 160MW to 110MW by running CCS. And performance has been erratic. The annual run rate for CO2 capture in 2015-21 ranges from 0.37-0.8MTpa and averaged around 0.65MTpa. This is most likely due to mechanical issues at the plant rather than issues with the solvent.
Solvent degradation has been relatively well tested, including in 2019, at a waste incineration plant in Norway (detailed notes in this data-file). In the first 2,500 hours of the solvent’s life, amine emissions were below a 0.4ppm limit level, on a daily averaged basis, over 99.5% of the time, while no significant breakdown products were released.
However, amine releases and breakdown product concentrations did increase in this pilot project over time. In hours 2,500-5,100, degradation of the amines progressively increased to about 10%, while amine emissions were in the range of 1-7 ppm about 4% of the time. We think this was triggered by ESP upsets, and rapid ramp-up/ramp-down of the plant. It could be mitigated by aerosol mitigation devices. Or simply by replacing the solvent after 2,500 hours.
In a 2021 technical paper, a maximum amine emission level of 0.2 ppmv was targeted after the water wash, in simulations around a CCGT. Even with operational upsets, relatively young solvent (up to 1,800 hours) did not materially exceed 0.1 ppmv emission over 24-hours, including spikes due to plant upsets.
Thermal energy needed for amine regeneration (i.e., reboiler duty) is most likely around 2.5 GJ/ton for coal-fired configurations (10% CO2 in exhaust) and rises to 3.1 GJ/ton for gas-fired configurations, based on technical data. This can be compared with other amines here. Economics of post-combustion CCS using amines can be stress-tested here.
Underlying data and further notes are in the data-file. So far, we think Shell’s CANSOLV and Aker Carbon Capture’s JustCatch are two of the front-runners in technically ready CCS amines. All of our CCS research is summarized here.
Over $100bn pa of industrial gases and $5-6bn pa of cryogenic air separation plants are produced each year. This data-file is a screen of leading industrial gas companies and cryogenic air separation companies, breaking down their market share (number of ASUs constructed) history, geography, sales and headcounts.
Industrial gases are relatively concentrated. Out of 20,000 units constructed historically, 50% of the market has historically been controlled by four large leaders: Air Liquide, Air Products, Hangyang and Linde.
A second tier of regional specialists are focused on specific countries such as Germany, Italy, Japan, Korea; several of which are listed. These companies are also broken out in the data-file.
As a result of this moderately concentrated industry structure, margins are fine, but not stellar. The average company is generating c20% EBITDA margins and c10% operating margins, with ROCE around 10% plus or minus a few percentage points.
Uptime and utilization are crucial to the economics of air separation units (model here). Hence this means that some of the largest and most experienced equipment manufacturers in the space can have a moat and generate higher margins and returns.
Decarbonization ambitions of different industrial gas companies are also noted in the data-file. Some of this is achieved through plant efficiency. For example, Linde notes that its technologies helped customers avoid 2x more GHG emissions than Linde itself emitted. Other industrial gas companies are gearing up in CCS and hydrogen value chains.
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.
Topsoe autothermal reforming technology aims to maximize the uptime and reliability of blue hydrogen production, despite ultra-high combustion temperatures from the partial oxidation reaction, while achieving high energy efficiency, 90-97% CO2 capture and <1 kg/kg CO2 intensity. This is achieved via twelve technology innovations.
Topsøe is a chemicals technology company, privately owned, headquartered in Denmark, founded in 1940, with 2,400 employees, $1bn of revenues in 2022 and 10% EBIT margin.
This data-file is focused on Topsoe’s autothermal reforming technology, for the production of blue hydrogen, which matters increasingly as blue ammonia and blue steel value chains start booming in the US.
Topsoe’s ATR design, called SynCor, has been deployed commercially since 2002, and may be the leading ATR technology in the marketplace in the early-2020s. Some examples of commercial deployments are noted in the data-file.
Advantages of Topsoe’s ATR technology are said to include high uptime, “best in class” energy intensity, 90-97% CO2 capture, <1 kg CO2/kg H2. But how is this being achieved, and how much of it is patent protected?
The first step of blue hydrogen reforming is a partial oxidation reaction, combusting methane with pure oxygen from an air separator, to produce CO and H2. This burner runs extremely hot. Flame temperatures reach 2,500-3,000ºC, and even by the upper portions of the catalyst bed, temperatures are still 850-1,100ºC.
These high temperatures cause unavoidable volatilization of materials, even refractory lining materials. Volatilized materials are later prone to being deposited on the catalyst beds. Or catalysts may be directly deactivated by exposure to excessively hot temperatures. Conversely, protecting the catalysts from very high temperatures causes pressure drops and energy penalties.
Overall, this means that key challenges for blue hydrogen reactors include reliability, uptime and maximizing energy efficiency.
Twelve innovations from Topsoe are discussed in the data-file, to address these challenges. In each case, we have aimed to explain what the innovation is, why it matters, and whether we can find support for the innovation via Topsoe’s patents.
There are alternative designs for blue hydrogen production, however our patent review leads us to wonder whether they will have lower rates of CO2 capture (e.g., KBR technology) or lower uptime and resiliency.
Our updated model of blue hydrogen costs integrates some of the considerations from this data-file and blue hydrogen technology review.
The global magnet industry is fragmented across hundreds of suppliers, including 800 in Asia-Pacific. The total market is worth $20bn pa. The purpose of this data-file is to highlight a dozen leading magnets and permanent magnets companies, including Rare Earth magnets (e.g., NdFeB), ferrites and other magnetic components.
More mundanely, permanent magnets are also sold into ordinary household appliances like tumble dryers; and electronics such as iDevices and audio equipment. Indeed, the largest specialist magnets companies in our screen sell products to over 2,000 active customers, ranging from <1mm micro-magnets to 200mm monsters, with energy products from 1-60 MGOe.
High competition is borne out by middling margins, which tend to average c20% at the EBITDA level, c10% at the EBIT level and single digits at the net level. Although further upstream, Rare Earth miners have recently generated EBITDA margins closer to 50%, and expanding. There may also be higher margins for specialized and premium companies.
Private permanent magnets companies. An interesting trend in the screen is rising private equity activity. For example, a consortium led by Bain Capital acquired Hitachi Metals in 2022, and re-spun the company as Proterial in early 2023.
Listed pure-play permanent magnets companies in the screen include two Chinese Rare Earths magnet-makers, and a $5bn Australian Rare Earths miner.
Diversified companies are also noted in the screen, with Rare Earths, magnetic materials or magnet components as part of the broader commercial portfolios, including a leading Japanese large-cap.
An overview of all of these companies, as well as an overview of energy and magnetism, is also given for TSE written subscription clients in our recent research note here. Useful industry data-points behind the note, such as different magnet types and their typical properties and magnet costs ($/kg), are also compiled in the data-file.
The DRI+EAF 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.
Electra is developing an electrochemical refining process, to convert iron ore into high purity iron, and ultimately into steel, using only renewable electricity. It has raised c$100M, gained high-profile backers, and is working towards a test plant. This 9-page note is an Electrasteel technology review, based on an exceptionally detailed patent, finding clear innovations, but also some remaining risks and cost question marks.
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). Hence the steel industry comprises 8% of global CO2 emissions.
Blue steel can be made by increasing the portion of blue hydrogen blending in directly reduced iron and electric arc furnaces, in a process that is already technically mature, comprises 6% of global steel production, and can yield 50-75% decarbonization of steel with minimal additional costs, and with a possible IRA-triggered boom on the way (note here).
Green steel can also be made via a similar pathway to DRI+EAFs and blending in green hydrogen as the reducing agent. In the past, we worried that this pathway would be overly expensive, and cause some inflationary circular reference errors in new energies value chains (note here).
Electra’s iron ore reduction process is an alternative method for steel production using only renewable electricity. It uses a proton exchange membrane electrolyser to generate protons from water, uses the protons to acidically dissolve Fe3+ ions from iron ores, electrochemically reduces Fe3+ to Fe2+, then purifies the Fe2+ ions, filters them to a separate electrowinning cell, and plates out pure Fe metal. This is patent protected.
This 9-page report is our Electrasteel technology review, based on a particularly detailed patent that we have assessed on our usual framework (pages 1-2). It covers in detail how we think Electrasteel’s technology works (pages 3-5), where we think the patents point to a breakthrough (page 6), possible energy intensity (page 7), renewable steel costs (page 8) and remaining technical challenges that need to be de-risked (page 9).
This data-file is a simple loss attribution for a thermal power plant. For example, a typical coal-fired power plant might achieve a primary efficiency of 38%, converting thermal energy in coal into electrical energy. Our loss attribution covers the other 62% using simple physics and industry average data-points.
In our power plant loss attribution, the largest losses are modeled to occur in the steam condensation stage of the Rankine Cycle (17% of losses), the boiler (14%), turbine losses (9%), heat lost in exhaust air (8%), fuel heating (4%), generator losses (2%), plant auxiliaries (2%), and other smaller losses, including incomplete combustion, fuel drying, fuel milling, flue gas desulfurization, NOx removal via selective catalytic reduction, dust removal via electrostatic precipitators and electrical losses such as transformers.
A range of typical efficiency factors are summarized from technical papers. But a reasonable base case might include 86% boiler efficiency, 90% turbine efficiency, 97% generator efficiency and 8.5% auxiliary losses (note the denominators differ case-by-case, as shown in the data-file).
Thermal power plant efficiency can vary from 20% to 50%. You can stress test different variables in rows 30-46, in order to test rules of thumb over the thermal efficiency of power plants.
Heat recovery. A massive 60% of a thermal power plant’s gross thermal energy ends up being imparted into hot exhaust gases from the boiler, and low pressure steam exiting a cascade of turbines. This is waste heat. The recapture of waste heat is the largest determinant of the efficiency of a thermal power plant. Our base case model assumes that 50% of the low-pressure steam heat and two-thirds of the exhaust gas waste heat is recaptured via heat-exchangers (e.g. warming up input air, fuel and cold water entering the boilers). Without this heat recovery, the thermal efficiency of our coal-fired power plant would be a pathetic 3%. And indeed, sub-10% efficiency factors were common from the dawn of the industrial revolution through to the start of the 20th century (data here). A 10pp increase in heat recovery raises our efficiency factor by 3% from 38% to 41%. However, in practice, this will also require higher capex.
Unit efficiency. Efficiency can be uplifted by around 4%, to 42%, by replacing average boilers, turbines, generators and auxiliary loads with best-in-class boiler efficiency, turbine efficiency, generator efficiency and auxiliary loads. However, in practice, this will also require higher capex.
Hotter cycles. Our base case model is a supercritical cycle around 566â—¦C, however, varying the maximum temperature of the cycle by +/- 100â—¦C changes the cycle efficiency by +/- 1%. The reason is that less working fluid is needed for a hotter cycle, which lowers the losses involved in evaporating and then re-condensing water; there is simply less water.
Hotter ambient temperatures. Our base case model assumes an ambient temperature of 20â—¦C. However, when ambient temperatures are 40â—¦C, efficiency falls by 0.3%, because it becomes harder to extract as much heat from the working fluid as it expands across the turbines and in the process cools towards ambient temperatures.
Higher-grade fuel. Coal grades vary. But generally, coal needs to be heated to above 400â—¦C to ignite, and above 500â—¦C to auto-ignite (data here). Replacing high-grade bituminous coal (6,500 kWh/ton) with low-grade lignite (3,500 kWh/ton) will lower efficiency by around 3%, because of the additional fuel-heating that is required.
Wetter fuel. Similar rules apply to fuels with a higher moisture content, as this moisture needs to be evaporated. Our base case coal has 10% moisture content, whereas a coal with 20% moisture content will lower efficiency by 0.3%.
Exhaust gas regulations. We think that 1.3% of the plant’s electricity will be lost in meeting developed world flue gas regulations, which require SO2 removal via flue gas desulfurization, NOx removal via selective catalytic reduction and dust removal via electrostatic precipitators. However, some thermal coal plants do not face exhaust gas regulations. Others face even more stringent regulations.
Biomass fired power. We have also developed a biomass-fired variant of the model, reflecting the lower thermal energy of wood versus coal, the higher moisture content and a lower combustion temperature. The base case thermal efficiency of a wood-fired power plant is 34%.
Gas turbines. We have also developed a gas-turbine variant of the model, reflecting the energy economics of the Brayton cycle from first principles, as a function of compression ratios and temperatures across the cycle. The base case thermal efficiency is 40% for a simple cycle gas turbine, rising to 57% efficiency for a combined cycle gas turbine (chart below). Here is hoping that this simple model of gas turbine efficiency is useful. Intriguingly, we think that the energy penalties for gas-fired CCS are only around 10-20%, versus 40% for CCS at power plants combusting solid fuels. For simple cycle gas turbines, the amine reboiler duty can often be met entirely via waste heat.
All of the variables above can be stress-tested in the data-file, which serves as a simple power plant loss attribution. The discussion above highlights that thermal power plants can have efficiencies anywhere from 20-60% depending on their configuration.
Electrostatic precipitator costs can add 0.5 c/kWh onto coal or biomass-fired electricity prices, in order to remove over 99% of the dusts and particulates from exhaust gases. Electrostatic precipitators cost $50/kWe of up-front capex to install. Energy penalties average 0.2%. These systems are also important upstream of CCS plants.
This data-file captures electrostatic precipitator costs, in order to remove particulate dusts from exhaust gases, especially in coal-fired power plant applications. As usual, we model what power plant increment is required to earn a 10% IRR on the up-front capex, opex and other costs of an air pollution control installation.
What is an electrostatic precipitator? ESPs flow exhaust gases through a honeycomb of tubes. Each tube contains a high-voltage wire, creating an electrical corona, imparting a charge to passing dust particles. The charged dust particles will then be attracted towards collecting plates, from which the dust can later be collected via rapping the plates (dry precipitators) or spraying the plates (wet precipitators).
Our base case cost estimate is that an electrostatic precipitator can add 0.5 c/kWh to the costs of a coal-fired power plant, to earn a 10% IRR on an ESP costing $50/kW, and incurring a 0.2% total energy penalty.
However, two-thirds of our cost build-up reflects subsequent disposal of captured dusts and particulates, especially where these dusts contain heavy metals. Not all facilities will incur these costs. Landfill costs vary by region. Trucking costs depend on distance. And different coals have different contaminants. Thus disposal costs can be flexed in the model.
The Electrostatic Precipitator market is approaching c$10bn per annum. It is increasingly important in the energy transition, as exhaust gases require large amounts of clean-up upstream of post-combustion CCS plants, to prevent releases of amines or their breakdown products, which can be problematic for air permitting and air quality. Also important for CCS stability are flue gas desulfurization (remove SO2) and selective catalytic reduction (remove NOXs).
Leading companies in electrostatic precipitators are briefly discussed on the ‘notes’ tab. The market includes industrial giants (Mitsubishi, GE, Siemens Energy, Alstom) through to more specialized companies that have historically installed over 5,000 air pollution control systems worldwide (Babcock, FLSmidth, Ducon, Wood Group).
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