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.

European gas and power model: natural gas supply-demand?

This data-file is our European gas supply demand model. Balances are assessed in European gas and power markets from 1990 to 2030, reflecting all of our research into the energy transition. 2023-24 gas markets will look better-supplied than they truly are. We think Europe will need to source over 15bcfd of LNG through 2030. A dozen key input variables can be stress-tested in the data-file.

Europe’s gas demand averaged 45bcfd in the decade from 2012 to 2021, of which c30% was consumed in industry, c30% in residential heating, c10% in commercial heating, c25% in electricity generation, and smaller quantities in T&D and transportation (chart below). Gas demand is disaggregated across a dozen different industries in the data-file.

European gas demand fell back below 40bcfd in 2022. We think that one half of the decline can be attributed to a particularly warm winter, and will naturally come back with more normal winter weather. And total demand will run sideways through 2030.

Gas demand in the European power market is actually seen rising from 11bcfd in 2021 to 13bcfd by 2030, as the electrification of heat and vehicles raise overall demand, while decarbonization ambitions are also likely to phase down 2.5x more CO2 intensive coal (chart below).

Europe’s indigenous gas supply looks increasingly pathetic. We will likely fall below 7bcfd of domestic gas production in 2023, down from a peak of 24bcfd, 20-years ago. Even amidst the supply disruptions of 2022, there is no sign yet that Europe is seriously considering long term supply growth. Although there is vast potential in European shale.

Europe has doubled its reliance on imports over the past 20-30 years, rising from a 40-45% share of final demand in 1990-2004, to an 80-85% share in 2021-25. Thank god for Norway, which is also the cleanest and lowest carbon gas in the world.

Recently, Russian supplies have collapsed, while our outlook sees a large pull on global LNG through 2030. We think this will support LNG prices.

Although in 2023-24, European gas markets may look better supplied than they really are, due to excess inventories, that were built up as an insurance policy in 2022. This is temporary.

The data file also contains granular data, decomposing gas demand across 8 major categories, plus 13 industrial segments, going back to 1990 (albeit some of the latest data-points are lagged); as well as 15 different supply sources, with monthly data going back a decade (chart below).

All models are wrong, but some models are useful. Hence variables that can be flexed in the model, for stress-testing purposes, include the growth rates of renewables (wind and solar), the rise of electric vehicles, the rise of heat pumps, the phase out of coal and nuclear, industrial activity, efficiency gains, LNG and hydrogen.

Please download the model to run your own scenarios. Our numbers have changed since the publication of our latest outlook for European natural gas, but if anything, we see the same trends playing out even moreso.

Post-combustion CCS: what energy penalties?

CCS energy penalties

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.

Thermal power plant: loss attribution?

Power plant loss attribution

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 566◦C, however, varying the maximum temperature of the cycle by +/- 100◦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 20◦C. However, when ambient temperatures are 40◦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 400◦C to ignite, and above 500◦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 of particulate removal?

Electrostatic precipitator costs

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).

Selective catalytic reduction: costs of NOx removal?

Selective catalytic reduction costs

This data-file captures selective catalytic reduction costs to remove NOx from the exhaust gas of combustion boilers and burners. Our base case estimate is 0.25 c/kWh at a combined cycle gas plant, which equates to $4,000/ton of NOx removed. Capex costs, operating costs, coal plants and marine fuels can be stress-tested in the model.

NOx pollution, mainly NO, is formed during combustion of fuels, when temperatures exceed 1,200ºC, and nitrogen gas in the air can oxidize. This matters as NOx gases are precursors to PM2.5 and ground-level ozone, which can exacerbate risks of premature death from cardiovascular disease, lung and kidney diseases.

NOx also matters in the energy transition. If you want to fit a combustion facility with CCS, it may be necessary to strip out the SOx then the NOx upstream of the amine unit, to avoid the formation of highly toxic nitrosamines (note here). High adiabatic flame temperatures of hydrogen will also form NOx. Meanwhile, using low-carbon ammonia as a fuel may release higher-than-normal NOx emissions as the NH3 molecule combusts (note here).

Selective catalytic reduction (SCR) has been used since the 1970s, using a metal oxide catalyst on a honeycomb ceramic or pleated metal sheet, to reduce NOx into harmless N2 and H2O. 4 NO + 4 NH3 + O2 ↔ 4 N2 + 6 H2O. The reaction uses ammonia or urea as a reducing agent.

History. The US already has about 1,000 SCR plants running, including at 650 CCGTs and 300 coal plants. We compiled data into the emissions of real world combustion facilities. Hence what are the costs?

Our base case model captures Selective Catalytic Reduction costs at a combined cycle gas-fired power plant. Untreated emissions might be 50-75ppm, and a $50/kW SCR can reduce this to 2-5ppm. Our base case cost increment is 0.25 c/kWh for a 10% IRR. This equates to a NOX removal cost of $4,000/ton. The numbers also include a 1.3% energy penalty and a 0.005 kg/kWh uptick in CO2 intensity.

Variations of the model capture the costs of NOx removal at a coal-fired power plant (about 2x higher, at 0.5c/kWh) and at a marine diesel engine (0.7c/kWh). Although as is shown in the chart below, capex costs and ultimate costs are very sensitive to context, specifically, how much NOx is in the exhaust gas to begin with, and how much is removed.

Please download the data-file to stress tests Selective Catalytic Reduction costs for NOx removal, in c/kWh and $/ton of NOx. The model is configured so that you can flex the capex, opex, catalyst costs, NOx removal, maintenance, labor, CO2 prices, tax rates and capital costs (hurdle rate).

Air quality: sulphur, NOx and particulate emissions?

flue gas of a combustion facility

The flue gas of a typical combustion facility contains c7% CO2, 60ppm of NOx, 40ppm of SOx and 2ppm of particulate dusts. This is our conclusion from tabulating data across 75 large combustion facilities, mainly power generation facilities in Europe. However, the range is broad. As a rule of thumb, gas is cleanest, biomass and coal are worse, while some diesel-fired units are associated with the lowest air quality in our sample.

Sulphur oxides (SOx) cause acidification, in the air, in rain and in natural habitats. Hence limits are placed on the sulphur emissions in the exhaust gases of large power facilities. The limits are typically 50-250ppm in Europe, 120ppm in the US and 75-300ppm in China. We think European coal plants emit 20-400 ppm of SOx, with an average of 85ppm, which has been reduced by installing gas scrubber units in recent years. Emissions from natural gas plants are effectively nil.

Nitrogen Oxides (NOx) cause ground-level ozones and smogs to form, which can contribute to respiratory problems. Thus limits in the exhaust gases of large power plants are 60-130ppm in Europe, 90-120ppm in the US and 75-150ppm in China. We think the average coal plant in Europe emits NOx at 110pm. The numbers are highest for large diesel plants averaging 160ppm, high for biomass plants averaging 80ppm, and lowest for gas turbines averaging 25ppm at CCGTs.

Particulates and dusts are combustion products that become airborne and are later deposited on buildings, machinery, natural habitats or worst of all inhaled. Dusts are limited to 3-9 ppm in the emissions of large power plants in Europe, 17ppm in the US and 22ppm in China. The average coal plant emits at 9 ppm in Europe, due to the installation of electrostatic precipitators and other exhaust gas treatments. Again, biomass and diesel plants can have high particulate emissions. Gas fired power plants seem to have particulate emissions well below 1ppm.

Underlying data on different power plants are broken down in this data-file. Note that European databases report estimated SOx, NOx and particulate emissions for large combustion facilities in tons, but we have applied our own back-of-the-envelope conversion factors, to translate the data into ppm and mg/m3 emissions intensities.

Flue gas desulfurization: costs of SO2 scrubbers?

Costs of SO2 scrubbers

This data-file captures the costs of flue gas desulfurization, specifically the costs of SO2 scrubbers, used to remove SO2 from the exhaust of coal- or distillate-fueled boilers and burners. We think a typical scrubber will remove 95% of the SO2 from the flue gas, but requires a >1c/kWh surcharge on electricity sales in order to earn a 10% IRR.

Coal typically contains >1% sulphur (>10,000 ppm), which results in exhaust gas containing 800ppm of SO2. And higher sulphur coals contain 2-3% sulphur (data here). But global regulations increasingly limit sulphur in exhaust gases to below 50-300ppm (data here). As a result, 250 coal-fired power plants in the US alone have installed 850 flue gas desulfurization units (aka scrubbers).

Flue gas desulfurization units work by spraying a sorbent into the top of a tall exhaust stack, while exhaust gases are fed in at the bottom. The most common sorbent for desulfurization is a solution/slurry of limestone, which has previously been crushed to 5-20μm in a ball mill. CaCO3 reacts with SO2 to form CaSO3 and CaSO4 (and CO2).

Capex costs to install a flue gas desulfurization system at a large power plant typically run to $150-300M, or $400/kW, based on useful EIA data. The costs are highly variable, and data are plotted below, correlating only loosely with the mass of exhaust gases. Recouping this capex cost with a 10% IRR adds 0.6c/kWh to the levelized cost of electricity.

Operating costs include limestone reagent, waste disposal costs, labor, maintenance and taxes. These are broken out in the data-file with sensible input assumptions.

CO2 intensity of SO2 scrubbers. 0.9 kg of CO2 is released per kg of SO2 that is captured. Substantively all of this is from the chemical reaction of SO2 with CaCO3, which releases CO2. The desulfurization plant will also have a parasitic load, but it is small, absorbing 0.1% of the coal plant’s power output. Altogether, this might add 0.03 kg/kWh to the CO2 intensity of coal power.

Levelized cost debates. One of our ongoing reasons for disliking levelized cost analysis is that comparisons are often not apples to apples. To reduce the SOx, NOx and particulate emissions of a coal plant to match a gas-fired plant is likely going to add 2c/kWh to the total levelized cost of coal power.

Diesel engines? We can also construct a variant of the model assessing the costs of SO2 scrubbers, for desulfurizing exhaust gases from diesel engines and generators. Costs are higher due to smaller scale and lower utilization, and can reach 2-3 c/kWh-u.

Companies? There is a well-diversified supply chain of companies commercializing scrubbers for onshore use. Alfa Laval, Wärtsilä, Yara are commonly cited technology providers for marine scrubbers.

Costs of hydrogen from coal gasification?

Costs of hydrogen from coal gasification

What are the costs of hydrogen from coal gasification? This model breaks down the economics, line-by-line, across different plant configurations, backed up with data from half-a-dozen technical papers. We think black hydrogen costs $1-2/kg, but CO2 intensity is very high, as much as 25 tons/ton. It can possibly be decarbonized resulting in semi-clean hydrogen costing c$2.5/kg.

SynGas is a mixture of hydrogen, carbon monoxide and CO2 that is produced by heating coal to around 1,400ºC in an oxygen-limited reactor. The process goes back to 1792, where it was used to produce ‘town gas’. Today, there are over 500 coal gasifiers operating in the world, largely in China and South Africa.

In our base case model, a typical syngas plant must charge around $500/ton, in order to generate a 10% IRR. The syngas can then be used in making chemicals (c50% of the syngas market, e.g., ammonia, methanol), for fuels (c30%), or combusted in a power plant (c20%).

However, CO2 intensity is very high, as much as 0.6 kg/kWh-th, 3x more than natural gas CO2, 1.5x more than average coal grades. Making syngas is only c70-80% efficient at harvesting the energy from coal, which is why the CO2 intensity of syngas is higher than coal itself. Moreover, the product is already partly oxidized (it contains CO), so it releases less energy when it is combusted.

Pure hydrogen can also be separated out from the syngas, by promoting the water-gas-shift reaction, then removing all of the impurities and acid gases. This is referred to as ‘black hydrogen’. We think a 10% IRR requires a hydrogen price of $1-2/kg. But again, CO2 intensity can be astronomically high, as much as 25 tons of CO2 per ton of hydrogen (i.e., 25 tons/ton). This is 3x more than generating hydrogen from steam methane reforming of natural gas (grey hydrogen). Please see our overview of hydrogen technologies.

As part of the energy transition, preserving a future for clean coal, it is feasible to purify and dispose of >90% of this CO2 from producing black-brown hydrogen. The result is a low-carbon hydrogen resource, maybe around 0.06kg/kWh-th. It is possible. But there is a lot of CO2 to dispose of, amplifying costs. The process could be economical at around $2.5/kg hydrogen, we estimate ($22/mcf-equivalent). Details in the model. But we still prefer blue hydrogen and turquoise hydrogen as leading options.

The costs of syngas and the costs of hydrogen from coal gasification depend on input variables. Capex costs are usually around $1,000/kWth of syngas. Other inputs are coal prices, efficiency factors, chemicals costs, labor costs and other variables. These can be stress-tested in different tabs of the data-file. Data from technical papers are tabulated in half-a-dozen back-up tabs.

Coal grades: what CO2 intensity?

CO2 intensity of coal

What is the CO2 intensity of coal? To answer this question, we have aggregated data on twenty five coal samples, across different countries, grades and technical papers. Sampled countries include China, Indonesia, Mongolia, Germany, Poland, the US, Canada, Australia, Japan and Korea.

The coal grades in the data file span across petcoke, anthracite, bituminous coal, sub-bituminous coal and lignite. All of these are classified as “coal”. Although their chemical and physical properties vary vastly.

The average coal grade in our data-file consists of 63% carbon, 30% volatile components that will gas out when coal is heated, 12% moisture (i.e., water) and 12% ash. (Note that the numbers do not add to 100% because some of the volatile components include hydrocarbons, including methane, which in turn contain carbon). Again these properties vary widely, from anthracites with >5% moisture to lignites and peats with over 50%.

The average energy content is 6,250 kWh/ton, within a range of 3,000 kWh/ton to 9,000 kWh/ton. This is mostly determined by the amount of carbon in the coal grade, which in turn will determine its CO2 emissions. CO2 intensity can then be calculated by dividing CO2 emissions (in kg) by energy content (in kWh).

The typical CO2 intensity of burning coal is estimated at 0.37 kg/kWh, looking across these twenty-five examples, with a straight line average. The range is approximately 0.3 – 0.5 kg/kWh. This is consistent with the CO2 intensity range given by the IPCC, which comes out around 0.35 kg/kWh.

The CO2 intensity of coal depends mostly upon the mineral composition of the coal sample, and appears to vary, sample by sample, with little underlying pattern. Strictly, for a full-cycle CO2 intensity calculation, we should also add in the CO2 intensity of producing, processing and distributing coal, i.e., Scope 1-2 CO2 intensity. And then we must also adjust for different fuel’s efficiency factors.

The data support the conclusion that coal is approximately 2x more CO2 intensive per unit of thermal energy than natural gas, where CO2 intensity is around 0.19kg/kWh. This is consistent with our analysis of bond enthalpies and energy units and conversions.

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