Energy economics: an overview?

Overview of Energy Economics

This data-file provides an overview of energy economics: 150 different economic models constructed by Thunder Said Energy, in order to help you put numbers in context. This helps to compare marginal costs, capex costs, opex costs and other key parameters of technologies and materials that matter in the energy transition.

Specifically, the model provides summary economic ratios from our different economic models across conventional power, renewables, conventional fuels, lower-carbon fuels, manufacturing processes, infrastructure, transportation and nature-based solutions.

For example, EBIT margins range from 3-70%, cash margins range from 4-85% and net margins range from 2-50%, hence you can use the data-file to ballpark what constitutes a “good” margin, sub-sector by sub-sector.

Likewise capital intensity ranges from $300-9,000kWe, $5-7,500/Tpa and $4-125M/kboed. So again, if you are trying to ballpark a cost estimate you can compare it with the estimated costs of other processes.

Renewables stand out. Despite high capital intensity (34% of revenues, 2x the average), once constructed, they also have the highest cash margins (76%, also 2x the average).

Low-carbon fuels and manufacturing/materials are similar. Both tend to have c20% average EBIT margins, after deducting 70-75% opex and c5-10% capex shares. This makes sense, as low-carbon fuels are effectively “manufactured” energy products.

The most exciting opportunities can also be picked out. They are clustered in the top-left of the chart, with high EBIT margins, low capital intensity and low costs once they are up-and-running.

Full data are available in the data-file below. To read the overview of energy economics send to our distribution list, please see our article here. All of the underlying economic models that feed into this data-file are available here.

Cement costs and energy economics?

Cement costs and energy economics

This data-file captures cement costs, based on inputs, capex and energy economics. A typical cement plant requires a cement price of $130/ton for a 10% IRR, on capex costs of $200/Tpa, energy intensity of 1,000 kWh/ton and CO2 intensity of 0.9 tons/ton. Cement costs can be stress tested in the data-file.

The world produces 4GTpa of cement, which is then blended with aggregates to yield 30GTpa of concrete in the construction industry. These are some of the most extensively produced materials in industrial civilization.

Cement is also important for the energy transition. A wind turbine uses 67 tons of cement per MW. So too might foundations of utility scale solar, power transmission lines, or the “pads” used to house batteries and hydrogen plants.

The marginal cost of cement production is estimated at $130/ton in this data-file, in order to achieve a 10% IRR, which is similar to the average price of cement in the US in 2021-22.

The breakdown of costs, in USD per ton of cement, includes: $40/ton for limestone inputs which are then calcined into clinker; $20/ton for heat which is mainly coal and petcoke today; $20/ton in capital costs for a 10% IRR; $20/ton for CO2 and the CO2 price can be flexed in the model; $10/ton for electricity; and $20/ton for other material inputs, labor, O&M and taxes.

CO2 intensity is estimated at 0.9 tons/ton in our base case, but there are interesting opportunities for decarbonization. Half of the CO2 from a cement plant is 20-30% concentrated CO2 from the thermal decomposition of limestone (CaCO3->CaO + CO2) which could be amenable to CCS.

Switching out solid fuels (coal) for gas would save 0.1 tons/ton. Around 100kWh/ton of electricity use is the grinding of inputs and clinker, and this is a very flexible load that can easy “demand shift” to run off a heavy share of renewables in future power grids.

Inflation in cement costs could be a challenge in the energy transition. European heat, electricity and CO2 prices can very easily double the marginal costs of production. Much of the growth in cement demand is also concentrated in emerging world countries, where cost sensitivity is high and CO2 is lower down the priority list. 

We have also screened technologies aimed at decarbonizing cement and concrete, such as Solidia, CarbonCure, or thinking laterally, substitution towards timber products.

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).

Direct reduced iron: costs and projects?

Direct reduced iron costs

Direct reduced iron (DRI) is produced by reacting iron ore with H2-rich syngas, fueled by natural gas, in over 150 facilities worldwide. Direct reduced iron costs $300/ton, consuming 3,000kWh/ton of energy and 0.6 tons/ton of CO2. The process can be decarbonized via low-carbon hydrogen, as the world strives towards decarbonized steel.

This data-file is an economic model of direct reduced iron (DRI) costs, including a breakdown of capex, opex, natural gas, electricity, iron ore, other materials, labor and taxes.

Direct reduced iron underpins 6% of global steel production, running to 120MTpa of the world 2GTpa global steel production and ramping up steadily since the 1970s (chart below).

How does the direct reduction iron process work? Iron ore is heated in a shaft furnace, alongside syngas, which contains CO and H2 derived from natural gas, thereby reducing the iron oxide, while forming waste gases of H2O and CO2. The product can later be upgraded into steel in an electric arc furnace.

Leading DRI technologies include Midrex and Tenova HYL, and the data-file contains a database of all the deployments to-date, plus future low-carbon plans.

DRI products include Hot DRI (converted straight into an EAF before it is cooled down), Cold DRI that is cooled down to below 60C before subsequent processing, and ‘Hot Briquetted Iron’ (HBI), which is a stabilized product and can be shipped globally in a bulk tanker.

Base case costs for producing DRI most likely run to $300/ton of iron, to earn a 10% IRR on a 2MTpa production facility costing $600M. Energy intensity is most likely around 3,000 kWh/ton and CO2 intensity is modelled at 0.6 tons/ton of iron, although this will vary according to the percent of iron reduction delivered by hydrogen versus CO (chart below).

CO2 intensity for the overall value chain is currently estimated at around 1.1 tons/ton, which is 50% lower than the blast furnace/basic oxygen furnace route.

For decarbonization of the steel industry, we think that direct reduced iron can increasingly be made with hydrogen comprising almost all of the reducing agent, and renewables-heavy electricity. Ultimately, this can reduce the total CO2 intensity to 0.6 tons/ton, which is 75% below higher-CO2 steel.

Bulk shipping: cost breakdown?

Bulk shipping cost

Bulk carriers move 5GTpa of commodities around the world, explaining half of all seaborne global trade. This model is a bulk shipping cost breakdown. We estimate a cost of $2.5 per ton per 1,000-miles, and a CO2 intensity of 5kg per ton per 1,000-miles. Marine scrubbers increasingly earn their keep and uplift IRRs from 10% to 12% via fuel savings.

Bulk carriers and global trade. 13,000 bulk carriers, with 100MT of carrying capacity, transport over 5GTpa of bulk commodities ever year, in vessels with deadweight tonnage (dwt) of 4,000 – 400,000 tons. This is c50% of all global trade by mass. Of this dry bulk, c25% is iron ore, 20-25% is coal, c10% is grain, while the remaining 40-45% spans other metals and materials.

Economic modelling. This data-file models the economics of bulk carriers, including a breakdown of bulk shipping cost, across capex, opex costs, fuel, crew charges, port charges, maintenance, and insurance.

In our base case a large Capesize (or Newcastlemax) bulk tanker, with 200,000 dwt of capacity, must charge a total day rate of $67,000 per day to earn a 10% IRR (chart above) off of $60M pa capex costs (chart below).

Bulk shipping cost per ton? Costs per ton are estimated at $2.5 per ton per 1,000 miles, while CO2 intensity is estimated at 5kg per ton per 1,000 miles, as a large bulk carrier will consume 300-500bpd of oil products. Inputs and outputs can be flexed in the model.

Which oil products as used by bulk tankers? Oil products will comprise 30-50% of total shipping costs for a bulk carrier, depending on whether the vessel is consuming marine gasoil (0.1% sulphur, EU/North American limits), low sulfur fuel oil (0.5%, IMO limit) or heavier fuel oil (3.5% sulphur, but this requires a scrubber to be IMO-compliant).

Marine scrubbers are increasingly being installed. They might cost $2-6M (depending on the ship size), but pay for themselves in subsequent fuel savings. Numbers can be stress-tested in the model, but we estimate that a vessel with a scrubber will either earn 35% higher cash margins, 2% higher IRRs overall, or achieve 7% lower total shipping costs. Our flue gas desulfurization (scrubber) model is linked here.

Costs can also be compared to our models of container shipping, LNG shipping, and CO2 shipping.

Leading companies in bulk shipping? Some of the largest bulk shipping fleets are associated with global mining companies, such as Vale, which operates the largest vessels in the world, above 400,000 tons, ferrying iron ore from Brazil to China. Leading pure-plays include Golden Ocean (listed, US/Norway), Oldendorff (private, HQ’ed in Germany) and Star Bulk (listed, HQ’ed in Greece).

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).

Silicon carbide: production costs?

Silicon carbide production costs

This data-file captures silicon carbide production costs: spanning from materials grade SiC ($1,500/ton marginal cost, 5 tons/ton CO2 intensity) through to SiC wafers that are used in the electronics industry ($30M/ton marginal cost, 200 tons/ton CO2 intensity). SiC semi-conductor remains one of the most opaque and hard-to-guess value chains we have looked at in our economic models.

Silicon carbide material is one of the hardest crystalline composites known to mankind, with an enormously high melting point of 2,700°C and very high chemical resistivity. Hence it is used in the steel/metals industry, aerospace, brake pads of high-end automobiles and bullet proof vests.

Silicon carbide material is made by super-heating high-grade silica (SiO2) with petcoke (C) in electric furnaces over 3-10 days. A 10% IRR might require a silicon carbide price of $1,500/ton. CO2 intensity is 5 tons/ton, of which approximately half is direct emissions from producing CO2, and the other 50% comes via 6MWH/ton of electricity use.

Silicon carbide can also be made into semi-conductor wafers, underpinning MOSFETs with low resistances, high switching frequencies, and increasing application in practically all new energies (note here).

However, measuring the price of SiC MOSFETs in terms of the cost per kg of SiC is a bit like measuring the price of Michelangelo’s David in terms of the cost per kg of marble. The value is not really in the material, but the very precise way it is arranged. And the ‘price’ is equally ineffable.

A 200mm SiC wafer might cost $1,500 to produce and weigh 50-grams, yielding an effective cost of $30M/ton of SiC contained, or $10M/ton of SiC consumed (assuming 2/3 material losses during formation/wafering).

Likewise, a large SiC fab producing 30,000 wafers per month might only use about 50 tons of SiC per year, in the production of 20 tons per year of wafers. So equally, a $1bn capex cost for such a facility equates to around $20M/Tpa, which is one of the highest numbers in any economic model we have ever constructed.

What underpins the exceptionally high costs is that forming SiC crystals from vaporized and highly purified SiC via the Lely Process at 2,000ºC proceeds at a rate of 100-300μm per hour. This is 1,000x longer than forming mono-crystalline poly-silicon from liquid silicon via the Czochralski method at 1,425ºC and at 25-100mm/hour. Thus a very large plant is required for SiC wafer production. Building and maintaining the plant seems to dominate the overall SiC wafer production costs.

Some sources say that the cost difference between silicon and SiC is about 15x (TSE data here), culminating in a 4x difference between resultant MOSFETs. But this is for 150mm wafers. It is inherently more difficult to form larger SiC wafers, and as we have modelled a 200mm wafer facility, our cost delta comes out at 20-40x on a $/kg basis.

The CO2 intensity (in kg/kg) embedded in SiC wafers might thus run to around 200 kg/kg. However, numbers remain uncertain.

Compared to other value chains that we have explored in our economic models, silicon carbide production costs remain more opaque and the numbers in this data-file are more like guesses (unsatisfyingly), versus the detailed cost breakdowns that we would usually look for in our modelling work. For now, this model is a placeholder, and we will look to gather more data breaking down production costs in semi-conductors.

Diesel power generation: levelized costs?

Levelized costs of diesel power generation

A multi-MW scale diesel generator requires an effective power price of 20c/kWh, in order to earn a 10% IRR, on c$700/kW capex, assuming $70 oil prices and c150km trucking of oil products to the facility. Levelized costs of diesel power generation can be stress-tested in this economic model.

A diesel genset includes an engine, power generator, switchgear, control systems, fuel supply systems, coolant and lubrication systems, a foundation, powerhouse civil works and wiring towards the connected load.

In the fuel cycle, air is drawn into the cylinder, compressed by 14-25x so its temperature reaches 700-900ºC, then a metered quantity of injected diesel spontaneously ignites, which provides the power to turn a rotating shaft, usually at 1,500-3,000 rpm (gas comparison here).

Total CO2 intensity is 0.6 kg/kWh for a diesel generator, at 40% average electrical efficiency, and including Scope 1, Scope 2 and Scope 3. This creates a rationale for expanding power grids and hybridizing diesel generation with solar and wind.

Some sensitivities are that each $10/bbl on the oil price translates into a 2c/kWh variation in power costs. For remote locations, each 100km of trucking distance adds another 0.2 c/kWh to the power price.

Capex costs can vary +/- 50%, especially depending on the emissions clean-up downstream of the generator (e.g., Diesel generators tend to be Tier 4, which emit 94% less NOx and 91% less particulate than Tier 2).

Another context where diesel generators are used is as a back-up power solution. Federal regulations require critical infrastructure, such as hospitals, care homes, airports, to have backup generators with 48-96 hours of fuel supplies. While facilities with risks of product spoilage might also have on-site generators to protect against grid failures, hence a typical super-market maintains a 250kW generator with 36 hours of fuel. When regulators talk of banning fossil fuels, it is not entirely clear what alternative is envisaged for these contexts.

The effective power price can be calculated for back-up generation systems, and might translate into around 100-200 c/kWh, depending on how frequently they are used. Although strictly, back-up generators exist to avoid much larger costs associated with power failures, rather than connoting a general willingness to pay 100-200c/kWh for electricity.

Companies with leading market share in diesel generators include Caterpillar, Generac, Cummins, Atlas Copco, AKSA, Aggreko.

Please download the economic model, to stress test the levelized costs of diesel power generation. The model allows for some easy flexing of power prices (c/kWh), capex costs ($/kW), oil prices ($/bbl), delivered diesel costs ($/gal), O&M costs ($/kW/yr) and CO2 prices ($/ton).

Cost of capturing CO2 using membranes?

Cost of capturing CO2 using membranes

This economic model captures the cost of capturing CO2 using membranes, with a base case of $50/ton to earn 10% IRRs on early commercial deployments, and a possibility of deflating to $20/ton in next-generation membranes.

A good membrane for CO2 capture should have a CO2 selectivity (versus Nitrogen) above 125x, and a CO2 permeance above 100 GPU, which means 0.67 m2 of membranes are needed per m3 of feed gas per hour. This membrane also needs to be stable, without degradation, for around 5-10 years. It also needs to cost around c$50/m2.

An exceptional membrane for CO2 capture should have a CO2 selectivity (versus Nitrogen) above 200x, and a CO2 permeance above 2,500 GPU, which means 0.1 m2 of membranes are needed per m3 of feed gas per hour.

Low pressure separation is also important, as compression energy costs comprise around a 13% energy penalty in this model.

Membrane stability is also important, as our recent research has highlighted how amines and other CO2-reactive compounds can degrade, especially in the presence of impurities.

The data-file allows you to stress test the costs of separating CO2 and nitrogen, as a function of membrane selectivity (x), membrane permeance (GPU), membrane costs ($/m2), capex costs ($M), CO2 concentration in the feed gas (%), pressure (bar), electricity use (kWh/ton), electricity prices (c/kWh), maintenance ($/ton), and CO2 prices ($/ton).

Useful data-points into the cost of capturing CO2 using membranes are compiled in the back-up tabs from technical papers and academic studies, into membrane permeance (GPU), selectivity (x), thicknesses (μm) and flux rates (m3/hour/m2 of membranes).

There is a question mark about whether membranes that satisfy permeability, selectivity and stability requirements will also be low cost. $50/m2 is a ‘target’ that is suggested in a large number of technical papers that crossed our screens. Whereas some of the highest-grade industrial membranes today can be as costly as $5,000/m2.

All of our broader CCS research is summarized in chronological order on our CCS category page. Our deep-dive note into membrane CO2 separations is linked here.

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.

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