Energy economics: an overview?

This data-file provides an overview of energy economics, across 175 different economic models constructed by Thunder Said Energy, in order to put numbers in context. This helps to compare marginal costs, capex costs, energy intensity, interest rate sensitivity, and other key parameters that matter in the energy transition. Our top five facts follow below.


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

For example, EBIT margins range from 3-70%, cash margins range from 4-80% 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; and to screen different industries, according to the capital intensity, opex costs and resultant profitability (chart below).

Capital intensity ranges from $300-9,000kWe, $5-7,500/Tpa and $4-125M/kboed. So if you are trying to ballpark a cost estimate you can compare it with the estimated costs of other processes. The median average industry has a capex cost of $750/Tpa (chart below).

Capital intensity of different energy sources also varies by an order of magnitude (chart below). Each $1 dollar that is disinvested from new hydrocarbon capex ideally needs to be replaced by $25 invested in wind and solar, in order to add the same amount of primary energy to the global energy system (chart below, note here).

Economies of scale are visible in the data-file, across our models of Air Separation, Cables, Comminution, Compressors, Electric Motors, Electrowinning, Fans, Flotation, Gas Dehydration, Harmonic Filters, Heat Exchangers, Inverters, Motor Drivers, Pumps, Rankine Engines, Tanks and Turbines. Generally, making these units 10x larger reduces their unit costs by around 45%.

Cost reduction from scale for different energy technologies.

Interest rate sensitivity is visible in our overview of energy economics. Each 1% increase in capital costs re-inflates new energies 10-20%, infrastructure 2-20%, materials 2-6%, and conventional energy 2-5% (chart below, note here).

Marginal cost inflation per 1% WACC increase for different energy technologies, materials, and infrastructure projects.

The energy intensity of materials is visible across our models of Acetylene, Aluminium, Ammonia, Carbon Fiber, Cement, Copper, Cyanides, Desalination, Glass, H2O2, Hydrogen, Industrial Gases, Lithium Batteries, Methanol, NaOH/Cl2, Nitric Acid, Paper, Plastics, Silicon, Silver, Steel, Wood Products. As a rule of thumb, energy is 50% of the cash cost of typical materials.

Renewables stand out. Despite high capital intensity (35% of revenues, 2x the average), once constructed, they also have the highest cash margins (75%, also 2x the average). The rise of wind, solar and electrification make capex costs and capital costs increasingly important.

The full data are available in the data-file below. However, please be aware that this is simply a compilation of headline figures across our library of 175 economic models. Access to all of the underlying models is covered by a Thunder Said Energy subscription.

Compressed air energy storage: costs and economics?

Capex and cash flows for a compressed air storage facility.

Our base case for Compressed Air Energy Storage costs require a 26c/kWh storage spread to generate a 10% IRR at a $1,350/kW CAES facility, with 63% round-trip efficiency, charging and discharging 365 days per year. Our numbers are based on top-down project data and bottom up calculations, both for CAES capex (in $/kW) and CAES efficiency (in %) and can be stress-tested in the model. What opportunities?


Compressed Air Energy Storage (CAES) seeks to smooth out power grids, using excess electricity to compress air into storage tanks or underground reservoirs at high pressures (e.g., 40-80 bar). The energy needed to compress air to different temperatures is plotted below. Electricity can later be recovered later by expanding these high-pressure gases across a turbine.

The round trip efficiency of CAES averages 60-65%, across projects that are sampled in the data-file. We can break down these numbers from first principles, assuming 78% compressor efficiency, 90% turbine efficiency and 97% generator efficiency (matching the numbers in our power plant loss attributions). Another 3-30% will be lost due to compressed gases cooling during storage (see below).

When gases are compressed they tend to heat up. For example, in an isentropic process — where heat is not exchanged with the external environment — compressing air to 30-60 bar will also tend to increase its temperature to 500-600°C. Inevitably, when the gas is stored, however, some of this heat does leak to the external environment, which means that there will be less energy to recover from the gas when it is expanded across the turbine. For more, please see our overview of thermodynamics.

We can model the capex costs of Compressed Air Energy Storage from first principles in the model, by combining our models of compressor costs, storage facility costs and turbine costs. Our numbers also match top-down costs reported for past projects and technical papers into CAES.

Hence our base case estimates for CAES costs require a 26c/kWh storage spread to generate a 10% IRR at a $1,350/kW CAES facility, with 63% round-trip efficiency, charging and discharging 365 days per year. As always, costs vary with WACCs, duration and the number of charge-discharge cycles (chart below).

But generally, CAES costs 30% more than a lithium ion battery storage system. Key reasons are the lower efficiency (discussed above) and 5-10x higher maintenance costs for the moving parts in a CAES system (compared to a LiB with no moving parts).

CAES economics are most competitive when input electricity costs are low and storage duration is increased. One advantage of a CAES system is that it can easily be scaled if the facility has access to a large underground storage reservoir, possibly ranging across thousands-millions of m3, with a tolerance for 40-300 bar pressures. In this case, we think capex costs could fall below $50/kWh for a long-duration battery (LiB comparison here).

Long duration storage leader? In theory a CAES system could thus provide 24-hours of storage for as little 30-40c/kWh. These numbers are generally lower than for 24-hour storage in lithium ion batteries, comparable to redox flow batteries, but still higher-cost than the costs of 24-hour storage in thermal energy storage systems.

Copper: the economics?

The economic cost of copper production is built up from first principles in this model, from mine, to concentrator, to smelter to 99.99% pure copper cathodes. Our base case is $7.5/kg copper cathode, with 4 tons/ton CO2 intensity, after starting from an 0.57% ore grade. Numbers vary sharply and can be stress-tested in the data-file.


70-80% of all primary copper is produced by the smelting route and mainly starting with sulphide ores. First, ore is mined, moved, crushed and concentrated to around 20-40% purity. The ‘CopperOreMine’ tab of the model captures the costs, energy use and CO2.

Further downstream, the ores may be roasted to change their crystal structure before smelting, smelted in an environment of enriched oxygen to reject sulfur as sellable sulphuric acid, yielding matte with c50-70% purity.

Even further downstream, matte is upgraded to blister with c99% purity, which is melted and cast into anodes for electrochemical refining, yielding copper cathodes with 99.99% purity. Copper cathode is one of the most traded metals on Earth, underpinning the LME copper contract, as pure copper is purchased and processed into semis, wires and cables.

The economic cost of copper production is built up from first principles in this model, from mine, to concentrator, to smelter to 99.99% pure copper cathodes. Our base case is $7.5/kg copper cathode, with 4 tons/ton CO2 intensity. Capex intensity of copper is plotted below in $/Tpa.

But the costs of copper production depend heavily on ore grade and mining/refining technology. We estimate that a 0.1% reduction in future copper ore grading increases marginal cost by around 10% and CO2 intensity by around 10%, which matters as copper demand is set to treble in the energy transition.

Moreover, each $100/ton of CO2 prices would increase marginal cost by another 5%. It is not unimaginable that copper prices could reach $15,000/ton in an aggressive energy transition scenario, if you stress-test the model.

There is no silver bullet to decarbonize primary copper production, because of the large number of processing steps described above and in the data-file. Hence the best option to decarbonize copper production are to increase the reliance on secondary production (i.e., recycling, e.g., Aurubis).

The best option to decarbonize primary copper, based on stress testing our models, is to use clean electricity for processes such as crushing and flotation, which can save over 1 ton/ton of CO2. Using these processes flexibly can potentially even help to integrate renewables. Finally, we think that electrochemical production, e.g., via solvent extraction then electrowinning (the favored route for oxide ores that cannot be floated), can reduce total CO2 intensity by a further 1 tons/ton when using clean electricity.

Pump costs: energy economics of electric pumps?

As pump power increases, pump costs per kWh decrease. The most significant reduction is in pump maintenance costs, while the total cost of electricity remains constant.

Total pump costs can be ballparked at $600/kW/year of power, of which 70% is electricity, 20% operations and maintenance, 10% capex/capital costs. But the numbers vary. Hence this data-file breaks down the capex costs of pumps, other pump opex, pump energy consumption and the efficiency of pumps from first principles.


This data-file captures the energy economics of electric pumps, which are used to move liquids in industrial applications, for commercial/domestic use such as within heat pumps, for demand shifting, for supercritical CO2, in geothermal applications, and in 15-20% of the world’s 1M oil wells globally (electric submersible pumps, or ESPs).

The capex costs of a pump are estimated from fifty commercial data-points, in $/kW, and a line of best fit suggests that pump costs approximately halve as pump size increases by 10x (chart below). In other words, larger pumps are less costly per kW of power.

Total pump costs, however, are usually only 5-20% capex, while the largest costs are for electricity use, at 50-90% of the total, depending on the pump size and utilization rate (chart below). All of these variables can be stress-tested in the ‘PumpModel’ tab.

The power consumption of a pump is modeled from first principles, using the formula that pump power consumption (in kW) equals flow rate (in m3/second) times back-pressure (in kPa) divided by pump efficiency (in %). The ‘PumpEnergy’ tab contains a simple and flexible calculator for pumping power (in kW).

Back-pressure on a pipeline, in turn, is the sum of static head (overcoming gravity), dynamic pressure (overcoming inertia) and head losses (calculated using the Darcy-Weisbach and Colebrook Equations from flow speed, Reynolds Numbers, pipeline diameter and pipeline surface roughness).

Energy costs of a pump are best minimized by using wider pipes with smoother internal surfaces (chart above). But these pipes will also have higher costs themselves. Hence a total systems approach is needed to find the lowest overall costs.

Electric submersible pumps in the oil and gas industry are also modelled in two further back-up tabs. A typical Electric Submersible Pump (ESP) will contribute $0.3/boe of cost and 5kg/boe of carbon, if powered by diesel, at a typical oilfield (chart below). And more at deeper wells with higher water cuts. Switching the ESP to run on renewable power, can readily reduce costs and CO2 intensity.

Electric Submersible Pump Optimisation Opportunities?

Please download the data-file to stress test the costs of electric pumps, as a function of lifetime (years), capex costs ($/kW), capital costs (%WACC), utilization rate (%), efficiency (%), flow rates (m3/hour) and other operating costs ($/kW/year).

Thermal energy storage: cost model?

This data-file captures the costs of thermal energy storage, buying renewable electricity, heating up a storage media, then releasing the heat for industrial, commercial or residential use. Our base case requires 13.5 c/kWh-th for a 10% IRR, however 5-10 c/kWh-th heat could be achieved with lower capex costs.


Thermal energy storage solutions aim to help integrate solar and wind into power grids, by absorbing excess generation that would otherwise be curtailed, and then re-releasing the heat later when renewables are not generating.

Different storage media are compared in one of the back-up tabs of the model. However, one-third of the companies in our thermal energy storage company screen are pursuing molten salt systems, hence our thermal energy storage model focuses on this option.

In our base case, the cost of thermal energy storage requires a storage spread of 13.5 c/kWh for a 10MW-scale molten salt system to achieve a 10% IRR, off of $350/kWh of capex costs. Costs are sensitive to capex, utilization rates, opex, electricity prices and round trip losses. The sensitivities can be stress tested in the data-file.

Capex costs of thermal energy storage may be reduced below our base case estimate, which has been built-up using the same input assumptions as our broader battery cost models. Larger systems require proportionately more storage material, larger tanks, and more insulation. But other lines in the capex build up do not change, and hence these costs deflate in MWH-terms.

The round-trip efficiency of thermal energy systems can also be higher than we might have naively expected, possibly in the range of 85-95%. The physics is modeled from first principles in other back-up tabs of the data-file. As a generalization, a large and well-insulated thermal energy storage system loses 1-2% of its stored heat over the course of 24-hours.

The full data-file contains the workings behind our recent deep-dive into thermal energy storage. We have also included similar estimates for residential-scale storage, adding an electrically heated hot water tank to absorb excess renewables, which looks simple and can be highly economical. Please download the data-file to stress test all of our numbers.

Hot potassium carbonate CCS: energy economics?

Potassium carbonate CCS

Hot potassium carbonate is a post-combustion CCS technology that bypasses the degradation issues of amines, and can help to decarbonize power, BECCS and cement plants. We think costs are around $100/ton and energy penalties are 30-50%. Potassium carbonate CCS can be stress-tested in this data-file, across 50 inputs.


Potassium carbonate (K2CO3) is a safe, abundant and low-cost salt that can absorb CO2, as soluble CO3(2-) ion reacts with H2O and CO2 to form 2 x HCO3(-) ions. The rich solution can then be steam-treated to re-release pure CO2, forming a CCS process.

Potassium carbonate has been used at over 600 hundred natural gas sweetening plants historically, removing small quantities of acid gases from pressurized gas streams (e.g., in the range of 20-bar) (aka the Benfield Process).

The great advantage of potassium carbonate CCS over the amine process is that there are no toxic breakdown products. This may be particularly helpful when the combustion source is burning waste, biomass/BECCS or cement plants.

The disadvantage of potassium carbonate CCS is that the reaction between CO2 and K2CO3 is slow. For more context see our overview of CCS absorber units. Thus realistic plant designs require higher temperatures (80-100ºC) and pressures (12-20 bar). This can create large energy penalties for potassium carbonate CCS, quantified herein.

What energy penalties for K2CO3 CCS? If there is only 4-12% CO2 in the exhaust gas of a boiler or burner, then compressing the entire exhaust stream towards the middle of this range can use up 65-90% of the useful energy released by combusting the fuel.

The best option to lower the energy penalties is to re-capture the energy of exhaust gas compression. This is achieved by re-expanding these compressed and CO2-depleted gases back across a turbine (which may directly drive the input compressors; for more background, please see our overview of thermodynamics and CCS energy penalties).

Potassium carbonate CCS
Energy penalties for CCS using hot potassium carbonate in percent kg per kWh and GJ per ton of CO2

Capsol Technologies (formerly known as Sargas) is listed in Norway and has filed patents for variations of this process running back to 2003 (tabulated in the data-file). It is currently developing what could be “Europe’s first large-scale negative emissions plant” capturing the CO2 from a bio-energy plant in Stockholm.

What energy economics for Capsol Technologies’ process? We have read some of Capsol’s patents, its claims of pressure recapture and steam-recirculation, and can simplistically model how this would impact costs and energy penalties (quantified in the data-file in $/ton, in % energy penalty terms, in kWh/ton or GJ/ton, and in kg/kWh CO2 intensities).

Others have looked to reduce the requisite pressurization energy for potassium carbonate CCS by blending K2CO3 with amines (often piperazine). But this seems to defeat the rationale for using potassium carbonate in the first place, which was to avoid emissions of amines or their toxic breakdown products.

Another interesting option could be exhaust gas recirculation, to boost CO2 concentrations and lower compression loads. In some configurations oxygen blending can further lower the volumes of gases that need to be compressed and cover the energy costs of oxygen generation in an air separation plant.

This data-file allows you to stress-test the energy penalties for potassium carbonate CCS in percentage terms, in kWh/ton, GJ/ton and to compute the resultant CO2 intensity of generated electricity in kg/kWh.

Redox flow batteries: costs and capex?

Redox flow battery costs are built up in this data-file, especially for Vanadium redox flow. In our base case, a 6-hour battery that charges and discharges daily needs a storage spread of 20c/kWh to earn a 10% IRR on $3,000/kW of up-front capex. Longer-duration redox flow batteries start to out-compete lithium ion batteries for grid-scale storage.


A redox flow battery charges and discharges when different electrolyte ions, with different redox potentials, on different sides of a proton exchange membrane simultaneously oxidize (surrendering an electron into one electrode) and reduce (gaining an electron from the other electrode). This absorbs or creates an electric current.

The purpose of this data-file is to build up the costs of redox flow batteries, starting from first principles, for Vanadium redox flow batteries.

Redox flow battery costs
Capex breakdown of Vanadium redox flow battery in $ per kW

A 6-hour redox flow battery costing $3,000/kW would need to earn a storage spread of 20c/kWh to earn a 10% return with daily charging and discharging over a 30-year period of backstopping renewables.

Past redox flow projects and studies that have crossed our screens average $4,000/kW and $750/kWh of up-front capex costs. However these costs are highly variable and depend upon the duration of the battery.

Redox flow battery costs
Capex of Vanadium redox flow battery in $ per kW based on past projects

One interesting facet of redox flow batteries is that they can be scaled up simply by enlarging their electrolyte storage tanks. Tank costs rise with capacity. But other costs remain fixed, such as membranes and electrodes. So per kWh costs fall as battery capacity rises (below).

Capex breakdown of Vanadium redox flow battery in $ per kWh

Thus a 12-hour redox flow battery that charges and discharges 250 days per year can achieve the same total storage spread as a 6-hour battery that charges and discharges around 360 days per year, both around 20c/kWh. This helps to integrate solar and wind into increasingly renewables-heavy power grids.

How do redox flow batteries compare to lithium ion batteries? Overall we think that for long-duration, grid-scale electricity storage, redox flow batteries are looking more economical than lithium ion, especially once storage durations surpass 6-8 hours. Our comparison file is here.

This data-file contains a bottom-up build up of the costs of a Vanadium redox flow battery. Costs, capex, Vanadium usage and tank sizes can all be stress-tested in this model. We have also published an outlook for redox flow batteries.

Gas dehydration: costs and economics?

Gas dehydration costs

Gas dehydration costs might run to $0.02/mcf, with an energy penalty of 0.03%, to remove around 90% of the water from a wellhead gas stream using a TEG absorption unit, and satisfy downstream requirements for 4-7lb/mmcf maximum water content. This data-file captures the economics of gas dehydration, to earn a 10% IRR off $25,000/mmcfd capex.


Wellhead gas might have up to 0.2% water entrained within it (100lb/mmcf). This should ideally be reduced by 90-95%, to below 7 lb/mmcf, sometimes below 4lb/mmcf.

The main reasons for reducing the water content of natural gas are to avoid issues in downstream equipment and pipelines, such as plugging or hydrate formation. For example, as an LNG plant cools the gas stream to -160C, any water is clearly going to freeze out.

Dehydration is also necessary for other gas streams. For example, some of the recent projects that have crossed our desk are aimed at dehydrating CO2 in CCS projects, so that it does not form carbonic acid and dissolve disposal pipelines. Hydrogen may also require dehydration, downstream of a reforming unit or some electrolysis plants.

Gas dehydration most commonly takes place by absorbing the water in tri-ethylene glycol (TEG). TEG acts as a solvent for water at ambient temperatures in an absorber unit. Then the water can be stripped from the TEG solution by heating to 200ºC in a reboiler unit. Many readers will note this is effectively the same plant configuration as for post-combustion CCS using amines.

The global TEG market is worth around $800M per year, implying c500kTpa of production at $1.5-2.0/kg. TEG is made via the step-wise oligomerization of ethylene oxide.

In our base case model, gas dehydration costs $0.02/mcf to earn a c10% IRR while covering the capex of the TEG unit, using up 0.03% of the energy in the gas itself (i.e., a 0.03% energy penalty) and adding 0.03 kg/mcf to the CO2 intensity of gas.

This data-file allows for stress-testing of TEG unit capex (chart below), maintenance, electricity use, heat consumption, CO2 prices, TEG make-up costs and other opex costs.

Gas dehydration costs
Capex costs of a TEG unit van vary widely but a good base case might be $25,000 per mmcfd of throughput

TEG dehydration units are under increasing scrutiny due to methane emissions, including from pneumatically powered components.

Alternatives to TEG dehydration units include solid sorbents and molecular sieves. For an overview, see our note into swing adsorption.

But we think the most interesting read across from our gas dehydration model is for CCS/DAC. Using this fully mature technology, for which over 200,000 units have been installed to-date, we think the costs “per ton of water removal” still equate to $450/ton and the capex costs equate to around $5,000/Tpa. Details in the data-file.

Fans and blowers: costs and energy consumption?

Fans and blowers

Fans and blowers comprise a $7bn pa market, moving low-pressure gases through industrial and commercial facilities. Typical costs might run at $0.025/ton of air flow to earn a return on $200/kW equipment costs and 0.3kWh/ton of energy consumption. 3,000 tons of air flow may be required per ton of CO2 in a direct air capture (DAC) plant.


Fans and blowers comprise a $7bn pa global market, moving large volumes of air for industrial and commercial purposes, at pressure closer to atmospheric pressure (up to 1.11x pressurization for a fan, up to 1.2x pressurization for a blower).

A good rule of thumb is that moving 1 ton of air through an industrial facility ‘costs’ 2.5 cents, using 0.3 kWh/ton of electricity and in order to re-coup a return on a $200/kW investment (as aggregated from equipment providers, chart below).

Fans and blowers
Capex costs of fans and blowers decline for larger and lower pressure units and a good average is $200 per kW

However, these numbers can all vary, rising considerably when there is more resistance in the system, and fans/blowers must work to overcome larger total pressure drops. The simple energy economics are that power consumption (in Watts, aka Joules per second) is a product of air flow (in m3/second) x the total pressure increase imparted to the air (in Pa, aka J/m3). In turn, the dynamic pressure rise is a square function of flow velocity.

Fans and blowers
Energy costs of fans and blowers in kWh per ton decay with wider flow volumes and rise linearly with static and dynamic pressure loads

The economic costs and energy costs of blowers and fans might sound small, but note that a direct air capture (DAC) plant will need to move something like 3,000 tons of air per ton of CO2 that is captured, which could cost $75/ton and 300-900kWh/ton of electricity just circulating air through the plant.

As a comparison, compressors typically step up gas pressures from 2-100x depending on the application, with costs around $850/kW in a $140bn pa global market today.

Underlying data into the capex, energy consumption and volumetric flow rates are tabulated in the tabs overleaf, simply aggregating public disclosures across companies supplying fans and blowers.

Gas fractionation: NGL economics?

Gas fractionation

Gas fractionation separates out methane from NGLs such as ethane, propane and butane. A full separation uses up almost 1% of the input gas energy and 4% of the NGL energy. The costs of gas fractionation require a gas processing spread of $0.7/mcf for a 10% IRR off $2/mcf input gas, or in turn, an average NGL sales price of $350/ton. Costs of gas fractionation vary and can be stress tested in this model.


Wellhead gas is mainly composed of methane, it also contains propane, butane, C5s and C6+ fractions, which are entrained in the gas. These condensates or natural gas liquids (NGLs) can be removed by first dehydrating the gas, then, cryogenically cooling it, to ‘drop out’ all of the NGL fractions in a demethanizer (chart below). (For more details, we have written an overview of cryogenics)

The NGLs may then be heat exchanged with steam or warm oils, to warm them back up, and fractionate out the components: with ethane evaporating first in the de-ethanizer (boiling point is -89 °C), next propane in the depropanizer (boiling point is -42ºC) and butane next in a debutanizer (-1ºC). There may be separate stages to separate n-butanes from i-butanes.

Gas fractionation
Input Gas is split into dry gas and NGLs in a demethanizer then the NGLs are fractionated to yield outputs such as C2, C3, C4

The process can vary. Some facilities only drop out mixed NGLs, which are then shipped onwards. Others will cool the gas to separate out C3+, but will leave the ethane entrained, due to limited ethane uses outside of ethane crackers. You can flex these options in the data-file. But our base case captures a full separation of all NGL fractions.

Energy costs of full natural gas fractionation will come to 113kWh/ton of input gas (using up 1% of its energy content) and 600kWh/ton of NGLs (using up 4% of its energy content).

Capex costs of full natural gas fractionation can be estimated with the simple rule of thumb of around $1M/mmcfd of demethanizer capacity plus $5M/kbpd of NGL fractionation capacity. This is based on past projects, tabulated in the data-file.

The costs of a natural gas fractionation plant require a fractionation spread of $0.7/mcf of input gas processed, in order to separate all the NGL fractions and earn a 10% IRR. In other words, if the input gas price is $2/mcf, then the fractionation plant needs to charge a blended average of $2.7/mcfe on sales gas and the various NGL products.

What NGL prices are needed for a 10% IRR? At $2/mcf, our model requires a blended price around $350/ton, across ethane, propane, butanes, and higher fractions. Recent pricing is below, based on data from the EIA. Each $1/mcf on the gas price requires a further c$80/ton onto the required average NGL price.

Gas fractionation
Product Pricing for NGL Components

NGL fractionation is increasingly important to provide feedstocks for advanced polymers used in new energies and energy efficiency technologies. But we also see a growing role for low-carbon natural gas in the energy transition. And fractionation is usually done before natural gas is liquefied into LNG.

Leading companies operating natural gas fractionation plants are constellated around the upstream and midstream industries, while companies such as Technip, Linde, Lummus and other industrial gas companies and oil service companies supply equipment and technology for NGL fractionation plants.

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