Industry Development

• Stage of development: early
• Existing facilities globally: 1
  (Canada, captures 365 metric tons/yr)
• Facilities in development globally: 1
  (Texas, will capture 1 million metric tons/yr, operational in 2024)

Energy Requirement

If energy were supplied entirely using solar power, it would take ~7,000 acres (reported range is 4,400-9,000 acres) to capture 1 million metric tons of CO₂. However, solar PV-provided energy cannot directly supply heat at the temperatures needed for regeneration. Thus, L-DAC requires a high-temperature clean energy heat-source, such as an industrial heat battery or green hydrogen (H₂) fuel. If H₂ fuel supplied the heat energy for L-DAC, 1,400 acres of solar fields could supply the electricity demand.

• L-DAC requires ~2.8 MWh of energy for every metric ton of CO₂ captured (estimates range from 1.8-3.7 MWh per metric ton CO₂)
• 80-100% of that energy is for heating. 0-20% is for electricity.

Footprint

• Each L-DAC contactor unit captures ~300-600 metric tons per year, and units are modular and stackable. Thus, footprints vary depending on how high units are stacked or how they are spread out.
• To capture 1 million metric tons of CO₂ per year, we estimate a facility would require about 200 acres of space. Reported estimates range from 50 to 1730 acres, depending on how contactor units are arranged.
• L-DAC units can be sited anywhere, as the only feedstock is ambient air.

Job Growth Potential

An L-DAC facility capturing 1 million metric tons CO₂ annually could produce about 75-270 permanent jobs in operation and maintenance, requiring skills that are transferable from other industrial repair and maintenance work industries.

Such a facility would also produce about 700-1,000 construction + installation jobs, as well as thousands of indirect jobs, such as those needed to construct solar fields to support the facility.

Location Equity

Noise levels = 50-70 decibels per contactor unit - that’s about as loud as a dishwasher or vacuum. A 1 million metric ton capture facility would need ~1,600 contactor units, spread over ~200 acres.

Impact will depend on how noise scales with additional contactor units (warrants further investigation) and the distance from urbanized areas.

Depending on site location, additional jobs could increase local traffic and employees could have long distance commutes.

Water Requirements

L-DAC requires significant amounts of water to dilute the solvent solution used to capture the CO₂, but that water + solvent solution is continuously recycled through the system, so water only needs to be replenished to compensate for evaporation. Average temperatures and humidity levels in Kern County would cause about 5 metric tons of water consumption per ton of captured CO₂ in the winter, and about 15 tons of water consumed per ton CO₂ in the summer. Very hot days with humidity levels below 20% could cause greater than 20 metric tons of water consumption per ton CO₂ captured.

Emissions, Byproducts & Waste

L-DAC facilities are expected to produce zero or near-zero emissions onsite that could be hazardous to the environment or human health.

Neither wastewater nor hazardous waste is generated in significant amounts in L-DAC facilities.

Regulatory Permitting: When sited in Kern County, California, all projects will be considered through a public process and environmental impacts will be reviewed and mitigated in accordance with the California Environmental Quality Act (CEQA).

Cost of Operation

To compare costs across carbon management industries, a ‘Lifetime Cost Assessment’ (LCA) model is used, which is the total cost per metric ton CO₂ resulting from the cost of building the facility (capital costs), the cost of maintenance and labor (operational costs) and the cost of energy (heat + electricity), over the lifetime of the plant. For an average L-DAC facility capturing 1 million tons CO₂ per year:

• Cost to build would be ~$470 million to $1.3 billion. If it ran for ~30 years, the capital costs over the lifetime of the facility would be ~$160-300 per ton of CO₂.
• Annual costs for operation staff and maintenance range from ~$60-110 per ton CO₂.
• Energy costs range from ~$45-257 per ton CO₂, with the variation reflecting different energy sources and uncertainty in energy requirements. These costs will also vary over time due to fluctuations in energy markets.

Potential Sources of Revenue

There are two potential sources of revenue for direct air capture:

1. Federal + State incentives:

   • Federal Incentive 45Q provides a tax benefit for CO₂ capture and storage using DAC of $180 per ton stored.
   • California's Low Carbon Fuel Standard (LCFS): credits technologies that reduce transportation-derived greenhouse gas emissions. (DAC qualifies because it removes CO₂ produced by gas-powered cars and trucks.) From 2018-2022, the LCFS credit has ranged from $62-218.
2. Private markets: Private businesses have purchased carbon storage at rates in the $600-1,000 per ton of CO₂ range for the most environmentally-secure types of storage.

Industry Development

• Stage of development: early
• Existing facilities globally: 17 pilot + commercial (captures 6,900 metric tons/yr, combined)
• Facilities in development globally: 1 (Iceland, will capture 36,000 metric tons/yr)

Energy Requirement

S-DAC requires ~1.5 MWh of energy for every metric ton of CO₂ captured (estimates range from 1.1-2.0 MWh per metric ton CO₂). 75-80% of that energy is for heating. 20-25% is for electricity.

If energy were supplied entirely using solar power, it would take ~3,600 acres (reported range is 2,675-4,900 acres) to capture 1 million metric tons of CO₂. Unlike L-DAC, where the heat requirements exceed what renewable resources like solar and wind can supply directly, S-DAC can be run entirely by renewable energy, even to meet the heat requirements to break the bonds between the sorbent and CO₂. However, to run an S-DAC facility continuously, battery storage of solar or wind energy would also be necessary.

Footprint

Each S-DAC contactor unit captures ~500 metric tons per year. These units are modular, stackable, and about the size of a shipping container. The footprint of the site will depend on how high the contactors are stacked or how far apart they are placed from one another. To capture 1 million metric tons of CO₂ with S-DAC contactors, we estimate a footprint of approximately 235 acres, but reported estimates range from 50 to 495 acres. These contactors can theoretically be placed anywhere, as the only required feedstock on-site is ambient air.

Job Growth Potential

An S-DAC facility capturing 1 million metric tons CO₂ annually could produce about 100-270 permanent jobs in operation and maintenance, requiring skills that are transferable from other industrial repair and maintenance work industries.

A new S-DAC facility would also generate approximately 700 construction and installation jobs in the region, as well as indirect jobs, like solar installation jobs to help support the facility’s energy needs.

Location Equity

Noise levels = 50-70 decibels per contactor unit - that’s about as loud as a dishwasher or vacuum. A 1 million metric ton capture facility would need ~2,000 contactor units, spread over ~235 acres.

Impact will depend on how noise scales with additional contactor units (warrants further investigation) and the distance from urbanized areas

Depending on where an S-DAC facility was placed, additional jobs could increase local traffic and employees could have long commutes.

Water Requirements

The solid sorbent material used to capture CO₂ in S-DAC facilities also binds with water vapor from the atmosphere. The more humid conditions are, the more water vapor condenses onto the sorbent material along with CO₂. When the contactor unit is closed and heated to release the CO₂ from the sorbent, the water will be heated back into vapor and removed along with the CO₂ in a gaseous stream. Then, the CO₂ and water can be separated from one another, and the water could be used by local communities or other facilities in the park.

Emissions, Byproducts & Waste

DAC facilities are expected to produce zero or near-zero emissions onsite that could be hazardous to the environment or human health.

There should be no significant amount of hazardous materials generated in S-DAC facilities.

Regulatory Permitting: When sited in Kern County, California, all projects will be considered through a public process and environmental impacts will be reviewed and mitigated in accordance with the California Environmental Quality Act (CEQA).

Cost of Operation

To compare costs across carbon management industries, a ‘Lifetime Cost Assessment’ (LCA) model is used. The LCA is the total cost per metric ton CO₂ resulting from the cost of building the facility (capital costs), the cost of maintenance and labor (operational costs), and the cost of energy (heat + electricity), over the lifetime of the plant. For an average S-DAC facility capturing 1 million tons CO₂ per year:

• Cost to build would be ~$630 million to $1.7 billion. If it ran for ~30 years, the capital costs over the lifetime of the facility would be ~$76-205 per ton of CO₂.
• Annual costs for operation staff and maintenance range from ~$11-29 per ton CO₂.
• Energy costs range from ~$0-278 per ton CO₂, with the variation reflecting different energy sources and uncertainty in energy requirements. These costs will also vary over time due to fluctuations in energy markets.

Potential Sources of Revenue

There are two potential sources of revenue for direct air capture:

1. Federal + State incentives:

   • Federal Incentive 45Q provides a tax benefit for CO₂ capture and storage using DAC of $180 per ton stored.
   • California's Low Carbon Fuel Standard (LCFS): credits technologies that reduce transportation-derived greenhouse gas emissions. (DAC qualifies because it removes CO₂ produced by gas-powered cars and trucks.) From 2018-2022, the LCFS credit has ranged from $62-218.
2. Private markets: Private businesses have purchased carbon storage at rates in the $600-1,000 per ton of CO₂ range for the most environmentally-secure types of storage.

Industry Development

• State of development for low- or no-carbon steel: early commercial
• Existing facilities globally: 1 (DRI with carbon capture, in United Arab Emirates)
• Low- or no-carbon steel facilities in development globally: 3 (Colorado, Massachusetts, Sweden)

Energy Requirement

The primary energy needs for a scrap-based steel mill come from the electric arc furnace (EAF), which requires about 0.4-0.9 MWh of energy per ton of steel produced. Casting, rolling and finishing the hot steel that is made in the EAF into usable products requires another ~0.01-0.6 MWh/ton steel. If DRI is made on site from pelletized iron ore feedstock, it would contribute an additional 3.0-4.5 MWh of energy needs, increasing the facility’s energy requirements by an order of magnitude. DRI requires temperatures of 900-1000°C to reduce the iron ore in the presence of a reduction agent like natural gas, syngas or hydrogen. Such high temperatures cannot be directly supplied by solar-derived electricity without also utilizing a heat battery (see our section on energy storage).

A 770,000 ton steel micro mill utilizing only scrap and solar energy would need about 690-2,900 acres of solar fields to supply the electricity demand. A 770,000 ton DRI micro mill using solar energy and only capturing CO₂ from process emissions of iron reduction would need 6,900-11,900 acres of solar fields (with heat battery storage) to operate. However, in this scenario, only 320,000 tons of CO₂ could be captured annually. A micro mill using oxy-fuel combustion with carbon capture as the sole power supply would require no solar input.

Footprint

A steel mill that utilized DRI and oxy-fuel combustion (the most emissions-intensive scenario) would need to produce about 770,000 tons of steel annually to emit 1 million tons of CO₂. The same size facility utilizing only scrap and solar energy, or scrap and oxy-fuel combustion, would emit near 0 tons CO₂ and ~115,000 tons CO₂, respectively. Based on the average facility footprint of six steel mini and micro mills built or in development in the United States within the last 5 years, a 770,000 ton steel micro mill would require about 510 acres of land.

Job Growth Potential

On average, it takes 0.5-1.5 man-hours to produce a ton of steel, depending on mill efficiency and automation. Given this range, a 770,000 ton steel mill could produce about 200-600 full-time equivalent jobs, a range consistent with estimates from recently built U.S. micro mills (which, scaled to 770,000 ton steel production capacity, would produce on average ~400 permanent jobs). Reported annual salaries for steel micro mill manufacturing jobs range from $60,000-$140,000 plus benefits, with higher salaries associated with technical positions. 400-600 thousand ton steel mini mills that are currently being developed in Arkansas and North Carolina report generating 500-600 construction jobs, which scaled to a 770,000 ton facility could provide up to 900 short term jobs in construction. Additionally, such a facility would produce thousands of indirect jobs to support facility needs, such as solar and battery installation jobs.

Location Equity

Steel mills do emit fine materials and gases that can have harmful health effects, like particulate matter, lead, nitrous oxides (NO₂), and sulfur oxides (SO_x), although there are techniques mills can use to trap matter and minimize emissions. Any mill developed within the carbon management park would be required to submit an environmental impact report and undergo pre-development review and operational monitoring to ensure emissions impacts remain within federal and state determined safety standards.

Steel mill operations are also loud - with most operational equipment emitting noise at levels that require hearing protection for workers. It is possible to design steel mills in ways that diffuse noise levels to minimize noise pollution in the vicinity. One steel mill in New Zealand integrated several noise-minimizing solutions into their facility, and measured noise levels about 0.75 miles from the facility of ~45 decibels, a typical sound level for an urban neighborhood.

Water Requirements

Steel mills require large volumes of water to operate, primarily for cooling, but secondarily for equipment descaling, dust scrubbing and other processes. About 90% of the water can be treated and reused or returned to the source, and water that is used for cooling never actually comes into contact with material or equipment. Seawater has been used for this purpose – it is possible that gray (reclaimed) water could be used similarly, minimizing the impact on local fresh water sources. If water is recirculated within the steel mill to minimize waste, it needs to be cooled and desalinated between uses. If a thermal network were integrated into a carbon management park, waste heat in the form of hot process water from the steel mill could potentially supply heat energy to other co-located industries. On average, steel mills that use electric arc furnaces require a water intake of 7,400 gallons of water per metric ton of steel produced, but discharge 7,000 gallons of water, for a net water requirement of about 400 gallons per metric ton of steel.

Emissions, Byproducts & Waste

In the electric arc furnace (the steel making phase of production), scrap metal is “charged”, or combined with DRI, pig iron (from integrated mills) and/or limestone, to add or remove impurities in the steel that control its properties (like strength and ductility). Elements that are separated out of the steel form a metal-oxide rich slag and small amounts of CO₂ (not enough to be economically captured) and other gas or fine particulate emissions. The slag is a waste byproduct that can typically be used in other industrial processes, and therefore poses little environmental risk.

Particulate emissions emitted from the EAF (and to a lesser degree from other steps in the steel making process) include particulate matter composed of iron and iron oxides, and depending on the composition of the source iron, could also include heavy metals such as zinc, chromium, nickel, lead and cadmium. Gaseous pollutants such as NO_x, CO and SO₂ can also be emitted. These emissions can be captured and scrubbed from facility exhaust streams, to keep facility emissions under regulated limits. However, regular maintenance and monitoring of facilities is critical to prevent fugitive emissions.

Regulatory Permitting: When sited in Kern County, California, all projects will be considered through a public process and environmental impacts will be reviewed and mitigated in accordance with the California Environmental Quality Act (CEQA).

Cost of Operation

To compare costs across carbon management industries, a ‘Lifetime Cost Assessment’ (LCA) model is used. The LCA is the total cost per metric ton CO₂ resulting from the cost of building the facility (capital costs), the cost of maintenance and labor (operational costs), and the cost of energy (heat + electricity), over the lifetime of the plant. However, for a micro steel mill, the cost of carbon capture is a comparatively small addition to the cost of building the mill. For simplicity, we assess the costs of creating the mill and of capturing carbon from the mill separately. A micro steel mill that uses scrap and clean energy (0 tons CO₂ emissions per ton steel) would cost about $398-848 per ton steel produced. A scrap mill that used oxy-fuel combustion for energy would cost ~$407-903 per ton steel produced, with the added cost of CO₂ capture being ~$68-112 per ton CO₂. A mill that used direct reduced iron (DRI) with point source carbon capture and oxy-fuel combustion would cost ~$564-946 per ton steel produced, and the cost of CO₂ capture would be $38-112 per ton CO₂.

For a 770,000 ton steel micro mill that could capture up to 1 million tons CO₂ per year:

• Cost to build would be ~$460 million to $1090 million. Over the lifetime of the steel mill, the capital costs would be ~$88-125 per ton of steel produced.
• Fixed operational costs (including labor, maintenance, and other fixed expenses) would range from ~$77-116 per ton of steel produced. Raw material costs depend on whether iron is sourced primarily from scrap ($192-557 per ton scrap) or iron pellets for producing DRI ($81-154 per ton iron).
• Energy costs also depend on the material used. Solar energy costs for a scrap-EAF mill are $41-50/ton steel, natural gas costs for a scrap-EAF mill are $40-88/ton steel, and natural gas costs for a DRI-EAF mill are $211-461/ton steel.
• The addition of carbon capture via oxy-fuel combustion on a scrap-EAF mill powered by natural gas (or syngas or RNG) would be $10-17/ton steel. The addition of both oxy-fuel carbon capture and point source carbon capture on a DRI-EAF facility would cost $75-118/ton steel.

Potential Sources of Revenue

There are 3 potential sources of revenue for steel production:

• Selling steel: The current price of steel in the U.S. is $1249-1719 per ton, depending on the type of finished steel product, although this price has increased significantly since 2020 due to global inflation and supply chain issues related to the Covid-19 pandemic.
• Federal + State incentives: Federal Incentive 45Q provides a tax benefit for CO₂ capture and storage processes other than direct air capture (DAC) of $85 per ton stored. Another possibility, explored in more depth in the downloadable report, is replacing natural gas with hydrogen as the mill fuel and iron reducing agent. A federal tax credit for near-zero emissions hydrogen production could make green hydrogen-steel technology cost competitive with other approaches, although this technique is still in early stages of development. Finally, both the federal and California governments have enacted ‘Buy Clean’ incentives, requiring federal and state building contracts to buy low-carbon building materials, thus increasing the competitiveness of these more expensive steel products.
• Private markets: Private businesses have purchased carbon storage at rates in the $600-1,000 per ton of CO₂ range for the most environmentally-secure types of storage.

Of the two types of carbon credit incentives, facilities must choose between the federal + state incentives and private markets - the same ton of carbon captured is not eligible for both revenue streams.

Industry Development

• Stage of development: early commercial
• Existing facilities globally: 16
• Facilities in development globally: 50

Energy Requirement

The energy needed to power a BiCRS/BECCS facility capturing 1 million metric tons of CO₂ annually is typically less than the total energy output, meaning that as facilities generate energy in the form of electricity or synthetic fuels for consumers, they can use part of the energy they generate to power their own operations.

BiCRS/BECCS is capable of generating about 0.83 MWh of energy for every metric ton of CO₂ captured. Estimates are approximate, as many bioenergy projects only report their energy output, not the total energy generated or the amount used to sustain their pyrolysis or gasification reactions.

Due to the high temperatures needed for pyrolysis or gasification, facilities generally require an energy source for heat. For BiCRS/BECCS, this energy is typically supplied by the biomass itself, which contains energy, or by the fuels (syngas, hydrogen, or other products) that are produced on-site by breaking down biomass. Depending on the model, some pyrolyzers need external fuel to start the process, which can be supplied from renewable sources like green hydrogen or renewable natural gas (RNG).

Footprint

A BiCRS/BECCS facility footprint is often relatively contained, with 1-3 large buildings (three or more stories in height, to accommodate the reactor equipment), space to store biomass before processing (this can be indoors, outdoors, or a mix), and space to hold any byproducts that need to be disposed of or sold. The tallest feature is typically a chimney stack or gas flare - these can be as much as 100 feet tall. On-site footprint estimates for BiCRS/BECCS facilities have been declining over the past decade, and pyrolysis and gasification facilities are notably smaller than bioenergy plants.

The primary land use requirements for a BiCRS/BECCS facility are dominated by the land required to generate biomass. Since most facilities are hoping to use waste biomass, leftover from agricultural or forestry operations, this should not contribute to the on-site land footprint.

Job Growth Potential

A BiCRS/BECCS facility capturing 1 million metric tons CO₂ annually could produce about 45-150 permanent jobs in operation and maintenance, primarily requiring skills that are transferable from other industrial repair and maintenance work industries. Estimates may vary depending on the specific processes at a facility.

A new BiCRS/BECCS facility would also generate anywhere from 1,000 to 4,000 construction and installation jobs in the region, as well as indirect jobs, like solar installation jobs to help support the facility’s energy needs.

Location Equity

Noise levels of BiCRS/BECCS processing facilities are relatively low, because the equipment used for pyrolyzers and gasifiers are housed inside buildings that can reduce noise distribution. Outdoor equipment that may cause noise includes moving conveyor belts and fans, which are not louder than typical farm equipment. Careful site planning can further reduce noise distribution from the equipment.

A BiCRS/BECCS facility requires significant daily feedstock additions - if biomass is not supplied by rail, it would increase local traffic. CO₂ output to biomass feedstock ratios are about 0.9-1.5, meaning that a facility capturing 1 million tons of CO₂ annually would need about 1,800-3,000 tons of feedstock delivered daily. That’s about 90-150 tractor-trailer truckloads each day. Additionally, depending on where the facility is sited, employees could have long commutes.

Water Requirements

Due to the range of biomass types, temperature, pressure, and other factors impacting how biomass breaks down in a BiCRS/BECCS facility, water use can vary dramatically. For processes that are upgrading gaseous products into synthetic fuels or hydrogen fuel, water use typically rises to help purify the gas stream and generate desirable alternative fuels. For some other processes, facilities have found they can actually produce excess water that can be used directly for irrigation or other purposes. An example is oxy-fuel combustion - a process that combusts syngas derived from pyrolysis (or other forms of methane) in a controlled environment in the presence of oxygen, such that the byproducts are only a pure stream of CO₂ and water, as well as some electricity. Such a facility could be developed in tandem with a BiCRS/BECCS facility for the sole purpose of CO₂ capture from biomass, or could be used to generate heat or electricity for co-located industries like steel or L-DAC.

Emissions, Byproducts & Waste

BiCRS/BECCS facilities are expected to produce few emissions onsite that could be hazardous to the environment or human health. BiCRS/BECCS facilities do emit particulate matter, as well as NO_x, carbon monoxide (CO), and volatile organic compounds (VOCs). However, these emissions can be up to 95-99% lower than they would be if the biomass was burned instead, as is typical for clearing forestry and agricultural waste. Additionally, pyrolysis and gasification emissions are much lower than that used in bioenergy or waste-to-energy plants, where biomass is also combusted. Regardless, monitoring these emissions to mitigate pollution for local residents is very important.

There should be no significant amount of hazardous material generated in BiCRS/BECCS facilities, but any byproducts do need to be properly disposed of. Solid wastes, like spent organic material or catalysts, will need to be landfilled. Some other products can be sold: ash as a fertilizer, and biochar as a soil amendment, compost additive, or chemical catalyst.

Regulatory Permitting: When sited in Kern County, California, all projects will be considered through a public process and environmental impacts will be reviewed and mitigated in accordance with the California Environmental Quality Act (CEQA).

Cost of Operation

To compare costs across carbon management industries, a ‘Lifetime Cost Assessment’ (LCA) model is used. The LCA is the total cost per metric ton CO₂ resulting from the cost of building the facility (capital costs), the cost of maintenance and labor (operational costs), and the cost of energy (heat + electricity), over the lifetime of the plant. For an average BiCRS/BECCS facility capturing 1 million tons CO₂ per year:

• Cost to build would be ~$350 million to $1.2 billion. If it ran for 30 years, the capital costs over the lifetime of the facility would be ~$30-189 per ton of CO₂.
• Annual costs for operation are dominated by the cost of biomass feedstock - which ranges from $20-60. Fixed operation costs (primarily for staff and routine maintenance) are typically 2-6% of capital costs, or $1-11. Variable operation costs, which include non-biomass feedstocks, waste disposal, and unplanned maintenance, range from $10-27 per ton CO₂.
• Energy costs are negligible.

Potential Sources of Revenue

There are 4 potential sources of revenue for BiCRS/BECCS:

• Selling energy: BECCS projects aim to maximize the energy output of biomass conversion, and sell a variety of products including electricity, ethanol and synthetic fuels that could be a low-carbon replacement for sectors that are hard to electrify, like shipping and aviation. A notable BiCRS product is hydrogen gas (H₂), which, in addition to CO₂, is generated through gasification. This can be sold for profit as a fuel or chemical feedstock, and is explored more in the Hydrogen Production - Biomass section.
• Selling byproducts: Biomass pyrolysis (and sometimes gasification) generates solid biochar, which can be sold as a soil amendment, compost additive, or chemical catalyst.
• Federal and state incentives: Federal Incentive 45Q provides a tax benefit for CO₂ capture and storage of $85 per ton permanently stored for capture processes other than direct air capture (DAC). California's Low Carbon Fuel Standard (LCFS) credits technologies that reduce transportation-derived greenhouse gas emissions, and can provide credits for makers of low-carbon alternative fuels or facilities supplying low-carbon electricity for transportation users. From 2018-2022, the LCFS credit has ranged from $62-218.
• Private markets: Private businesses have purchased carbon storage at rates in the $600-1,000 per ton of CO₂ range for the most environmentally-secure types of storage.

Of these two types of carbon credit incentives, facilities must choose between the federal + state incentives and private markets - the same ton of carbon captured is not eligible for both revenue streams.

Industry Development

• Stage of development: early
• Existing facilities globally: 0
• Facilities in development globally: 4

Energy Requirement

A biomass gasification facility producing 1 million tons of CO₂ for capture can produce about 70,000 tons of hydrogen if it is powered entirely through an external source of energy. For a facility to be self-sufficient (effectively needing no external energy input), about 30% of the syngas produced in the gasification step of hydrogen production is needed. In this case, for every million tons of CO₂ produced, only about 50,000 tons of hydrogen is produced. Whether and to what degree produced syngas or external energy sources are used depends on the relative cost of available energy sources, and the marketplace value of green hydrogen.

Most of the energy needs for biomass hydrogen production are used to attain the necessary heat and pressure to gasify the organic feedstock. The exact amount of required heat energy is difficult to ascertain, as the process is still relatively new. Additionally, as most facilities meet this energy need with their own supply of syngas, it is often unreported. Regardless of the scale of heat energy requirements, if solar-sourced energy were used, it would need to be paired with heat batteries, which likely would make it uneconomical compared to utilizing a portion of the syngas. As for the electricity demands, most facilities either pursue a grid connection as back-up or set up their own solar panels to meet any electrical demand. For a facility capturing 1 million metric tons of CO₂, the estimated solar capacity would be 135 MW, occupying ~945 acres.

Footprint

A biomass gasification facility is typically quite small, and can be contained in only a few buildings, with an on-site gas flare and evaporation ponds to handle any waste. Footprint estimates for biomass-based facilities have been declining over the past decade. The primary land use needs are dominated by the land required to generate biomass and renewable energy to support hydrogen production. Since many facilities intend to use waste biomass, left over from agriculture or forestry operations, this should not contribute to the on-site land footprint and are not included in this estimate.

Job Growth Potential

A biomass hydrogen production facility capturing 1 million metric tons CO₂ annually could produce about 45-150 permanent jobs in operation and maintenance, requiring skills that are transferable from other industrial repair and maintenance work industries.

Like other BiCRS/BECCS technologies, a new biomass hydrogen production facility would also generate approximately 1,000 to 4,000 construction and installation jobs in the region, as well as indirect jobs, like solar and battery installation jobs to help support the facility’s energy needs.

Location Equity

Much like other BiCRS facilities, noise levels for biomass hydrogen production are relatively low. The primary noise components are the conveyor belts and fans within the gasifier. The gasifier is housed within a building, dampening noise, such that outside the building ambient noise is not impacted. Designing to mitigate sound exposure to workers with absorbent materials, and requiring workers to wear ear protection on-site, can further reduce noise impacts. Any noise impact for local communities will depend on the distance from urban areas, as sound diffuses quickly with distance.

Depending on where a biomass hydrogen facility is placed, local traffic could increase due to the need to provide feedstock and new jobs, and those employees could have long commutes. Like other BiCRS facilities, biomass hydrogen production requires a significant amount of feedstock delivered daily. For a facility capturing 1 million tons of CO₂ annually, about 1,800 tons of feedstock (~90 tractor-trailer truckloads) need to be delivered each day. The added traffic burden could be diminished if feedstocks were delivered by rail.

Water Requirements

Although researchers are working to reduce the water requirements needed for hydrogen production via biomass gasification, currently, water is used to perform the water-gas shift reaction to generate hydrogen and CO₂ from the CO produced during the gasification step, and to purify the gaseous products. Some forms of gasification also rely on steam or supercritical water, which can increase the overall water demand. The most conservative facilities use about equal quantities of biomass and water in their process. Ongoing research efforts are aimed at using wastewater or other reclaimed water in the gasification process, to minimize the impact on freshwater resources. If used to purify gas, water is typically stored in evaporation ponds on site, and could be treated for reuse with appropriate equipment.

Emissions, Byproducts & Waste

Biomass hydrogen production facilities rely on gasification, and thus generate a small amount of various atmospheric pollutants, including particulate matter, NO_x, carbon monoxide (CO), and volatile organic compounds (VOCs). The concentration of these pollutants in process emissions are as much as 95-99% lower than what is emitted through biomass combustion, which occurs during crop burning or in traditional bioenergy power plants.

There should be no significant amount of hazardous materials generated in biomass hydrogen production facilities. Evaporation ponds handle wastewater discharge, most byproducts (like ash) can be sold; less-frequently replaced items, like spent catalyst, can be landfilled or recycled by the manufacturer, depending on the material.

Regulatory Permitting: When sited in Kern County, California, all projects will be considered through a public process and environmental impacts will be reviewed and mitigated in accordance with the California Environmental Quality Act (CEQA).

Cost of Operation

To compare costs across carbon management industries, a ‘Lifetime Cost Assessment’ (LCA) model is used. The LCA is the total cost per metric ton CO₂ resulting from the cost of building the facility (capital costs), the cost of maintenance and labor (operational costs), and the cost of energy (heat + electricity), over the lifetime of the plant. A biomass hydrogen production facility producing 1 million tons of CO₂ would have a levelized cost of about $2.50-$3.60 per kilogram of hydrogen produced, which translates to an estimated range of $125-257 per metric ton of CO₂ captured. With increased plant capacity, the costs of CO₂ capture could decline by as much as 50%, but the capacity potential for a hydrogen biomass facility is constrained by the regionally available biomass feedstock.

For an average biomass hydrogen production facility capturing 1 million tons CO₂ per year:

• Cost to build would be ~$278 million to $328 million. If it ran for 30 years, the capital costs over the lifetime of the facility would be ~$24-52 per ton of CO₂.
• Operational costs would range from ~$60 million to $101 million. The feedstock is the largest amount of this cost, accounting for an estimated $44 million annually. The next big cost categories come from chemical, material, and utility costs, while labor, maintenance, and waste treatment make up a small amount of the operating expenses.
• Energy costs are variable. Self-sustaining plants—which can meet their own energy needs—are the most expensive to build, but have the lowest operational costs. Plants that receive some or all of their energy from external sources are typically cheaper to construct, but more expensive to operate and maintain.

Potential Sources of Revenue

There are 4 potential sources of revenue for biomass hydrogen production:

• Selling hydrogen: Biomass gasification generates hydrogen gas (H₂), in addition to CO₂. This hydrogen can be sold as a fuel or chemical feedstock. Currently, hydrogen generated from biomass gasification is not competitive with carbon-emitting forms of hydrogen production, like gray or blue hydrogen, which cost $1-2 per kg (see report for full details). However, the sale of byproducts and added financial incentives for capturing carbon can help make biomass gasification a viable low-carbon route for hydrogen production.
• Selling byproducts: Biomass gasification also generates byproducts including ash, which can be collected from the gasifier and sold as a fertilizer.
• Federal + State incentives: Federal Incentive 45Q provides a tax benefit for CO₂ capture and storage processes other than direct air capture (DAC) of $85 per ton stored. A hydrogen-specific federal incentive established by the Inflation Reduction Act in 2022, Section 45V, is expected to give a tax credit of $3/kg hydrogen for a near-zero emissions hydrogen production process, but the Treasury Department is still setting the rules for eligibility. Producers can choose between the 45Q and 45V tax credits, but cannot receive both. California's Low Carbon Fuel Standard (LCFS): credits technologies that reduce transportation-derived greenhouse gas emissions. Hydrogen is an eligible alternative fuel if sold for transportation use in California. From 2018-2022, the LCFS credit has ranged from $62-218.
• Private markets: Private businesses have purchased carbon storage at rates in the $600-1,000 per ton of CO₂ range for the most environmentally-secure types of storage.

Of these two types of carbon credit incentives, facilities must choose between the federal + state incentives and private markets - the same ton of carbon captured is not eligible for both revenue streams.