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DOE OSTI2026

Technology Impact and Resource Assessment of Existing and Planned U.S. Biofuel Production: Life Cycle Water Consumption, Water Stress, Land Use, and Criteria Air Pollutants

Biofuels have the potential to strengthen the U.S. energy supply, enhance energy security, and promote economic development. As the United States continues to expand biofuel production, quantifying resource requirements and location-specific constraints is crucial for planning, siting, and technology development to support long-term viability. Accordingly, this work assesses the life cycle resource consumption (water consumption, and land use), water stress and criteria air pollutants associated with expanded U.S. biofuel production over the 2020–2035 period, based on producers’ plans. We perform a bottom-up technology impact assessment and resource assessment by integrating facility-level production statistics with Argonne’s Research and Development (R&D) GREET model and county-level water-stress characterization factors from Available Water Remaining for the United States (AWARE-US) model. Results suggest that by 2035, biofuels could meaningfully contribute to U.S. energy demand, driven primarily by first-generation and waste-based feedstocks with plans for substantial capacity expansion, although cellulosic and e-fuel technologies remain limited. However, growth must be managed to minimize impacts on water resources and land use. These impacts vary by fuel type and facility location, specifically, projected expansion increases water consumption and can elevate water-stress impacts in certain regions like Nebraska, Kansas, Colorado, Idaho, California and North Texas. Direct land use also increases overall, particularly for first-generation feedstocks such as corn and soybeans. These findings underscore the need for continued technological improvements and innovative strategies to manage resource demands as the industry scales and to support complementary deployment within the evolving U.S. energy system.

09 BIOMASS FUELS↗
DOE OSTI2025

Systems Analysis of Biomass and Coal Co-firing Power Plants with Deep Carbon Capture Toward Net-zero Emissions

Achieving a net-zero emission economy in the United States requires integrating diverse low-carbon and negative-emission technologies into the existing fossil fuel-dominant power fleet. Potential technologies from the low-carbon portfolio include renewable power, fossil power with carbon capture and storage (CCS), bioenergy with CCS (BECCS), and direct air capture (DAC). Renewable power is a clean energy source but has to pair with costly battery storage to provide dispatchable electricity. Fossil power with CCS offers dispatchable electricity yet still relies on DAC to offset residual emissions, even when deploying deep CCS with more than 90% CO2 capture. Coal-biomass co-firing with CCS, a subset of BECCS, is a reliable energy production technology that can be retrofitted from existing electricity generation units (EGUs). Power plant retrofit maximizes the use of the current U.S. coal power fleet without the need for large-scale deployment of new renewable power, battery storage, or DAC. Retrofitting coal-biomass co-firing with deep CCS in EGUs is a promising option, but not a universal solution. Biomass co-firing at a power plant introduces economic challenges and indirectly poses pressure on land and water resources. Meanwhile, retrofitting deep CCS affects plant efficiency and raises electricity generation costs. Overall, the technical feasibility and economic viability of plant retrofits vary across EGUs, as they are contingent upon the regional availability of biomass, unit-specific characteristics, site-specific fuel supply costs, and adjacent CO2 storage potential. Government incentives like 45Q can improve the retrofit viability, though the impact requires further quantification. A comprehensive analysis at the unit level is essential to address the question regarding the fate of the U.S. coal-fired electricity generation fleet toward the net-zero emission goal. This study conducts a systematic techno-economic-environmental assessment of EGUs to identify the viability of biomass co-firing and deep CCS retrofits in the U.S. coal-fired power fleet. Specifically, it characterizes the techno-economic performance of deep carbon capture, estimates life cycle greenhouse gas (GHG) emissions, and conducts a fleet-level assessment on retrofit viability. The key objectives are (1) to estimate the unit-specific performance and retrofitted cost under various biomass co-firing levels and CO2 capture rates; (2) to determine the possibility of reaching net-zero emission at the fleet level; (3) to quantify the cumulative capacities that are suitable for plant retrofits under current and future biomass supply scenarios; and (4) to improve the understanding of policy impacts on such retrofits to help the power sector’s transition to a net-zero economy. Techno-economic Model of Deep Carbon Capture. This study develops the performance and economic models for Monoethanolamine-based post-combustion CO2 capture at 95–99% capture rates. The process is simulated in Aspen Plus, analyzing the performance of carbon capture technology by varying the plant sizes, solvent lean loading, CO2 concentrations, and flue gas inlet temperature. Based on the key inputs and output parameters of CO2 capture, a reduced-order performance model of deep carbon capture is formulated. In addition, an engineering-economic model integrating the performance metrics is developed to estimate the capital as well as operation and maintenance (O&M) costs. Capital cost estimations follow the framework of the Integrated Environmental Control Model (IECM) and incorporate data regressions from three technical reports by IECM, the National Energy Technology Laboratory (NETL), and the National Renewable Energy Laboratory. The O&M cost estimation utilizes the actual inventory consumption rate and labor requirements. Both performance and cost models are embedded into IECM v13.0-beta, a fossil-fuel power plant modeling tool. Life Cycle Assessment of Power Plants. This study estimates the GHG emissions of power plants through life cycle assessment (LCA). The LCA scope includes fuel supply, combustion-based power generation, and CO2 transport and storage. The fuel-based life cycle module is designed following the framework of the NETL Unit Process Library and CO2U LCA Guidance Toolkit. The module is then incorporated into IECM v13.0-beta. The process-based LCA is applied to estimate the GHG emissions of coal and biomass supply, coal- and coal-biomass co-firing power plant operation, as well as CO2 pipeline transport and geographical sequestration. An uncertainty analysis is conducted to quantify the variability and uncertainty associated with the LCA using the Latin Hypercube Sampling (LHS) method. Fleet-level Assessment. This study evaluates the technical and economic feasibility of selected coal-fired EGUs, examines the role of tax credits in retrofit viability, and assesses the competitiveness of retrofitted units against other low-carbon options. Unit screening identifies EGUs for the study, focusing on new, efficient baseload units with air pollution controls. The power plant databases are then established to organize unit-specific information on performance and operating conditions from the relevant public databases. Biomass for co-firing retrofits is selected based on home and neighboring county availability, ensuring sustained operation with at least a 5% co-firing level. The CO2 storage site is determined by state-level storage potential, with ArcGIS Pro and NETL CO2 Saline Storage Cost Model used to identify the optimal balance between the nearest transport distances and affordable storage costs. The latest IECM v13.0-beta is then employed to configure and evaluate the eligible EGUs with or without the deployment of deep CCS and biomass co-firing. A supply curve is established to illustrate the cumulative installed capacity suitable for retrofits at different cost levels. A sensitivity analysis on tax credits for carbon sequestration is performed. Finally, a unit-level cost comparison is conducted among retrofitted plants, renewable power with battery storage, and abated fossil fuels with DAC. Expected Results. This study evaluates the technical, economic, and environmental metrics of each EGU across an array of CO2 capture rates and biomass co-firing level scenarios. Unit-level comparisons will identify critical factors influencing technical performance. The supply curves with and without tax incentives will provide insights into the impact of tax credits on biomass co-firing and CCS deployment. The cost comparisons with renewables and DAC-retrofit will assess the competitiveness of the retrofitted units. Life cycle emissions from each unit will be assessed to identify the scenarios under which net-zero emissions can be achieved. These analyses are expected to determine the total coal-fired capacity suitable for serving as a low-carbon energy source with or without tax incentives. The study results are novel in identifying optimal unit-specific strategies for producing carbon-neutral power, whether through retrofitting EGUs with deep CCS, biomass co-firing, DAC, or installing renewable power with battery. The findings will provide insight into nationwide efforts to ensure reliable, affordable, and low-carbon electricity. It also will inform investment decisions and policies in the deployment of deep carbon capture and negative emission technologies for a net-zero energy future.

Biomass Co-firing↗
DOE OSTI2026

Admissible Powertrain Alternatives for Heavy-Duty Fleets: A Case Study on Resiliency and Efficiency

Heavy-duty vehicles dominate global freight movement and primarily rely on fossil-derived diesel fuel. However, fluctuations in crude oil prices and evolving emissions regulations have prompted interest in alternative powertrains to enhance fleet energy resiliency. This study paired real-world operational data from a large commercial fleet with high-fidelity vehicle models to evaluate the potential for replacing diesel internal combustion engine (ICE) trucks with alternative powertrain architectures. The baseline vehicle for this analysis is a diesel-powered ICE truck. Alternatives include ICE trucks fueled by bio- and renewable diesel, compressed natural gas (CNG) or hydrogen (H 2 ), as well as plug-in hybrid (PHEV), fuel cell electric (FCEV), and battery electric vehicles (BEV). While most alternative powertrains resulted in some payload capacity loss, the overall fleetwide impact was negligible due to underutilized payload capacity for the specific fleet considered in this study. For sleeper cab trucks, CNG-powered trucks achieved the highest replacement potential, covering 85% of the fleet. In contrast, H 2 and BEV architectures could replace fewer than 10% and 1% of trucks, respectively. Day cab trucks, with shorter daily routes, showed higher replacement potential: 98% for CNG, 78% for H 2 , and 34% for BEVs. However, achieving full fleet replacement would still require significant operational changes such as route reassignment and enroute refueling, along with considerable improvements to onboard energy storage capacity. Additionally, the higher total cost of ownership (TCO) for alternative powertrains remains a key challenge. This study also evaluated lifecycle impacts across various fuel sources, both fossil and bio-derived. Bio-derived synthetic diesel fuels emerged as a practical option for diesel displacement without disrupting operations. Conversely, H 2 and electrified powertrains provide limited lifecycle impacts under the current energy scenario. This analysis highlights the complexity of replacing diesel ICE trucks with admissible alternatives while balancing fleet resiliency, operational demands, and emissions goals. These results reflect a US-based fleet’s duty cycles, payloads, GVWR allowances, and an assumption of depot-only refueling/recharging. Applicability to other fleets and regions may differ based on differing routing practices or technical features such as battery swapping.

BEV↗
DOE OSTI2021

The Influence of Pressure on Flame-Flow Characteristics of a Reacting Jet in Crossflow

This work experimentally investigates the effects of elevated combustor pressures on the characteristics of a lean premixed reacting methane/air jet injected into a lean vitiated crossflow using a 12.7 mm axial jet. Experiments were conducted in an axially staged combustor, which implements a reacting jet in crossflow (RJIC) configuration and operates over a pressure range of 1–5 atmospheres. Simultaneous CH* chemiluminescence and particle image velocimetry (PIV) are used to study the flow field and flame behavior. The results show that the reacting jet trajectory exhibits greater penetration with elevated pressure, which is a novel finding compared to available data in the literature. However, the flame liftoff point and ignition delay time both decreased with elevated pressure, which was attributed to decreased vorticity along the flame boundary which corresponds to increased Damköhler numbers (Da). Emissions measurements confirm the NOx increase with pressure as reported in the literature for single-stage gas turbine combustors. Concurrently, emission measurements for the staged configuration show the strong NOx benefit of the RJIC system: the data prove a reduction of global outlet emission levels at elevated pressure with the axially staged configuration. Here, the axial emission reduction was attributed to the decreasing liftoff at elevated pressure levels. Hence, the research emphasizes that the flame and emission characteristics are coupled; they are not only dependent on the geometric parameters and momentum flux ratios but are also a function of pressure.

03 NATURAL GAS↗
DOE OSTI2021

The Effect of Pressure on NO x Entitlement and Reaction Timescales in a Premixed Axial Jet-In-Crossflow

This paper investigates the pressure dependency of a lean premixed jet injected into a lean vitiated crossflow with an experimentally verified detailed chemistry computational fluid dynamics (CFD) model and 53 species considered. Experimental data were taken in an axially staged combustor with an optically accessible test section, allowing the use of particle image velocimetry (PIV) and CH* chemiluminescence techniques as well as point measurement of species concentration, temperature, and pressure. The experimental data cases at one, three, and five atmospheres were selected to describe the flame stabilization dependency on pressure and gain the required knowledge for an extrapolation to engine condition. Simulated exit nitrogen oxide levels were validated with experimental emission data, and a global emission trend for the NO reduction at elevated pressure and constant turbine inlet temperature level was defined. The nitrogen oxide benefit at elevated operating pressure was justified with the significantly smaller flame surface area: the analysis of the simulated spanwise and top-view profiles showed a relatively short receded core flame with nitrogen oxide production in the center at high pressure relative to a longer and larger shear layer flame at atmospheric condition that produced NO toward the inner and outer side of the flame. Furthermore, decomposition of the Damköhler number revealed the strong influence of the reaction timescales with higher reaction rates at elevated pressure, along with a moderate influence of the turbulent timescales, showing higher turbulence intensity in the lee-side recirculation zone at lower pressure.

03 NATURAL GAS↗
DOE OSTI2024

Sustainable Aviation Fuels from 30,000 feet – Scoping Report

A literature review, first principles analysis, and mapping of the airline-fuel infrastructure were performed to reassess the potential for various means of realizing a sustainable aviation sector. The literature review found a plethora of technical methods to make the airline industry net-zero CO 2 but limited work on the emergent barriers to sustainable aviation implementation such as land use, repurposing of fuel refining assets, and airline cost structures. First principles analyses of the energy, land, and costs of three broad net-zero strategies were performed to determine if sustainable aviation is feasible even in the most optimistic scenarios. Those methods were biomass-derived sustainable aviation fuel (SAF), fuel produced from CO 2 captured from the air and H 2 produced from water electrolysis (air-to-fuel: ATF), and offsetting fossil-derived Jet Fuel with carbon dioxide removal from the atmosphere (direct air capture and storage: DACS). Offsetting CO 2 emissions from using fossil Jet Fuel with DACS was found to consume the least energy, require the smallest quantity of land, and be the cheapest option. Replacing Jet Fuel with SAF was found to be only slightly more expensive than DACS but require substantially more land. ATF was found to be the most expensive and energy intensive option, though it did spare land relative to SAF. We found that calls to utilize waste biomass are well-founded, but wastes alone cannot cover the needs of the global airline industry. This means additional land will need to be allocated for biomass cultivation if SAF becomes the primary pathway to sustainable aviation. While differences were found in the performance of different types of biomass, those differences were small relative to differences with ATF and DACS. An analysis of the pricing structure of the airline industry suggests that some of the cost advantage of DACS may be erased by consumer sentiment which could explain why, to-date, the airline industry is focused primarily on SAF and to a lesser extent ATF. Further work is required to estimate the transportation, capital cost, and financing cost implications of greenfield and brownfield sites for SAF, DACS, and ATF. In the final report, we will analyze the potential to retrofit corn ethanol facilities to operate the ethanol-to-jet fuel process in response to decreasing gasoline demand as the electrification of road transport progresses. We will also construct a prioritization of land use to determine whether each net-zero CO 2 aviation pathway can make claim to the land required by their technology.

09 BIOMASS FUELS↗
DOE OSTI2024

Biomass Attributes and Attribute Modifications Affecting Systems and Methods to Separate and Fractionate

Chemical and physical heterogeneity in biomass feedstocks such as agricultural or forestry residues is due to substantial differences in plant tissue types. These differences can contribute significant challenges to handling, preprocessing, and conversion in biorefining processes. An understanding of this chemical and physical heterogeneity can be used to inform fractionation technologies that could facilitate more streamlined processing and potentially be employed to yield multiple co-product streams for a single feedstock. In this chapter, the motivation and scope of biomass fractionation is first outlined. Physical and chemical properties of biomass feedstocks, along with their distribution and diversity within plants, are next discussed with respect to how these differences can be exploited in a fractionation process. A summary of some of the key physical principles that allow for fractionation is next covered along with how these physical principles are exploited in equipment designs. Examples from the literature are briefly discussed that highlight how these approaches can be employed to achieve processing objectives. Several case studies on physical fractionation of corn stover and forestry residues are presented that illustrate how integrated fractionation processes could be employed. Lastly, prospects and potential economic drivers for adoption of biomass fractionation technologies are discussed.

09 BIOMASS FUELS↗
DOE OSTI2020

Making coal relevant for small scale applications: Modular gasification for syngas/engine CHP applications in challenging environments

Small-scale coal gasification technology, coupled to a reciprocating engine generator, has the potential for making coal a cost competitive resource for meeting the flexible energy needs and resiliency requirements of utilities across the United States. To maintain grid stability and reliability, electrical generation must be regulated to match the load at the proper voltage and frequency. With the expansion of intermittent sources into the grid, such as wind and solar, frequency and voltage regulation become increasingly important and challenging. This work presents the results of a Front End Engineering Design (FEED) effort to detail the engineering and preliminary economics of a small-scale, air blown, fixed-bed gasification process, operating at near-atmospheric pressure, with gas cleanup to provide syngas and pyrolysis liquid fuels for use in reciprocating engine generators for combined heat and power at the University of Alaska Fairbanks. A very detailed assessment of capital and operating costs allows the evaluation of a levelized cost of electricity of 208.06 $/MWh, which can be reduced through the selling of by-products (steam for heating purposes and pyrolysis liquids to be used for power generation in an existing diesel engine). Here, a combined sensitivity analysis, based on the Monte Carlo approach, has been carried out to evaluate the effects of the uncertainties (capital and operating costs and plant annual availability) on the LCOE.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2025

Opportunity Assessment for Sustainable Aviation Fuel Production from Woody Biomass via Ex Situ Catalytic Fast Pyrolysis and Refinery Hydroprocessing

Biofuels have become a promising solution to reduce emissions in hard-to-electrify transportation sectors, such as aviation. However, several biofuel conversion pathways will likely be needed to scale sustainable aviation fuel (SAF) production to meet lower carbon intensity goals when biomass feedstock availability constraints are considered. This study evaluates the future potential of the catalytic fast pyrolysis (CFP) pathway to contribute to U.S. SAF production goals as outlined in the U.S. Department of Energy’s (DOE) SAF Grand Challenge, understanding that the CFP pathway is still under development toward maturity and scaleup. National forestland resource data from the DOE’s 2023 Billion Ton Study are integrated with recent experimental results demonstrating end-to-end woody biomass conversion to SAF via CFP and hydroprocessing in a novel bioeconomy optimization framework. U.S. refinery hydroprocessing capacity is also considered with repurposing and coprocessing strategies. Results indicate that the CFP process can contribute up to 4.6 billion gallons of SAF annually by 2040, meeting 13% of the 2050 SAF Grand Challenge target while reducing the carbon intensity (CI) of the U.S. jet fuel pool by 16%. The study further explores optimal processing strategies, suggesting that colocating CFP operations with existing petroleum refineries and repurposing some U.S. hydrocracking capacity may offer significant cost advantages and enhance the commercial viability of the CFP pathway. These results underscore the CFP pathway’s potential to support the global aviation industry’s lower carbon intensity objectives while producing other renewable fuels and products.

09 BIOMASS FUELS↗
DOE OSTI2020

Carbon Capture and Conversion

Worldwide concern over climate change and its consequences has become a regular topic in the news. Extremes of weather appear to be more and more commonplace all over the planet. Release of man-made carbon dioxide, a greenhouse gas, has been associated with climate change, as the levels of CO 2 have continued to increase at a steady rate. In response to this change, many scientists and engineers have began research either to look at ways to sequester carbon dioxide from the atmosphere or to capture it at its source to avoid having to concentrate the CO 2 from the air. At the same time, CO 2 has been highlighted as an inexpensive C1 carbon source, and research efforts are underway to use CO 2 directly in chemical production.

10 SYNTHETIC FUELS↗
DOE OSTI2019

Making Coal Relevant for Small Scale Applications: Modular Gasification for Syngas/Engine CHP Applications in Challenging Environments

This Front-End Engineering Design (FEED) study is funded by the US Department of Energy (DOE), and managed by the National Energy Technology Laboratory (NETL) through a Cooperative Agreement awarded to the University of Alaska Fairbanks (UAF) to perform a technical and cost study for the design and installation of a Hamilton-Maurer International (HMI) gasifier for generating a clean syngas for firing in reciprocating engines. An existing diesel engine generator (DEG) and a commercially available spark ignition engine are used to generate electricity with the low-Btu syngas. Other than the HMI gasifier, only commercially available technologies were assumed for this study. An important objective of this design study was to estimate capital and operating costs of small modular coal and coal/biomass fired generating units to provide wind regulation services. Although this study is based on retrofitting an existing coal fired power plant with the HMI gasifier, sufficient data was developed to characterize greenfield units. The original concept was to provide clean syngas and tars/oils from the gasification process to the existing Colt-Pielstick PC2.6B diesel engine generator (9.6 MWe) installed at the UAF Atkinson Power Plant. The intent was to convert the diesel engine to operate in a dual fuel mode, firing both syngas and tars/oils. As the project progressed, Fairbanks Morse Engine (FME), current licensee for the Colt-Pielstick engine line, was not able to develop a modification package for the engine to allow for syngas firing. Although this type of modification is available for firing natural gas, the capability does not extend to syngas. Western Energy Systems, distributor for Innio Jenbacher, was able to offer the Jenbacher Model JMS620 engine. After review of available options, the project team selected a design configuration using two Jenbacher engines rated at 1965 kWe each to fire the syngas, with the oils/tars directed to the Colt Pielstick diesel to be blended with ultra-low sulfur diesel oil (ULSD). The Jenbacher engines are expected to operate at continuous base load, with some load-following ability, while the existing diesel engine will operate in grid support service, with loads varying from a nominal 25% to 100%. An annual capacity factor for the diesel engine is projected to be between 50% and 60%. The overall gasifier and gas clean-up system is sized to produce enough syngas to adequately fuel three Jenbacher Engines for a nominal power output of 5.9 MWe, but this study assumes that only two Jenbacher engines will be installed due to space constraints in the Atkinson Power Plant, and because of expected air emission permit limitations. There is still potential that the excess syngas capacity equivalent to about 2 MWe could be used as supplemental fuel for the DEG. The exhaust from the Jenbacher engines is passed through heat recovery units to generate low pressure steam, thereby providing a significant portion of the steam required for operating the gasifier. The overall performance of the HMI gasifier/engine configuration is summarized as follows: 1) Overall electric efficiency, Jenbacher and diesel engines, based on gasifier fuel production (syngas and pyrolysis liquids) is 35.2% LHV, 2) Overall cogenerating efficiency (electricity plus steam), based on gasifier fuel production (syngas and pyrolysis liquids) is 54.8% LHV, 3) Overall electric efficiency, Jenbacher and diesel engines, based on coal input, is 29.6% LHV, and 4) Overall cogenerating efficiency, electricity plus steam, based on coal input is 46.0%. This project is estimated to have a Bare Erected Cost (BEC) of $\$$ 33.4 million and a Total Plant Cost (TPC) of $\$$ 45.7 million. Based on the original scope, sending both the clean syngas and the oils and tars to the existing diesel engine, the BEC and TPC values would have been $\$$ 23.3 million and $\$$ 32.1 million, respectively. A variable Cost of Electricity (COE) is calculated to reflect only those costs that will be incurred by incremental operation of the system for the HMI gasifier/Jenbacher engine combination. Operation of the diesel engine is determined separately. The variable COE values are: Case 1: 100% Usibelli Coal: (a) HMI gasifier/Jenbacher Engines -- 8.3 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh, and Case 2: 80% Usibelli Coal + 20% wood chips (proportion based on Btu input, LHV basis): (a) HMI Gasifier/Jenbacher -- 13.7 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh. The incremental cost of operating the gasifier/Jenbacher system increases with co-firing of wood chips due to the high cost of this material, over five times as costly as Usibelli coal delivered to the Atkinson Power building. The diesel cost is constant as the oils and tars are priced at the same value as the ULSD for the purposes of fueling the diesel engine. Section 8 of this report provides details of the O&M costs. The overall power system is configured to be modular and scalable to provide a wide range of generating capacity using the same components. This allows for reduction in cost, risk, schedule time to engineer and construct, and provides some degree of repeatability for air permitting.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2020

A New Process for Carbon Dioxide Conversion to Fuel

In this project, TDA developed a new mixed metal oxide-based sorbent that converts CO 2 (captured from coal fired power plant) to CO, which can then be combined with renewable H 2 generated by water electrolysis to produce different liquid fuels. TDA’s absorbent-based CO 2 conversion process uses a redox process, which splits the reverse water gas shift reaction steps into two stages: CO 2 reduction to CO and H 2 oxidation to H 2 O and eliminates the equilibrium limitations. The CO produced in the two-stage reactor system can then be further reacted with renewable H 2 to produce methanol, naphtha, diesel, or gasoline. We worked with the Gas Technology Institute (GTI) and Advanced Power & Energy Program (APEP) of University of California, Irvine (UCI) to design and develop the liquid fuel synthesis process that is built around this new material. We demonstrated the techno-economic viability of the new sorbent based redox process to convert CO 2 into synthesis gas by: 1) demonstrating continuous carbon dioxide reduction in a prototype test system for over 500 hours while converting up to 0.4 kg CO 2 /day. With the successful completion of the R&D effort, the technology is now ready for a larger pilot-scale demonstration and the technology readiness has been raised from TRL 3 to TRL 5. In collaboration UCI, we also completed a high-fidelity process design and economic analysis. The required selling price (RSP) for methanol (Case 1 H2-MeOH) is $\$$3.06/gal, naphtha and diesel (Case 2 H2-FT) are $\$$6.21/gal and $\$$8.91/gal, and for gasoline (Case 3 H2-MTG) is $\$$6.96/gal on a 2011 dollar basis. To put these costs in perspective, the recent (June 2020) U.S. price for methanol made from natural gas is about $\$$1.19/gal according to Methanex, a major methanol producer in North America. The recent (June 2, 2020) California prices for gasoline and diesel with California’s strict specifications are $\$$3.35/gal and $\$$3.73/gal according to the U.S. Energy Information Agency. On the other hand, it should be noted that the gasoline and diesel produced by the designs of Case 2 and Case 3 would be both nitrogen and sulfur free. These RSPs are based on a cost of imported electricity of $\$$64/MWh based on the low-end current wind generated electricity cost (Genevieve and Ramsden, Wind Electrolysis: Hydrogen Cost Optimization, Technical Report, June 2011, NREL/TP-5600-50408). This cost is by far the largest component of the variable costs used in computing the RSPs. The cost of the imported electricity has to approach zero for the RSP to be competitive for methanol produced in Case 1 and naphtha and diesel produced in Case 2 while the cost of electricity has to be less than $\$$10/MWh for gasoline produced in Case 3.

01 COAL, LIGNITE, AND PEAT↗