The Ensembles of Photosynthetic Nanoreactors (EPN) Energy Frontier Research Center is gaining new knowledge that will help bridge the gap in solar-to-hydrogen energy conversion efficiency between what is observed, i.e. <1%, and necessary, i.e. >10%, to substantially mitigate the effects of global climate change. A major focus is to couple correlative microscopic and spectroscopic measurements with numerical simulations. By doing so, we are overturning conventional wisdom in the understanding of the basic science and engineering that dictate several observations in the field of photocatalytic solar water splitting. Notably, charge separation in state-of-the-art Rh-doped SrTiO 3 and BiVO 4 nanoparticles is not driven by electric fields due to band bending, but instead by differences in mobility and/or lifetime of mobile electronic carriers. Moreover, we have observed that dopants in Rh,La-codoped SrTiO 3 nanoparticles sometimes reside in unexpected crystallographic locations. We have also observed extensive incorporation of Pt cocatalysts into the bulk of Rh-doped SrTiO 3 nanoparticles during Pt photodeposition, which coincides with the induction period for observation of H 2 . Also, using atomic layer deposition to deposit ultrathin permeable oxide coatings on Rh-doped SrTiO 3 nanoparticles, we have observed increased selectivity for photocatalytic H 2 evolution. Lastly, using thermodynamically rigorous detailed balance models, which support observations from experiments, we have shown that the solar-to-hydrogen energy conversion efficiency of an ensemble of optically thin light absorbers can exceed that of optically thick materials, providing new motivation for the study and advancement of photocatalytic, over photoelectrochemical, solar water splitting. Collectively, our discoveries support new approaches, and motivate additional research pathways, toward the development of technoeconomically promising artificial photosynthetic devices.

Generating hydrogen from local energy resources such as solar or wind would unlock a low-carbon energy carrier that could be used to reduce greenhouse gas emissions in sectors such as industry and transportation. Yet, the allocation of new or existing power generation solely to hydrogen production remains contentious due to disputes regarding emissions accounting. Photocatalytic (PC) hydrogen production technologies offer a unique solution, as hydrogen is produced directly from solar energy and water, without the need for electricity generation. However, cost projections for all photocatalytic designs to date have suggested that they are not cost competitive compared to conventional electrolysis systems manufactured at scale. Herein, we offer the first illustrative benchmark of cost and carbon intensity of hydrogen produced in a type 2 "Z-scheme" photocatalytic reactor design, which employs suspended semiconducting nanoconductor particles organized into two stacked volumes in a raceway design. The "Z-scheme" system utilizes two separate photoabsorber particles, tuned to drive either the hydrogen evolution reaction or the oxygen evolution reaction individually, connected via a reversible, charge transfer redox couple in solution. The results suggest a highly competitive and scalable technology, that justifies further experimental validation and prototyping in the field.

Hydrogen is seen as a potential energy intermediary between renewable energy sources and end-use applications including transportation, power, and industrial feedstocks. Central to this approach is low-cost generation of hydrogen via water electrolysis. Significant research has been undertaken to improve the electrolysis stack technology, including enhancements in electrical efficiency, lowering performance degradation, and lowering total stack cost. Strategic Analysis Inc. (SA) has developed a process-based Design for Manufacturing and Assembly (DFMA) cost model for Alkaline, Proton Exchange Membrane (PEM), and Anion Exchange Membrane (AEM) electrolysis cell stacks. We assess the impact of technology improvement and manufacturing scale-up on the projected selling price of electrolyzer stacks for near-term and future deployments. Relative to the total cost of installing an electrolysis plant, the stacks contribute less than 50% of the initial capital investment. Therefore, from an electrolysis project perspective, the mechanical balance of plant and electrical systems required to operate the plant are equally important to understand. To explore the near-term and future cost projection for levelized cost of hydrogen via electrolysis, SA has developed a bottom-up project cost model for Alkaline, PEM and AEM hydrogen production plants. This project cost model incorporates: 1) Stack cost, 2) Mechanical Balance of Plant Cost, including process equipment, piping, valves, and instrumentation, derived from equipment quotes, scaling, database values, and Aspen estimates; 3) Electrical Balance of Plant Cost, including wiring, rectification, and electrical infrastructure upgrades, derived from time and material cost correlations; 4) Site Preparation Cost, focused on green field installation; and 5) Construction Overhead Cost, including engineering, procurement, and construction (EPC) costs and project contingency. Through a project level perspective, potential stack cost improvements through catalyst optimization and cell refinement can be contextualized against cost reductions from scaling up hydrogen plant deployment. The SA project cost model results are fed into a Levelized Cost of Hydrogen (LCOH) model that accounts for the full CapEx and OpEx involved in plant operation, including electricity and water consumption, labor, maintenance, and stack replacements. The SA project cost model and the LCOH model are used to conceptualize electrolysis system sizes from 10 MW to 1 GW for Alkaline, PEM, and AEM electrolysis systems. From a project perspective, electricity costs contribute 50-80% to the LCOH while capital and maintenance costs contribute the remaining 20-50% to the LCOH. Although improvements in stack performance and cost can provide incremental LCOH reductions, significant cost decreases will require optimization of the stack cell voltage and operating current density, as well as reductions in net electricity prices through integration with low-cost electricity. SA will explore potential opportunities to reduce hydrogen production costs through stack operating point optimization and scenarios where hydrogen production plants can selectively use low-cost renewable electricity to reduce net hydrogen costs.

We extend our past cost analysis of gigawatt-scale solid oxide electrolysis (SOE) facilities that produce high purity hydrogen gas from water by estimating construction and operating costs for three new alternative design cases: (1) offsite feed steam generation; (2) near-atmospheric pressure (NAP) stack; and (3) onsite electric boiler feed steam generation. Pressure effects on hydrogen electrode-(cathode-)supported SOE cell (SOEC) stack performance are estimated to determine facility-wide stack capital costs for achieving a fixed H-2 production at different pressures. Capital costs for modular balance of plant (BOP) process equipment are estimated for each new design case using our past equipment sizing, design, and cost data and scaling relationships. We update BOP equipment sizing and design for the NAP case using Aspen (R). Vendor quotes for electric boilers are used to estimate costs for electric boiler design cases. Factory and onsite assembly and installation costs for SOEC stacks and BOP equipment are calculated using our past first-principles approach. First-of-a-kind (FOAK) and N-th-of-a- kind (NOAK) production maturity costs are estimated for all cases. Use of NAP stacks offers the lowest facility total capital cost (TCC, similar to 23% lower than base) while use of small electric boilers requires the highest TCC (similar to 3% higher than base). H-2 production costs decrease from the base of similar to$2.17/kgH(2) to similar to$1.92/kgH(2) for 1 GW(e) DCSIP facilities utilizing NAP stacks supplied by offsites steam situated in large modules and blocks for $0.030/kWh(e) and $0.009/kWh(t) electricity and heat prices, respectively. We report all costs in 2021 US dollars.

Generating hydrogen from renewable resources would unlock a low-carbon energy carrier that could be used to reduce greenhouse gas emissions in sectors such as industry and transportation. Yet, the allocation...

The United States' focus on decarbonization has spawned interest among policymakers in deploying water electrolysis technology for clean hydrogen production. However, water electrolyzers also raise concerns regarding their substantial use of carbon-intensive materials. Here, we conduct a comprehensive life-cycle analysis (LCA) of three prominent water electrolyzer technologies to investigate the environmental implications of their manufacturing and life cycles under different energy sources. All electrolyzer technologies employing low-carbon energy (nuclear, solar, or wind) exhibit life-cycle greenhouse gas (GHG) emissions of 0.3-2.4 kg-CO2-eq/kg-H-2. This is significantly lower than the corresponding GHG emissions for hydrogen production via both conventional steam methane reforming and alternative autothermal reforming with carbon capture and storage (by > 50%). The well-to-gate GHG emissions of low-carbon electrolyzers (0-0.36 kg-CO2-eq/ kg-H-2) qualify for Tier I of the production tax credit in the U.S.' Inflation Reduction Act of 2022, indicating their suitability for producing decarbonized hydrogen under this program.

We estimate construction and operation costs of gigawatt-scale solid oxide electrolysis (SOE) facilities for producing high purity hydrogen gas from water. Manufacturing and assembly costs for two types of SOE cell stacks are estimated using a detailed design for manufacture and assembly (DFMA®) analysis. Modular balance of plant (BOP) process equipment is designed and sized with Aspen®, and cost estimated using equipment vendor quotes. Factory and on-site assembly and installation costs for SOEC stack and BOP equipment integration into modular SOE process units are calculated using a simplified DFMA® method. Total stack costs on a stack input power (SIP) basis reduce to <$100/kWe DCSIP for >500 MWe DCSIP/year production rates with electrode cermet, interconnects, and high-temperature heat treatments dominating the total cost. Integration of stacks with larger BOP equipment operating at higher pressures offers ∼36% cost reduction in total facility capital cost due to an economies of physical scale effect since BOP equipment comprises >50% of facility costs. Optimized H2 prices decrease from ∼$4/kgH2 to ∼$2/kgH2 for 1 GWe DCSIP facilities using $0.025/kWh electricity price. All costs are reported in 2021 US dollars.

The realization of an environmentally sustainable and widely-adopted hydrogen economy may require lowering hydrogen production costs of production pathways with ultra-low greenhouse gas emissions to $1/kg H 2 . The allocation of new or existing renewable electricity generation solely to hydrogen production remains contentious due to disputes regarding emissions accounting. Photoelectrochemical (PEC) hydrogen production technologies offer a unique solution, as hydrogen is produced directly from solar energy and water, without the need for electricity generation. However, cost projections for past photoelectrochemical designs have suggested that they are not cost competitive compared to conventional electrolysis systems manufactured at scale. Herein, we offer the first illustrative benchmark of cost and carbon intensity of hydrogen produced in a Type 2 Z-scheme photocatalytic reactor design that employs suspended semiconducting nanoparticles organized in two stacked baggies in a raceway design. To explore the near-term and future cost projection for hydrogen production via Type 2 photocatalytic Z-scheme raceways, the authors developed a bottom-up total installed capital cost model. This project cost model incorporates: 1) raceway reactor cost, derived from a Design for Manufacturing and Assembly (DFMA) process-based cost model, 2) mechanical balance of plant, including process equipment, piping, valves, and instrumentation, derived from equipment quotes, scaling, database values, and Aspen estimates; 3) electrical balance of plant, including wiring, derived from time and material cost correlations; 4) Site Preparation, focused on green field installation; and 5) Construction Overhead, including engineering, procurement, and construction (EPC) costs and project contingency. The capital cost model is fed into a Levelized Cost of Hydrogen (LCOH) discounted cash flow model that accounts for electricity and water consumption, in addition to other operating costs, including labor, maintenance, and raceway replacements. A hybrid life-cycle approach was used to develop an inventory of greenhouse gas emissions from all materials and energy flows associated with the facility life cycle. These flows are converted to emissions based on specific emission factors, or by using physical units-based input–output LCA models associated with the broader economic impacts of fuel and materials production, use, and end use. Estimates for levelized cost of hydrogen suggest that a 50 metric ton H 2 per day (MTD) raceway plant can approach $2.50/kg H 2 at an 8% solar-to-hydrogen efficiency with further cost improvements possible through increased performance and larger plant scales. Carbon intensity is estimated to be well under clean hydrogen targets for global warming potential of <2-4 kg CO 2 e/kg H 2 produced. The results suggest a highly competitive and scalable technology, that justifies further experimental validation and prototyping in the field. Figure 1

Hydrogen is seen as a potential energy intermediary between renewable energy sources and end-use applications including transportation, power, and industrial feedstocks. Core to this approach is low-cost hydrogen generation via water electrolysis. Significant research has been undertaken to improve the electrolysis stack technology, including enhancements in electrical efficiency, materials degradation, and total stack cost. However, relative to the total cost of installing an electrolysis plant, the stack contributes <50% of the initial capital investment. Therefore, from an electrolysis project perspective, the mechanical balance of plant and electrical systems required to operate the plant are equally important to understand. To explore the near-term and future cost projection for hydrogen production via electrolysis, Strategic Analysis, Inc. (SA) has developed a bottom-up project cost model for Alkaline, Proton Exchange Membrane (PEM), and Anion Exchange Membrane (AEM) electrolysis technologies. This project cost model incorporates: 1) Stack cost, derived from a Design for Manufacturing and Assembly (DFMA) process-based cost model developed by SA, 2) mechanical balance of plant, including process equipment, piping, valves, and instrumentation, derived from equipment quotes, scaling, database values, and Aspen estimates; 3) electrical balance of plant, including wiring, rectification, and electrical infrastructure upgrades, derived from time and material cost correlations; 4) Site Preparation, focused on green field installation; and 5) Construction Overhead, including engineering, procurement, and construction (EPC) costs and project contingency. The SA project cost model is fed into a Levelized Cost of Hydrogen (LCOH) model that accounts for electricity and water consumption, in addition to other operating costs, including labor, maintenance, and stack replacements. The SA project cost model and the LCOH model were used to conceptualize electrolysis system sizes from 100 MW to 1 GW for Alkaline, PEM, and AEM electrolysis systems. From a project perspective, electricity costs contribute 50-80% to the LCOH while capital and maintenance costs contribute the remaining 20-50% to the LCOH. Improvements in stack performance and cost offer incremental improvements in LCOH; however, larger reductions in hydrogen cost will only be possible through optimization of the stack cell voltage and operating current density in conjunction with reductions in net electricity price through integration with low-cost, probably renewable, electricity. Results from SA’s polarization performance optimization model show that lower cost Alkaline stacks, having somewhat lower performance (than PEM), tend to optimize at lower current densities leading to a larger stack active area, and benefit from low operational voltage to obtain higher conversion efficiencies. Higher cost PEM stacks with higher performance (than Alkaline stacks) tend to optimize at higher current densities to reduce the size/capital cost of the stacks and can afford a lower stack efficiency. Multivariable sensitivity analyses show the statistical variation in capital cost leading to the most likely range in LCOH for each technology. The results of this study provide guidance on where the largest incremental reductions in LCOH can be achieved on a project basis.

To explore the near-term and future cost projection of hydrogen production via water electrolysis, Strategic Analysis, Inc. (SA) has developed a bottom-up project cost model for Alkaline, Proton Exchange Membrane (PEM), and Anion Exchange Membrane (AEM) electrolysis technologies. This project cost model incorporates: 1) Stack cost, derived from a Design for Manufacture and Assembly (DFMA) process-based cost model; 2) mechanical balance of plant (BOP) cost; 3) electrical BOP cost; 4) site preparation cost; and 5) construction overhead cost. The SA project cost model results are fed into the Hydrogen Analysis (H2A) model to estimate the Levelized Cost of Hydrogen (LCOH), accounting for electricity and water consumption, in addition to other operating costs. The SA project cost model and the H2A model were used to conceptualize electrolysis system sizes from 100 MW to 1 GW. SA conducted operating point optimization to determine the current density and cell voltage that minimizes LCOH for each system. The expected LCOH for a grid-fed electrolyzer plant is similar for all major low-temperature water electrolysis systems.

The U.S. Department of Energy recently announced its first Energy Earthshot on Clean Hydrogen, with a cost target of $1/kg-H2 by 2031. Assuming future utility-scale grid electricity prices from photovoltaics ($0.02/kWh), 80% of the cost of H2 would come from performing low-temperature water electrolysis at its thermoneutral voltage, with zero additional overpotential. This fact motivates alternative, less-expensive means of using light to generate mobile charge carriers than photovoltaics, and reactor designs with exceedingly low capital costs, like those we recently invented. Systems using low capital cost reactors benefit from low-voltage operation, which represents a paradigm shift from current state-of-the-art electrolyzers that aim to operate at high current densities. Analytical models predict that solar photocatalytic water splitting inherently operates at low voltages through use of an ensemble of optically thin photoabsorbers each operating at a low rate. Collectively the ensemble exhibits larger overall solar-to-hydrogen conversion efficiencies in comparison to optically thick designs. In efforts to attain these predicted higher efficiencies, we are performing detailed studies on the properties of state-of-the-art doped SrTiO3 and BiVO4 photocatalyst particles. During my talk, I will share our recent efforts in atomic-layer deposited ultrathin oxide coatings to impart redox selectivity and materials stability, single-photocatalyst-particle current–potential behavior and mobile charge carrier properties, and atomic-level information on dopant distributions and materials interfaces obtained from electron microscopies and X-ray spectroscopies. Collectively, our discoveries provide new design guidelines and additional research pathways for the development of effective composite materials to serve as active components in techno-economically viable artificial photosynthetic devices.

This final technical report summarizes hydrogen storage system cost analysis results from 2017-2021. Results include onboard hydrogen storage system costs for light-duty vehicles, medium-duty vehicles, heavy-duty vehicles, class 8 long haul trucks, and passenger buses. Multiple storage systems are included, primarily focusing on compressed and cryo-compressed hydrogen in Type 3 and Type 4 storage systems. Additional analysis includes large-scale gaseous and liquid hydrogen storage at refueling stations in tube trailers and Dewars; advanced materials-based storage systems such as metal organic frameworks and metal hydrides; and a baseline setting analysis of compressed natural gas storage systems in support of the Institute for Advanced Composites Manufacturing Initiative (IACMI). Analyses were primarily conducted using a Design for Manufacture and Assembly® methodology, which is a bottom-up process-based approach to estimating factory costs. Multiple annual production rates are reported to project high-volume costs relevant to mature markets.

emerging alternative for energy storage, where hydrogen can be used as a transportation fuel, combusted to generate electricity, utilized in a fuel cell, or used as a feedstock for chemical synthesis. Techno-economic analysis (TEA) is a valuable tool for understanding how to inform research directions that could make hydrogen from electrolysis cost competitive with that produced by conventional means like steam methane reforming. The current state of knowledge on TEA of electrolysis systems suggests cost reductions are likely to result from advances in system design and materials, scale-up of manufacturing processes, and learning by doing effects as electrolysis deployment increases. Future directions and opportunities for TEA of electrolysis systems include dispatchable operation in wholesale power markets, optimization of capital cost and system durability, and analysis of pathways for hydrogen to support economy-wide decarbonization.

This report summarizes project activities for an assessment of transportation fuel cell system cost from 2017 to 2021. The project defined and projected the mass production costs of direct hydrogen PEM fuel cell power systems for LDVs (automobiles), MDVs, and HDVs for current and future technologies. In each year of the project, the fuel cell power system designs and cost projections were updated to reflect technological advances. Systems were defined corresponding to direct H2 PEM FC power systems for ~80 kWnet LDVs, 70-170 kWnet MDVs, and 275-330 kWnet HDVs. A selection of systems was analyzed in each year. Major components, their functionality, and relevant parameters were defined in system diagrams. The system definitions were supported by system performance modeling calculations. A BOM for each system analyzed was created that tabulated all system components and subsystems contained in the power systems. Several annual manufacturing rates were considered for each system analyzed.

This paper compares the relative cost of long-distance, large-scale energy transmission by electricity, gaseous, and liquid carriers (e-fuels). The results indicate that the cost of electrical transmission per delivered MWh can be up to eight times higher than for hydrogen pipelines, about eleven times higher than for natural gas pipelines, and twenty to fifty times higher than for liquid fuels pipelines. These differences generally hold for shorter distances as well. The higher cost of electrical transmission is primarily because of lower carrying capacity (MW per line) of electrical transmission lines compared to the energy carrying capacity of the pipelines for gaseous and liquid fuels. The differences in the cost of transmission are important but often unrecognized and should be considered as a significant cost component in the analysis of various renewable energy production, distribution, and utilization scenarios.