United States

Hydrogen is often viewed as an important energy carrier in a future decarbonized world. Currently most hydrogen is produced by steam reforming of methane in natural gas (“gray hydrogen”) with high carbon dioxide emissions. Increasingly many propose using carbon capture and storage to reduce these emissions producing so-called “blue hydrogen” frequently promoted as low emissions. We undertake the first effort in a peer-reviewed paper to examine the lifecycle greenhouse gas emissions of blue hydrogen accounting for emissions of both carbon dioxide and unburned fugitive methane. Far from being low carbon greenhouse gas emissions from the production of blue hydrogen are quite high particularly due to the release of fugitive methane. For our default assumptions (3.5% emission rate of methane from natural gas and a 20-year global warming potential) total carbon dioxide equivalent emissions for blue hydrogen are only 9%-12% less than for gray hydrogen. While carbon dioxide emissions are lower fugitive methane emissions for blue hydrogen are higher than for gray hydrogen because of an increased use of natural gas to power the carbon capture. Perhaps surprisingly the greenhouse gas footprint of blue hydrogen is more than 20% greater than burning natural gas or coal for heat and some 60% greater than burning diesel oil for heat again with our default assumptions. In a sensitivity analysis in which the methane emission rate from natural gas is reduced to a low value of 1.54% greenhouse gas emissions from blue hydrogen are still greater than from simply burning natural gas and are only 18%-25% less than for gray hydrogen. Our analysis assumes that captured carbon dioxide can be stored indefinitely an optimistic and unproven assumption. Even if true though the use of blue hydrogen appears difficult to justify on climate ground

Interest in the low-cost production of clean hydrogen is growing. Anion exchange membrane water electrolyzers (AEMWEs) are considered one of the most promising sustainable hydrogen production technologies because of their ability to split water using platinum group metal-free catalysts less expensive anode flow fields and bipolar plates. Critical to the realization of AEMWEs is understanding the durability-limiting factors that restrict the long-term use of these devices. This article presents both durability-limiting factors and mitigation strategies for AEMWEs under three operation modes i.e. pure water-fed (no liquid electrolyte) concentrated KOH-fed and 1 wt% K₂CO₃-fed operating at a differential pressure of 100 psi. We examine extended-term behaviors of AEMWEs at the single-cell level and connect their behavior with the electrochemical chemical and mechanical instability of single-cell components. Finally we discuss the pros and cons of AEMWEs under these operation modes and provide direction for long-lasting AEMWEs with highly efficient hydrogen production capabilities.

Gaseous fuels with low life-cycle emissions of greenhouse gases (GHG) play a prominent role in the European Union’s (EU) decarbonization plans. Renewable and low-GHG hydrogen are highlighted in the ambitious goals for a cross-sector hydrogen economy laid out in the European Commission’s Hydrogen Strategy. Renewable hydrogen and biomethane are given strong production incentives in the Commission’s proposed revision to the Renewable Energy Directive (REDII). The EU uses life-cycle analysis (LCA) to determine whether renewable gas pathways meet the GHG reduction thresholds for eligibility in the REDII. This study aims to support European policymakers with a better understanding of the uncertainties regarding gaseous fuels’ roles in meeting climate goals. Life-cycle GHG analysis is complex and differences in methodology as well as data inputs and assumptions can spell the difference between a renewable gas pathway qualifying or not for REDII eligibility at the 50% to 80% GHG reduction level. It is thus important for European policymakers to use robust LCA to ensure that policy only supports gas pathways consistent with a vision of deep decarbonization. For this purpose we conduct sensitivity analysis of the life-cycle GHG emissions of a number of low-GHG gas pathways including biomethane produced from four feedstocks: wastewater sludge manure landfill gas (LFG) and silage maize; and hydrogen produced from eight sources: natural gas combined with carbon capture and storage (CCS) coal with CCS biomass gasification renewable electricity 2030 EU grid electricity wastewater sludge biomethane manure biomethane and LFG biomethane. For each pathway we estimate the life-cycle GHG intensity using a default central case identify key parameters that strongly affect the fuel’s GHG intensity and conduct a sensitivity analysis by changing these key parameters according to the range of possible values collected from the literature. Figure ES1 summarizes the full range of possible GHG intensities for each gaseous pathway we analyzed in this study—biomethane is depicted in the top figure and hydrogen is shown in the bottom. The bars represent the GHG intensity of the central case and vertical error bars indicate the maximum and minimum GHG intensity of each pathway according to our sensitivity analysis. The dotted orange horizontal line illustrates the fossil comparator which is 94 grams of carbon dioxide equivalent per megajoule (gCO2e/MJ) for transport fuels in the REDII. The dotted yellow line represents the GHG intensity of a 65% GHG reduction goal for biomethane used in the transportation sector or 70% GHG reduction for hydrogen. Pathways are situated from left to right in increasing order of GHG intensity of the central case. Comparing the central cases of the four biomethane pathways the waste-based biomethane pathways generally have negative GHG intensity. However considering the uncertainty in these GHG intensities manure biomethane might have more limited carbon reduction potential in the 100-year timeframe if methane leakage from its production process is high. In contrast wastewater sludge biomethane and LFG biomethane even after accounting for uncertainties retain relatively low GHG emissions. On the other hand biomethane produced from silage maize can have much higher emissions; in the central case we find that silage maize biogas only reduces GHG emissions by 30% relative to the fossil comparator—the low carbon reduction potential is due to the significant emissions emerging from direct and indirect land use change involved in growing maize. Taking into account the variation in assumptions silage maize biomethane can be worse for the climate than fossil fuels.

This report The Future of Clean Hydrogen in the United States: Views from Industry Market Innovators and Investors sheds light on the rapidly evolving hydrogen market based on 72 exploratory interviews with organizations across the current and emerging hydrogen value chain. This report is part of a series From Kilograms to Gigatons: Pathways for Hydrogen Market Formation in the United States which will build on this study to evaluate policy opportunities for further hydrogen development in the United States. The goal of the interviews was to provide a snapshot of the clean hydrogen investment environment and better understand organizations’ market outlook investment rationale and areas of interest. This interview approach was supported by traditional research methods to contextualize and enrich the qualitative findings. This report should be understood as input to a more extensive EFI analysis of hydrogen market formation in the United States; the directions that companies are pursuing in hydrogen production transport and storage and end use at this early stage of value chain development will inform subsequent analysis in important ways.

In this study we consider fuel cell-powered electric trucks (FCETs) as an alternative to conventional medium- and heavy-duty vehicles. FCETs use a battery combined with onboard hydrogen storage for energy storage. The additional battery provides regenerative braking and better fuel economy but it will also increase the initial cost of the vehicle. Heavier reliance on stored hydrogen might be cheaper initially but operational costs will be higher because hydrogen is more expensive than electricity. Achieving the right tradeoff between these power and energy choices is necessary to reduce the ownership cost of the vehicle. This paper develops an optimum component sizing algorithm for FCETs. The truck vehicle model was developed in Autonomie a platform for modelling vehicle energy consumption and performance. The algorithm optimizes component sizes to minimize overall ownership cost while ensuring that the FCET matches or exceeds the performance and cargo capacity of a conventional vehicle. Class 4 delivery truck and class 8 linehaul trucks are shown as examples. We estimate the ownership cost for various hydrogen costs powertrain components ownership periods and annual vehicle miles travelled.

In the future the world may have large stranded resources of low-cost wind and solar electricity. Renewable electricity production does not match demand and production is far from major cities. The coupling of nuclear energy with renewables may enable full utilization of nuclear and renewable facilities to meet local electricity demands and export pipeline hydrogen for liquid fuels fertilizer and metals production. Renewables would produce electricity at full capacity in large quantities. The base-load nuclear plants would match electricity production with demand by varying the steam used for electricity versus hydrogen production. High-temperature electrolysis (HTE) would produce hydrogen from water using (a) steam from nuclear plants and (b) electricity from nuclear plants and renewables. During times of peak electricity demand the HTE cells would operate in reverse fuel cell mode to produce power substituting for gas turbines that are used for very few hours per year and that thus have very high electricity costs. The important net hydrogen production would be shipped by pipeline to customers. Local hydrogen storage would enable full utilization of long-distance pipeline capacity with variable production. The electricity and hydrogen production were simulated with real load and wind data to understand under what conditions such systems are economic. The parametric case study uses a wind-nuclear system in North Dakota with hydrogen exported to the Chicago refinery market. North Dakota has some of the best wind conditions in the United States and thus potentially low-cost wind. The methodology allows assessments with different economic and technical assumptions - including what electrolyzer characteristics are most important for economic viability.

Due to its much lower air pollution and potential greenhouse gas (GHG) emissions benefits liquefied natural gas (LNG) is frequently discussed as a fuel pathway towards greener maritime transport. While LNG’s air quality improvements are undeniable there is debate within the sector as to what extent LNG may be able to contribute to decarbonizing shipping. This report “The Role of LNG in the Transition Toward Low- and Zero-Carbon Shipping” considers the potential of LNG to play either a transitional role in which existing LNG infrastructure and vessels could continue to be used with compatible zero-carbon bunker fuels after 2030 or a temporary one in which LNG would be rapidly supplanted by zero-carbon alternatives from 2030. Over concerns about methane leakage which could diminish or even offset any GHG benefits associated with LNG and additional capital expenditures the risk of stranded assets as well as a technology lock-in the report concludes that LNG is unlikely to play a significant role in decarbonizing maritime transport. Instead the research finds that LNG is likely to only be used in niche shipping applications or in its non-liquefied form as a feedstock to kickstart the production of zero-carbon bunker fuels when used in conjunction with carbon capture and storage technology. The research further suggests that new public policy in support of LNG as a bunker fuel should be avoided existing policy support should be reconsidered and methane emissions should be regulated.

Effective global decarbonization will require an array of solutions across a portfolio of low-carbon resources. One such solution is developing clean hydrogen. This unique fuel has the potential to minimize climate change impacts helping decarbonize hard-to-abate sectors such as heavy industry and global transport while also promoting energy security sustainable growth and job creation. The authors estimate suggest that hydrogen needs to grow seven-fold to support the global energy transition eventually accounting for ten percent of total energy consumption by 2050. A scaleup of this magnitude will increase demand for materials such as aluminum copper iridium nickel platinum vanadium and zinc to support hydrogen technologies - renewable electricity technologies and the electrolyzers for renewable hydrogen carbon storage for low-carbon hydrogen or fuel cells using hydrogen to power transport. This report a joint product of the World Bank and the Hydrogen Council examines these three critical areas. Using new data on the material intensities of key technologies the report estimates the amount of critical minerals needed to scale clean hydrogen. In addition it shows how incorporating sustainable practices and policies for mining and processing materials can help minimize environmental impacts. Key among these approaches is the use of recycled materials innovations in design in order to reduce material intensities and adoption of policies from the Climate Smart Mining (CSM) Framework to reduce impacts to greenhouse gas emissions and water footprint.

Across the globe energy production and usage cause the greatest greenhouse gas (GHG) emissions which are the key driver of climate change. Therefore countries around the world are aggressively striving to convert to a clean energy regime by altering the ways and means of energy production. Hydrogen is a frontrunner in the race to net-zero carbon because it can be produced using a diversity of feedstocks has versatile use cases and can help ensure energy security. While most current hydrogen production is highly carbon-intensive advances in carbon capture renewable energy generation and electrolysis technologies could help drive the production of low-carbon hydrogen. However significant challenges such as the high cost of production a relatively small market size and inadequate infrastructure need to be addressed before the transition to a hydrogen-based economy can be made. This review presents the state of hydrogen demand challenges in scaling up low-carbon hydrogen possible solutions for a speedy transition and a potential course of action for nations.

The majority penetration of Variable Renewable Energy (VRE) will challenge the stability of electrical transmission grids due to unpredictable peaks and troughs of VRE generation. With renewable generation located further from high demand urban cores there will be a need to develop new transmission pathways to deliver the power. This paper compares the transport and storage of VRE through a hydrogen pipeline to the transport of VRE through a High Voltage Direct Current (HVDC) transmission line. The analysis found a hydrogen pipeline can offer a cost-competitive method for VRE transmission compared to a HVDC transmission line on a life-cycle cost basis normalized by energy flows for distances at 1000 miles with 2030 technology. This finding has implications for policy makers project developers and system operators for the future development of transmission infrastructure projects given the additionality which hydrogen pipelines can provide in terms of energy storage.