The report, Fueling Up: How to Make U.S. Clean Hydrogen Projects Happen, draws upon the views and expertise of a range of sector specialists to explore what steps could be taken to realize clean hydrogen’s potential.

The report argues that the U.S. should boost exports to provide additional routes to market, bolster domestic manufacturing for hydrogen technologies, and prioritize ‘backbone’ infrastructure to reduce project risk.

The report says the Inflation Reduction Act and Bipartisan Infrastructure Law have generated commercial interest in American clean hydrogen projects. But the legislation, and implementation of those regulations, come with complexities and caveats that require navigation.

One issue is tax credits. Designed as incentives to encourage companies to produce clean hydrogen, helping them transition from early-stage development and planning to construction, the arrival of proposed IRS regulations on Section 45V in December 2023 have been considered too stringent by many, offering up more questions than answers, the report said.

For hydrogen to be considered ‘clean’ and eligible for credits it must meet three criteria: additionality, time matching, and deliverability. These criteria require that hydrogen facilities cannot draw power from a source more than three years older than the hydrogen project, electricity-producing hydrogen must be generated within the same hour as the hydrogen, and the electricity source and hydrogen facility must be in the same geographical area, as defined by the DOE’s transmission needs analysis.

Troutman Pepper says that as a result, many concerned developers and utilities are halting progress, warning that it will drive up costs and make it harder to get projects funded and constructed in this nascent sector, as they await further clarity from the IRS on its finalized rules.

Meanwhile, off-takers are asking for improved clean hydrogen certification standards to offer transparent reassurance that they are getting the product they think they are. To stimulate demand, the Biden Administration made $7 billion available to support seven regional clean hydrogen production hubs across the country.

However, businesses inclined to follow this route, such as chemical and metal producers, oil refineries, and transportation and utility companies, are feeling uneasy about the potentially ambiguous nature of hydrogen classifications, the report said. Faced with directives to reduce their environmental impact, businesses are struggling with a lack of visibility, guidance, and uniform certification to verify how green any available fuel actually is.

The report notes that more states could encourage greater uptake of clean hydrogen, similar to what numerous states previously did with regard to renewable portfolio targets. For instance, only California, Oregon, and Washington have introduced low-carbon fuel standards thus far. State-led commitments along these lines could provide clean hydrogen users with greater confidence to support the development of a robust domestic clean hydrogen market, the report said.

Beyond the domestic market, some commentators within the report argue there is an opportunity to establish the U.S. as a clean hydrogen exporter, particularly to Europe and Asia, including in the form of ammonia. Industries globally are under regulatory pressure to decarbonize. Many countries outside the U.S. face greater challenges in relation to their regional energy transition policies, making U.S. hydrogen a potentially attractive proposition, bringing in capital and off-take certainty from around the world, while developing a spot market for clean hydrogen and related products.

On U.S. soil, report commentators have encouraged the building out of U.S. manufacturing facilities for hydrogen technologies, while prioritizing nationwide ‘backbone’ infrastructure to reduce project risk. Bloomberg New Energy Finance recently reported that 68% of global electrolyzer manufacturing is in China. In the short-term, this represents a reassuring level of access to equipment, but in the longer-term, the federal government has committed to growing domestic production to counteract that reliance.

Equally, interviewees argued that the government needs to unlock investments to support infrastructure, helping producers store and move their product more efficiently and economically. The DOE recognized this challenge in its June 2023 National Clean Hydrogen Strategy & Roadmap, where it reported that between $2 billion and $3 billion of investment annually is needed in hydrogen infrastructure projects between 2023 and 2030 to enable the U.S. to achieve annual production of 10 million metric tons by 2030.

“When compiling this report, we found that most commentators and sector specialists agreed about the vast potential of clean hydrogen to become a highly useful non-fossil component of America’s energy mix,” said Mindy McGrath, a regulatory and finance Partner in the energy practice group at Troutman Pepper. “And it’s been encouraging to see government incentives and financial support acknowledging that potential in an effort to drive both production and demand.

“What is less clear at present is how these mechanisms and stimuli will play out in the real world. Regulators are justifiably concerned about doing things the right way. That said, if the rules surrounding the sector are too onerous or ambiguous it is going to stifle progress. Major energy businesses – developers, producers, utilities, and investors – are rightly wary of this uncertainty. In this report we look at why there needs to be a concerted effort to demystify complex regulatory matters, and why clear guidance is needed to create a cohesive framework of strategies to properly advance the sector.”

Fueling Up: How to Make U.S. Clean Hydrogen Projects Happen can be downloaded here.

In a news release Friday, Gov. Michelle Lujan Grisham said she’ll lead a delegation to an industry summit exhibition in the port city of Rotterdam seeking the “opportunity to sell New Mexico as a dynamic and thriving place for hydrogen industry investment.” She led a similar mission last year to Australia to talk with hydrogen entrepreneurs.

Lujan Grisham, a Democrat, has been a vocal proponent of investments in hydrogen as a transition fuel that can replace fossil fuels with cleaner-burning hydrogen as an energy source for vehicles, manufacturing and generating electricity.

Some environmentalists call hydrogen a false solution because it frequently relies on natural gas as a fuel source. Several New Mexico-based groups have resisted proposed state incentives for hydrogen development, citing concerns that it would prolong natural gas development and increase demand for scarce water supplies.

Hydrogen also can be produced through electrolysis — splitting water molecules using renewable energy sources such as wind and solar power, as well as nuclear power.

New Mexico is a major energy producing state with extensive natural gas reserves and broad recent investments in electrical transmission lines aimed expanding renewable energy production from sources including wind and solar.

The Biden administration last year passed over a four-state bid by New Mexico, Colorado, Utah and Wyoming for a share of $7 billion aimed at kickstarting development and production of hydrogen fuel. It chose instead projects based in California, Washington, Minnesota, Texas, Pennsylvania, West Virginia and Illinois.

The hydrogen summit in Rotterdam has an array of public an private sponsors. Lujan Grisham is traveling with office staff, New Mexico cabinet secretaries for the environment and transportation, and husband Manny Cordova. The New Mexico delegation also includes Rob Black, president of a statewide chamber of commerce.

This site, which is the largest green hydrogen plant in Baden-Württemberg, will be the first to supply hydrogen directly to the H2-Aspen industrial park and the JET H2 hydrogen filling station.

The project in Schwäbisch Gmünd represents a milestone in the market ramp-up of green hydrogen in Germany and exemplifies the integration of renewable gas into local ecosystems. The plant, which will use renewable electricity secured from hydro, wind and solar power purchase agreements, should be commissioned in the second half of 2024.

The project, which is part of the HyFIVE (Hydrogen For Innovative Vehicles) project, has received €6.4 million ($6.7 million) in funding from the European Regional Development Fund (ERDF).

Luc Graré, head of Central & Eastern Europe at Lhyfe said, “The project demonstrates the economic viability of hydrogen solutions in the transport and industry sectors and also supports the state of Baden-Württemberg in its efforts to become a model region for the development of hydrogen refueling infrastructure.  We very much welcome the fact that the state and the city of Schwäbisch Gmünd want to implement their ambitious goals for a hydrogen economy based on renewable energies and that we are taking this step together. With the construction of the production plant, we are making an important contribution to the goals of the federal government.”

Richard Arnold, major of Schwäbisch Gmünd in Germany added, “Through cooperations like this, Schwäbisch Gmünd is developing into a model region for the nationwide development of a hydrogen and filling station network as a central supply infrastructure. Schwäbisch Gmünd is part of the model region of the state of Baden-Württemberg and, with the completion of the plant, will then also be the largest hydrogen producer in the state. We are thus creating a basis for marketing the land in Aspen, which will enable the companies to produce climate-neutrally.”

Today, Lhyfe’s business pipeline represents a total installed production capacity of 10.3 GW across Europe.

Originally published by Power Engineering International.

While electrification and renewables are the most optimal vector for decarbonization, hydrogen has grown in popularity as a viable decarbonization solution for hard-to-abate sectors.

Its versatility and ability to store and transport energy make it a promising option for industries such as heavy transportation, aviation, and certain industrial processes that face unique challenges in reducing their carbon emissions.

By embracing hydrogen as a decarbonization tool alongside electrification, we can ensure a comprehensive and effective approach to achieving a sustainable future.

For decades, hydrogen has held a fundamental position in various manufacturing processes. However, the emergence of Green Hydrogen (GH2) is rapidly transforming it into a crucial resource for propelling industrial operations towards a carbon-free future.

Considering the urgent need to halve global CO2 emissions by 2030, the role of green hydrogen becomes even more critical in meeting both industrial and environmental imperatives.

Green hydrogen, produced through electrolysis using renewable energy sources, offers a sustainable solution to address the challenges of reducing carbon emissions in industries.

The potential of green hydrogen to revolutionize industries and contribute to a sustainable future is undeniable. Together, we can accelerate the market adoption of green hydrogen to make way for an industrial landscape that mitigates climate change impacts and drives sustainable growth.

Decarbonizing hard-to-abate sectors

A few figures illustrate the magnitude of hydrogen’s contribution to today’s GHG emissions. Currently, we’re producing 70-80 million tons per annum (Mtpa) of unabated hydrogen obtained by steam-reforming fossil fuels, and the waste product CO₂ is released directly into the atmosphere. 

Every kilogram of such unabated hydrogen produces 12kg of CO₂, for a total of close to 1 billion tons – or possibly 5% of total global emissions – every year. About 33% of this hydrogen is then dedicated to industrial gas applications, with the remaining 66% going toward refining and chemical production.

As industries continue to use fossil fuels to power their production, electrification is a viable option for reducing related carbon emissions and improving efficiencies.

However, this option is not always feasible due to technological limitations, infrastructure constraints, or energy-intensive processes. This leaves a significant demand for processes or segments that can’t be powered by electricity alone.

That’s where green hydrogen will become essential.

By utilizing green hydrogen as an alternative, it can replace natural gas and deliver enormous savings in emissions. The versatility of green hydrogen allows it to serve as a reliable and clean energy source for industries, transportation, and heating where electrification may not be a practical solution.

By incorporating green hydrogen into the energy mix, we can make substantial progress in decarbonizing sectors that were previously challenging to abate, ensuring a more sustainable and environmentally friendly future.

However, commercial scale production of green hydrogen has a few challenges and risks. For large-scale use, developers and operators need to pay close attention to production and operations to ensure plant economics can support this much-needed transition to adopting green hydrogen.

Unleashing the full potential: Unraveling the value chain of green hydrogen

To accelerate production, developers need to consider the entire value chain at the plant level.

The overall architecture for a green hydrogen plant site consists of the following:

• Power Generation, including a renewable energy source such as wind turbines, solar panels, battery electric storage systems, and grid connections enabling bidirectional power flow.
• The hydrogen production unit, which includes a water treatment plant, electrolyzers, separators, and other production-related equipment and systems.
• Downstream Hydrogen unit, which utilizes the produced hydrogen, e.g., ammonia production, pipeline injection, cavern storage, or mobility fueling stations.

In all three aspects of this architecture, optimized control is imperative to ensure:

• Reliable integration of power supply resources to guarantee production.
• Production maximization based on available power and electrolyzers.
• Maximized utilization of available hydrogen with optimized conversion rates.

An integrated production system oversees and coordinates this entire value chain, with capabilities that include renewable power forecasting, electrolyzer production optimization, overall efficiency monitoring, and operations simulations. A unified enterprise control system can be deployed for control from a centralized operations center for multi-plant operators.

Accelerating the market adoption of hydrogen

As an emerging technology, green hydrogen production brings some challenges for project developers and owners.

Industry leaders need to address key improvements to keep projects on track and profitable throughout their operation – along with solutions to ensure our partners’ success, including:

1. Increase cost competitiveness: Both initial capital expenditures (CapEx) and ongoing operational expenditures (OpEx) figure into the levelized cost level of the green hydrogen a plant produces throughout its lifespan.
   For lower CapEx, organizations need to optimize energy management and process automation to shorten ramping-up periods. For lower OpEx, companies must optimize energy sourcing, increase system efficiency, and maximize annual full-load hours of electrolysis systems.
2. De-risking introduction of technologies: To help minimize risk with this new technology, safety instrumented systems can offer a unified system to control process operations and energy consumption. Having a training and simulation platform will also help facility operators explore what-if scenarios in a safe, digital environment.
3. Supply chain optimization: Facilitating the use of digital twins to enable predictive simulations of power and production availability will optimize supply chains. Facilities will be able to manage their energy supplies to optimize renewables use while minimizing costs and uptime.
4. Collaboration and knowledge sharing: Collaboration across industry players, research institutions, and governments is key to overcoming challenges in green hydrogen production. Sharing best practices, technical expertise, and lessons learned fosters innovation and accelerates the development of cost-effective and efficient solutions. Collaborative initiatives can also facilitate standardization, certification, and knowledge dissemination, promoting the global adoption of green hydrogen technologies.

By focusing on these aspects, project developers can navigate the challenges and unlock the full potential of green hydrogen as a sustainable and decarbonized energy solution for the future.

The investment in green hydrogen solutions may be expensive, but the long-term benefits of this renewable option are hard to turn down. By implementing the right architecture with the right solutions at the right time, we can pave the way for a decarbonized future.

Originally published on Power Engineering International.

ABOUT THE AUTHORS

Manuel Hernandez, Global Power Generation Segment Leader for Process Automation, at Schneider Electric

Ahmed Wafi, Global Business Development at Schneider Electric

Integrating hydrogen production with hydropower can enhance grid stability through energy storage, reoxygenate water for downstream environmental improvements and support decarbonizing energy production. The data, models and analyses developed through this partnership will help determine the viability of hydropower and hydrogen integration, for Idaho and facilities across the U.S.

“INL and PNNL will evaluate the coupling of electrolytic hydrogen production technologies with hydropower plants to identify scenarios that could help Idaho Power achieve its goal of providing 100% clean energy by 2045,” said Brett Dumas, Idaho Power’s director of environmental affairs. “This approach will help maximize use of the clean energy produced by Idaho Power’s 17 hydroelectric power plants.”

Hydropower generates more consistently than other renewable energy sources, and adding hydrogen production can increase flexibility by helping balance wind and solar generation. This is especially important during hours of peak electricity use. Additionally, hydrogen produced using excess electricity from hydropower easily can be converted back into electricity when needed. This option would be especially useful during peak hours when electricity from hydropower may not be readily available, helping to meet energy demand and reduce reliance on nonrenewable power generation.

“Storing hydrogen as a fuel could help stabilize the grid and offer a cleaner alternative to fossil-fuel backup power generation. This approach could give electrical system operators greater flexibility to ensure reliable and economical service,” said INL’s Daniel Wendt, principal investigator and researcher on the project.

In addition, reservoirs behind dams may have low levels of dissolved oxygen, particularly during summer and early fall. Dissolved oxygen in a river is necessary for fish and other aquatic species. INL and PNNL researchers will evaluate the potential of using excess oxygen generated by the hydrogen generation process to reoxygenate water in rivers with hydropower plants. “Idaho Power is already seeing positive results from adding oxygen into the water flowing out of Brownlee Dam in Hells Canyon,” Dumas said.

INL, PNNL and Idaho Power are taking the first step by analyzing the economic and environmental impacts of integrating hydrogen production with hydropower. The project team will develop advanced modeling and analytical methods to explore various deployment scenarios and maximize the benefits associated with hydropower-based hydrogen production.

“To effectively schedule hydrogen production, advanced modeling and optimization techniques are required to account for both energy shifting opportunities and oxygen needs subject to both system- and component-level constraints,” said Di Wu, a chief research engineer and the technical lead at PNNL.

INL researchers will use a U.S. Department of Energy software tool proven to be effective for techno-economic evaluation of other hydrogen production and usage applications. The Hydrogen Analysis (H2A) tool can perform screening studies of the most promising electrolysis technologies and hydrogen use cases. H2A allows the user to access all calculations as well as check intermediate results.

PNNL researchers will build on the results of the screening study to model and optimize the hydrogen production system. Through the Hydrogen Energy Storage Evaluation Tool and data analysis, INL and PNNL researchers will determine how to implement the right set of technologies to achieve the best performance.

“While hydropower and hydrogen both offer immense economic and environmental benefits on their own, combining their use in one application offers new opportunities for enhancing grid stability, improving environmental outcomes and creating a cleaner energy economy,” Wendt said.

A new report by the National Renewable Energy Laboratory (NREL) examines the types of clean energy technologies, along with the scale and pace of deployment needed for the U.S. to reach 100% clean electricity by 2035.

The NREL study, Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035, found multiple pathways to a decarbonized grid by 2035. However, the exact technology mix and costs would be determined by research and development, manufacturing, and infrastructure investment decisions made over the next decade.

NREL said the study scenarios considered many new factors: a 2035 full decarbonization timeframe, higher levels of electrification and an associated increase in electricity demand, increased electricity demand from carbon dioxide removal technologies and clean fuels production, higher reliance on existing commercial renewable energy generation technologies, and greater diversity of seasonal storage solutions. The report was also influenced by decades of prior research.

For each scenario, researchers modeled the least costly generation, energy storage, and transmission investment portfolio to maintain reliable power throughout the year.

“For the study, [NREL’s Regional Energy Deployment System] helped us explore how different factors—like siting constraints or evolving technology cost reductions—might influence the ability to accelerate renewable and clean energy technology deployment,” said Brian Sergi, a co-author of the study.

Clean technologies must scale up quickly

As modeled by NREL, wind and solar energy would provide 60%–80% of generation in the least-costly electricity mix in 2035. The overall generation capacity would grow to roughly three times the 2020 level by 2035—including a combined 2 TW (terawatts) of wind and solar.

To achieve those levels would require an additional 40–90 GW of solar on the grid per year and 70–150 GW of wind per year by the end of the decade, said NREL. That is more than four times the current annual deployment levels for each technology.

If challenges arise around siting and land use restrictions, researchers said nuclear power capacity would help make up the difference. However, nuclear resources would need to more than double the current installed capacity.

Across four scenarios modeled by NREL, 5–8 GW of new hydropower and 3–5 GW of new geothermal would also be deployed by 2035. Energy storage between 2–12 hours of capacity would also increase, with 120–350 GW of capacity deployed by 2035.

NREL also said seasonal storage capacity in 2035 could range from about 100 to 680 GW. Seasonal storage is important when clean electricity makes up about 80%–95% of generation and a mismatch exists between variable renewable supply and demand.

Seasonal storage is represented in the study as hydrogen-fueled combustion turbines, but it could also include other emerging technologies.

In all scenarios, significant transmission is also added in many locations, mostly to deliver energy from wind-rich regions to load centers in the eastern U.S. As modeled, the total transmission capacity in 2035 is one to almost three times the current capacity. That would require between 1,400 and 10,100 miles of new high-capacity lines per year, assuming new construction were to start in 2026.

Clean energy benefits

In all modeled scenarios, NREL found that the health and climate benefits associated with fewer emissions exceed the power system costs to get to 100% clean electricity.

To decarbonize the grid by 2035, researchers said the total system costs between 2023 and 2035 would range from $330 billion to $740 billion. The scenarios with the highest cost modeled by NREL included restrictions on new transmission and other infrastructure development.

In the scenario with the highest cost, the amount of wind to be delivered to large population centers would be constrained, with more storage and nuclear generation deployed.

Overall, researchers said that as a result of the emission reductions and better air quality, up to 130,000 premature deaths would be avoided in the coming decades, saving $390 billion to $400 billion. Those totals would likely exceed the cost of decarbonizing the electric grid.

NREL said that when factoring in the avoided cost of damage from the impacts of climate change, a net-zero grid could save more than an additional $1.2 trillion.

“The benefits of a zero-carbon grid outweigh the costs in each of the more than 100 scenarios modeled in this study, and accelerated cost declines for renewable and clean energy technologies could lead to even larger benefits,” said Patrick Brown, another co-author.

Headwinds to decarbonization

NREL identified four key challenges that must be addressed in the next decade, through further research and other societal efforts, to enable full power sector decarbonization.

Dramatic acceleration of electrification

Electrification of some end-use energy services in the buildings, transportation, and industrial sectors is a key strategy for decarbonizing those sectors. NREL said increased electrification also increases overall electricity demand and the scale of the power system that needs to be decarbonized.

New energy infrastructure

This would include siting and interconnecting new renewables and storage at a rate three to six times greater than recent levels, which would set the stage for doubling or tripling the capacity of transmission, upgrading the distribution system, building new pipelines and storage for hydrogen and CO2, and/or deploying nuclear and carbon management technologies. The recently-enacted Inflation Reduction Act could jumpstart the deployment needed by making it more cost-effective.

Expanded clean energy manufacturing

The unprecedented deployment rates would require growth in raw materials, manufacturing facilities, and a trained workforce throughout clean energy supply chains. NREL said further analysis is needed to understand how to rapidly scale up manufacturing.

Continued R&D

NREL said technologies currently being deployed widely can provide most of U.S. electricity by 2035 in a deeply decarbonized power sector, but achieving a net-zero electricity sector at the lowest cost will take advances in research & development into emerging technologies—particularly to overcome the last 10% to full decarbonization.

NREL said getting from a 90% clean grid to full decarbonization could be accelerated by developing large-scale, commercialized deployment solutions for clean hydrogen and other low-carbon fuels, advanced nuclear, price-responsive demand response, carbon capture and storage, direct air capture, and advanced grid controls.

What about the new law?

The new report follows the enactment of the Inflation Reduction Act (IRA), which is estimated to reduce economy-wide emissions in the U.S. to 40% below 2005 levels by 2030. Initial analysis from the U.S. Department of Energy (DOE) estimates that grid emissions could decline to 68%–78% below 2005 levels by 2030.

NREL said the longer-term implications of the new law are uncertain, but they likely will not get the U.S. all the way to 100% carbon-free electricity by 2035.

None of the scenarios presented in NREL’s report include energy provisions in the IRA or the previously enacted infrastructure law, but researchers said their inclusion is not expected to significantly alter the 100% systems explored—and the study’s insights on the implications of achieving net-zero power sector decarbonization by 2035 are expected to still apply.

NREL’s study was funded by DOE. For more, here is a closer look.

DOE will partner with private companies to research advanced technology solutions that could make hydrogen a more available and effective fuel for electricity generation. This includes improving capture of carbon dioxide (CO2) associated with hydrogen production from carbon-based resources and technologies to more efficiently use hydrogen in gas turbines for electricity generation. The six projects will fast-track the development of technologies that will improve the performance, reliability and flexibility of existing and new hydrogen technologies, DOE said.

“Across the Department, we’re working to make clean energy sources — like hydrogen — more affordable and accessible to help decarbonize America’s electrical grid and directly combatting climate change,” said U.S. Secretary of Energy Jennifer M. Granholm. “The public-private partnerships announced … are paving the way for more domestic clean hydrogen production and use to support the President’s plans to combat climate change, accelerate clean energy use, and create good-paying clean energy jobs for Americans.”

Hydrogen can be produced through a variety of low-carbon pathways, including domestic resources like natural gas and waste coal, coupled with carbon capture and storage; biomass; and renewable energy sources. These qualities make it an attractive fuel option for electricity generation and industrial applications, such as in buildings and manufacturing.

DOE’s National Energy Technology Laboratory (NETL) under the purview of the Office of Fossil Energy and Carbon Management (FECM) will manage the selected projects:

8 Rivers Capital LLC (Durham, N.C.) will complete an engineering design study for a hydrogen production plant that produces 99.97% pure hydrogen and captures 90% to 99% of CO2 emissions, which will be transported and stored at Painter Reservoir Gas Complex in Evanston, Wyoming. (Award: $1,412,863)

Gas Technology Institute (Des Plaines, Ill.) will study the use of ammonia-hydrogen fuel mixtures in gas turbines to strengthen the use of ammonia as a clean low-carbon fuel for electricity generation. (Award: $3,000,000)

General Electric Company (Greenville, S.C.) will develop and test gas turbine components with natural gas-hydrogen fuel mixtures up to 100% hydrogen, to study and address combustion challenges associated with burning highly reactive hydrogen fuels. (Award: $5,986,440)

General Electric, GE Research (Niskayuna, N.Y.) will study the operation of hydrogen-fueled turbine components, which could substantially improve gas turbine efficiency for simple- and combined-cycle power generation applications. (Award: $6,999,923)

Raytheon Technologies Research Center (East Hartford, Ct.) will develop and test the effectiveness of natural gas turbine engine components in high-temperature rigs using natural gas-hydrogen fuel mixtures with increasing hydrogen content. (Award: $4,499,999)

Raytheon Technologies Research Center will study, develop and test an ammonia-fired gas turbine combustor that generates low nitrous oxide emissions, with robust operability and stability for greater than 99.99% efficiency. (Award: $2,999,219)

The Bipartisan Infrastructure Law is providing $8 billion for clean hydrogen demonstration and research hubs.

FECM funds research, development, demonstration and deployment projects to decarbonize power generation and industrial production to remove CO2 from the atmosphere and to mitigate the environmental impacts of fossil fuel production and use. Priority areas of technology work include point-source carbon capture, CO2 conversion, CO2 removal, reliable carbon storage and transport, hydrogen with carbon management, methane emissions reduction, and critical minerals production.

The U.S. Department of Energy (DOE) announced new funding aimed at improving the efficiency of hydrogen-fueled turbines that could one day be used in clean power plants.

The Department’s Office of Fossil Energy and Carbon Management (FECM) earmarked $4 million, which would fund several projects focusing on the research and development of ceramic matrix composite components, which allow hydrogen turbines to operate at higher working temperatures.

DOE said the effort would enable operations at 150°C higher than current ceramic matrix composite technology and 450 °C higher than existing nickel-based materials allow, while reducing the amount of cooling air required.

Electricity made from clean hydrogen—whether produced from renewable resources or from fossil or carbon-based waste resources, coupled with pre-combustion carbon capture and durable storage—will help in achieving the Biden-Harris Administration's goal of a zero-carbon U.S. power sector by 2035.

The Department said projects would be selected under two areas: Benchmark of CMC Performance with Predictive Modeling and Improvement to Temperature Performance of CMC Materials.

As the energy industry works to meet decarbonization goals, the advantages of hydrogen combustion include fuel flexibility, through the ability to burn hydrogen and fossil fuels like natural gas; fuel security through integration with hydrogen storage; the ability to meet large demands for electricity; and the flexibility to follow loads from variable generation.

Major OEMs in the power generation industry like GE, Siemens and Mitsubishi Power have been focusing their efforts on hydrogen combustion in gas turbines, particularly for large-scale generation.

The industry has developed materials and systems to increase the concentration of hydrogen that can be combusted. According to the U.S. Department of Energy (DOE), these advances have allowed hydrogen to be fired at concentrations over 90% in simple-cycle turbines or aero-derivative machines, and at concentrations of up to 50% in large-frame combined-cycle turbines.

But experts note while hydrogen combustion offers a promising energy storage and conversion pathway, it is not a “drop-in” fuel for much of today’s natural gas fired energy conversion devices.

According to the DOE’s hydrogen plan, though significant progress has been made, additional research, development and demonstration is needed to address issues such as auto-ignition, flashback, thermo-acoustics, mixing requirements, aerothermal heat transfer, materials issues, turndown and combustion dynamics, NOx emissions, and other combustion-related issues.

Those are the key findings in a new report from consultancy Wood Mackenzie. The project pipeline for both CCUS and low-carbon hydrogen saw record growth in 2021. The report said that developers were encouraged by increased net zero targets, new policy support and technology advancements.

More than $66 billion was invested in hydrogen in 2021, with projects looking at every aspect of the value chain from R&D to refueling infrastructure.

The report said the CCUS pipeline of announced projects grew seven-fold, with 50 new hub projects globally. The low-carbon hydrogen pipeline more than doubled, with green hydrogen projects making up 75% of the announcements.

Mhairidh Evans, principal analyst, CCUS and Emerging Technologies, and co-author of the report said, “We don’t believe we will see the same growth rate for the CCUS and hydrogen pipelines in 2022.

She said that the coming year will be about maturing projects and securing funding. Around 75% of the CCUS pipeline is in early development. For hydrogen, almost 40% of the project pipeline does not have an estimated date of operation and 25% lacks even an estimated capacity. Evans said that a mark of success for 2022 “will be more projects in advanced development or under construction.”

Wood Mackenzie said it is tracking 15 CCUS projects aiming for final investment decision (FID) this year. If developed successfully, they will add around 35 million tonnes per annum (Mtpa) of new CO₂ capture or storage capacity and would require investment of around $18 billion. The firm said that large volumes of CCUS capacity are not expected to come online in 2022.

Wood Mackenzie said more capital flow is needed for hydrogen production projects, requiring more offtake agreements. This could mobilize anywhere from $3.5 billion to $22 billion that the firm said is necessary for hydrogen production projects to reach FID in 2022.

In 2022, 33 projects – mainly in Europe and Asia – should begin operation. Those facilities would represent 0.1 Mtpa of low carbon hydrogen and 50 ktpa of green ammonia entering the market.

Wood Mackenzie also looked at the implications of the United States’ Build Back Better Act, which is stalled in the Senate due to opposition by Sen. Joe Manchin (D-WV). The report said that “significant investment hangs on the act passing Congress this year.”

In mid-December, Wood Mackenzie and the Solar Energy Industries Association said that logistical challenges and price increases in the solar supply chain could result in a 7.4 GW (25%) drop in solar installations for 2022 compared to previous forecasts. They said that passage of the Build Back Better legislation would help to mitigate that potential decline.

Flor Lucia De La Cruz, senior research analyst, Hydrogen & Emerging Technologies, said that 2022 likely will be an important year for translating policy into reality.

“It’s a tough political ask in some countries and we expect drawn-out negotiations to mean delays,” she said.

Technology scale-up will be crucial to maintain and build momentum for CCUS and hydrogen, the report said. Green ammonia has been hailed as one of the cheapest pathways to transport green hydrogen around the world but it, and hydrogen carriers in general, have their challenges.

Wood Mackenzie said it expects more technological solutions related to storage and chemical plant design in 2022. Direct Air Capture is expected to move from wildcard to reality, with drivers including $3 billion of funding through the Bipartisan Infrastructure Bill, growing demand for e-fuels and the growing voluntary carbon market.

Engineering work on the facility is underway, and Mote said it expects to produce around 7 million kilograms of hydrogen and remove 150,000 metric tons of CO2 from the air annually. The company said it could start production in 2024.

Through its process, biomass is heated in a limited-oxygen environment to above 1500°F, converting it to a mixture of gases. In a series of operations, the mixture is reacted, separated, and purified into hydrogen for sale as a transportation fuel and CO2 for storage. The remaining ash is sold as a fertilizer additive.

Mote said it is in talks with CarbonCure Technologies on the potential of permanently storing its CO₂ in concrete using CarbonCure’s carbon removal technology, which is used in CO₂ mineralization systems at concrete plants.

Engineering firm Fluor will support integrating equipment into the facility. And SunGas Renewables, a unit of GTI International, signed an Engineering Services Agreement to provide its gasification systems to the Mote California Central Valley Project.

Components for Mote’s process have been commercially operating in other industries, and are being scaled with the aim of reducing carbon at a lower cost than other carbon removal approaches.

Earlier this year, Mote was selected to be part of Rice University’s Clean Energy Accelerator. It closed a seed funding round this past fall with support from Preston-Werner Ventures, Counteract, and investor Joffre Baker.