Clean hydrogen is seen as essential for decarbonizing difficult-to-abate sectors of the U.S. economy, such as heavy manufacturing, chemical production and transportation. In power generation, hydrogen can be combusted in natural gas-fired engines or turbines.

These projects, funded by the Bipartisan Infrastructure Law, are intended to help advance electrolysis technologies and improve manufacturing and recycling capabilities for clean hydrogen systems and components. The projects are expected to enable U.S. manufacturing capacity to produce 14 GW of fuel cells per year, and 10 GW of electrolyzers per year – enough to produce an additional 1.3 million tons of clean hydrogen per year.

Managed by DOE’s Hydrogen and Fuel Cell Technologies Office (HFTO), these projects represent the first phase of implementation of two provisions of the Bipartisan Infrastructure Law, which authorizes $1 billion for research, development, demonstration, and deployment (RDD&D) activities to reduce the cost of clean hydrogen produced via electrolysis and $500 million for research, development, and demonstration (RD&D) of improved processes and technologies for manufacturing and recycling clean hydrogen systems and materials.  

The selected projects will address clean hydrogen technologies in the following areas:    

• Low-cost, high-throughput electrolyzer manufacturing (8 projects, $316 million): Selected projects will conduct RD&D in the effort to enable greater economies of scale through manufacturing improvements, including automated manufacturing processes; design for processability and scale-up; quality control methods to maintain electrolyzer performance and durability; reduced critical mineral loadings; and design for end-of-life recovery and recyclability.   
• Electrolyzer component and supply chain development (10 projects, $81 million): Selected projects will support the U.S. supply chain manufacturing and development needs of key electrolyzer components, including catalysts, membranes, and porous transport layers.    
• Advanced technology and component development (18 projects, $72 million): Selected projects will demonstrate novel materials, components, and designs for electrolyzers that meet performance, lifetime, and cost metrics to enable cost reductions and mitigate supply chain risks.
• Advanced manufacturing of fuel cell assemblies and stacks (5 projects, $150 million): Selected projects will support high-throughput manufacturing of low-cost fuel cells in the United States by conducting RD&D meant to enable diverse fuel cell manufacturer and supplier teams to flexibly address their scale-up challenges and achieve economies of scale.  
• Fuel cell supply chain development (10 projects, $82 million): Selected projects will conduct R&D to address deficiencies in the domestic supply chain for fuel cell materials and components and develop advanced technologies that could reduce or eliminate the need for per- and polyfluoroalkyl substances (PFAS), often referred to as “forever chemicals.”  
• Recovery and recycling consortium (1 project, $50 million): This funding establishes a consortium of industry, academia, and national labs to develop innovative and practical approaches to enable the recovery, recycling, and reuse of clean hydrogen materials and components. It will aim to establish a blueprint across the industry for recycling, securing long-term supply chain security and environmental sustainability.   

The fuel cell power system, which combines Kohler’s power generation control platform and system integration expertise with a fuel cell module from Toyota, can be used as a prime or back-up power source or as part of a distributed network.

Klickitat Valley Health

Klickitat Valley Health (KVH) is a hospital that serves as the principal medical center for over 10,000 people in their district.

The hospital previously announced plans to reinforce their electrical infrastructure including backup and secondary power generation that included a hydrogen fuel cell to ensure uninterrupted operations.

According to Ben Crawford, business development manager, Kohler Energy and Richard Ferguson, new markets manager, business development, Fuel Cell Solutions at Toyota Motor North America, this type of solution was a good fit for KVH.

“For installations such as healthcare facilities, resiliency is critical…The KOHLER Fuel Cell System features a Toyota Solid Polymer Electrolyte Membrane (PEM) fuel cell for high-efficiency energy conversion, and the system has been designed for fast start-up and exceptional transient handling.

“Kohler provides one-source responsibility for the generating system and accessories, with the fuel cell unit being prototype-tested and factory-built within Kohler facilities. This approach results in a highly optimized and scalable solution that is built to last.”

The fuel cell system

Toyota has consolidated various components from a second-generation Toyota Mirai passenger vehicle fuel cell system into a single, compact fuel cell module.

The newly created module includes the second generation’s improved fuel cell stack and the elements responsible for the generation of electricity (air containing oxygen and the gaseous hydrogen fuel), system cooling, and on-board power control.

“Toyota has been exploring various applications of our fuel cell technology and this opportunity with Kohler highlights the decarbonization opportunities that hydrogen as a fuel can provide for customers,” said Chris Yang, Group vice president, Business Development, Toyota. “Our fuel cell technology can be scaled and used to power a wide variety of products beyond transportation, and it does so without any emissions except water.”

Kohler will also complete the system integration and balance of the plant to ensure all supporting components and auxiliary systems needed to deliver energy operate together safely and reliably and within a turnkey package.

“Kohler is committed to investing in new technologies to help our customers achieve their resiliency goals without sacrificing their climate-related objectives, and fuel cells are a hugely promising opportunity – both on their own, and when combined with other complementary technologies for more flexible power strategies, such as microgrids,” said Charles Hunsucker, Kohler Power Systems president.

According to Ben Crawford and Richard Ferguson, on-site or emergency power is becoming more prevalent because every mission-critical facility needs back-up power.

“It is a fundamental building block of resilient energy supply.

“In some cases, highly efficient generators using renewable fuel, such as hydrotreated vegetable oil (HVO), represent the best solution for mission-critical applications. In other cases, it will be hydrogen fuel cell systems.”

Originally published by Power Engineering International.

The Inflation Reduction Act created two new credit delivery mechanisms—elective pay (or direct pay) and transferability—that are meant to help enable state, local, and Tribal governments; non-profit organizations; Puerto Rico and other U.S. territories; and other entities to take advantage of clean energy tax credits.

Until the Inflation Reduction Act introduced these new credit delivery mechanisms, governments, many types of tax-exempt organizations, and some businesses could not fully benefit from tax credits like those that incentivize clean energy deployment.  

“The Inflation Reduction Act’s new tools to access clean energy tax credits are a catalyst for meeting President Biden’s historic economic and climate goals,” said Secretary of the Treasury Janet L. Yellen. “They are acting as a force multiplier, bringing governments and nonprofits to the table for the first time and enabling companies to realize greater value from incentives to deploy new clean power and manufacture clean energy components. More clean energy projects are being built quickly and affordably, and more communities are benefitting from the growth of the clean energy economy.”

The Inflation Reduction Act allows tax-exempt and governmental entities to receive elective payments for 12 clean energy tax credits, including the major Investment and Production Tax (45 and 48) credits, as well as tax credits for electric vehicles and charging stations. Businesses can also choose elective pay for three of those credits: the credits for Advanced Manufacturing (45X), Carbon Oxide Sequestration (45Q), and Clean Hydrogen (45V). 

The Inflation Reduction Act also allows businesses to transfer all or a portion of any of 11 clean energy credits to a third party in exchange for tax-free immediate funds, so that businesses can take advantage of tax incentives if they do not have sufficient tax liability to fully utilize the credits themselves. Entities without sufficient tax liability were previously unable to realize the full value of credits, leaving only corporations able to take advantage of federal tax incentives. Final rules on transferability will be finalized in the near future.

Treasury’s elective pay final rules are intended to provide certainty for applicable entities to understand the law’s scope and requirements for eligibility. The final rules also lay out the process and timeline to claim and receive an elective payment.

Along with final rules on elective pay, Treasury today also issued a separate Notice of Proposed Rulemaking (NPRM) that is intended to provide further clarity and flexibility for applicable entities that that co-own clean energy projects and would like to utilize elective pay.

Under the IRA, entities treated as partnerships for federal tax purposes are not eligible for elective pay, regardless of whether one or more of its partners is an applicable entity. However, the proposed elective pay regulations clarified, and the final regulations confirm, that there are pathways for an applicable entity to access elective pay for credits it earns through a joint ownership arrangement including validly “electing out” of partnership tax treatment. Treasury and IRS agreed with commenters that existing guidance on making a valid election out of partnership tax treatment for clean energy arrangements was limited, and updates were needed for these arrangements to be more effective.

The section 761(a) NPRM issued provides a broader and more accessible pathway for applicable entities that co-own renewable energy projects to elect out of partnership tax status and therefore access elective pay. To qualify under these proposed rules, co-ownership arrangements must be organized exclusively to produce electricity from their applicable credit property, have one or more applicable entity co-owners that will claim elective pay, and meet certain other requirements.

Specifically, these proposed regulations would:

• Permit renewable energy investments to be made through a noncorporate entity, rather than requiring direct co-ownership of the property or facility by the applicable entity;
• Modify certain joint marketing restrictions to provide that multi-year power purchase agreements would not violate the requirements to elect out of partnership tax treatment.

This article was originally published on Renewable Energy World.

Firing existing boilers with hydrogen seems novel and new to many people. However, packaged boilers have been running on nothing but hydrogen for decades. Many boiler manufacturers have experience in dealing with hydrogen. They should be able to advise you on the peculiarities of burning it by itself or in combination with natural gas.

Hydrogen-based boilers are often found in refineries and chemical plants. The reason is simple. Hydrogen is often available in abundance in such facilities as a byproduct of other processes. Why waste hydrogen when you can harness it in boilers and eliminate fuel costs? But interest in hydrogen firing has broadened of late as one way to make progress toward decarbonization goals. Those running their boilers on natural gas, for example, can introduce some hydrogen into the mix to lower carbon emissions. In some cases, that may require a retrofit. Here are some points to consider for those interested in adding hydrogen to existing boilers.

Possible boiler modifications

There are certain technical factors that must be considered related to the combustion of hydrogen and how it compares to other fuels. Natural gas is denser than hydrogen. Hence, facilities will need a lot more of it by area than natural gas. This impacts the size of storage vessels and metering stations as well as diameter of piping and the size of valves. Valves and seals may also have to be replaced to prevent leakage. Those responsible for the design of the hydrogen supply system should be tasked with providing systems that can accommodate the higher volume of gas needed at the desired pressure and obtain the necessary BTU input for the boiler.

Pay attention, too, to impurities and water content in the hydrogen supply as they can shift the Wobbe Index of the fuel. While natural gas and hydrogen can have a similar Wobbe Index, the presence of a small amount of water, natural gas, or carbon dioxide can significantly lower the Wobbe Index.

Further, hydrogen combustion produces larger amounts of water than natural gas as a byproduct. Drainage systems and drying measures should take this factor into account. Coordination with burner manufacturers should help determine if any modifications may be needed to support the combustion of hydrogen.

Environmental systems

Environmental bodies now consider methane as a greenhouse gas as its combustion produces CO₂, sulfur dioxide, and nitrous oxide (NOx). By adding hydrogen to natural gas, CO₂ emissions can be reduced. However, hydrogen combustion does produce NOx as the peak flame temperature of hydrogen is higher than that of natural gas. Thus, hydrogen blending may lead to issues in meeting NOx targets. Some facilities may need to add flue gas recirculation (FGR) and selective catalytic reduction systems (SCR) to reduce NOx emissions from boilers blending hydrogen with natural gas.

Safety systems

The explosive range of hydrogen is greater than that of coal and natural gas. While methane ranges from a lower explosion limit (LEL) of 5% to an upper explosive limit (UEL) of 15%, hydrogen’s LEL is 4% and its UEL is 70%. Safety systems, therefore, will need to be upgraded to prevent leakage and mitigate the risk of explosion.

Consider, too, that some boiler components materials may have to be upgraded. Engineers should check the superheater and reheater for metal overstress and make any necessary surface adjustments. Depending on the distribution of heat transfer surfaces, higher or lower attemperation will also be required.

To keep retrofit costs down, packaged water tube boilers are probably the easiest type of boiler to gain experience in hydrogen combustion. Their flexibility and straightforward design simplify the addition of hydrogen while keeping risk relatively low.

Anyone moving forward with a feasibility study on a boiler retrofit for hydrogen is advised to conduct an evaluation of the entire boiler system. This should include all combustion equipment. It should examine potential changes in heating surfaces such as superheaters and reheaters, the possible addition of flue gas recirculation, attemperator capacity etc. As well as reviewing fans, air heaters, air ducts and overfire air systems, it should also encompass boiler control and automation systems, including the burner management system as upgrades may be needed there.

Certainty of hydrogen supply

Anyone wishing to fire their boilers with a blend of hydrogen better pay attention to supply. Hydrogen is far from widely available. There are projects that are receiving government funding to produce hydrogen using an electrolysis process. If a hydrogen electrolyzer exists or is being planned in your area, that may be one way to ensure regular supply.

Note that there are already plenty of gas turbines around certified to be able to run on 25% or more hydrogen. However, many of them continue to operate on 100% natural gas. Why? There isn’t any hydrogen available or if it is, the price tag is too high for boiler operation. Therefore, before investing heavily in hydrogen-related modifications to lower your carbon footprint, pay attention to the availability of hydrogen supply.

About the Author: Gerardo Lara is Vice President Fired Boiler Sales at Rentech Boiler Systems, Inc. of Abilene, TX. For more information, visit www.Rentechboilers.com.

The Cavendish NextGen Hydrogen Hub draws solar power from a nearby FPL site, using electrolysis to produce hydrogen.

The hydrogen produced will be compressed, stored and mixed into existing natural gas infrastructure at FPL’s Okeechobee Clean Energy Center, a 3-on-1 combined-cycle plant with a capacity of approximately 1622 MW.

FPL has said a 5% blend of hydrogen will initially be tested in one of the three natural gas combustion turbines on site.

The utility called the hub an important pilot project that allows FPL “to learn more about clean fuels and their potential benefits to customers.”

Florida Power & Light aims to fully decarbonize its power generation assets by 2045.

Almost 50 environmental justice groups on Tuesday sent a letter to leaders of the federally-funded Midwestern hydrogen hub, imploring them not to try to loosen requirements for tax incentives for hydrogen produced with clean energy.  

The U.S. Treasury in December published draft rules saying that to receive lucrative 45V tax credits for producing clean hydrogen, the energy used must not be diverted from the grid, but be “additional” energy created specifically to power the electrolysis process used to produce pure hydrogen from water. 

Environmental advocates are largely pleased with Treasury’s draft rules, which also say clean energy must be generated around the same time and near where it is used for hydrogen production, to reap incentives. But organizations are worried that industry groups are lobbying to weaken the draft rules, which are open for public comment through Feb. 26. 

The Midwest Alliance for Clean Hydrogen (MachH2), a coalition of industry and research groups that won up to $1 billion in Department of Energy hydrogen hub funding, has proposed to produce much “pink hydrogen” powered by nuclear energy from Illinois. Critics say this, as well as “green hydrogen” produced with solar and wind, could divert zero-emissions power from other users and hence prolong the lives of fossil-fuel-fired generators that fill the gaps. 

“If MachH2 imperils the achievement of our states’ climate goals, harms the health of our communities, and causes electricity price spikes that disproportionality impact low- and moderate-income households, it will face stiff opposition from our coalition and from communities that will bear the brunt of harmful, and avoidable, pollution,” says the letter from 47 organizations, including We the People of Detroit, Interfaith Power & Light, North Dakota Native Vote, StraightUp Solar, the Sierra Club, Eco-Justice Collaborative and Illinois People’s Action. 

MachH2 declined to comment for this story. 

Three pillars 

The environmental and justice groups praised the draft 45V rules for including “three pillars” the groups see as crucial to making sure “clean hydrogen” is truly clean. Those pillars mean clean hydrogen production tax credits will only be awarded if new clean energy is used to power the projects, and the clean energy can actually be delivered to the site of the electrolysis around the time it is needed. The draft rules say that to be considered “additional,” the energy source must have been built within 36 months before the hydrogen production goes online. 

Accounting known as hourly matching, which can be verified with Environmental Attribute Certificates, ensures that hydrogen production isn’t removing clean energy from the grid that could be used by consumers at times of high demand.

A 2023 study by researchers at Princeton University’s Center for Energy and the Environment modeled the emissions impact that hydrogen production by electrolysis would have in the western U.S., and found that all three “pillars” would be necessary to ensure overall emissions don’t exceed fossil fuel generation. 

The environmental justice organizations’ letter notes that the EPA has supported the Treasury department’s decision that induced emissions on the grid — caused by replacing electricity diverted for hydrogen production — should be counted as indirect emissions of hydrogen.  

“Backsliding on Treasury’s proposed rule… would lead to significant emissions increases from hydrogen production, in violation of 45V’s statutory requirements,” said the organizations’ letter. “It would also directly harm communities that are home to some of our states’ dirtiest power plants, which would run more to replace the zero-carbon energy diverted to hydrogen production.” 

Lauren Piette, a senior associate attorney in the clean energy program for Earthjustice, said, “The important thing now is to make sure Treasury holds the line against pressure to weaken the rules.” 

Treasury asked for comment on possible exemptions to the additionality requirement, including the possibility that existing nuclear and hydroelectric plants could receive the tax credit, or that existing plants could get the tax credit if it helps them avoid retirement. Advocates have called these possible changes in the rules “loopholes.” An analysis by the Rhodium Group found these exemptions would generally increase greenhouse gas emissions, compared to modeling under the rules without exemptions. 

“Treasury needs to reject the loopholes industry is demanding, which would create enormous subsidies for dirty hydrogen, lock in more fossil fuel production and use, and increase dangerous health and climate-harming pollution,” Piette said. “Especially damaging would be any loopholes to the incrementality requirement, which are based on industry’s speculative claims about retirement risk, curtailment, and modeling. Such loopholes would reward the hydrogen industry for siphoning critical zero-carbon energy from the grid, creating a massive power demand that would be filled by our dirtiest power plants – the ones that should be retiring, not ramping up.”

The letter charges that if the three pillars aren’t mandates for receiving tax incentives, the electricity diverted from the grid to hydrogen production will cause consumers’ energy bills to spike. They point to cryptocurrency mining as an example of how this phenomenon has played out. 

“Cryptomining, which is subject to minimal constraints and requirements, has increased utility bills by tens to hundreds of millions of dollars for households and businesses in upstate New York and led to costly grid strains in Texas,” the letter says. 

Industry arguments 

BP’s Whiting oil refinery in Northwest Indiana is a focal point of the proposed Midwest hydrogen hub, as the company plans to ramp up hydrogen production at the site and provide it to regional users. BP asked the Treasury department to allow hydrogen made from existing generation to receive tax credits. 

“We encourage the IRS and Treasury to adopt flexible criteria on ‘additionality’ especially at this nascent stage,” said BP America’s comment to the IRS. “Strict additionality rules requiring electrolytic hydrogen to be powered by new renewable energy is not practical, especially in the early years, and will severely limit development of hydrogen projects.” 

BP and other members also argued against the requirement for hourly matching of renewable energy generation to use in hydrogen production, arguing instead for yearly matching. The draft rules currently allow for yearly matching until 2028, then hourly matching becomes mandatory. 

“Stringent requirements such as hourly zero-emission matching have the potential to devastate the economics of clean hydrogen production,” said BP’s comment. “Moreover, such restrictive requirements are likely not practical or feasible in these early stages. If a green hydrogen production facility can only produce during hours when wind and solar are available, the low utilization rate will dramatically increase the price of the hydrogen produced.” 

Bloom Energy Corporation, which manufactures electrolyzers, also said that adequate technology does not exist to timestamp energy generation and use in order to ensure that clean energy is generated when it is needed for hydrogen production. 

“Since electrolyzers will comprise a very small percentage of the overall EAC-qualifying energy produced for many years to come, there is ample time for those state, regional and voluntary bodies to work through their stakeholder processes and make any changes as needed to adjust those systems so as to avoid unintended outcomes,” said Bloom Energy in its comment, referring to Environmental Attribute Certificates.

The Princeton study noted that hourly matching can add considerable costs to hydrogen production, but said the 45V tax credit would be lucrative enough to compensate for those costs while driving the market development of better hourly matching mechanisms.  

Constellation Energy, owner of Illinois’s nuclear plants, also supported a mandate for hourly matching.  

“Setting an expectation of hourly matched clean energy will provide a market signal for the clean energy investments needed to further drive decarbonization in the power sector,” said the nuclear company’s comment. 

But Constellation is asking for exemptions to additionality, asking the government to decide that hydrogen made with behind-the-meter generation from existing plants qualifies for tax credits. The MachH2 hydrogen hub proposal calls for an electrolyzer on the site of Constellation’s LaSalle nuclear plant in Illinois, which could provide behind-the-meter electricity. But this electricity would still represent clean power that otherwise could have been sent to the grid, critics say. 

Constellation also argued against adding carbon emissions related to the nuclear supply chain when calculating hydrogen’s lifecycle greenhouse gas emissions. 

“Measuring carbon content for nuclear fuel is not typically done by the mining, enrichment, fabrication and transport vendors in the nuclear fuel supply chain, and it would be extremely cumbersome, costly, and labor intensive to impose these requirements on said vendors,” Constellation said.

An EJ platform for hydrogen 

The letter to MachH2 comes as grassroots groups and environmental organizations are increasingly organizing around still murky but well-funded plans for hydrogen to be used in everything from power generation to steelmaking to transportation, including as part of the seven federally-funded hubs. 

On February 1, the national collaborative Just Solutions Collective released an Environmental Justice Platform on hydrogen, demanding strict limits on the type of hydrogen production and use that is incentivized as part of a clean energy shift. 

The organization says hydrogen production from natural gas, and hydrogen produced with power from the grid, should be “ruled out” since “fossil fuel-based hydrogen fails to reduce greenhouse gas emissions,” by many estimates. They also demanded strict safety protocols around new hydrogen development, strident protections for water resources, protections around chemicals added to hydrogen fuels, and transparency in all hydrogen-related projects. 

Just Solutions leaders hope their platform influences policymakers and also helps community groups more effectively weigh in on plans for expanding hydrogen, including as the U.S. Department of Energy invests $7 billion in the seven hydrogen hubs nationwide. 

“The framework is meant to be a resource for climate and environmental justice advocates so they can advance clean energy technology that meaningfully addresses the climate crisis and to stop false solutions from taking root in our communities,” Just Solutions senior fellow and strategist Sylvia Chi said in a January webinar. 

Environmental justice organizations in other parts of the country have also opposed hydrogen hub plans. Last summer Indigenous, environmental justice, and youth groups urged the Biden administration not to fund a hydrogen hub based in Colorado, New Mexico, Utah and Wyoming, and that proposal was not among the seven selected.   

“DOE is saying a lot of the right things, but there is widespread concern that environmental justice is going to be set off to the side and figured out later, after contracts are signed and projects are approved,” said Piette. “We have yet to hear a clear answer on whether communities will be able to say no to a Hub project. DOE needs to give its own guidance teeth and hold Hubs accountable to local communities, especially those already experiencing cumulative burdens of decades of fossil fuel pollution.”

Excess energy

The Institute for Energy and Environmental Research (IEER) produced a report released in January commissioned by the Just Solutions Collective.

The report points to a pilot program in New York state where the Nine Mile nuclear plant is powering hydrogen production. While the nuclear power is zero emissions, it displaces energy from the grid that, when replaced by New York’s natural gas-heavy energy mix, increases overall greenhouse gas emissions. 

IEER argues that the ideal place for zero-emissions-produced hydrogen is in areas like California and Texas where there’s often much more wind or solar power available than the grid can handle. These renewables are regularly curtailed, or kept off the grid, simply going to waste. A possible exemption to the additionality requirement for tax credits that Treasury has floated includes existing generation during times that renewables would be curtailed. 

The IEER report estimates that curtailed renewables at current levels could produce 34,000 tons of hydrogen annually in California, and 150,000 tons in Texas. And the availability of renewables in those and other states is only expected to increase. 

The environmental justice organizations’ letter similarly says that in the Midwest, MachH2 could successfully procure new renewables to power green hydrogen production. 

“The MachH2 hub is one of the best situated in the country, able to take advantage of excellent wind and solar resources in the Midwest,” the letter says. “With the anticipated buildout of new renewable energy in this region, the projects funded by the hub will have no difficulty procuring cost-competitive, new, hourly-matched power from the proposed deliverability zone to claim the 45V tax credit.”

This article first appeared on Energy News Network and is republished here under a Creative Commons license.

Hydrogen, as an alternative fuel for gas turbines, will play a role in decarbonizing traditional power generation, however, concerns have been raised by industry leaders about whether there is a sufficient supply of green hydrogen to sustain this green transformation.

“I get into conversations about hydrogen co-firing [and] the thing that comes up almost every time is ‘are we really going to have supply’?”

This was the question posed by Jason Jermark, vice president of Global Services Operations at Siemens Energy, who refers to the hydrogen supply issue as the “elephant in the room”.

Jermark was joined by industry heavy hitters, such as Jeffrey Goldmeer, Emergent Technologies Director – Decarbonization, GE Vernova and Benjamin Thomas, senior manager of Hydrogen Production Engineering of Mitsubishi Power Americas for a panel discussion on the future of gas turbine decarbonization.

Decarbonizing gas assets with hydrogen and ammonia was front and center of the discussion at POWERGEN International, which took a candid turn to explore some of the headwinds facing the sector.

Hydrogen as an alternative

“To be honest, years ago I was skeptical of it,” said Jermark.

“If you think about the scale that’s going to be required, to be able to support the vast amount of [gas] generation that we have, is it going to be possible… and is this really the best use of the hydrogen molecule?”

According to Jermark, there has been a four-fold increase in hydrogen supply projects globally in the last few years. An increase in projects in action and an increase in the speed of production prove the industry is asking for hydrogen to future-proof generation, he suggests.

“Because of the continued interest in the production front, it leads us to believe the supply will happen.

“It may not happen at the scale and speed that some would like, it also may happen in pockets, based on local availability, but it is going to be there.”

Hydrogen as an alternative to gas is not new. Siemens Energy has been using hydrogen in various applications for over four decades, with about 2.5 million operating hours accumulated across that time frame.

The market is maturing, said Jermark, spurred on by the [Inflation Reduction Act] and applicable tax credits in the US, as well as other carbon tax regulations in the EU and Asia.

However, even if supply is available, the panelists questioned whether hydrogen in co-firing is the best use of the molecule.

The role of ammonia

Jermark stated that while the hydrogen gas turbine market is more mature than ammonia, ammonia has a higher energy density and a broader available network to transport it.

“Ammonia is also an interesting application…there’s a lot of discussion about using it as alternative co-firing for gas turbines – our focus is how can we have the infrastructure in place to be able to transport it.”

Benjamin Thomas added that the outlook is quite complex in Japan, where LNG is currently being imported. The country needs products that can work in a variety of situations. There are different grid profiles to respond to in Japan, as wind and solar are developed, which is why there is a big focus on developing ammonia, a big focus for countries without a large hydrogen supply.

Also, in South Korea, a country focused on decarbonizing its gas-fired combined cycle plants, it’s critical to secure the hydrogen required and to transport it effectively. “The best way to do that is with ammonia as the carrier,” added Thomas.

Thomas explained that this drive for decarbonization is opening up opportunities for partnerships and wider developments such as that of zero carbon propulsion systems, providing support for the international maritime organization remit in reducing emissions.

Jeff Goldmeer highlighted that when it comes to ammonia, there is a technology challenge and an economics challenge.

“Study after study has shown that if you want to move hydrogen over long distances, you don’t want to do it as hydrogen, you need to move it as another molecule.

“Ammonia tends to be one of the simplest and cheapest molecules, a lot of people want to talk methanol but then you need to source carbinol. Ammonia just needs nitrogen, which is easily available.”

According to Goldmeer, from an economic perspective, ammonia makes the most sense.

There are technical challenges, however, emphasized Goldmeer. “We acknowledge ammonia does have a toxicity issue,” adding that even small amounts of ammonia will create a NOx problem.

“You need to be 99.9% ammonia-free in your hydrogen to avoid a NOx problem, so face the NOx problem and say I need a new combustor.”

Despite these technical challenges, Goldmeer and the other panelists agreed that there’s a well-established industry in the production and safe use of ammonia.

Currently 15-20 million metric tons of ammonia are moved by ship around the world and many ports already have ammonia bunkering capacity, proof of the molecule’s technical and economic viability.

No matter the molecule or path to decarbonization, the industry experts agreed that it’s a complicated journey and requires time and collaboration.

Concluded Jermark: “I don’t think there’s a one-size-fits-all answer [to that] which is why the situation is so complicated.”

Listen to this episode of the Energy Transitions Podcast with Javier Cavada, President and CEO of Mitsubishi Power EMEA, for insights into achieving speed and scale in decarbonizing generation.

On. Dec. 22, 2023, the U.S. Department of the Treasury and the Internal Revenue Service issued guidance for claiming the 45V Clean Hydrogen Production Tax Credit, established under the Inflation Reduction Act (IRA). This Treasury guidance comes three months after the announcement of seven new regional hydrogen hubs backed by $7 billion in funding with the intent to leverage $40 billion in private co-investment.

Establishing a functioning hydrogen economy is not without challenges that could impact the extent of future deployment. The Infrastructure Investment and Jobs Act (IIJA) was designed to kick-start renewable energy and carbon mitigation projects across the U.S., while the IRA was meant to serve as the economic engine. As we look toward a future that incorporates hydrogen energy production into the larger energy industry, we can expect some of the following opportunities and challenges:

1. The Treasury guidance to qualify for 45V Clean Hydrogen Production Tax Credit is surprisingly restrictive. Unlike the ethanol industry, in which Congress defined the playing field, Treasury took a more active role defining qualifications. The department was careful in its consideration to avoid any potential for this infrastructure deployment to negatively impact carbon emissions. The primary mechanism chosen to achieve this goal was through an “additionality” requirement, which avoids displacing other existing renewable energy. Compliance will be established through time-matching renewable generation with real-time utilization starting in 2028.
   
   Unfortunately, the initial guidance did not incorporate the use of existing nuclear power for electrolysis. A conflict arises because one of the hydrogen hubs awarded by the Department of Energy (DOE) relies on the use of existing nuclear power.
   

2. The DOE hydrogen hub awards provide less cost share per project. When DOE announced the allocation of $7 billion to support seven hydrogen hubs, it specified that the funding would supplement a $40 billion co-investment by the awardees. This 15% federal financial co-investment for projects under the hydrogen hub program is unlikely to support the many projects seeking funding, especially when compared to the 50% cost share anticipated by many project participants. This may require DOE to reevaluate the cost share portion or risk canceled projects.

For hydrogen hubs that received awards, those not formally selected or hubs that choose not to participate in the DOE grant program, a potentially more advantageous option is to engage with the DOE Loan Program Office (LPO). Currently, this program is well-funded and actively seeking to assist larger projects moving forward. For example, steam methane reforming (SMR) or autothermal reforming (ATR) with carbon capture projects typically have adequate scale exceeding $200 million to benefit from an LPO program loan.

3. Blue ammonia production is an emerging winner. Blue ammonia refers to ammonia produced from clean hydrogen using the Haber-Bosch conversion process. The hydrogen feeding the process is produced from SMR or ATR, employing natural gas as the feedstock and capturing emissions via carbon capture technology. Japan, South Korea and Singapore are executing strategies to import and utilize clean ammonia as a key component of their decarbonization strategies to meet their COP28 commitments. Energy providers in these countries have now demonstrated and successfully burned pure ammonia directly in boilers. Use of ammonia as a fuel creates the potential to establish dependable, long-term supply contracts with strong financial backing. Businesses and residents in these countries already face higher fuel prices, so the premium for clean ammonia is relatively lower when considered as a percentage of the total costs. What makes this market particularly intriguing is the potential to thrive without being entirely reliant on IRA of 2022 hydrogen production tax credits or DOE cost-sharing initiatives.

4. The economic models that worked several years ago won’t work today. Many industries continue operating in a market constrained by supply chain disruptions, significant inflation and higher interest rates. The project economics, which were originally calculated during the hydrogen hub application process, may no longer align with market realities. While some elements of project capital costs are nearly 40% higher than pre-COVID levels, developers and energy providers face the additional burden of increased costs driven by higher interest rates. Unfortunately, under the IRA, hydrogen production tax credits can’t be adjusted for inflation until 2026, meaning the potential for hydrogen tax credits to track inflation won’t improve for a few years.

5. Integrating hydrogen into a gas pipeline is onerous due to leakage. Research conducted by the Argonne National Laboratory (ANL) has found that hydrogen’s propensity to increase distribution system leakage is a limiting factor for blending hydrogen into natural gas transmission lines feeding residential utilities. When an operator incorporates a 30% hydrogen blend into the pipeline and does not modify the flow rate, emissions from gas transmission lines should remain relatively stable. This, however, does not deliver equivalent heating content to gas system users, such as household appliances. Per ANL, establishing an equivalent heat content with a 30% hydrogen blend can increase fugitive emissions by 100%. Hydrogen possesses one-third of the energy density of methane, requiring operators to replace a standard cubic foot of gas with 3 standard cubic feet of hydrogen to deliver the same energy to end users. This replacement necessitates a 30% increase in pipeline flow rate, a 70% increase in pressure and a twofold increase in compression power. While not as high as methane, the global warming potential of fugitive hydrogen emissions is still substantial. 

6. EPA is leveraging regulatory action to create significant hydrogen demand through rulemaking on greenhouse gas standards and guidelines for fossil fuel-fired power plants. In a recent request for additional comments on the impact on small communities, EPA showed its hand on current cost impact analysis with assumptions that most in the industry would identify as overly aggressive for hydrogen production costs as less than natural gas. Notably, EPA presumes the realization of a $3 per kg clean hydrogen production tax credit.

7. Use of dedicated renewable electricity to power electrolyzers still likely to occur in specific applications. These applications are likely to be co-located near demand modes. Many of these projects are likely to be pilot or demonstration sized systems with ability to expand production as demand increases.

Initial customers and industry leaders willing to pay a premium for hydrogen generated via electrolysis, or hydrogen-produced “green” ammonia, will likely come from the transportation and maritime sectors. Another consideration favoring electrolyzers is that alternative hydrogen production technologies require a massive scale that likely doesn’t match well with the demand from early adopters.

While attention to hydrogen has grown with the announcement of the hubs and the Treasury guidance, improving financial and operational strategies will be necessary to move the hydrogen industry forward. It’s our job as an industry to continue to help educate and engage DOE, EPA and Treasury, providing clear feedback on the challenges and opportunities in front of us in order to get this right.

About the Author: Grant Grothen is a principal and business development manager at Burns & McDonnell. Over a 30-year career, Grant has consulted with utilities throughout North America, Europe and Asia on nuclear, renewable and fossil generation resource issues, including air quality control and water and wastewater systems.

The company unveiled a new Hydrogen Testing Facility for validation of its NovaLT industrial turbines meant to run blends all the way up to 100% hydrogen, it said. The new facility includes a test bench to allow full load testing, with complete fuel flexibility up to 100% hydrogen, and features a 300-bar pressure and 2,450 kg storage capacity. Baker Hughes says this infrastructure allows it to test turbines in all project conditions, and it will later serve as a hub for Baker Hughes’ collaboration with customers in the hydrogen economy.

Baker Hughes also recently completed manufacturing and testing of its NovaLT16 hydrogen turbines for Air Products’ Net-Zero Hydrogen Energy Complex in Edmonton, Canada. The NovaLT16 turbines underwent full load testing at the new Hydrogen Testing Facility. This family of turbines can be deployed for a variety of industrial applications, including combined heat and power, as well as for pipeline and gas storage operations, the company said.

The company reported progress on another Air Products’ hydrogen project, with the delivery of the first two trains of hydrogen compression solutions for the NEOM project in Saudi Arabia, the largest green hydrogen project in the world through the equal joint venture of ACWA Power, Air Products and NEOM. Baker Hughes recently invested in expanding its manufacturing site in Modon, Saudi Arabia, to further support the delivery of projects in the country, including NEOM, with localized testing and packaging solutions.

The company also executed a collaboration agreement with HyET – a company that provides technologies for distributed power generation and hydrogen production at high pressure – for the development, industrialization, and commercialization of a hydrogen compression solution.

Baker Hughes signed a memorandum of understanding with Green Energy Park, a vertically integrated renewable energy company with ammonia and hydrogen terminal projects worldwide, and part of Green Energy Park Global group. The agreement aims to set out the principles of a potential collaboration between the two companies in multiple areas of the green hydrogen value chain, including production, storage, transportation, and utilization of green hydrogen and ammonia-based fuels, as well as exploration of possible co-development of related technologies and projects at the gigawatt scale.

Last August, Baker Hughes and airport management company Avports agreed to a memorandum of understanding to develop and operate onsite hydrogen-fueled microgrids at U.S. airports.

Earlier that year, NET Power announced a partnership with Baker Hughes as it works toward a commercial deployment of its near zero-emission power systems. Baker Hughes said it would supply its supercritical CO₂ turboexpanders and other pumping and compression technology for the NET Power plants. The energy tech company will also bring its system integration and process knowledge experience to help accelerate market deployment.

In a filing to the North Carolina Utilities Commission (NCUC), the utility forecasted even greater electricity demand than projected in the proposal last summer.

Duke said “new economic development wins, including manufacturing and technology projects across the Carolinas” make up the primary driver of the increased electric demand. The utility said annual demand expects to increase 22% by 2030 and 25% by 2035 from 2022 planning cycles — driven by
significant additional economic development activity that took place during 2023.

Notably, according to the Census Bureau, South Carolina’s population grew faster than any state’s in 2023.

“We’re already projecting eight times the load growth we anticipated just two years ago,” said Mike Callahan, Duke Energy’s South Carolina president.

Duke Energy put forth its original resource plan to regulators in August 2023. The company presented three portfolio scenarios but recommended one that achieves 70% CO2 emission reductions from 2005 levels by 2035.

MORE: Duke Energy proposes site for new nuclear in North Carolina

The company’s latest update, its “Portfolio P3 Fall Base,” introduces almost 6.8 GW of additional resources.

The adjustments include the following new proposed resources by 2031: 460 MW of new solar, 175 MW of storage to be paired with solar and 425 MW of new natural gas-fired combustion turbine capacity. The proposed changes also include 2,720 MW of natural gas combined-cycle (NGCC) capacity by 2033, 134 MW of pumped storage hydro by 2034 and 2,400 MW of offshore wind by 2035.

Duke said the new gas plants would hydrogen-capable, including a proposed combined-cycle plant to be built in South Carolina. The 2.4 GW of offshore wind would be built off the coast of North Carolina, subject to necessary regulatory approvals and support.

On Jan. 25, the Public Service Commission of South Carolina (PSCSC) approved Duke Energy’s proposal to provide the proposed adjustments and reset the previously approved regulatory schedule for the process. Under South Carolina’s IRP statute, that new schedule now plans for a hearing in mid-September. Regulators will order a path forward, likely in November 2024.