Re-published with permission by Burns & McDonnell

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.

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