45V or 45Q? How Tax Credits Will Influence Low-Carbon Hydrogen’s Development

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Clean hydrogen has emerged as a crucial tool to help decarbonize hard to abate economic sectors and achieve both climate and energy security targets. The Inflation Reduction Act introduced generous incentives to spur the growth of the emerging U.S. clean hydrogen sector. Two of these incentives—the 45V clean hydrogen production tax credit and the 45Q tax credit for carbon sequestration—are critical for projects that produce hydrogen from fossil fuels with carbon capture, utilization, and storage (CCUS), otherwise known as “blue” or low-carbon hydrogen.

A pivotal question facing project developers is which of these two tax credits will be the optimal choice to finance their projects. Ongoing debate over 45V policy trade-offs have often dismissed its applicability to low-carbon hydrogen projects due to restrictive emissions requirements. It is instead commonly assumed that low-carbon hydrogen projects will rely on the 45Q tax credit, which is calculated solely on the amount of carbon captured and sequestered. However, this is an open and continuously evolving question. Project developers will have to evaluate which credit is optimal on a case-by-case basis. Understanding how policy trade-offs will impact access to tax credit incentives is critical to ensuring that low-carbon hydrogen technologies are deployed while delivering promised climate benefits.

Reviewing the Lifecycle Emissions of Low-Carbon Hydrogen

The 45V tax credit is granted based on a project’s lifecycle greenhouse gas emissions per kilogram of hydrogen (kg CO2e/kg H2). Thus, understanding lifecycle emissions and the options available to mitigate them is essential to assess tax credit options. Emissions from natural gas-based low-carbon hydrogen can be grouped into three broad categories: direct emissions from hydrogen production; upstream emissions from feedstock sourcing, such as from methane leakage across natural gas supply chains; and indirect emissions from electricity sourced to power operations.

Direct Emissions

These will be principally addressed by CCUS, but carbon capture rates will vary by type of hydrogen production technology. Most of the hydrogen produced today in the United States is made via steam methane reforming (SMR) without carbon capture. Capture rates for SMR plants range between 30 to 50 percent since current plant configurations only capture emissions from synthesis gas (the hydrogen-rich gas produced by the SMR process) that contains about 50 to 60 percent of total plant CO2 emissions. To increase capture rates, developers will have to reconfigure SMR processes to also capture emissions from the flue gas produced by gas furnaces, which are used to generate the heat that drives the process. Others are opting for autothermal reforming (ATR) as an alternative process that uses some of the feedstock natural gas as an internal source of heat. This produces a single, less diluted stream of carbon to capture, yielding a higher capture rate potential. For example, ExxonMobil’s upcoming facility in Baytown, Texas, aims to reach capture rates as high as 98 percent by employing ATR technology.

Upstream Emissions

As CCUS progresses toward higher capture rates, a greater portion of low-carbon hydrogen’s lifecycle emissions will be attributed to the upstream emissions from natural gas supply chains. This category is perhaps the most challenging to address, owing to the highly dispersed nature of methane emissions across gas supply chains. Reported emissions based on field measurements also exhibit large spatial and temporal variability. One study frames this variability in a hydrogen context and concludes that low-carbon hydrogen produced using natural gas from the Permian Basin had an emissions intensity of approximately 7.4 kg CO2e/kg H2. This figure is twice that of low-carbon hydrogen produced using gas from the Marcellus Shale in the Appalachian Basin, which had an emission intensity of approximately 3.3 kg CO2e/kg H2. Importantly, only the latter would qualify for some 45V support.

The main policy drivers for cutting emissions from natural gas production and transmission will be the Environmental Protection Agency’s (EPA) new rule regulating methane from the oil and gas industry, as well as the Inflation Reduction Act methane fee and associated EPA reporting requirements. Policymakers and gas buyers are already examining ways to measure, verify, and reduce emissions across natural gas value chains. Implementation of the 45V tax credit could provide an added demand pull for the already burgeoning market for differentiated gas. A strong framework for differentiated natural gas will increase the transparency, accuracy, and verifiability of emissions, and could eventually support low-carbon hydrogen emissions accounting as well.

The 45V tax credit would present a similar boost for renewable natural gas (RNG), which could act as a feedstock with a lower carbon intensity than traditional natural gas. However, relying on RNG to reduce lifecycle emissions has attracted controversy. Advocacy groups argue that RNG offsets could end up stunting the deployment of CCUS for emissions mitigation. A proposed compromise suggests that RNG should be used exclusively to offset upstream emissions, thus preventing offsets from being used to “average out” direct emissions from hydrogen production.

Indirect Emissions

The last category of indirect emissions draws direct parallels to the ongoing debate over what constitutes clean electricity under the 45V tax credit. CCUS and reforming technologies require significant electricity to operate. The ATR process alone requires nearly three times more than SMR process. Project developers will therefore need to procure clean electricity if they want to maximize the value of the 45V tax credit.

Tax Credit Choice and Project Development

According to BloombergNEF, low-carbon hydrogen currently costs $1 per kilogram (kg) to $2 per kg more than incumbent hydrogen production from unabated fossil fuels. Project developers will rely on tax credits to bridge this gap. The key question is how developers will choose between the 45V and 45Q tax credits.

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On one hand, the 45Q tax credit is considerably more practical to access since it is granted solely on how much carbon a facility captures and sequesters. Project developers would be awarded up to $85 per metric ton of carbon captured and sequestered. This translates to as much as $0.80 per kg H2, commensurate with carbon capture rates. This tax credit is the best option for projects with capture rates of up to about 70 percent (see figure below), and the only option available for projects with high lifecycle emissions.

At the other end of the spectrum, 45V should be the tax credit of choice for all projects with lifecycle emissions below 1.5 kg CO2e per kg H2. These projects are granted a tax credit of $1 per kg H2, higher than what could be attained through 45Q. The Treasury Department’s proposed 45V guidance sets a fixed methane leakage rate of 0.9 percent for upstream emissions. Under this proposed rate, only projects with a capture rate of over 95 percent and which procure clean electricity to power their operations will be awarded the $1 per kg H2 credit (refer to figure). Treasury is currently seeking input on the technological readiness to verifiably measure and report upstream emissions values. Allowing operators to provide their own upstream emissions data raises the risk of misreporting as well as verification challenges. On the other hand, using a fixed value could mischaracterize upstream emissions that are highly variable across production basins and operators.

The more complicated calculations and trade-offs between tax credits will happen for projects with lifecycle emissions between 1.5 to 4 kg CO2e per kg H2. The fixed upstream emissions rate from Treasury’s initial guidance places projects with carbon capture rates of over 70 percent within this emissions bracket. Both tax credit values will range from $0.60 to $0.75 per kg H2, with 45V often offering a better incentive than the 45Q tax credit (see the figure below). Projects within this range will have to assess if the added logistical costs of procuring clean electricity and gathering the data to report project lifecycle emissions will be worth the slight tax credit boost offered by 45V. Developers may also opt for 45Q under specific circumstances, for example if a project’s lifecycle emissions fall just shy of a 45V emissions threshold, and capture rates are high enough for 45Q to grant a better incentive than 45V. This is exemplified by the 80 to 85 percent carbon capture rate range.

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Addressing the lifecycle emissions of low-carbon hydrogen from natural gas feedstocks will be an arduous task. Initial 45V guidance has fallen just short of laying the groundwork for developers to start reducing emissions along low-carbon hydrogen value chains. Big questions related to the use of differentiated gas and RNG as cleaner feedstocks for low-carbon hydrogen have been delayed until at least March, following a public comment period. And as noted, there is an open question related to the ability of developers to self-report their upstream methane leakage rates, as opposed to applying a fixed 0.9 percent rate across the board.

Tax credits for clean hydrogen production can be an arcane issue, but the fine distinctions over various tax benefits determine which types of projects qualify and which potential loopholes may emerge that shape net emissions outcomes. Mirroring the 45V dilemma for renewable hydrogen, Treasury has the unenviable task of striking a “strict but attainable” balance in its final guidance for low-carbon hydrogen from natural gas. Making it too strict will result in project developers falling back on the 45Q tax credit, which does not require them to reduce the lifecycle emissions of low-carbon hydrogen. Making it too permissive could result in a misrepresentation of low-carbon hydrogen’s emissions intensity, negating its climate benefits.

Mathias Zacarias is a research associate with the Energy Security and Climate Change Program at the Center for Strategic and International Studies (CSIS) in Washington, D.C. Joseph Majkut is the director of the CSIS Energy Security and Climate Change Program.

Former intern Kjersti Swanson contributed research support to this commentary.

Mathias Zacarias
Research Associate, Energy Security and Climate Change Program
Joseph Majkut
Director, Energy Security and Climate Change Program