Annual matching requirements for new IRA tax credits could jump-start economically competitive green hydrogen production

Written by Melany Vargas, Kara McNutt and Chris Seiple

Hydrogen can play a critical role in the United States’ journey to net zero as a low-carbon fuel to support the decarbonization of hard-to-electrify sectors of energy demand. The Inflation Reduction Act’s 45V production tax credit is intended to incentivize the development of low-carbon hydrogen by accelerating the learning curve and enabling cost reductions.

The highest tax credits for hydrogen with the lowest carbon content reach up to $3/kg. However, rules on how to measure the carbon intensity (CI) of hydrogen and the potential entitlement of emission offset mechanisms such as renewable energy credits (RECs) are still under development. These rules, currently set by the Treasury Department, could have significant impacts on the economic competitiveness of electrolytic or green hydrogen projects and on the CI and absolute emissions of electricity networks.

As a result, hydrogen CI timing has become a very hot topic in recent months in industry and policy circles. The discussion is largely focused on electrolytes that rely on grid electricity for all or part of their energy needs. Some organizations would like to see green hydrogen developers demonstrate that they are using 100% renewable energy by matching their electrolyte electricity consumption with hourly renewable energy production. Others argue that these requirements will limit the economics and development of green hydrogen projects.

Given the wide range of perspectives on the topic, Wood Mackenzie set out to test the impact of grid-connected green hydrogen generation. We examined the CI impacts of electricity grids and hydrogen production, as well as electrolyte device capacity factors in a REC-enabled scenario against an hourly matching policy where an electrolyte’s load would be matched to corresponding renewable energy generation profiles.

We leveraged proprietary electricity market and levelized cost of hydrogen (LCOH) models to analyze these impacts in two unique power markets, ERCOT South and WECC Arizona. In each market we assessed the impact of adding 250 MW of electrolysis capacity to the grid and assumed that hydrogen development occurred with commensurate generation of renewables to support the electrolyte load and generation of local RECs. This analysis is then compared to the case-based hourly production, pricing and emissions data we have for each market.

The economic implications are clear

Our analysis found that an annual matching scenario that allows RECs as an offset mechanism, can result in net zero CI and economically competitive green hydrogen production. Conversely, hourly matching requirements, depending on their application, could lead to unfavorable economics for the adoption of green hydrogen by limiting operating hours to those when renewable sources are available, ultimately reducing the capacity factor of the electrolyte. The result is that operators must spread their costs over a smaller volume of hydrogen production, requiring a higher price to recoup their capital for each kilogram of hydrogen sold.

With a direct hourly matching of renewable generation, our analysis shows that an electrolyte capacity factor ranging from 46-72% leads to an LCOH increase of 68%-175% over an annual matching scenario that allows operators to reach at a capacity factor of 100 %.

In the Arizona WECC market, the results are an LCOH (with a $3/kg tax credit) rising from about $2/kg in 2025 and $1.50/kg in 2030, in an annual matching scenario, to about $4-5/kg in an hourly matching script. This degree of cost increase could delay the ability to produce cost-parity green hydrogen to lower-cost blue or gray hydrogen, ultimately hindering the economic competitiveness and adoption of both grid-connected and 100% renewable green hydrogen as a fuel low carbon.

In contrast, modeling of an annual matching scenario shows that an electrolyte operating at 100% capacity factor, under an annual matching regime that allows for REC shifts, could achieve economics below $2/kg by 2025 and below $1.50 /kg in 2030 in both markets. This range of economics is consistent with blue hydrogen parity and supports DOE green hydrogen LCOH targets of $2/kg by 2025 and $1/kg by 2030.

CI implications are more complex

While the economics are more favorable in the annual matching scenario, there are a number of emissions and carbon intensity trade-offs to consider. In the case of annual matching, the electrolyte relies on grid electricity for 19 – 35% of electricity requirements. Although during certain hours the grid must draw more from thermal sources, the gradual generation of renewable energy sources also displaces peak-hour thermal energy from renewable sources, thereby reducing the CI of the grid. In 2025, network CI reductions of 0.2 and 0.5% are observed in the ERCOT and WECC regions, respectively.

However, there is a trade-off between CI and absolute emissions. The analysis shows that despite the lower CI, there is a marginal increase in absolute emissions in both the ERCOT and WECC markets due to the added demand source and increased installation of thermal units during low renewable hours. Furthermore, as power grids become greener, the benefits of incremental renewables additions to CI become smaller, and the increase in load leads to even greater pull on thermal plants during low renewables hours. As a result of this effect, the CI benefits observed in 2025 are smaller in 2030 and absolute emissions increase marginally in both markets.

Because of these findings, we explored sensitivities to test some mechanisms for mitigating increases in absolute network emissions and/or CI under an annual matching scenario. The analysis found that a slight overbuild of renewables or a strategic cut in hydrogen production during peak heat hours could be effective tools to minimize these unwanted emissions impacts in the 2020s.

In addition, annual matching requires REC offsets to result in a net zero CI for hydrogen production. At ERCOT South, the pre-displacement CI of green hydrogen produced is 4.3 kg CO2/kgH2 in 2025 and 3.4 kg CO2/kgH2 in 2030. At WECC Arizona, the CI, before offsets, is 7.9 kg CO2/kgH2 in 2025 and 4.7 kg CO2/kgH2 in 2030. In both cases, these carbon intensities are lower than the estimated 10 kg CO2/kgH2 CI estimate for gray hydrogen production, which could lead to significant decarbonization in target sectors for hydrogen adoption. However, these carbon intensities are also significantly higher than the zero CI of a 100% green hydrogen renewable energy.

Another key point is that this analysis focused on Texas and Arizona where renewable energy potential is high. More research is needed in these and other markets to fully assess the economic and emission offsets considered here. Results are expected to vary significantly on a regional basis and may also vary as hydrogen production scales well after a 250 MW electrolyte is added in an area.

Management of exchanges

Policymakers and regulators are faced with the difficult trade-off between carbon emissions and green hydrogen economics in the context of rapidly changing US energy markets. This early analysis shows that on a cost-effective basis, annual matching could be the catalyst the green hydrogen industry needs to support the early adoption and development of the nascent low-carbon hydrogen industry. When it comes to meeting climate goals, green hydrogen should be developed alongside other solutions, so the faster the adoption, the faster the benefits can be realized. After 2030, as wind, solar and storage generation supports lower carbon grids across the US and electrolyte costs decline, hourly matching could become a more appropriate mechanism to support 100% renewable green hydrogen production and decarbonisation of the electricity grid. tandem.

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