The United States is in the early stages of its clean hydrogen development strategy and already faces a critical decision juncture. The Inflation Reduction Act (IRA) introduced the 45V Hydrogen Production Tax Credit, which awards up to $3 per kg of hydrogen produced to projects with a lifecycle greenhouse gas emissions intensity of less than 0.45 kilograms per kilogram of hydrogen (kg CO2e/kg H2). Upcoming Treasury Department guidance will determine how emissions intensity of electrolysis-based hydrogen is calculated. Stakes are high. Missing out on the full credit value could determine the financial viability of electrolysis-based hydrogen. Meanwhile, climate goals depend on clean hydrogen to eliminate the sector’s 100 million metric tons of CO2 emissions per year. CSIS recently hosted a panel of experts to pick apart modeling efforts and explore the nuance of this trade-off. This piece expands upon that conversation and articulates a path towards sensible implementation of tax credit requirements.
Keeping Hydrogen Clean: The Case for Strict Guidelines
In a joint letter, a coalition of academics, energy companies, and environmental organizations presented a case for strict implementation of the clean hydrogen tax credit, arguing that weak guidelines would lead to an increase in net emissions and result in the subsidization of hydrogen with higher emissions intensity than current unabated natural gas-derived production methods. The coalition proposes a stringent emissions accounting system that hinges on three pillars: additionality, deliverability, and hourly time-matching.
Additionality would require the clean electricity sourced for hydrogen production to come from (1) new clean generation sources, (2) an increase in the rate of electricity production from existing clean generation, known as uprating, or (3) electricity from existing clean generation that would otherwise not have been produced, known as curtailed electricity. Deliverability would require electrolyzers to source clean electricity from within their same operating region. This limits the extent to which grid congestion might curtail the clean generation resource and drive a ramp up of a local fossil fuel resource to meet the electrolyzer demand. Lastly, hourly time-matching requires electrolyzers’ electric consumption to match clean energy production down to the hour. For example, an electrolyzer using solar power would need to ramp down overnight to match the solar array’s production curve.
A recent report by Energy Innovation finds that without these three standards in place, electrolytic hydrogen projects could end up emitting anywhere from 1.5 to up to 5 times the amount of greenhouse gas emissions than from current unabated fossil fuel-based production methods, which emit about 10 kg CO2e/kg H2. This increase in emissions intensity comes from the assumption that sourcing unmatched, nonlocal, and non-additional clean energy leads to the dispatching of emissions intensive marginal generation resources, such as coal- and natural gas-fired power plants, to serve the increased grid-wide demand. Burning fossil fuel resources to produce the electricity that powers an electrolyzer is considerably more energy intensive than directly converting these resources into hydrogen. The authors argue that it is through the implementation of the three pillars that these indirect emissions impact can be minimized.
Challenges and Detractors of Strict Guidelines
Mirroring the coordinated effort for stringent standards, hydrogen developers and energy companies have put forward statements of their own, with letters arguing against additionality requirements and for an annual rather than hourly time-matching approach.
The argument against additionality hinges on the idea that requiring it would add “unreasonable costs and delays for clean hydrogen producers.” The coalition points at the nearly two terawatts of solar, wind, and storage currently sitting in the grid interconnection queues and argues that additionality would not accelerate clean energy deployment past the interconnection bottleneck.
There are also concerns that mandating additionality would leave deployment at the mercy of interconnection queue timelines, slowing the needed scaling-up and derived cost reductions that hydrogen production, and in particular electrolyzer equipment, urgently needs. Lastly, the coalition posits that these added costs would further disadvantage renewables-based hydrogen when compared to fossil fuel-based hydrogen production with carbon capture and storage (CCS), which has the option to choose between the 45V tax credit and the 45Q tax credit for carbon sequestration.
Arguments for annual matching focus on costs savings, decarbonization viability, and practicality of implementation. Analysis by Wood Mackenzie found that an hourly matching requirement could be 60 to 175 percent more expensive than annual matching, based on the assumption that limiting electrolyzer operating hours will reduce its capacity factor and thus distributing costs over a smaller amount of hydrogen produced. Exactly how much additional cost is created by this requirement is a subject to debate. A Princeton study found cost concerns to be overstated, and that overbuilding renewables and selling off the excess clean electricity would greatly improve project economics. Other remaining costs concerns, as presented by the Rhodium Group, would include the need for electricity storage solutions in cases where the project would rather avoid sourcing electricity from the grid and in which the employed electrolyzer technology would require a steadier flow of clean electricity for operation.
On the emissions accounting front, a comparative study released by the American Council on Renewable Energy (ACORE) and Energy and Environmental Economics (E3) finds that out of 40 evaluated scenarios, 25 result in annual matching that yields lower carbon emissions than hourly matching, and 34 result in low enough emissions for projects to receive the full tax credit. The study’s guiding principle revolves around the idea that a slight overbuild of renewable energy needed for hydrogen production under an annual matching approach would offset the increase in carbon emissions from hydrogen production during hours in which said renewable energy is not available.
In contrast, all of the previously listed studies submit opposite findings, and the answer as to why that is the case may lie in the Princeton study. The ACORE and E3 study appears to only account for attributional emissions, or those directly linked to hydrogen production based on net electricity consumption, and fails to account for consequential emissions, which include “long-run electricity system-level emissions” considerations, e.g., the impact of new loads on marginal emissions. This results in an overbuilding scenario that does not account for electricity market demand forces and leads to future disinvestment in plants that offer similar services to the grid, i.e., other renewables. Hourly time-matching schemes would appropriately address both attributional and consequential emissions concerns.
Lastly, there are concerns with regards to the feasibility of implementing hourly versus annual matching. Although multiple initiatives offering hourly energy attribute certificates (EACs) have emerged in recent years, these resources are not uniformly available across the nation, so challenges to equitable implementation and data procurement from utilities and power companies remain. Nevertheless, requiring hourly time-matching in the near term could compel otherwise reluctant actors to partner with third parties in order to prop up the requisite systems. Energy Innovation envisions that hourly matching implementation could be “feasible and administrable” by 2026.
Emerging Compromises and Guidance from Abroad
In recognition of the challenges attached to the nationwide implementation of an hourly matching scheme, calls for a phased-in approach have started to emerge. In recent analysis, the Rhodium Group proposes that instead of fixating on the time-matching challenge, the Treasury Department could instead focus on implementing the “low-hanging fruit” aspects of the guidelines: (1) regional market deliverability that matches clean electricity with hydrogen production, (2) annual matching that makes use of existing tracking systems, and (3) additionality requirements that are easy to implement, such as in-service dates requirements for new clean generation. These would allow for the continued deployment necessary to catalyze scale-derived hydrogen production cost reductions while keeping deployment as low emissions as practically possible, allowing the industry a grace period to prop up the systems required for further emissions accounting stringency.
A glance at the hydrogen incentive strategies implemented by international players provides valuable lessons and guidance for U.S. implementation. The European Commission recently released its definition for renewable hydrogen to guide its contracts for difference (CfD) hydrogen subsidies while outlining a phased-in approach to the standards discussed above. On additionality, the European Union sets requirements for renewable electricity to begin operation “not earlier than 36 months” from the start of hydrogen production, with exemption for grid areas with 90 percent renewable electricity and projects in operation before 2028; on deliverability, requirements for electrolyzers are to be located in the same bidding zone as sourced renewable energy to avoid grid congestion; and on time-matching, the European Union starts with a monthly time-matching scheme that leads into hourly matching by 2030, both for domestic and imported renewable hydrogen. The United States will have to set guidelines that are at minimum at the levels of the European Union’s if it would like to keep the region as a prospective export market. Perhaps a sign of a good compromise, the energy industry criticized the definition as strict and costly while environmental groups expressed their concerns about the lax additionality rule and its impact on emissions.
The United States sits amid international competition for leadership in the emerging hydrogen economy. Japan, another prospective hydrogen importer, is set to release its updated national hydrogen strategy by the end of May, in which it would increase its clean hydrogen supply target to 12 million tons by 2040, although it remains unclear if it will set a life cycle emissions standard for renewables-based hydrogen. Australia, which aims to become one of the top three exporters to Asia, has recently announced a Hydrogen Headstart program to award “competitive hydrogen production contracts” and is already exploring a hydrogen trade partnership with Japan. Canada has established tax credits for eligible hydrogen production equipment are based on lifecycle emissions intensity, albeit with yet to be defined clean electricity sourcing standards. India has opted to support both hydrogen production and local electrolyzer production with a subsidy scheme. These examples showcase the popularity of contract-oriented schemes and production equipment subsidies and indicate a global emphasis on ensuring electrolyzer technology is deployed. The United States needs to shape policy to compete in this environment and ensure project development proceeds at pace. Set against the international perspective, there is again a strong case for a phased-in tightening of standards.
It has become increasingly clear that the short-term priority is to ramp up electrolyzer deployment in order to move down the electrolytic hydrogen cost curve. This in turn allows the production method to scale up and cost-effectively meet forecasted volumes of hydrogen demand while securing leadership in clean hydrogen production costs. The long-term and ultimate priority is ensuring that hydrogen is truly clean via hourly matching of hydrogen production with clean electricity resources from the same market. It is critical to both U.S. climate objectives and competitiveness in international hydrogen markets that hydrogen produced in the United States is certified by rigorous standards. These short- and long-term goals are not, and do not have to be, competing priorities. If electrolytic hydrogen does not scale, the effectiveness of hydrogen as a decarbonization pathway will be stifled, delaying emissions reduction for harder to abate industrial sectors. A phased-in approach that advances toward truly clean hydrogen with clear guideposts and urgent timelines for the onset of increased stringency will send the right signals to developers both domestically and abroad.
Cy McGeady is an associate fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies (CSIS) in Washington, D.C. Mathias Zacarias is a research associate with the CSIS Energy Security and Climate Change Program.
