“Acceleration is key to meeting our climate goals. However, this must be done in a strategic and holistic way” – US National Clean Hydrogen Strategy and Roadmap, June 2023.

The United States recognizes the importance of accelerating the development of clean hydrogen. It is a necessary (and sometimes, the only) solution to decarbonize much of the 30% of global emissions associated with industrial and heavy-duty transport processes. The United States understands the need to strategically plan for hydrogen’s development to ensure investments maximize benefits to the climate, local communities, and the US economy. Strategically balancing the need for clean hydrogen’s acceleration in the near term with holistic, long-term considerations of the technology’s role and climate impact is at the forefront of decisions the country is currently facing to define and regulate clean hydrogen production.

The market for clean hydrogen is relatively nascent today and must quickly overcome several early technology and market scaling constraints. In efforts to bolster the deployment of clean hydrogen, the Inflation Reduction Act (IRA) established a production tax credit (PTC) to act as a financial catalyst for projects that would otherwise not be developed at current costs. The PTC, also known as 45V, is structured to provide the most benefit to the projects that produce the lowest emissions hydrogen and can be a powerful carrot to help accelerate a fully decarbonized grid and support lasting industrial decarbonization projects.

In the case of “green” hydrogen — projects that produce hydrogen using an electrolyzer powered by electricity — hydrogen producers would need to consume between 90 to 97.5 percent zero-carbon power to qualify for the largest tax credit. When such a project is powered by a dedicated renewable energy array, also known as “behind-the-meter” renewables, the emissions accounting is straightforward. But when a project uses power from the grid, it produces hydrogen with the emissions intensity of that grid — and the US grid is currently dominated by fossil fuel-intensive generators.

Given the potential emissions impact of grid-connected hydrogen production, the US Department of the Treasury is establishing regulations to clarify what grid-connected projects will need to do to meet the statutory emissions standards and receive the credit. Depending on how Treasury decides to write rules for this credit, developers will respond with projects of varying electrolyzer operation, costs, and infrastructure needs, which could fundamentally shape the size and shape of the US hydrogen markets. The rules decided by Treasury will ultimately determine the trajectory of emissions resulting from domestic hydrogen production and impact the realization of the national clean industrial strategy.

Striking the correct balance between achieving the emissions reductions intended by this policy and accelerating a clean hydrogen industry in a strategic and holistic manner is possible.

RMI recommends hydrogen PTC rules provide some flexibility for first movers, which will help reduce costs and complexity for early projects and give electrolytic hydrogen the boost it needs to achieve cost competitiveness. On January 1, 2028, these flexible rules should phase out and the tax credit should only be granted to projects that meet emissions-accurate, forward-looking standards. The early flexibility will help bring the nascent industry to scale and compete with current fossil-based pathways, while the phaseout and requirement of more granular emissions accounting rules will ensure that the hydrogen economy grows in a strategic, holistic, and climate-aligned manner.

1. Regulating to Support US National Clean Hydrogen Strategy Goals

The Goals of the National Strategy

The US national clean hydrogen strategy outlines the ambition and roadmap to furthering deep decarbonization of the US economy with clean hydrogen in an equitable and resilient manner. The roadmap balances the goals of accelerating the development of hydrogen in the near term with the required actions needed to establish resilient and equitable hydrogen markets in the long term. Near-term goals of 10 million metric tons (MMt) of annual hydrogen production and $1/kg production costs across clean pathways by the end of this decade pair with project development across many US geographies through the regional hubs strategy and market penetration across several high-priority end uses including steel manufacturing, fertilizers production, trucking, maritime transport, industrial heating, and long-haul aviation.

The hydrogen PTC is a powerful tool to help accomplish the goals of the national strategy. The rules of this credit should be designed to ensure deployment and scale of low-emissions hydrogen production with the holistic vision in mind of where hydrogen production will occur, where end-use projects will exist, and what clean power and transportation infrastructure will be needed to achieve these goals.

Maximizing Emissions Reductions

First and foremost, the national clean hydrogen strategy was established to decarbonize the economy. Investments in hydrogen as an alternative to highly polluting unabated fossil fuels should aim to maximize the reduction of carbon emissions. This is essential to meeting climate goals, minimizing the total costs of decarbonization, and fostering an equitable clean transition.

Not all clean hydrogen production pathways share the same emissions risks throughout their supply chain nor the same potential for emissions reduction. Even with high capture rates and low upstream methane leakage rates, steam methane reforming (SMR) and carbon capture and sequestration-based (CCS) hydrogen production paths (often referred to as “blue” hydrogen) will see non-zero carbon emissions. For example, with a very high capture rate of 90% and a low upstream methane leakage rate of 0.2% (US average leakage rates are around 1.5%) SMR + CCS production sees emissions of over 2kg CO₂e/kg hydrogen (H₂).

Existing policy frameworks don’t stimulate gas-based hydrogen producers to drive carbon emissions to net zero. Gas-based hydrogen producers can qualify for either 45V PTC or 45Q, a tax credit for carbon capture and sequestration. Regardless of which credit they choose to take, given the structure of the 45V credit and the cost tradeoff with reaching higher capture rates, projects may be incentivized to reduce emissions only up to the point where they qualify for the credit — 4 kg CO₂e/kg H₂ — and no further so that hydrogen can be classified as “clean.” Furthermore, the increased 45Q tax credit doesn’t incentivize life-cycle emissions reduction as it is calculated in absolute terms providing $85 credit per each ton of sequestered CO₂rather than linked to an emissions threshold. In the early phase of market development many project developers may opt for the 45Q credit to minimize risks associated with achieving the high capture rates and low upstream methane emissions needed to access higher levels of PTC funding.

Electrolysis, on the other hand, can produce 0 kg CO₂e/kg H₂ while using either dedicated renewable arrays or connecting to the grid with necessary emissions accounting regulations in place. The near-term emissions uncertainty around grid-connected electrolysis is dwarfed by the ultimate emissions risk of letting gas-based hydrogen projects dominate the US market in a medium-term (2030). Should gas-based blue hydrogen dominate the early US market, there is a risk of doubling emissions over the lifetime of projects built to meet the nation’s 2030 hydrogen production goal, as seen in Exhibit 1.

Exhibit 1

The above exhibit illustrates the potential risk in immediately implementing strict emissions regulations for grid-connected hydrogen compared to RMI’s recommend policy scenario of providing time-bound qualification pathways that are phased out by 2028. The near-term emissions from allowing looser regulations for electrolysis pathways are minor compared to the emissions observed from the potential lock-in of gas-based hydrogen pathways if those projects dominate the early market. Ensuring electrolysis can compete on a level playing field with abated gas-based pathways is essential to minimizing emissions from US hydrogen production.

Scaling Production Pathways

SMR + CCS pathways are well positioned to scale within this decade. Despite available tax credits for electrolysis, gas-based pathways often remain cheaper across a wider range of project locations and business models. Exhibit 2 below highlights the cost differential of a behind-the-meter electrolysis project with mid-tier production costs to SMR or SMR + CCS, showing a $0.60 to $1/kg cost premium after subsidies (at a $5/MMBtu and $3/MMBtu gas price, respectively) in this scenario.

Exhibit 2

The production of gas-based hydrogen is not geographically contingent and can be co-located with demand centers and continuously supplied with fuel, shielding these projects from the added costs and complexities that electrolysis projects must address. The clarity around access to 45Q credits for carbon capture and sequestration provides added incentive for near-term investment in gas-based production pathways.

Electrolytic-based hydrogen production has the potential to play a large role in US hydrogen supply given the long-term attractive economics and emissions reduction potential but needs an enabling regulatory framework to nurture early project development. Supply chains and manufacturing are more nascent than gas-based alternatives, and early projects face greater costs, system complexity, and geographic restrictions.

Early electrolysis projects face unique hurdles to development, in part driven by offtake requirements for resilient supply and the geographic restrictions brought by the need to collocate production with accessible demand centers. Many early off-takers will require consistently available hydrogen supply to match the resiliency found in fossil fuel reliance. To enable this, electrolysis producers will need to rely on more firmly generated electricity to run the electrolyzer more often, and/or buffer hydrogen production with hydrogen storage. This can drive up costs, as batteries or baseload power sources like hydropower, geothermal, nuclear, or gas + CCS can increase the cost of electricity, and the limited availability of large-scale, low-cost hydrogen storage infrastructure may force reliance on more expensive available options.

Additionally, due to the lack of hydrogen transportation infrastructure, projects may incur additional costs through the need to collocate production with concentrated demand centers like industrial hubs. Doing so can often result in higher production costs due to the poorer quality renewable electricity observed in these locations. Early projects will benefit from dynamic strategies to meet early market offtake needs of resiliency at competitive price points.

Creating a level playing field for electrolytic pathways is essential to meeting the US hydrogen strategy goals of scale, production diversity, and emissions reduction. To meet these ambitions, roughly 50-80 gigawatts (GW) of electrolyzers may need to be installed by 2030, orders of magnitude greater than the mere hundreds of megawatts (MW) of presently installed US capacity. This scale of investment requires the development of both best-in-class electrolysis projects (the ones that will receive financing and deploy regardless of regulatory decisions) as well as projects where the business case is more uncertain (those that will need qualification for the hydrogen PTC to demonstrate financial viability). Supply chains must rapidly mature to enable this level of development, and projects must be built quickly.

As supply chains start to mature and economies of scale are realized, electrolysis production costs will drop. This will strengthen the business case for investment in electrolysis across a broader set of proposed locations and end-uses, particularly for those “marginal” projects on the edge of financial viability now. The creation of an enabling ecosystem for early investments in these types of projects will further accelerate the observed rate of cost decline, increasing the likelihood of widespread project viability.

When the average costs of hydrogen produced via electrolysis fall below that of gas-based alternatives, least-cost business models will align with those that provide certainty of lowest emissions. This will help to maximize the emissions reduction observed through the transition away from fossil fuels to clean hydrogen. Given electrolysis’ potential for sustained lower costs than gas-based pathways once cost reductions are realized, accelerating investments in electrolysis will minimize the total public and private sector spending to produce equivalent volumes of hydrogen and avoid the need for indefinite subsidies.

Exhibit 3 illustrates how early investment in electrolysis accelerates cost reduction and shows the point at which cost-competitiveness is observed with gas-based alternatives. To reach subsidized cost parity with SMR + CCS at $5/MMBtu, electrolyzers need to reach an uninstalled capital cost of ~$800/kW at $25/MWh electricity. Without subsidy, this becomes ~$300/kW. For context, today’s electrolyzers range between $1000/kW to $1500/kW. To ensure the long-term competitiveness of electrolytic hydrogen, the duration of PTC access must be leveraged to develop electrolysis manufacturing, establish supply chains, and share learnings across projects, as this will ensure the realization of necessary cost reductions and set the production pathway up to scale.

Exhibit 3

As clean hydrogen scales, development must lay the groundwork for market penetration across core offtake sectors to align with policy goals. Supply-side investments in production pathways must be met with viable offtake across priority end-use sectors in industry and heavy-duty transportation. To penetrate the market, clean hydrogen must be delivered at the price thresholds required to compete with incumbent fossil fuels or alternative decarbonization solutions, as seen in Exhibit 4. Sectors like trucking can take a higher price of hydrogen, while sectors like shipping or industrial heat require low prices. Ideally, these investments are seen in geographies across the United States, prioritizing projects that maximize emissions reduction, community benefits, and long-term project resiliency.

Exhibit 4

2. Recommendations, Flexibilities, and Red Lines: RMI’s Position on 45V Guidance

Regulations applied to electrolysis today need to focus on the critical goal of bolstering the development of this nascent market while putting US hydrogen supply on a trajectory for climate alignment. Our policy recommendations aim to strike a balance between incorporating early flexibilities that will help enable development and provide market certainty for first movers while ensuring final rules will shape the hydrogen industry in a way that is strategic, climate-aligned, and competitive in the long run.

Ideally, the clean electricity being used to match hydrogen production electricity consumption would be “additional.” This means the clean electricity generation would only exist because of the investment from the hydrogen user and would not otherwise have been built. This is extremely difficult to prove and implement as rules for a tax credit. Therefore, a few simpler pillars can be combined and together serve as a rough proxy for additionality with the added benefit of being more easily implemented. Within each recommendation, we provide flexible guidance on adjustments that could promote greater certainty of credit uptake and a red line that will render the accounting standard ineffective if crossed.

These policy pillars could be achieved for qualifying hydrogen production using grid power by either contracting with dedicated clean energy generation (a power purchase agreement) or through the purchase of energy attribute certificates (EACs) which provide validation that energy purchased for the purpose of compliance with these standards meets the required standards.

New Clean Power

From an emissions perspective, it isn’t sufficient for hydrogen production to simply prove its use of clean power from the grid. Rather, hydrogen production must prove that it uses new clean power. Why the distinction? If the load of the hydrogen production simply takes existing clean power, it takes away available clean electricity an alternative load could be using. Subsequently, this alternative load may be forced to rely on marginal fossil generation, which could result in a net increase in emissions. Without this requirement, hydrogen production is unlikely to contribute to deeper system decarbonization.

The requirement to procure new clean power to match electrolyzer demand has the greatest impact on emissions reductions for grid-connected projects. Therefore, every project seeking to qualify for the credit should be required to procure clean power that has been built less than 36 months prior to the hydrogen project. This does not guarantee that the clean power would only have been built due to the load of hydrogen production it is matching (true additionality), but it is a useful proxy that can be implemented easily and from day one. Requiring new clean power within this timeframe will incentivize more clean energy projects to come onto the grid and help ensure that projects within interconnection queues have offtake for generated electricity through the addition of new electrolyzer loads.

The 36-month window aligns with the European Union’s clean hydrogen standard. While Europe exempts projects built before 2028 from needing to contract with new power, RMI recommends no such allowance. Unlike the United States, Europe has an emissions cap in place which mitigates some of the emissions impacts of allowing projects to match their load with existing clean power. Additionally, the Inflation Reduction Act sets specific emissions tiers into law that each hydrogen project must meet to earn the credit. It is both a legal and climate imperative that new power be paired with new hydrogen projects.

RMI’s recommended flexibility for this rule includes allowing certain activities at existing zero-carbon electricity generators to qualify as new for the purpose of meeting this requirement. These activities include uprating, waste heat efficiency crediting, and repowering.

Temporal Matching: Defining When Hydrogen Can be Produced

Temporal matching intends to align the times when a load uses power with when that clean power is generated. Temporal matching requirements for systems should be calibrated to promote long-term emissions reduction without undermining the competitiveness of early electrolytic hydrogen projects so that renewables-based hydrogen production can scale broadly and quickly.

The enforced timescale of temporal matching — be it within an hour, throughout a month, or over the course of a year — will influence how an electrolyzer project is designed. Under an hourly matching requirement, an electrolyzer can only claim zero carbon power if the amount of clean electricity it needs during that hour is generated within that same hour. Inherently, this restricts hydrogen production to mirror the availability of clean electricity, which can be intermittently available. In a monthly or annual matching requirement, an electrolyzer can consume grid power from the grid at any time of day as long as during that same month or year the equivalent amount of electricity is generated onto the grid by clean electricity resources.

This gives monthly or annual matched systems a greater degree of flexibility in operation than hourly matched systems. On the one hand, this flexibility in operation is what risks hydrogen to be produced using high-emitting fossil generation, but is also what can lead to a reduction in costs or infrastructure needs to help ease project development and meet offtake requirements for supply resiliency.

To establish early offtake contracts, many industrial end users will require 24/7 hydrogen supply. Industrial processes — including steel making, ammonia production, chemicals synthesis, or refining — are operated under high pressures at high temperatures. These processes cannot be fully shut down without incurring a high cost and will see a slow responsiveness in ramping up or down production. Fossil fuel feedstocks can be consistently supplied into these processes, and early industrial users will require the same resiliency of hydrogen fuels or feedstocks. Ultimately, off-takers need assurance that hydrogen will be available at the times and volumes required for hydrogen to be a viable alternative to incumbent fossil fuels.

Forcing a disconnect between the times in which hydrogen can be produced — i.e., hourly match’s restriction of hydrogen production to only the hours intermittent solar or wind power is generated — with the round-the-clock consistency required of hydrogen supply will result in added system costs and complexity. For an hourly matched system to supply 24/7 hydrogen to an end user, it must rely on expensive batteries, greatly oversized renewables and electrolyzer capacity, and/or hydrogen storage, adding both cost and heightened infrastructure needs to the project. In contrast, monthly or annual systems have the added option of drawing power across more periods of the day to produce hydrogen more consistently, allowing for greater ease in meeting the required consistencies of supply. In the early market, limited supply infrastructure and scaled storage will be available. While in the medium term addressable, these limitations may pose a barrier to project development and supply resiliency for initial projects. Early producers will benefit from the ability to produce hydrogen more consistently by accessing more of the steadily available electricity found in monthly or annual matching schemes, helping to both reduce costs and infrastructure needs.

An analysis from TU Berlin illustrates the resulting difference in cost seen across temporal matching schemes. In their study, costs of hourly matched hydrogen can match those of annual matched systems if there is no need to supply hydrogen around the clock or if low cost, underground hydrogen storage can be leveraged. If hydrogen needs to be supplied consistently and the project cannot access geographically restricted underground storage options, their scenarios show that costs of hourly matched hydrogen can be 1.5 times that of annual matched systems if more expensive hydrogen storage is used, or over 2 times greater if no hydrogen storage is available.

TU Berlin’s study also showed the differences in required infrastructure capacity — renewable electricity, electrolyzer, or storage — across each potential requirement. They found that an hourly matched system could require up to twice the electrolyzer capacity than an annual matched system, and potentially 5 times the amount of hydrogen storage capacity, all to produce the same amount of hydrogen and deliver it with the same consistency as an annually matched system. Furthermore, an analysis by the MIT Energy Initiative found 1.5 times to 3 times the amount of renewable resource capacity could be needed in an hourly matched system compared to an annual matched system depending on the extent to which the electrolyzer can flexibly respond to changes in electricity input.

Mandating hourly matched electrolysis immediately may delay project deployment as many projects could fail to realize the price points or consistency of supply required for demand-side adoption. Gas-based hydrogen production alternatives will not see these same cost or infrastructure challenges as their natural gas feedstocks can be supplied consistently. To help spur the adoption of electrolytic hydrogen in the short term, RMI recommends that a less stringent monthly matching approach be available for the first 5 years, as this will enable a wider range of competitive projects while profit margins remain slim and cost thresholds to compete against incumbent fossil fuels are low. This flexibility should be phased out by 2028, at which point every project should meet an hourly matching standard. In the long run, reaching an end-state of hourly-matched requirements is necessary to ensure a low-emissions future for US hydrogen supply.

Benefits of Phased-In Hourly Matching

A transition to hourly matching rules creates better long-term project outcomes without stifling early-stage industry growth. A transition to hourly matching in 2028 will ensure that hydrogen production maintains long-term emissions reduction ambitions, disincentivizes projects that will be non-competitive and unsustainable in the long term, and provides necessary conditions for the United States to establish itself as a leading presence in the global hydrogen market.

Early projects will benefit from looser monthly matching across two main dimensions:

• Higher electrolyzer utilization rates can be realized due to the increased flexibility in when electrolyzers can draw power from the grid, which helps to supplement revenue during a financial period when paying down large capital expenditures is critical and increase resiliency of supply to meet offtake specifications.
• The timeline in which the added infrastructure requirements for an hourly matching requirement is delayed. This can lower the required initial capital outlay for projects, provide flexibility through longer project construction periods, and ease the risk of new renewable load failing to connect to the grid given the current project backlog and transmission constraints.

These benefits from initially relaxed temporal matching requirements provide first movers with a broader set of immediately cost-competitive projects across a greater breadth of serviceable offtake markets and feasible production locations, given the lower production costs associated with near-term flexibility.

With a lower delivered price, hydrogen can access more end-use markets (see Exhibit 4), which helps de-risk investments for first-mover producers as there are a greater set of possible off-takers as well as helps align with ambitions of offtake diversity in the US hydrogen strategy. If delivered prices are above $2/kg, clean hydrogen may only be able to access the trucking sector as it has the highest allowable price threshold (up to $5/kg, see Exhibit 4). If delivered prices reach $1–$1.50/kg, hydrogen can start to penetrate steel production, maritime shipping, or industrial heating end uses.

Exhibit 5 maps the price for hydrogen required to replace incumbent fossil fuels across a variety of end uses to modeled costs of hourly and annual matched hydrogen production in Texas or Florida. In both locations, the lower price of annual matching enables a greater breadth of accessible off-takers.

Exhibit 5

This figure demonstrates why a regulatory framework that includes early flexibility can help foster competitiveness for electrolytic pathways. If electrolysis can expand its accessible off-takers and reduce its costs, it will be more likely to effectively replace incumbent fossil fuels and compete against natural gas-based hydrogen alternatives in doing so. The intent is for early flexibility to foster competitiveness of these “marginal” electrolysis projects — projects under consideration today but risk locking in higher emitting, natural gas-based pathways if electrolytic hydrogen production proves too expensive.

The tax credits should not be designed to create immediate cost competitiveness in every location where hydrogen development could occur. If that becomes the goal, the rules would need to be so weak as to lose all credibility that they are supporting low-emissions hydrogen. Once the market scales, electrolysis costs will fall, and the long-term economic viability of proposed projects in new regions will be strengthened. Projects today should be rewarded for business plans designed to succeed under rules requiring hourly matching and continue beyond the lifetime of the credit. In all questions considering the rules for this tax credit, the Treasury should ask what kinds of projects and long-term investments should be encouraged, and how will rules dictate where and what kinds of early projects develop.

Why 2028?

A long-run mandate of hourly matched hydrogen production is necessary to ensure the emissions of grid-connected hydrogen production are minimized. Exhibit 6 illustrates the significantly higher emissions if annual matching is allowed over the long run compared to hourly matching requirements.

Exhibit 6

The recommended timeline to transition to hourly matching is in 2028. This is an advantageous and feasible timeline for reasons including:

• An hourly transition in 2028 aligns with EU regulations, which will ensure that the United States can compete on a global scale for exports into demand centers like Europe with strict carbon limits.
• Hourly matching market infrastructure will be more than ready, and rules will be clarified in a safe environment for early projects, giving them operational flexibility in early years while not locking in inflexible project configurations. While some United States tracking systems are starting to implement hourly energy attribute certificates (EACs) and hourly tracking accounting measures, such as M-RETS and PJM’s Generation Attribute Tracking System, widespread hourly matching schemes are relatively nascent. By 2028, the wider availability of temporal renewable energy credits and higher maturity of accounting systems will enable widespread implementation of tradeable hourly tracked EACs.
• By this point, cost premiums of hourly matching will fall as electrolysis technologies will become cheaper and least-cost operation will start to converge with regulations. This is due to the correlation between lowest-cost grid electricity with the times in which clean electricity is generated. Once electrolyzer capital costs fall down their learning curves with greater deployment or individual projects pay off their initial capital outlay, hydrogen producers will pivot from prioritizing increased electrolyzer utilization to pay off capital expenditures to operating to reduce electricity costs.
• A successful phaseout requires the near-term buildout to ready the infrastructure, identify bottlenecks, and build developer and financing certainty by 2028. It’s important to note that an hourly system could be foundational for a broad range of government efforts related to differentiating low carbon industrial products.

A mandate of hourly match within the decade will help accelerate the markets and technology needed to achieve the Biden administration’s goal that 50% of the clean electricity procured by the federal government will be hourly matched by 2030.

Exemptions from this Mandate?

Decisions made on what projects, if any, are exempted from the phaseout of loose temporal matching requirements will strongly impact potential emissions observed from US hydrogen production. Three approaches to phaseout exemptions are typically discussed:

1) All projects must comply with tightening of rules in time (no phaseout exemptions).

2) Projects producing hydrogen by a certain date can be exempt from hourly restrictions (“placed in service” phaseout exemptions).

3) Projects that begin construction by a certain date can be exempt from future hourly restrictions (“commence construction” phaseout exemptions).

Changing the structure of phaseout exemptions across these three scenarios will have a far greater emissions impact than delaying the timeline of monthly matching phaseout. Exhibit 7 highlights the resulting difference in total hydrogen production covered by monthly matching across these three scenarios, and subsequently the potential difference in carbon emissions under each approach. Under the RMI proposed system, hourly transition in 2028 with no exemptions, 95% of the total hydrogen produced in the credit period would be covered by hourly matching. If the United States follows the European system, 85% of the total hydrogen produced would be covered. The more hydrogen production covered by hourly matching means more truly low-carbon hydrogen.

Exhibit 7

Delivering Clean Power

Where does new, temporally-matched clean electricity need to be produced to ensure it can “power” green hydrogen production? Could solar in Hawaii or wind in Oklahoma be considered eligible for hydrogen production in New Jersey?

Deliverability is the concept that clean electricity generated for hydrogen production can physically “reach” the electrolyzer. This provides an added layer of assurance that hydrogen production is using clean electricity rather than relying on carbon-intensive fossil generation to meet its energy needs.

For clean electricity to be “delivered” to the electrolyzer, it must avoid constraints and congestion along the power grid, which otherwise prevent the flow of electricity from point A to point B. For example, a wind farm in Oklahoma would have a hard time meeting a strong deliverability requirement for an electrolyzer in New Jersey as it is unlikely that electricity could travel between those two points without running into congested power lines preventing its ultimate flow to the electrolyzer.

Conclusion

Regulations for grid-connected hydrogen production should follow the intent of the billions of dollars of funding offered within the Inflation Reduction Act and align with the goals of the national clean hydrogen strategy: to rapidly accelerate the development and market penetration of low-carbon hydrogen in a strategic and holistic manner.

Decisions made by the Biden administration this fall will result in an observable impact on the types of hydrogen production pathways scaled, the timelines in which end-use sectors begin to switch from fossil fuels, and ultimately the emissions observed from US hydrogen production. Following RMI’s policy guidance will help to ensure that electrolytic-based hydrogen pathways can sufficiently scale alongside abated-gas pathways, production can penetrate high-priority end uses like steel production and maritime shipping, and rapid cost reductions of clean hydrogen pathways are realized. The enabling environment for electrolysis development will minimize the public spending necessary to observe widespread market penetration of clean hydrogen alternatives and maximize the emissions reductions in the switch from fossil fuels.

The accounting system developed will determine whether key industrial products reliant on hydrogen — i.e., steel, ammonia, synthetic fuels — are considered “low carbon,” with impacts on Buy Clean policies and the development of clean commodity markets. Given the strong international connectivity of hydrogen markets and supply chains, these decisions could ripple through the international ecosystem and shape the profile of international trade partnerships or the development of global supply chains, both for hydrogen and its commodity derivatives. The United States has an opportunity to position itself as a global leader for its standards of climate integrity and as an integral player within the global hydrogen ecosystem.

The design of the hydrogen credit further provokes questions that impact the entire electrifying economy: how do producers prove they are consuming zero-carbon electricity from the grid? And what is the role of new loads in contributing to grid decarbonization? How will the US government and governments around the world validate green and clean hydrogen and the products it helps create? These questions get to the heart of some of the greatest decarbonization challenges we face. The hydrogen production tax credit, by nature of its monetary value and potential impacts on the power sector, represents a unique opportunity to set a precedent in policy implementation across all areas of decarbonization.

Effective emissions accounting for the 45V hydrogen production tax credit will encourage greater innovation, accelerate granular energy attribute tracking, build durable decarbonized industrial hubs, and advance the way emissions are measured across agencies and nations worldwide. Because we cannot manage what we cannot measure, accurate and verifiable emissions measurements, jumpstarted by effective 45V regulations, will be a key tool for achieving our decarbonization goals during the decades ahead.