What lessons the U.S. can draw from Europe’s first attempt to define “green” hydrogen

Alexandru Floristean

FiveT Hydrogen Operating Partner

When can hydrogen be considered green?

The general principle is that hydrogen generated by electrolyzers is considered renewable if, and only if, it was produced using electricity from renewable sources. But which facilities and plants can provide the green electricity needed? What happens when the wind isn't blowing and the sun isn't shining?

Defining precisely, according to clear criteria, what can be called “green hydrogen” is crucial to make investment decisions and kickstart countries’ renewable H2 initiatives around the world.

As frontrunners in the development of clean energy technologies, the United States and the European Union stand to benefit greatly from the development of a strong hydrogen sector. Green hydrogen creates jobs and value for their respective economies, helps improve energy security and, of course, drives decarbonization without jeopardizing economic well-being.

After several years of debate, the European Commission has recently formally adopted and published two delegated regulations establishing detailed rules on the bloc’s definition of renewable hydrogen. Industry representatives fear that the complex, strict texts risks driving the costs of green H2 projects up and limit their expansion, and in doing so, affecting Europe’s ambition to reach the goals of the European Green Deal and the REPowerEU plan.

On the other side of the Atlantic, discussions on similar regulations are underway. The U.S., which is also harboring great ambitions for green hydrogen, is debating guidelines for companies that want to claim renewable H2 tax credits under the Inflation Reduction Act (IRA).

The EU has been the first big market to try and set such “green hydrogen” standards, so what can the U.S. learn from the bloc’s process and ensuing decisions?

The EU policy approach and definition of “green” hydrogen

After intense debate, which delayed the adoption of European Delegated Acts[1] by more than 18 months, the rules for producing renewable and low-carbon hydrogen in Europe are now in effect and will apply to H2 and its derivatives both domestically produced as well as imported into the EU.

Two separate but interconnected legal acts deal with (i) the methodology for calculating the greenhouse gas emissions (GHG) intensity of hydrogen production (based on Life Cycle Assessment approach) and (ii) the conditions for counting electricity as “renewable” when used for hydrogen production.

In short, for the electricity powering the electrolyzers to be considered as renewable and zero-carbon, EU rules require producers of Renewable Fuels of Non-Biological Origin (RFNBOs) to procure (i) electricity otherwise curtailed or (ii) electricity which is, at the same time:

  • “additional” (i.e. produced by unsubsidized renewable energy sources which came into operation no later than 36 months before the electrolyzer)
  • “Temporally correlated” (i.e. produced in the same calendar month, until 2030 and in the same hour afterwards as the moment it is consumed)
  • “Geographically correlated” (i.e. produced in the same “bidding zone”[2] as the electrolyzer)

Failure to meet these criteria will mean that the hydrogen produced will inherit the average GHG intensity and renewable share of the power grid where it is produced — potentially pushing its GHG intensity above the legally mandated threshold and, therefore, losing the policy benefits associated with its production and use.

These rules have been designed to be enforced strictly. The policy logic was that such rules were acceptable because the policy proposals for the European Commission’s flagship “Fit-for-55” package contained strong binding targets for the adoption of RFNBOs in Transport and in Industry. This would have created a large captive market for hydrogen in the EU — which in turn would have allowed said strict rules to function, as all hydrogen producers would be given a difficult, yet level playing field to compete on. Unfortunately, the final versions of the package, agreed upon between the European Parliament and Member States, were much softer on such binding targets, diluting them or placing hydrogen in open competition with other decarbonization options and with non-abated fossil fuels.

Hy24’s internal analysis indicates that, in the current policy context, a large share of gray hydrogen consumption in Europe will likely not be decarbonized due to the interaction between light binding targets (depressing demand) and difficult rules for production (limiting supply).

The negative impact on investment

Investors find it difficult to understand, model and plan for all the ramifications that result from such complex rules. Those who can do so still face uncertainty and increased costs, potentially pushing some projects that would otherwise have been investable into “risky” or “unprofitable” territory.

At best, the rules have delayed investment decisions until the full range of consequences are understood, and associated risks are properly mitigated. At worst, they could lead to the cancellation of projects that would have otherwise contributed to the decarbonization of Europe’s energy system.

Most projects are now burdened with higher costs that they cannot pass through to consumers, who lack sufficient economic incentive to move away from their dependence on fossil fuels. This lowers profitability of projects and disincentives further investment in the sector, creating a vicious circle that prevents the development of the necessary economies of scale.

The benefit of hindsight for the U.S.

Following the passage of the U.S. Inflation Reduction Act, which includes significant incentives to invest in hydrogen production projects, the U.S. is now following in European footsteps and going through a staggeringly similar debate process.

Ultimately, the level of incentive provided under the IRA is dictated by the GHG intensity of the hydrogen produced. The U.S. Department of Energy (DoE) has to issue guidance on the manner in which emissions are calculated and accounted for when producing H2. As in the EU, the difficult part is how to account for GHG emissions associated with renewable energy, procured directly from a renewable energy source, or taken from the power grid.

One main difference is that the U.S. has the benefit of hindsight. It can learn from the EU’s process and decisions, applying the rules that seem to be effective and workable and abandoning those that may stifle investment.

Unpacking the rules

In this context, it is worth evaluating each rule, its reason for being in place, and why it likely would or would not work within the context of the U.S. energy sector.

“Additionality,” as a concept, is very difficult to argue against. Simply put, it states that “additional demand for renewable energy should be met by supplementary renewable energy generation capacity.

The rules that have been developed to tackle this concept, however, are difficult to implement and, according to some, discriminatory. These measures seek to avoid a situation where the increased consumption of renewable energy driven by hydrogen production outpaces the increase in energy generation capacity — and therefore, lead to a net negative impact on the residual GHG intensity of the remaining electricity in power grids.

These fears and perceptions, whether true or not, have led policy makers in Europe to put the responsibility of the development of new energy generation assets on green hydrogen (i.e. RFNBO) producers. This, in turn, will force them to source only renewable energy that did not exist before their electrolyzers came into operation.

The issue with “additionality” lies not with the principle itself, but with the discriminatory situation in which it places hydrogen producers and the uncertainty it creates vis-à-vis the availability of electricity that is compliant with the rules.

Potential competitors of hydrogen for various uses such as batteries and even the use of fossil fuels such as natural gas (e.g. in steel production) are not made responsible for additionality at each individual plant level and hence, imposing such requirements on H2 producers alone puts them at a competitive disadvantage.

Ideally, the U.S. should take additionality into account, as the principle is solid. However, the country should do so in a way that shifts the burden of proof away from individual hydrogen producers.

  • Temporal correlation

“Temporal correlation” is perhaps the most debated and the most consequential of the rules. In essence, it requires H2 producers to match the energy consumed by the electrolyzer with the energy produced by the contracted RES (renewable energy sources) assets in a certain timeframe. In the EU, this period has been established at one month until 2030, before a shift to one hour.

Proponents of a strict (i.e. a short-time interval) temporal correlation argue that, by allowing electrolyzers to operate at different times than the moments when the contracted RES asset is producing electricity, the physically consumed electricity is more likely to come from non-renewable dispatchable energy and therefore will lead to more overall emissions across the system — rather than less.

However, the reverse is also true. No matter the time interval used, matching production of renewable energy and its subsequent consumption is necessary for any quantity of electricity consumed from the grid. Therefore, an equivalent quantity of contracted renewable energy will displace an equivalent quantity of grid electricity.

This means the overall GHG impact is not defined solely by the GHG intensity of the grid electricity used by the electrolyzer, but by the net difference between the average GHG intensity of the grid when the contracted RES asset is not producing (and the electrolyzer consuming) and the average GHG intensity of the grid when the contracted RES was producing (and the electrolyzer not consuming). The result of this difference, depending on the day, hour and season could be minimal, positive, or even negative.

In conclusion, the effects of a shorter or longer temporal correlation interval in terms of GHG emissions are difficult to calculate and the differences between a short period and a long period are going to vary depending on the specificities of each grid. This point might be solved by innovative digital solutions in the cleantech space.

What is clear, from the European experience, is that operational costs resulting from a short interval are exceedingly high for hydrogen producers, as it severely limits their ability to generate hydrogen when the consumer requires it.

The first lessons from Europe seem to show that imposing a short temporal correlation interval disproportionately burdens H2 producers while having a minimal impact on overall GHG emissions.

Instead of imposing strict temporal correlation requirements, it could be wiser to impose a longer period and allow price signals to drive the hydrogen producers’ choices. In this way, they should be able to select the moments when it is most beneficial to draw electricity from the grid (even if that moment comes at times the RES asset is not producing) and when to curtail the electrolyzer (allowing the energy it has previously contracted to flow to other consumers). Such a policy choice is likely to offer a higher societal value, better grid management (in response to price signals) and allow more operational freedom for hydrogen producers.

  • Geographic correlation

“Geographical correlation” requires a hydrogen producer to contract renewable electricity produced in the same “bidding zone” — a network within which electricity can flow freely without the need for specific capacity allocations. The policy goal was to avoid electricity transmission imbalances between renewable-energy-rich areas and energy demand clusters.

This requirement has a direct impact on the choices made by investors when selecting production locations and tends to favor areas with abundant, low-cost renewable energy to build electrolysis capacity. It is difficult to say what the right policy should be adopted in the U.S. given there are so many structural differences across the country’s wider energy market. What is clear though is that a one-size-fits-all policy will have very different implications in one geographic market over another. 


The world needs clean hydrogen to meet its decarbonization goals. At the same time, the hydrogen sector needs investments to drive down costs to deliver on its promise to decarbonize hard-to-abate sectors and replace polluting fossil fuels. Imposing complex, strict, unreasonable rules on a nascent sector from the very beginning risks staving off investment. This reduces the sector’s ability to develop projects at the scale needed to reach economies of scale and to drive costs down.

As the publication of the detailed rules in the U.S. is delayed, as compared to the original August 16 deadline, and as the European rules are further clarified by the European Commission through interpretative guidelines, we urge regulators on both sides on the Atlantic to enable regulatory clarity, certainty, simplicity, stability — and not least, to contribute to a global level playing field that allows all decarbonization solutions to play the role they are best suited to play in enabling a carbon neutral energy system.


[1] Delegated Regulation (EU) 2023/1185 establishing a minimum threshold for greenhouse gas emissions savings of recycled carbon fuels […] and Delegated Regulation (EU) 2023/1184 establishing a Union methodology setting out detailed rules for the production of renewable liquid and gaseous transport fuels of non-biological origin

[2] Bidding zone is the largest geographical area within which market participants are able to exchange energy without capacity allocation