The IRS’ Hourly Time-Matching Provision – A Prescient Boon or A Stymieing Bane?

Electrolytic, or green hydrogen, is being championed as a solution to decarbonise hard-to-abate industrial sectors.

But investments, being considered in green H2, rely heavily on government-sponsored incentives as the nascent sector attempts to take root. To help accelerate the development of green H2, the Inflation Reduction Act (IRA) has established tax incentives, but the eligibility criteria continue to be a source of uncertainty. In December 2023, the Internal Revenue Service (IRS) – the tax authority in the U.S. under the U.S. Department of Treasury – provided guidance on the three main criteria governing eligibility of green H2 to IRA incentives, namely:

1. Incrementality, also known as additionality
2. Time-matching, also known as temporal correlation, and
3. Deliverability, also known as geographic correlation

Among the announced rules, perhaps the most controversial is the requirement for hourly time-matching between renewable power generation and green H2 production. Utilising our analytical hydrogen optimisation tools, AFRY has analysed the impact of time-matching on the overall economics of green H2 production. In this paper, we compare key project features and costs of both annual time-matching and hourly time-matching for a green H2 production facility located in the U.S. Gulf Coast to serve a flat demand profile.

The annual time-matched case consists of an alkaline electrolyser that relies solely on solar power, whilst in the hourly-matched case the optimisation exercise results in wind power being used as an additional renewable power source. For both simulations, the assumed renewable generation profiles are taken from AFRY's knowledge base for solar and wind assets located in Texas. This shift in time-matching from annual to hourly results in a different mix of renewable energy sources (RES) and impacts the optimal sizes of various system components. These changes, in turn, increase costs.

The overall cost implications of the proposed regulations when comparing annual time-matching to hourly time-matching can be summarised into three main points:

1. An overall capital expenditure (CAPEX) increase of 36%, mainly driven by the need for wind capacity to complement solar, more hydrogen storage capacity, and increased electrolyser capacity.
2. A decrease of the electrolyser capacity factor - the % of time an electrolyser operates at its maximum potential - from 77% to 53% due to the need for additional H2 generation flexibility during peak generation hours.
3. An overall increase of the levelized costs of hydrogen production (LCOH) by 15%.

Whilst the IRA is widely seen as a key enabler to develop green H2 at scale in the United States, the increase in LCOH stemming from the hourly time-matching requirement could impact the viability of some proposed projects. It will also likely impact the global cost-competitiveness of H2 produced in the United States. However, despite the cost increases, do the announced rules put the U.S. H2 in a position to gain access to export markets?

According to the International Energy Association (IEA), there is increasing global interest in developing the hydrogen (H2) economy to help decarbonise hard-to-abate sectors, to enhance energy security, and to develop new industrial sectors that will rely on H2 or its derivatives as fuel. At the time of writing, 62 countries have articulated their hydrogen strategies. A recurring theme among these strategies is support for reduction of green H2 production costs. This support via policy and legislation is a crucial enabler to incentivise early H2 adopters and generate investment momentum.

Green H2 production is less dependent on geology as hydrocarbons or coal; hence, it is not expected to be as geographically concentrated. But, it does favor locations with high mean wind speeds and solar irradiance that underpin the potential for low-cost renewable power. As such, some of the key demand regions like the EU and East Asia are expected to be net importers of H2 due to a lack of low-cost renewable energy. In the EU’s case, H2 imports are also expected to be driven by decarbonization targets that mandate the use of green H2¬ in various industrial sectors.

In contrast, the United States is in an advantageous position due to ample availability of land, wind and solar resources, and water – the natural resources needed to develop green H2 at scale. Additionally, the passing of the IRA extended existing tax incentives for renewable power generation, expanded the scope of these incentives to include stand-alone energy storage, and introduced new incentives for green H2 production. In short, the IRA offers several stackable tax incentives that help reduce costs of key components of green H2 production systems.

In addition to a favorable endowment of natural resources and supportive policy, the U.S. also possesses a large industrial base that can generate strong domestic H2 demand. These factors have put the U.S. in a position to develop H2 at a large-scale that can not only meet domestic demand but also generate an exportable surplus of green H2. The existing H2 transportation infrastructure in the U.S. Gulf Coast region, as well as experience and expertise in operating and maintaining this infrastructure, is also supportive of the case for U.S. H2 exports.

IRS Guidance – December 2023

Although the IRA defined the emissions intensity of the produced H2 to qualify for the full extent of the tax incentives on offer, some uncertainty around requirements for incrementality, time-matching, and deliverability remained.

In the December 2023 guidance, the IRS finally provided additional clarity on the eligibility rules for green H2¹ .

1. Incrementality requires construction of new or incremental RES to power green H2 production to avoid displacing existing RES that feeds the grid. The IRS has set the threshold for the installation of renewable power generation to meet incrementality requirements to be no more than 36 months prior to hydrogen (H2) production.
2. Time-matching requires that the volume of renewable power generation be precisely matched to the volume of green H2 production within a specified time interval. This is to ensure that the produced green H2 is in fact produced from renewable power. The IRS guidance requires time-matching of renewable power and the produced H2 to shift from an annual basis to an hourly basis starting in 2028. Time-matching was the most hotly debated criterion among the three - with some stakeholders advocating for annual-matching to manage costs and accelerate adoption, and others advocating for hourly-matching to ensure close correlation between renewable power generation and H2 production.
3. Deliverability defines the relative positioning of the renewable power generation and the H2 facilities and has been to put in place to ensure that the renewable power is physically transportable to the electrolyzer. To meet the deliverability requirements set by the IRS, the renewable power source (RES) and the electrolyzer must be co-located within the regions defined within the U.S. Department of Energy ‘s (DoE) National Transmission Needs Study published in October 2023² .

These rule announcements have important implications for project developers and investors alike as they site and configure RES-integrated H2 systems and evaluate investment opportunities. It is certain that the corresponding rules for green H2 set by the EU have influenced the IRS’ guidance, as, for any H2 to access the European market at large, the eligibility criteria must align closely with the EU’s. Eligibility rules in Japan are somewhat less strict³ .

It is important to note that the IRA incentives are intended to address the supply-side by reducing the LCOH via tax credits and grow supply in the near-term, relying on technological advancements to contribute to cost reduction over time. This focus on supply-side incentives is supportive of the case for U.S. H2 exports by encouraging development at scale and making U.S. H2 cost-competitive relative to other sources of supply. The export case is further enhanced by the following sources of comparative advantage:

• Potential for RES (particularly solar) and incentives in place to develop large-scale, low-cost renewable power in the U.S.
• Availability of incentives for domestic manufacturing, and advanced research and development, e.g., for solar panel manufacturing, for advanced electrolyzer manufacturing, and for electrolyzer supply chains. These will help improve deployment of RES and electrolyzers and provide protection from supply chain disruptions
• Access to water (although this varies by region), particularly in comparison with water-stressed regions like the Middle East.
• Access to existing H2 transportation infrastructure, and expertise in developing such infrastructure – particularly in the U.S. Gulf Coast region.
• Availability of incentives in place to develop Regional Clean Hydrogen Hubs (see also: Are the U.S.' Hydrogen Hubs the Kickstart Needed to Accelerate the Clean Hydrogen Revolution?) ; these hydrogen hubs (H2Hubs) are intended to consolidate end-users and optimize the infrastructure build-out.
• Large domestic industrial base and large population centers that will absorb part of the production from H2 projects via contract purchases, and reduce the merchant risk and spot market risk, i.e., facilitate H2 project development at scale.
• Stable geopolitical environment and low country-risk that will drive large-scale investments into politically stable sources of supply.

Moreover, schemes involving contracts for differences and government-funded long-term purchase agreements of H2 and H2 derivatives (like ammonia and methanol) have been announced in Europe that are meant to facilitate offtake in the European Union (EU) and support H2 imports. There is also increasing interest from Japanese investors and utilities to develop H2 capacity in the U.S. These early indications seem to suggest that the sources of comparative advantage discussed earlier will likely help establish the U.S.’ competitiveness edge, and position the U.S. as a preferred destination for investors and project developers.

Figure 1. Illustration of AFRY’s reference case. Annually-matched system of solar RES, an alkaline electrolyzer and hydrogen storage.

The main impact of the shift from annual to hourly time-matching is a 15% increase in LCOH⁴ driven by the rise in CAPEX of the re-optimised case (see Figure 2). Although this negatively impacts the cost-competitiveness of U.S. green H2, it also aligns the U.S.’ rules more closely with the EU’s and paves the way for U.S. green H2 to access the European market.

Figure 2. AFRY’s re-optimised case and its capex impact. AFRY’s Hydrogen Project Configuration & Optimization Tool was used to optimize the configuration.

AFRY Analysis

To better understand the impact of the new IRS rules, let’s take a closer look at the AFRY analysis, and expand on the IRS rule changes and their impacts. In this analysis, we have also compared the IRS’ rules to the European Union’s rules that govern qualification of H2 as a renewable liquid and gaseous fuel of non-biological origin (RFNBO). RFNBOs are a key part of the EU’s decarbonization efforts with quotas for RFNBO use in industry and transport sectors including aviation and maritime transport. The EU’s RePowerEU initiative has set a target for 10Mt of domestic hydrogen production and an additional 10Mt of hydrogen imports by 2030.

Incrementality:

To qualify for IRA’s H2 tax credits and be classified as a renewable liquid and gaseous fuel of non-biological origin (RFNBO), grid connected electrolyzers must meet ‘additionality’ or ‘incrementality’ requirements. To satisfy this, new hydrogen production should be matched with new (‘incremental’ or ‘additional’) renewable electricity capacity, i.e., the renewable power capacity used to produce H2 must be “newly installed.” The definition of “newly installed” is somewhat nuanced and allows the renewable assets to be installed up to 36 months prior to the electrolyzer becoming operational. In addition, the capacity for H2 production has to be the same or less than the renewable power claimed through the power purchasing agreement between the H2 producer and the renewable generator.

For the U.S. producers to export RFNBO H2 to the EU, they would need to comply with the region’s somewhat stricter rules. In addition to the additional renewable capacity being installed no earlier than 36 months prior to the electrolyzer becoming operational, any expansion to the electrolyzer capacity shall be considered to have the initial installation date as long as the expansion takes place within 36 months of the original. More importantly, these new renewable developments must also have not received any support in the form of operating (ongoing financial support) or investment aid (initial funding). This means that U.S.-produced H2 that seeks to access the EU RFNBO market cannot stack incentives for renewable power and hydrogen.

Time-Matching:

In addition to meeting ‘incrementality’, the H2 produced must comply with time-matching requirements to be eligible for incentives in the U.S. The time-matching or temporal correlation has been a source of uncertainty and a matter of debate, and the IRS guidance has finally provided some much-needed clarity. The mandated temporal correlation is hourly starting 1 January 2028; this brings the U.S. in compliance with the EU’s requirements for hourly temporal correlation for RFNBO-compliant H2 by 2030, and is the most-aligned criterion between the U.S. and the EU. Some H2 stakeholders had been advocating for annual time-matching of renewable power generation and H2 production to allow greater flexibility when using intermittent renewable power.

The hourly time-matching mandate will increase the levelized costs of hydrogen production. However, based on AFRY’s analysis, the flexibility inherent within annual time-matching also comes at a cost if balancing costs are imposed (i.e. having to purchase power from the grid at the power market price to balance the system). As a result, the differential between the LCOH of hourly-matched H2 and the LCOH of annual-matched H2 is lower. Flexibility on temporal correlation requirements is likely to be associated with some form of balancing requirements from the grid, which will likely come at a cost. This is due to the flexibility of using electricity in hours when the dedicated renewable sources are not generating at the same level as consumption by the electrolyzer. Because of this mismatch between renewable generation and electrolyzer consumption, the grid can help balance supply and demand by accepting excess electricity from dedicated renewables, or supply electricity to the electrolyzer when renewable generation falls short.

Even though the energy balance within the allowable temporal correlation window (e.g. hourly or annually) should be zero (assuming no curtailment), the cost is likely to be non-zero. This is because electricity prices when selling electricity to the grid are very likely to be different from the electricity prices when buying from the grid to balance the system (see Figure 3). This cost depends on the specific system’s characteristics (e.g. renewable energy sources and generation profiles, demand profile, hydrogen storage, etc.) as well as on grid prices relative to those characteristics.

Figure 3. Illustration of electricity flows and potential balancing costs with annual time-matching

In an optimized system with an objective to minimize production costs, the cost of balancing the system by taking advantage of any flexibility on temporal correlation is weighed against other options. For example, in the presence of cheap large underground hydrogen storage, it could be an overall cheaper solution to use more hydrogen storage and less grid balancing, especially if the electricity prices relevant to the characteristics of the hydrogen plant introduce high balancing costs. In our analysis here, we have used market projections of electricity prices to reflect the cost of balancing when time-matching is annual. As a result of considering this balancing cost in combination with all other factors (e.g. generation capacity factors and CAPEX), the optimal configuration that minimizes production costs was determined.

Figure 4 below illustrates the evolution of re-optimized CAPEX due to a shift from an annual to an hourly time-matching requirement. The values are normalized based on the initial CAPEX estimate for the annual correlation.

Figure 4. CAPEX evolution for annual vs hourly temporal correlation scenarios.

For the reference case (see Figure 1), with an electrolyzer powered by 557 MW of solar, the annual correlation CAPEX is divided into two main components:

1. Solar RES accounting for 70%, and
2. Electrolyzer accounting for 29%. Meanwhile, the hydrogen storage CAPEX represents only 1% of the total sum in the annual case.

As observed, the total CAPEX increases by 36% when hourly correlation is enforced. The stricter temporal correlation requirement will require H2 production to be more closely aligned with renewable power generation. This close alignment requires additional flexibility within the installed renewable power units and electrolyzers, which can only be achieved by increasing the capacity of some of the installed components.

The biggest increase stems from the wind CAPEX, which is driven by the need for complementary generation profiles of solar and wind in the hourly case – this is to counteract the inherent intermittency of renewables, and to take advantage of negative correlations between the availability of wind and solar irradiation. The combination of both technologies offers a more reliable and steady power supply than in the annual case, where solar is the only power generation source. In the re-optimized case, the solar CAPEX investment is reduced - partially substituted by the new wind capacity. The need to install more electrolyzer capacity to take advantage of renewable power when it’s available results in an increase in CAPEX as well.

Lastly, the investment associated with the hydrogen storage capacity further raises the overall CAPEX by 6%. The additional storage buffer brings more flexibility to the overall system by allowing the excess generation to be redirected to H2 production rather than to the grid. The results are summarized below in Table 1.

Table 1. Installed capacity comparison for hourly and annual simulations

Deliverability or Geographic Correlation

We have looked at “incrementality” and “time-matching” thus far and seen that these two criteria are in close alignment between the U.S. and the EU – except for the ability to stack renewable power and H2 incentives to access the EU RFNBO market. Now, let’s take a look at the third criterion – “geographic correlation” or “deliverability” - as it is commonly referred to in the United States. The IRS guidance has shed light on how “deliverability” or “geographic correlation” will be defined in the U.S., but it is seemingly at odds with the EU’s definition, and thus it is important to note the distinction between the geographic correlation requirements to qualify for the U.S. IRA credits and for the EU RFNBO denomination. To qualify for the IRA’s H2 credit, the IRS Guidance introduced clarifications into the geographic correlation (deliverability) requirement. The new geographic correlation requirement states that the hydrogen production facility and the renewable electricity generation source must be in the same region following the map defined in the latest DOE National Transmission Needs Study⁵ published in 2023 (see Figure 5). The region of the H2 facility and the renewable generator will be based on the balancing authority to which they are electrically interconnected, with each balancing authority linked to a single region.

Figure 5. Geographic correlation regions in the U.S.⁶

This map provides clarity to fulfill the geographical correlation requirement in the U.S. and, as a result, qualify for IRA credits.

The complexity increases when trying to understand whether the U.S. geographic regions fulfill the European geographic correlation requirements. This is key to understanding if U.S. generated H2 classifies as RFNBO when imported into Europe.

Based on the EU Electricity Regulation definition, the hydrogen production facility and the renewable electricity generation source must be in the same bidding zone. Bidding zones are defined as the largest geographical areas within which market participants are able to exchange energy without capacity allocation. According to the European Network of Transmission System Operators for Electricity (ENTSO-E)⁷ , the boundaries of each of the European bidding zones are well-defined. The majority are defined by national borders, e.g. mainland France, Spain, or the Netherlands; some have multiple within their borders, e.g. Italy; and others are larger than their national borders, e.g. Germany and Luxembourg forming a single zone (see Figure 6).

In the context of the United States, the equivalent of bidding zones is unclear due to one main intrinsic market design difference. Contrary to EU power markets relying on uniform pricing in bidding zones, liberalized U.S. electricity markets apply nodal pricing. An illustrative example of the market design difference can be found when comparing New York ISO (NYISO; the independent electricity system operator in the state of New York) and the Spanish market. The Spanish market has a single bidding zone and covers a total area that is more than 3 times the one of NYISO. Meanwhile, NYISO is a nodal market with more than 700 nodes that are grouped into 11 control zones.

Figure 6. Geographic correlation regions in the EU

However, following the current public disclosed guidelines, the most reasonable hypothesis is to consider the areas managed by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), e.g. NYISO, CAISO, or ERCOT, as the best equivalent of the European bidding zones. These boundaries match in most cases with the regions defined by the U.S. DOE in the latest National Transmission Needs Study⁸ published in 2023, apart from a few exceptions such as MISO, where it is divided into Midwest and Delta. Within the ISOs/RTOs, the market participants can exchange energy without new capacity allocation as they are part of the same balancing authority. Outside of the existing ISO/RTOs, the current best equivalent could be the individual balancing authorities.

Due to the lack of official guidelines from the EU, the two hypotheses are preliminary and should be confirmed as soon as new disclosures are released. The differences in market structure and design between the European power markets and their U.S. counterparts makes it difficult to define the equivalent U.S. bidding zones with complete certainty. The current hypothesis, which is based on disclosed technical guidelines, points towards the ISOs/RTOs as being the closest to bidding zones in the United States. However, this criterion remains a source of uncertainty for U.S. H2 producers aiming to supply H2 to the EU’s RFNBO market and further clarifications or exemptions will need to be provided to help derisk U.S.-based H2 export-oriented facilities.

Concluding Remarks

The IRS’ proposed guidelines have generated much debate and have generated over 30,000 comments arguing for or against the proposals. Although the public comment period over the past 9 months has been useful to collect feedback, there have also been calls to finalize the regulations quickly to restore investment momentum in the nascent sector. The Department of Treasury has set the end of 2024⁹ as the deadline to finalize regulations governing eligibility of electrolytic hydrogen for the IRA credits.

In January 2025, the newly elected president will be inaugurated in Washington D.C., and with the potential of a victory for former President Donald Trump, there’s a risk that the finalized regulations will be rolled back. The American Clean Power Association, an industry association for the renewable power industry in the U.S., has come out against implementing hourly time-matching by 2028 and asked for it to be delayed till 2032¹⁰ . The seven H2Hubs selected by the DoE for the Regional Clean Hydrogen Hubs Program have also raised joint concerns about the impact of hourly time-matching on investment costs and viability of projects. This hasn’t deterred Democrat lawmakers to send a letter to President Biden urging him to finalize the proposed regulations in their current form including the stricter hourly time-matching provision¹¹ .

The Democrat lawmakers acknowledge that the financial viability of some projects will be impacted but have cited the centrality of emissions reduction to the spirit of the IRA and have argued that hourly time-matching is critical to minimizing emissions from electrolytic hydrogen production as well as tackling indirect emissions from the use of grid-connected electrolyzers. After the public comment period, the Treasury Department is now working on adjustments to the provisions and wants to maintain the IRA’s emissions standards including the focus on indirect emissions. This is pointing towards the continuance of hourly time-matching in the finalized regulations. The cost impact of hourly time-matching as shown by the AFRY analysis, and its implications for clean hydrogen offtake are not lost on Energy Secretary Granholm who has alluded to guaranteeing a price for hydrogen within the DoE’s H2Hubs. The DoE has since announced that it is contemplating a demand-side support mechanism¹² to create bankable clean hydrogen demand in the DoE H2Hubs and facilitate the development of hydrogen projects.

The adoption of hourly-matching will undoubtedly create cost challenges for some developers, but it will also unlock access to hydrogen-hungry export markets like the EU for U.S. producers. The DoE’s demand-side support mechanism can also help bridge the bid-ask spread and overcome the short-term offtake challenges. The combined fiscal support needed for the supply-side tax incentives and demand-side purchasing support will be politically challenging. Republican lawmakers have threatened to repeal large parts of the IRA, but U.S. oil and gas firms like ExxonMobil, Phillips 66, and Occidental Petroleum see the benefits of the incentives for developing their hydrogen businesses and have urged President Trump’s campaign to adopt a softer line¹³ . Coincidentally, these firms have operations in hydrogen hubs that are most-conducive to hydrogen exports.

How AFRY Can Help?

At AFRY, we offer a ‘One-Stop-Shop’ for our clients at whatever stage of their journey in the energy transition from high-level strategy, through project and business case development to full implementation. For more information, please reach out to Hasan Tarique or John Williams below.

Contributors: Hasan Tarique, Solomos Georgiou, Alex de Diego Rodriguez and Roberto Andrade.