The Iberian green industrial opportunity: Green hydrogen

As the energy transition gathers pace, decarbonization is a growing priority across sectors. While electrification and renewable energy are likely to play a major role in this process, these levers may have limitations in abating emissions in certain industries. In these hard-to-abate industries, green hydrogen could emerge as a key solution (see sidebar “About green hydrogen”).

Hydrogen can be used as an energy source or as a feedstock in several industries. Today, hydrogen is mainly used as a feedstock in two sectors: refining (for example, crude oil hydrocracking and hydrotreating to produce fuels) and the production of chemicals such as ammonia and methanol. Green hydrogen has the potential to replace grey hydrogen in these sectors and could also be used in the production of synthetic fuels (such as e-methanol or e-ammonia for maritime transport and e-kerosene for aviation), as well as in other sectors such as steelmaking (via H₂-DRI-EAF), helping to decarbonize industries where electrification is not feasible.¹The use of hydrogen to produce direct reduced iron (DRI), which is then processed in an electric arc furnace (EAF) to produce steel.

The European Union has put in place several initiatives to foster the demand of green hydrogen as part of its Fit for 55 package, including the Renewable Energy Directive (RED), FuelEU Maritime, and ReFuelEU Aviation regulations.²“Fit for 55,” European Council, April 12, 2024. These not only impose minimum quotas for renewable fuels in different sectors, but also binding renewable fuels of nonbiological origin (RFNBO) targets.³Renewable fuels of nonbiological origin. Projects using biomethane to produce low-carbon hydrogen via SMR would not comply with the current EU RFNBO definition and quotas set by EU regulation, although this low-carbon hydrogen could be used to comply withCO₂ reduction targets or lower carbon intensity of produced fuels.

With its abundant potential to produce cost-effective renewable energy, Spain is well-placed to take a leading role in growing Europe’s nascent hydrogen economy. While several barriers would need to be overcome, the country could leverage its competitive renewables and existing industrial hydrogen demand to lead the transition to green hydrogen in Europe.

In this article—the fourth in our series looking at the Iberian green industrial opportunity—we draw on insights from McKinsey research and members of our Industry and Energy Transition Initiative (see sidebar “The Industry and Energy Transition Initiative”) to explore how Spain can take advantage of its green hydrogen potential to achieve decarbonization, while also creating significant value.

Here we discuss how Spain is in a favorable position to become a major green hydrogen producer in the European Union due to its natural and technical endowments, which create a unique window of opportunity for green hydrogen development. Spain’s ambition of 11.0 gigawatts (GW) of installed electrolyzer capacity by 2030 could translate into the annual production of around 1.1 megatons of green hydrogen, requiring a total investment of about €20,000 million for the electrolyzers alone, with additional investment required for renewable energy.

However, green hydrogen faces several challenges that would need to be addressed for Spain to realize its ambitions. Recent cost increases and limited commitment shown so far from potential offtakers have reduced the speed at which green hydrogen is being developed in Spain compared to expectations.

In this article, we highlight how demand for green hydrogen could be attracted through public–private partnerships and mechanisms to foster and underpin offtake agreements. Production could be accelerated by supporting large-scale green hydrogen production projects to demonstrate technology at scale. Planning grid capacity upgrades in line with advancement of green hydrogen projects would also be a key unlock.

Public stakeholders could facilitate green hydrogen development by defining RFNBO quota quota penalties under the EU Renewable Energy Directive (RED) III, streamlining renewable energy source permits or creating an RFNBO credit market. The availability of soft loans and guarantees offered by public institutions (such as multilateral development banks and export credit agencies) may be fundamental to improving bankability and kick-start large green hydrogen projects. It would also be critical to find the most efficient distribution of public incentives both at the EU and Spanish levels.

Spain’s green hydrogen potential

Spain currently produces around 0.6 megatons per annum (Mtpa) of hydrogen, all of it grey, which accounts for around 8 percent of the European Union’s total hydrogen production.⁴Clean hydrogen monitor 2023, Hydrogen Europe, November 2023.

However, Spain is well-placed to become a leader in green hydrogen production. A ready supply of cost-effective renewable energy is a crucial component in producing green hydrogen, and Spain has the potential to produce abundant, low-cost renewable energy, thanks to its unique natural and technical endowments.⁵For more, see “The Iberian green industrial opportunity: Seizing the moment,” McKinsey, July 30, 2024.

Spain has around 300 sunny days per year, resulting in a levelized cost of energy (LCOE) for solar that is approximately 40 to 50 percent lower than the EU average. Although LCOE does not directly translate into levelized cost of hydrogen (LCOH),⁶For cost calculations, we used PPA prices as the baseline, as described later in this article. a lower cost of electricity is key to cost-competitive hydrogen production. Furthermore, Spain has one of the world’s most mature power purchase agreement (PPA) markets. Thanks to all these factors, green hydrogen could be produced for €4.0 to €5.5 per kilogram in Spain by 2030, around 10 to 20 percent below the projected production cost in Central Europe.⁷Assuming no incentives, the same capital expenditure, operating expenditure, and financial cost, and a difference in the cost of electricity proportional to the difference in estimated LCOEs between Spain and Germany of 40 percent.

Additionally, Spanish demand dynamics are already strong, with around 0.6 Mtpa of hydrogen consumed in 2023. Refining currently accounts for around three-quarters of the Spanish hydrogen demand, with chemicals production accounting for the remaining quarter. Within chemicals, ammonia production for fertilizers accounts for 60 percent of hydrogen demand, while methanol and other chemicals represent around 40 percent.⁸Clean hydrogen monitor 2023, November 2023. These sectors currently largely consume grey hydrogen but could switch to green hydrogen as production ramps up. Spain also has a well-established industrial and transport footprint with the potential to drive new hydrogen and synthetic fuels demand in applications where electrification is not feasible or efficient.

Hydrogen-based fuel production requires large amounts of CO₂, and Spain (together with Portugal) is the fifth largest emitter of biogenic CO₂ in the European Union due to its large pulp and paper industry and bioenergy power plants. Spain currently emits approximately 9.0 Mtpa of biogenic CO₂, which, if captured, would be sufficient to cover the expected CO₂ demand coming from synthetic fuel production by 2030 (0.6 Mtpa CO₂) or even 2040 (3.6 Mtpa CO₂). This, combined with an abundance of low-price renewable energy, positions Spain as a potential synthetic fuel powerhouse with the ability to supply other synthetic fuel-demanding countries that don’t have access to large amounts of biogenic CO₂ or competitive renewables.

Regarding the transport of hydrogen, Spain has the potential to retrofit its existing network of gas pipelines for the transportation of green hydrogen, both for domestic consumption and for export. Additionally, Spain enjoys an advantageous geographical position for maritime trading routes. Its large liquefied natural gas (LNG) regasification terminals, if retrofitted, could be leveraged to export hydrogen and its derivatives.⁹Ana Maria Jaller-Makarewicz, “European LNG tracker,” Institute for Energy Economics and Financial Analysis, February 2024.

Together, these factors put Spain in a strong position to become a leader in green hydrogen production in Europe. However, the country must act fast to take advantage of this window of opportunity, as other regions, such as Germany, Sweden, and the United States, are already competing to fill the green hydrogen space.

Spain could install 15 to 20 percent of the total EU electrolyzer capacity target by 2030

The European Union aims to increase green hydrogen consumption to 20 Mtpa by 2030, with half produced domestically and the rest imported from countries outside the region.¹⁰“EU hydrogen strategy,” European Commission, accessed August 2024. To meet this domestic production target, member states would need to reach 65 GW of installed electrolyzer capacity, based on EU estimates. However, the necessary total installed electrolyzer capacity could be higher depending on the actual electrolyzer utilization and efficiency.

In an aspirational scenario based on the targets laid out in the nonbinding National Integrated Energy and Climate Plan 2021–2030 (PNIEC), Spain could install 11 GW of electrolyzer capacity by 2030, reaching 15 to 20 percent of the total EU target and producing around 1.1 Mtpa of green hydrogen (Exhibit 1).¹¹National integrated energy and climate plan 2021–2030 (PNIEC), Spanish Ministry for the Ecological Transition and the Demographic Challenge, 2020. In September 2024, the Spanish government published an updated target of 12 GW of electrolyzer capacity by 2030 in Boletin Oficial del Estado (BOE).¹²“Ministry for the ecological transition and the demographic challenge,” Official State Bulletin, September 23, 2024. However, in the analyses included in this paper, we will refer to the previous target of 11 GW when referring to PNIEC.

In a scenario based on the fulfillment of policies currently in place and the existing market trajectory, there is a high risk of not meeting the PNIEC’s targets, as Spain would only reach a total installed electrolyzer capacity of 5 to 6 GW by 2030. Although the total announced electrolyzer capacity for green hydrogen projects in Spain until 2030 is higher than 11 GW (more than 20 GW have been announced to be operational by 2030), our analysis shows that more than 95 percent of those announcements are still in feasibility and pre-front-end engineering design (FEED) stages, and only a fraction are likely to pass final investment decision (FID) to be operational by 2030.

Public funding targeting investments into green hydrogen production is already being mobilized in the European Union and within Spain. For example, through the National Recovery and Resilience Plan, Spain has already allocated around €490 million to 77 renewables, hydrogen, and storage projects.¹³“PERTE for renewable energy, renewable hydrogen and storage,” Spanish Government, Recovery plan, transformation, and resilience, 2021. However, most of those incentives have not been disbursed yet, and around €2,660 million of the total funds available remains unallocated as of April 2024. The European Union has also recently approved a Spanish program of €1,200 million aiming to support green hydrogen production projects, targeting projects of more than 100 MW of installed electrolyzer capacity under the condition that at least 60 percent of the expected hydrogen to be produced is secured under an offtake agreement.¹⁴Eduardo González, “Brussels approves 1.2 billion to support renewable hydrogen production in Spain,” Diplomat, July 28, 2024. Increasing the speed and agility with which this funding is assigned and disbursed would help support green hydrogen developers and ensure that the European Union’s and Spain’s ambitious green hydrogen targets are met.

Key challenges and unlocks for Spain’s 2030 aspirations

For Spain to be able to fulfill its potential for green hydrogen production and demand, barriers may need to be overcome in five key areas: fostering demand for green hydrogen and derivatives; scaling up green hydrogen production and ensuring its competitiveness; navigating EU and Spanish regulations on green hydrogen; financing first-of-a-kind green hydrogen projects and making them bankable; and deploying the infrastructure needed to develop green hydrogen production, transport, and storage.

Each of these is examined below, along with identified unlocks that could help Spain become a leader in green hydrogen and achieve its aspirational targets.

1. Fostering demand for green hydrogen and derivatives

Since regulatory green hydrogen quotas are met at the point of consumption, not production, of hydrogen, both production and consumption would need to occur within the country for Spain to reap the full benefit of the green hydrogen ecosystem.

As such, demand for hydrogen and derivatives would need to grow, both through existing uses switching from grey to green hydrogen and through new applications. In the aspirational scenario, Spanish green hydrogen production would fully meet internal demand, with only around 20 percent of the green hydrogen produced by 2030 exported to other EU countries.¹⁵In the short term, these exports would be in the form of derivatives such as ammonia and synthetic kerosene rather than hydrogen molecules, and these would be used primarily as end products rather than being reconverted to hydrogen (for example, green ammonia for fertilizer production).

Production targets would fully meet regulatory demand set by the green hydrogen quotas established by the European Union. RFNBO quotas set under RED III¹⁶“Renewable Energy Directive,” European Commission, November 2023. in existing industries (such as refining and chemicals), as well as those set in FuelEU and ReFuelEU in sectors where hydrogen is not yet being used (such as transportation), would result in around 0.5 Mtpa of regulation-driven green hydrogen demand by 2030 in Spain. This would be split into approximately 0.3 Mtpa of “regulatory demand,” referring to demand directly coming from the application of a RFNBO subquota (for example, a quota of 1.2 percent RFNBOs in aviation set by ReFuelEU), and 0.2 Mtpa of “incentivized demand,” referring to the demand for green hydrogen that can be used to fulfill other regulatory targets that are not specifically RFNBO subquotas (for instance, the quota of 5.5 percent advanced biofuels and RFNBOs set in RED III).¹⁷For more details on this split between regulatory and incentivized demand, see section 3, “Navigating EU and Spanish regulation on green hydrogen.”

Including this regulatory demand, our analysis suggests that Spain has the potential to increase its internal demand for green hydrogen to around 0.9 Mtpa by 2030, leveraging both traditional hydrogen-consuming sectors, such as refining and chemicals, and new sectors that could be decarbonized through hydrogen, such as steel, maritime, and aviation (Exhibit 2).

Hydrogen-consuming industries (refining and chemicals) switching from grey to green hydrogen would account for around 50 percent of the aspirational demand by 2030, mainly driven by RED III quotas. Additionally, rising CO₂ costs (driven by the expansion of the EU Emissions Trading System, the implementation of the European Union’s Carbon Border Adjustment Mechanism, and the phasing out CO₂ allowances), along with potential green premiums, would also drive green hydrogen demand in new applications such as green steel, maritime, and aviation. However, current production technologies would require extensive retrofitting and additional time and investments.

Other potential applications, including road transport (mainly fuel cell electric vehicles for heavy-duty trucks or buses) and blending with natural gas for commercial and residential buildings,¹⁸In the case of blending hydrogen with natural gas for buildings, the International Energy Agency estimates that a blending rate of 20 percent of green hydrogen would only reduce the CO₂ emissions associated with heating and cooling buildings by 7 percent; Global hydrogen review 2021, International Energy Agency, October 2021. could also increase the demand for green hydrogen but at a smaller scale, since these sectors are not subject to specific RFNBO targets or there are alternative decarbonization technologies that can be more cost-competitive, such as electrification, biofuels, or biomethane.

Challenges and unlocks

Offtake agreements: The projected reduction in green hydrogen production costs over time could reduce the willingness to commit to long-term offtake agreements, which increases the uncertainty of the viability of green hydrogen production plants today and reduces their bankability.

This could be offset by providing public guarantees for green hydrogen offtake agreements. This would help reduce uncertainty of demand, especially in the long term, increasing viability and bankability. For example, in Spain, the CESCE/FERGEI fund provides a similar mechanism for PPAs.¹⁹“Credit risk coverage program for electro-intensive consumers,” CESCE, accessed May 24, 2024. Additionally, it would be important to ensure offtake credibility through partnerships between players along the value chain. Players with “skin in the game” (both equity and offtake agreements) would increase creditworthiness and facilitate bankability of the projects. This strategy has been used in H2 Green Steel’s project in Sweden, where 13 equity sponsors, including offtakers, collectively raised €2,100 million.²⁰“H2 Green Steel raises more than €4 billion in debt financing for the world’s first large-scale green steel plant,” H2 Green Steel, January 22, 2024.

Hydrogen-demanding industries: Low prices of grey alternatives, such as natural gas direct reduced iron (NG-DRI) for low-carbon steel production could impose obstacles for industrial players to rapidly switch to green hydrogen. New technologies would also need to be put in place to adapt to green hydrogen.

The cost-competitiveness of synthetic kerosene compared to other sustainable aviation fuel (SAF) alternatives in aviation, or the uncertainty around the winning maritime low-carbon fuels, can also make it difficult for organizations in these sectors to back the transition to specific synthetic fuels. Additionally, the limited port refueling infrastructure for methanol and ammonia, as well as the lack of hydrogen refueling stations in road corridors, could prevent private players committing to the transition to hydrogen and hydrogen-derived fuels.

Creating an appealing regulatory, fiscal, and financial environment could help attract hydrogen-consuming industries (for example, steel manufacturers or fertilizer producers). This could incentivize potential green hydrogen offtakers to develop new greenfield capacity in Spain, reindustrializing the country and ensuring future demand for green hydrogen. For example, the US Inflation Reduction Act (IRA) incentivizes foreign players to build their new manufacturing capacity in the United States.²¹Leigh Collins, “US awards about $335m of investment tax credits for new hydrogen-equipment manufacturing facilities,” Hydrogen Insight, April 19, 2024.

A complementary strategy could be the international promotion of Iberian endowments for green hydrogen and derivatives production, with trade missions and investment programs for renewable energies. These initiatives would also attract foreign capital in green hydrogen production projects to the country.

Finally, public incentives could also be deployed for hydrogen downstream technologies, such as the Fischer-Tropsch process or methanol synthesis, to incentivize specific demand segments.

Green premiums: Increasing visibility on green premiums for green hydrogen-based products would help to reduce uncertainty around future cash flows and improve the economic viability of green hydrogen production projects. For example, for green steel, some offtakers, including automotive OEMs and high-end real estate developers, are starting to signal their willingness to pay premiums ranging from €100 to €300 per ton of green steel.

2. Scaling up green hydrogen production and ensuring its competitiveness

In Spain, existing green hydrogen production projects mostly range from 1 to 10 MW of electrolyzer capacity, with the largest operational project as of April 2024 having an installed capacity of 20 MW (Iberdrola’s plant in Puertollano).²²“Puertollano green hydrogen plant: Iberdrola installs the largest green hydrogen plant for industrial use in Europe,” Iberdrola, May 24, 2024. To reach the country’s targets, hundreds of megawatt- and even gigawatt-scale projects would need to be operational by 2030, and the average size of electrolyzers would need to grow 100- to 200-fold. This would require proving and choosing the optimal electrolyzer technology to operate at scale, considering electrolyzer efficiency, intermittency of renewable energy sources (RES), and required firmness for hydrogen derivatives production (offtakers).

More developed green hydrogen supply chains and larger electrolyzer manufacturing plants would also be needed. In 2023, the European Union had 3.9 GW per year of electrolyzer manufacturing capacity (with no large-scale²³More than 100 MW. electrolyzer manufacturing capacity in Spain). Based on announcements from OEMs, this would increase to 21 GW per year in 2025 and 25 GW per year in 2030, which would be sufficient to meet the target for installed electrolyzer capacity for 2030.²⁴“European Clean Hydrogen Alliance,” European Commission, 2020; “Electrolyser summit—State of play,” European Commission, June 22, 2023. However, some of the expansions may not materialize as we see orders and FID get delayed.

It would also be important to ensure the availability of the necessary feedstocks (renewable electricity and water) for these large-scale projects, along with access to crucial materials (including platinum group metals and iridium) and critical components, such as transformers and rectifiers.

For it to scale up, green hydrogen production would need to be cost-competitive. However, cost projections for green hydrogen have increased over the last few years, mainly due to increases in capital expenditure (capex), electricity prices, inflation, and interest rates. This, combined with the expected normalization of natural gas prices as new production capacity comes online in the years ahead, could increase the gap between willingness to pay and LCOH in the short term (Exhibit 3).

By 2030, the LCOH in Spain could be around €4.0 to €5.5 per kilogram of hydrogen, with the cost of electricity as its largest contributor. Grid access fees also play a role in the total electricity cost, with current fees in Spain around €10 to €15 per MWh for industries such as green hydrogen. Regulatory requirements could also significantly impact the LCOH and the future development of green hydrogen in Europe. Finally, the LCOH will decline as electrolyzer efficiency increases and technology development and capex reductions materialize, as the market matures. Several variables could affect the LCOH to different extents (see sidebar “LCOH sensitivity analysis”).

Ensuring low electricity prices, achieving economies of scale, gaining clarity on potential green premiums (besides the price of CO₂), and defining penalties for noncompliance with regulatory RFNBO quotas would all be key to bridge the gap between willingness-to-pay and LCOH in the short term.

Challenges and unlocks

Cost-competitiveness: Economies of scale and the technological development of electrolyzers are both happening slower than anticipated, increasing the projected capex curve. There is also a limited number of top-tier electrolyzer OEMs and EPCs²⁵Engineering, procurement, and construction companies. capable of building large-scale green hydrogen production plants, which increases prices and reduces the bargaining power of green hydrogen developers. To offset this, companies could pool electrolyzer demand to achieve better prices through economies of scale, such as Air Products, which in 2020 ordered 2 GW of electrolyzers from Tyssenkrupp-Nucera to be delivered in batches over a six-year period.²⁶“Air Products and thyssenkrupp sign exclusive strategic cooperation agreement for world-scale electrolysis plants to generate green hydrogen,” Air Products, May 7, 2020; McKinsey analysis.

For operating expenditure (opex), although electricity prices are projected to fall as RES becomes a larger part of the energy mix, there is still uncertainty around the magnitude of the reduction, especially given the recent impact of geopolitical events on the European Union’s energy markets. On top of that, grid connection fees could represent 10 to 25 percent of total green hydrogen production costs by 2030 in Spain.²⁷McKinsey analysis. Additionally, high inflation over the last two years has increased labor and material costs, resulting in an increase in the total production cost for green hydrogen.

The barriers around opex could be tackled in two ways. Electricity prices could be reduced through partnerships between RES and hydrogen developers, achieving electricity prices closer to the levelized cost of energy (LCOE). For example, Lhyfe and EDPR signed a 15-year partnership to produce green hydrogen in Germany.²⁸“EDPR chosen by Lhyfe to supply clean energy in a long-term contract in Germany,” EDP Renewables, January 24, 2024. The LCOH could also be reduced by optimizing RES configuration for electrolyzer utilization. Based on green hydrogen output requirements, developers could optimize the configuration of RES (solar, wind, and potentially batteries) together with electrolyzer and hydrogen storage size to reduce the overall green hydrogen production cost and ensure optimal utilization. For example, under certain circumstances, it might be optimal to combine and oversize solar and wind generation capacity to around two to three times combined the installed electrolyzer capacity²⁹Optimal RES and electrolyzer configuration will depend on the site location of RES. to help green hydrogen producers achieve electrolyzer utilizations above 50 percent while reducing LCOH.³⁰McKinsey Hydrogen Insights LCOH optimization tool.

An option for countries such as Spain and Portugal that benefit from abundant cost-competitive RES, is to connect to the grid and produce green hydrogen intermittently when RES generation is high and day-ahead electricity prices are below the threshold of €20 per MWh or 36 percent of the EU ETS carbon allowance price defined by EU regulation. This is becoming more frequent as RES penetration increases, with electricity prices in certain periods of the day falling to near zero. This would allow green hydrogen producers to connect their electrolyzers directly to the grid, without PPAs, and get the full green hydrogen credentials for their production during those hours. In a country like Spain, this strategy could reduce LCOH by approximately €0.5 per kilogram in 2030, achieving LCOH levels around €4.0 per kilogram with utilizations of 35 to 40 percent. However, these results are highly dependent on RES deployment and intermittent generation, which increase uncertainty and would make it difficult for green hydrogen producers to secure an offtake agreement with a player that requires certain firmness levels.

Another challenge around cost-competitiveness is the low number of offtake agreements, with less than 10 percent of the announced projects in Spain having publicly announced a signed offtake agreement.³¹McKinsey Hydrogen Insights project tracker. This raises the risk profile of projects, increasing risk premiums. A lack of technological maturity for large-scale electrolyzers also increases the risk premium, and thus the cost of financing large-scale green hydrogen projects. However, in certain cases, green hydrogen producers could unlock additional revenue streams (see sidebar “Other potential revenue streams”).

Scaling up green hydrogen production: The availability of different electrolyzer technologies (for example, alkaline, proton exchange membrane [PEM], and solid oxide electrolyzer cell [SOEC]) can generate uncertainty around which the optimal choice at scale is, and create hesitancy among green hydrogen developers, with over 50 percent of the projects post-FID not having announced an electrolyzer technology yet.³²Hydrogen insights 2023, a joint report from McKinsey and the Hydrogen Council, May 2023.

Green hydrogen supply chain: There is a limited number of top-tier electrolyzer OEMs with demonstrated experience and capability to provide reliable large-scale electrolyzers. Given the first-of-their-kind nature of large-scale green hydrogen projects, quality, safety, and flexibility of electrolyzers are likely to be key issues that OEMs may have to face.

Developers are likely to look for top-tier OEMs that are able to guarantee operational performance of electrolyzers. Therefore, although the total announced electrolyzer manufacturing capacity might be enough to meet targets for installed electrolyzer capacity, only top-tier OEMs with secured backlogs might be able to move ahead with their manufacturing facilities, while second-tier OEMs compete for a more uncertain demand. This barrier could be overcome by supporting pilot projects to generate knowledge on technology scale-up, allowing for faster-time-to-market of technological breakthroughs. Such support could come from both private and public institutions.

Another opportunity for Spain would be to incentivize local green hydrogen supply chains, including efforts to attract major international manufacturers with expansion plans. Some potential strategies to attract these electrolyzer manufacturers could involve introducing economic incentives, reducing permitting burdens, developing skilled local talent, and ensuring the availability of supply chains for electrolyzers, as well as engineering, procurement, and construction companies (EPCs) with which to partner. Spain is already one of the preferred choices for some electrolyzer manufacturers, such as Cummins, a global hydrogen player that is building an electrolyzer manufacturing facility in Guadalajara, Spain, expected to come operational in 2024.³³El Digital Castilla-la Mancha, “The Cummins gigafactory in Guadalajara passes the last procedure before its start-up,” El Español, December 28, 2023. Another example is the Chinese Hygreen Energy, one of the world’s leading electrolyzer manufacturers, which has recently announced their plans to build a new electrolyzer manufacturing plant in Spain with initial capacity for 1 GW (with plans to expand to up to 5 GW of electrolyzer manufacturing capacity in the future).³⁴“Who is Hygreen Energy? The Chinese giant of electrolyzers for green hydrogen with a strong Spanish accent,” el Economista, August 28, 2024.

However, manufacturers are also choosing competing regions for their new facilities, thanks to the incentives those regions offer. For instance, Cummins expanded its Belgium manufacturing facility to 1 GW, following European (Hy2Tech) and regional (Flanders Innovation and Entrepreneurship Agency) financial support.³⁵“Cummins scaling Belgium electrolyzer manufacturing capacity to 1 gigawatt through IPCEI support,” Cummins, September 8, 2022. On the other hand, Nel, one of the European Union’s largest electrolyzer manufacturers, announced a $400 million investment in a new electrolyzer gigafactory in Michigan, United States, with the direct federal and state incentives amounting to $150 million as a crucial factor in this decision.³⁶Holly Martin, “Electrolyser maker Nel stacks up nearly $170m in subsidies for proposed Michigan gigafactory,” Hydrogen Insight, April 5, 2024. The United States has attracted several top-tier electrolyzer manufacturers by awarding a total of $335 million of investment tax credits for new hydrogen-equipment manufacturing facilities under the Inflation Reduction Act (IRA 48C).³⁷Leigh Collins, “US awards about $335m of investment tax credits for new hydrogen-equipment manufacturing facilities,” Hydrogen Insight, April 19, 2024.

Beyond electrolyzer manufacturing, Spain could aim to develop certain components internally, including electrical equipment, water treatment and gas management systems, and engineering services to build new green hydrogen production plants.

Feedstock availability (water and renewable energy): Scarcity of and competition for water resources is a concern in the industry. In Spain, more than 40 percent of announced green hydrogen projects are likely to be located in highly water-stressed areas.³⁸Water for hydrogen production, International Renewable Energy Agency and Bluerisk, 2023. Additionally, the configuration of RES (solar, wind, and, potentially, batteries) required to achieve high utilization of electrolyzers could increase the cost of electricity.

These risks could be offset by increasing the efficiency of electrolyzers and cooling processes. This can reduce the overall water withdrawal per kilogram of hydrogen produced. In coastal areas, desalination can also be a cost-effective option (with an estimated price impact of €0.02 to €0.05 per kilogram of hydrogen) to reduce water consumption, but environmental effects of thermal pollution and brine management should be carefully studied before this solution is implemented.³⁹Water for hydrogen production, 2023.

3. Navigating EU and Spanish regulation on green hydrogen

There are numerous EU and Spanish regulations that could impact the cost-efficiency of green hydrogen, as well as demand and willingness to pay (see sidebar “EU regulations on green hydrogen”).

To ensure that the regulatory demand is met, penalties for noncompliance with the RFNBO quotas will be put in place. We conducted a theoretical exercise to estimate the potential impact of these penalties on the willingness-to-pay (WTP) by calculating the decarbonization potential of green hydrogen and its derivatives for each application assuming a potential penalty of €400 per ton of CO₂ “not saved” (Exhibit 4).⁴⁰This level of penalty is similar to that found in the transposition of RED II for biofuel targets in some EU countries. However, it is important to note that the real penalties will be defined by the European Union and member states. For RED III, member states will define their own penalties when transposing the directive; for FuelEU a unified penalty will be defined by the European Union, pending on setting a price for sustainable maritime fuel; and for ReFuelEU, member states will define the penalties, starting from a minimum penalty set by the European Union and pending on setting a price for synthetic kerosene.

For refining, the impact on WTP of this theoretical penalty could be €3.3 to €3.7 per kilogram of green hydrogen not fulfilled. It would have a similar impact on chemicals. In maritime, the impact would be €3.2 to €2.8 per kilogram of green hydrogen not met (estimate based on the carbon intensity of low-sulfur, heavy fuel oil compared to e-methanol), while aviation could see an impact of €1.8 to €2.2 per kilogram of green hydrogen (conventional kerosene compared to synthetic kerosene).

Challenges and unlocks

Delegated Act requirements: Temporal matching, when required on an hourly basis after 2030, would be the main constraint to developers, as it constrains the use of PPAs and guarantees of origin. Also, additionality of RES will still be required for projects starting after 2028 if Spain’s grid emissions do not fall below 18g CO₂ per megajoule (MJ). While additionality is still in place, projects will face RES permitting timelines of between two and six years and will not be eligible for public funding. In addition, producers would be required to prove a 70 percent reduction in greenhouse gas (GHG) emissions intensity of the hydrogen and synthetic fuels produced compared to conventional fuels to be considered RFNBO.

Restrictions on using grid electricity and the high intermittency of RES could lead to an irregular output of green hydrogen. This enters into conflict with the output requirements for hydrogen derivative production like ammonia, methanol, e-fuel, and green steel production. Firmness constraints could also lead to significant RES oversizing and storage needs.

To overcome these barriers, temporal correlation requirements could be eased by fostering and investing in large-scale storage. Requirements could also be standardized to avoid cross-border recognition challenges within the European Union and with third country trade partners.

Additionally, visibility on timelines to reach green grid conditions could be provided. If Spain’s grid emissions fall under 18g CO₂ per MJ (compared to around 35g CO₂ per MJ in 2023), this would allow producers to avoid the additionality requirement.⁴¹For further information, see Red Eléctrica’s website, iee.es/es. According to a draft PNIEC review to be approved in 2024, the Spanish grid aspires to reach emissions of around 12g CO₂ per MJ in 2025 and around 8g CO₂ per MJ in 2030.⁴²“Draft update of the national integrated energy and climate plan 2023–2030,” Spanish Ministry for the Ecological Transition and the Demographic Challenge, June 2023. In line with this, some European developers are already adjusting their PPA lengths to switch to regular grid connection as soon as decarbonization thresholds are expected to be reached. Also, a proportion of annual RES generation over 90 percent in the bidding zone would allow for direct connection to the grid without temporal correlation or additionality requirements.

RFNBO quotas and penalties: Spain has not yet defined quotas and penalties in line with the latest regulation (including RED III and ReFuelEU), with final transposition expected to be completed by 2025–26. By that time, most of the green hydrogen projects should have passed FID to meet PNIEC’s electrolyzer capacity target by 2030. Additionally, there are significant differences in penalties established in the past across different EU countries (such as for RED II), generating a risk of “carbon leakage” to countries with lower or no penalties. There is also uncertainty around how the RFNBO certification process will work.

To address these barriers, an RFNBO credit market could be created to allow companies to trade credits to meet their obligations, similar to how the European Union’s emissions trading system (ETS) works today but focused on RFNBOs. Unifying penalties for noncompliance with RFNBO targets across countries could be key to restrict “carbon leakage.” Finally, Spain could also incentivize players to use green hydrogen to decarbonize by covering additional costs incurred by switching technologies. This could be done, for example, with mechanisms such as contracts for difference (CfD) or carbon contracts for difference (CCfD).

4. Financing first-of-their-kind green hydrogen projects and making them bankable

Achieving Spain’s aspiration for green hydrogen production would require large capital deployment, around €20,000 million (without considering RES) for the target of 11 GW of installed electrolyzer capacity, according to our analysis.⁴³Assuming average capex of €1,750 per MW of electrolyzers installed. This, together with the high-risk profile derived from the first-of-their-kind nature of announced projects, make the development of large-scale green hydrogen production plants a challenge.

Some of the necessary capex could be covered by public incentives schemes such as the Spanish PERTE-EHRA incentives or by part of the more than €500,000 million in EU incentives available for the energy transition. However, an estimated 70 to 90 percent of the total capex would have to come from the private sector. Large developers could be able to fund smaller projects (tens of megawatts) using their own equity and corporate debt. Our analysis shows that, for larger projects (hundreds of megawatts and above), project finance-like structures could be used, with 60 to 75 percent of the investments covered by debt investors (such as private banks, multilaterals, and export credit agencies) requesting additional guarantees, with the remainder financed through sponsors’ equity (such as developers and infrastructure funds).

However, the window of opportunity is narrowing. Spain may need to act fast to attract these investments and seize the opportunity to become a leader in green hydrogen.

Challenges and unlocks

Public incentives: Transparency and effectiveness of hydrogen incentive mechanisms are important to maximize their utility. Only around 15 percent of Spain’s PERTE-EHRA incentives had been allocated (not yet disbursed) by the end of 2023, delaying access to these funds. Surveyed stakeholders report that the high level of uncertainty of hydrogen tenders, compared to simple and tradable production tax credits considered in the US IRA, significantly delays final investment decisions, especially as tender results have also been delayed. In addition, complex administrative processes, incompatibility of subsidies, and funds being diluted by numerous projects with various levels of feasibility might limit the efficiency of funding allocation.

To overcome this barrier, public support could be streamlined by standardizing application processes. Different incentives could be clearly mapped with transparent and shorter deadlines while allowing companies to submit several applications in parallel or through a “one-stop shop” application process. For example, Belgium and France combine procedures of several permitting processes into “single permits.”⁴⁴“Guidance to member states on good practices to accelerate permitting processes,” European Commission, Directorate-General for Energy, May 18, 2022. On top of this, penalties could be defined for projects accepting public funding and not delivering the announced results in order to avoid speculative accumulation of incentives.

There are two types of support mechanisms: investment incentives, including most of the incentives currently available in the European Union, and production incentive, such as tax credits for hydrogen production or competitive bidding schemes for production grants (see sidebar “EU Hydrogen Bank”). Regulators should explore the efficiency of the different incentive structures to determine which schemes should be prioritized. Some EU countries, such as Germany, are choosing auction-as-a-service schemes as the preferred option to allocate public incentives.

Optimization can also be achieved by finding the right balance between allocating large incentives to a smaller number of projects or more modest incentives to many initiatives, with the former being the preferred option among the Iberian Industry and Energy Transition Initiative members. Other criteria can be followed to further optimize the distribution of incentives, for example, prioritizing projects with offtake agreements or prioritizing those with the highest potential to reduce emissions on end-use applications.

Private funding: The first-of-their-kind nature of large-scale green hydrogen projects means they can require substantial capex investments with risk profiles similar to those of early-stage technologies. Developers can apply derisking levers to better attract debt and equity providers by managing the main risks, including financial and technical risks.

Financial risks include low cash flow predictability due to the emerging nature of the green hydrogen market or the lack of long-term offtakers (less than 10 percent of the announced projects in Spain publicly announced a signed offtake agreement as of the second quarter of 2024). Merchant exposure restrictions by equity and debt investors may vary for different end products (ammonia has a global merchant market, while the green hydrogen market is still immature). Additionally, smaller entities may struggle to prove creditworthiness due to limited resources and unclear track record, requiring partnerships with experienced EPCs and operations and maintenance companies.

Technical risks include a lack of experienced EPC players and issues when scaling electrolyzer technology. There is a high level of uncertainty regarding long-term maintenance and operational costs as well as difficulties in securing competitive long-term power supply agreements. Debt equity investors usually require full visibility on power prices in the long-term through solid PPAs, regardless of whether the project is bundled with RES or not, as well as clear contractual clauses defining the accountability of the different stakeholders along the complex hydrogen value chain.

A potential lever to attract private funding is easing capital requirements through public financial institutions and bank pooling. Multilateral banks and export credit agencies could offer “soft loans” with favorable repayment conditions as well as guarantees that improve the financial reliability of these projects. This was demonstrated by Euler Hermes, the European Investment Bank, and the Swedish National Debt Office providing debt, cover, and guarantee for H2 Green Steel.⁴⁵“H2 Green Steel raises more than €4 billion in debt financing for the world’s first large-scale green steel plant,” H2 Green Steel, January 22, 2024.

5. Deploying the infrastructure to develop green hydrogen production, transport, and storage

The green hydrogen ecosystem in Spain includes the infrastructure to generate and transport the electricity required to produce hydrogen, as well as hydrogen transport and storage systems to connect green hydrogen production initiatives with national and international offtakers via pipelines, shipping, and road transport.

The expansion of green hydrogen production would require the optimization of grid infrastructure to ensure sufficient access capacity for demand to connect electrolyzers and for generation to connect RES to the grid. Additionally, streamlining the permitting process for renewable power generation development would be important to ensure that the announced green hydrogen plants can be operational by 2030. Currently, the average permitting timeline for RES in Spain ranges from two to six years. This would mean that nearly 20 GW of additional RES would have to launch construction by 2027 to 2028 to meet PNIEC’s target of 11 GW electrolyzer capacity by 2030.

There are four main options for transporting hydrogen, depending on distance, terrain, carrier, and end use: pipelines, ships, trucks, and trains. However, the transport of hydrogen over long distances without optimized infrastructure adds sizable costs to hydrogen end products. Therefore, in the short term (before 2030), while adequate transport infrastructure is not yet deployed, production plants for green hydrogen and derivatives would be most efficient if they were co-located to reduce the associated logistics costs.

Within this context, trucks, despite being comparatively more expensive (costs under €1 per kilogram of hydrogen for distances under 100 kilometers), could present an attractive option to absorb low and fluctuating demand in the early stages of the hydrogen economy. In the longer term, national and international pipeline networks and export terminals could gain relevance once exports of green hydrogen and derivatives become more mature. Pipelines will be the most cost-efficient option for both short- and mid-range distribution (cost of less than €0.1 to €2.6 per kilogram for distances between 100 kilometers and 5,000 kilometers), assuming high capacity utilization, leaving shipping as the preferred option for long-range and intercontinental trade (cost of €2.2 to €3.1 per kilogram depending on selected carrier, including conversion costs).⁴⁶H2 and carriers transport cost estimations obtained from European Hydrogen Backbone 2023 report, European Hydrogen Backbone, 2024; and Global hydrogen review 2023, IEA, September 22, 2023. Another alternative would be to use cargo trains, to transport hydrogen derivatives from production source to demand or export points (less expensive than trucks but more costly than pipelines or inland vessels).

Once economies of scale and production technology maturity are reached, a hydrogen transportation ecosystem can help connect hydrogen production and demand hubs across regions. The European Hydrogen Backbone, a transmission system operator (TSO)-led nonbinding initiative, already envisions a Pan-European hydrogen pipeline network, including a Spanish National Backbone with an inner mesh and connections with France and Portugal, aiming to turn Spain into a major green hydrogen supplier in Europe (Exhibit 5).

Although some sections such as the BarMar connection have started their preliminary engineering studies, this grid section is not likely to be deployed by the announced timelines and other international connections could be subject to additional delays, as observed in other cross-border infrastructures. However, if the grid is deployed at scale in the future, this would give a clear competitive advantage to EU green hydrogen producers over overseas ones that would need to convert the hydrogen into a shipping carrier and then reconvert it back to hydrogen, increasing landed cost.

Hydrogen storage provides the output firmness required by green hydrogen offtakers, partially solving the electrolyzer utilization constraints that stem from the inherent intermittency of RES. Hydrogen storage is a versatile technology, but it is currently in the early stages of its development. In the short term, artificial tanks (storing compressed or liquid hydrogen) may be more suitable due to higher technology maturity and flexibility to adapt to small-scale storage. In the long run, geological storage has the potential to be the most competitive option for large-scale, long-term storage to bridge major seasonal changes in production and demand.

Challenges and unlocks

Power grid infrastructure access for hydrogen production: A lengthy and difficult permitting process in Spain may be delaying target commercial operation dates (COD) for green hydrogen production plants. Furthermore, the accommodation of 11 GW of electrolyzer capacity, as well as over 20 GW of dedicated RES generation for green hydrogen production by 2030, would require significant upgrades to the transmission grid, substations, and lines. Finally, grid fees in Spain could represent a substantial portion (15 to 25 percent)⁴⁷Assuming an average electricity price of around €50.0 per MWh and a grid fee for electro intensives of €11.4 per MWh. of final electricity cost, impacting the LCOH directly.

Several interventions could be considered. First, the RES permitting process could be sped up by transposing the EU Renewable Energy Act to national regulation, incorporating the maximum of two years of permitting processes for new RES projects. Second, the grid access process could be facilitated by creating a one-stop shop for all permitting-related requests. For example, in the United States, FAST-41 oversees projects with a value of more than $200 million, tracking timetables and providing transparency, including completion dates for all federal authorizations and environmental reviews.⁴⁸“Fast-41,” United States Office of Electricity, accessed August 2024.

Third, grid access capacity could be ensured by planning and executing the required investments. According to our analysis, grid expansion is a critical enabler with relatively low investment requirements compared to the €20,000 million of total capex needed for electrolyzer production capacity to meet Spain’s 2030 target.

To accommodate 11 GW of electrolyzer capacity for green hydrogen projects, the Spanish grid will require further upgrades in the new 2025–30 plan that the national grid TSO is developing (as of April 2024). This was already done in the previous 2021–26 plan review with, for example, Repsol’s green hydrogen project in Tarragona and the new Francolí substation. Planned investments in upgrading or expanding the transmission grid would need to be coordinated with the development of the most viable green hydrogen projects through an objective categorization based on development phase, committed offtakers, and public support, among other criteria. Agile planning adjustments should be facilitated to quickly identify future green hydrogen hubs and reassess investment needs, while financial guarantees could help avoid speculative attributions of capacity.

Fourth, stakeholders could explore alternatives to reduce the impact of power costs. For example, granting exemptions for certain grid fees for energy-intensive industries. These policies would need to consider the risk of incompatibility with other incentives and the impact on other grid fee payers.

Hydrogen transport infrastructure: Hydrogen transmission pipelines could kickstart a network of connected green hydrogen producers and offtakers maintaining cost-competitiveness at a national and continental scale. However, demand uncertainty and the large investments required, along with operational risks, could cast doubt on the cost-effectiveness of deploying national and international hydrogen pipeline infrastructure. In addition, the long-distance shipping of green hydrogen is yet to be proven at scale, with no carrier emerging as a clear frontrunner (ammonia is the most frequently announced today). Immature reconversion technologies and the lack of existing port infrastructure compound the difficulty of establishing intercontinental trade routes by 2030. In parallel, the development of the hydrogen ecosystem would have to go hand in hand with the definition of safety protocols, especially for new use cases (both end products like ammonia and infrastructure).

To overcome this barrier, stakeholders could explore public–private partnerships to establish international hydrogen supply chains, such as through international import-export agreements that ensure enough demand to justify investments in port infrastructure. For example, ACE Terminal and Cepsa signed an agreement to export green ammonia from southern Spain to a new import terminal in Rotterdam.⁴⁹“Cepsa and ACE Terminal join forces to create green hydrogen supply chain from Spain to the Netherlands,” Cepsa, February 20, 2023. Developing and maturing ammonia (or other hydrogen carriers) cracking technologies and capabilities in import terminals would also be key to unlocking international trade. In addition, TSOs could be incentivized to invest in infrastructure build-out with compensation mechanisms if utilizations fall under a minimum threshold, similar to the system used in UK’s Nuclear Regulated Asset Base that ensures a base level of revenues for nuclear generators even when underutilized.⁵⁰“Guidance: Nuclear regulated asset base (RAB) model: Statement on procedure and criteria for designation,” Department for Energy Security and Net Zero and Department for Business, Energy and Industrial Strategy, UK Government, April 11, 2022.

The targeted development of hydrogen infrastructure could be enabled through cost-efficient retrofitting of natural gas pipelines and hydrogen corridors prioritization, avoiding extensive oversizing in the short term, which would hinder the economic viability of the system. In Belgium, Fluxys is building a dual-purpose pipeline, ready to switch from natural gas to hydrogen transport when needed.⁵¹Sarah Simper, “Fluxys builds new natural gas and hydrogen pipeline,” World Pipelines, June 8, 2023. The development of announced pipeline projects would have to be in line with the maturity of the green hydrogen production ecosystem and the readiness of players to import or export hydrogen as a molecule (not as a derivative). This could further attract green hydrogen producers to Spain to export hydrogen toward their offtaking facilities in Central Europe.

In addition, stakeholders could invest in research to overcome technological barriers that deter the use of hydrogen carriers as transportation vectors. This could align different regions and countries on a single carrier regulation and harmonize their infrastructure needs.

---

Spain is in a favorable position to become a major green hydrogen producer in the European Union thanks to its natural and technical endowments, which create a unique window of opportunity for the development of a new ecosystem.

However, green hydrogen faces several challenges that would need to be addressed for Spain to realize its ambitions. Private and public stakeholders could act now to embrace the opportunity of turning Spain into a leading EU green hydrogen hub—generating sustained growth in the country while achieving the decarbonization of hard-to-abate sectors.