Dolf Gielen, Priyank Lathwal and Silvia Carolina Lopez Rocha at the World Bank present a thorough review of the pathway to financing global clean renewable hydrogen over the coming decades. The wind and solar that powers production will continue to get cheaper, and so will electrolyser costs as they scale up. Nevertheless, the total financing will still be considerable. World Bank analysis shows around $30tn between now and 2050 will be needed globally for hydrogen production, transportation, and final use. But that investment needs to rise only gradually to meet targets, or less than $150bn per year to 2030 for the production element. A priority is to secure long term offtake customers to keep costs down, lower risks and attract investors. Putting an emissions price on grey (fossils-based, the current dominant production method) hydrogen will close the cost gap between the more expensive green H2 while that gap is being closed. The authors go into detail over all financing aspects, and which regions and nations are already committing, not least the U.S., EU and China. Special mention is made of the opportunity for emerging markets and developing countries: they have the wind and solar potential and the land, and World Bank modelling sees between 25% to 50% of global hydrogen will come from there by 2050. The World Bank is preparing a new flagship hydrogen financing report, to be presented at COP28.
Costs: the 1-10-20-30 rule
Renewable hydrogen has emerged as key to the global energy transition because of the decreased costs of solar and wind generation. But renewable hydrogen is still expensive: as a rule of thumb a million ton per year of renewable hydrogen production capacity requires 10 gigawatts (GW) of electrolyser capacity, which requires 20GW of solar and wind power generation capacity and this requires a $30 billion investment (1-10-20-30).
Amortisation and financing costs dominate
When renewable power supply and hydrogen production are a single project, the amortisation and financing cost dominate the total production cost. The cost of capital is therefore critical for the total hydrogen production cost as the cost of renewable power is the largest component. Around 55 kilowatt hours (kWh) of electricity is needed per kilo of hydrogen.
The importance of the renewable power component at the project level is also evident at a global scale: replacing all the grey hydrogen that is used today with renewable hydrogen would require all solar and wind power generation capacity that is currently in operation.
Emerging markets and developing countries (EMDCs) often have better renewable resources and more available space to develop renewable power projects. Therefore, the production and trading of hydrogen and hydrogen derivatives is economically attractive. The EU has a target of 10 million tonnes (Mt) of hydrogen imports by 2030 and has signed green hydrogen agreements with Egypt, Kazakhstan, Morocco, and Namibia to supply the bloc with hydrogen, with more such agreements to come. Individual European countries including Germany have additional bilateral agreements.
However, developing countries also face higher financing costs that offset the better renewables resource advantages. Unfortunately, accurate data regarding the Weighted Average Cost of Capital for renewable power is scarce. The International Renewable Energy Agency (IRENA) has recently indicated a range of 1 percent -12 percent across both developed and developing countries. Data from the Climate Policy Initiative indicates a 7 percent -52 percent as expected return.
The recent rise of financing costs – in combination with inflation and rising equipment costs – has made this aspect more important. Combined with the shrinking fiscal space in developing countries, strategies to reduce the financing cost in developing countries have become more important. Access to affordable financing will be critical to realise the imports. Without this, Europe may miss its own hydrogen production target of 10Mt by 2030.
Financing needs to 2030 and 2050
World Bank analysis shows a global financing need for hydrogen production, transportation, and use of around $30 trillion between now and 2050. This translates into $1 trillion per year. Around half of that finance is related to hydrogen production, mostly green hydrogen.
This financing needs to rise only gradually. Last year around 1GW of hydrogen electrolyser capacity was added, and $6 billion was invested in renewable hydrogen supply (See figure 2). Various scenarios suggest that 150GW-225GW electrolysis capacity is needed by 2030. This translates into $500 billion of investment into hydrogen production between now and 2030, or less than $150 billion per year. This financing need is only for production; transportation and use may double this. Also, 11Mt of low carbon hydrogen is expected to come onstream by 2030, which also adds to the investment needs.
The investment and financing issue is especially pertinent for EMDCs. Modeling studies suggest that by 2050 25 percent -50 percent of all hydrogen will be produced in EMDCs. This implies an annual average investment in the order of $250 billion-$500 billion between now and 2050. To put that into context, in 2021, the total announced greenfield foreign direct investment in developing countries amounted to $131 billion (roughly half the pre-covid level).
Some projects in developing countries have been announced. The most notable one is the $8.5 billion NEOM project in Saudi Arabia, which has reached financial closure. Oman has recently signed six agreements worth a total of $20 billion with international developers to build green hydrogen production plants inside the country, the first round of bidding in Oman’s green hydrogen auctions. Around 65 projects have been announced across the MENA region. World Bank is supporting efforts in Brazil, Chile, India, Mauritania and Namibia, amongst others. So, the ambition and is there and preparations are ongoing. But very few projects have so far reached Final Investment Decision (FID)stage.
What is the current cost gap?
One of the reasons why it is difficult to reach FID is that renewable hydrogen is more expensive than grey hydrogen. The business case is therefore challenging. Consequently, merchant plants will not be able to ensure financing from banks. Project developers need an offtake contract that specifies a premium for the clean product, at a certain price for a certain period of time. For example, in the NEOM case, Air Products has guaranteed the renewable ammonia offtake for 30 years at an undisclosed price, eyeing the road transportation market where a price premium can be generated. What that price should be depends on the willingness of the consumer to pay for the clean product, but the price should be high enough to cover the production cost, to ensure a viable business case.
The cost gap between renewable hydrogen and grey hydrogen is of particular interest from a government financing perspective, it shows the subsidy that will be needed to create a viable business case and to create a bankable project proposal that can go ahead.
There is no market for renewable hydrogen yet, therefore the cost and price information are generally based on model analysis. But various sources such as S&P/Platts, IRENA, Lazard, Argus, and Aurora publish estimates that suggest production cost of $5-$6per kilogram of hydrogen. In the most favorable conditions, for projects coming onstream in the next three to four years, this may drop to $3/per kilogram.
In comparison, the cost of grey hydrogen is determined by natural gas prices and are country specific. But typically in gas producing countries the hydrogen production cost is $1-$2 per kilogram. The cost gap – $1-$5 – is an indication of the subsidy that is needed. The range is wide, and so subsidy estimates vary widely. Reducing that uncertainty is critical. There are mechanisms emerging that will help to reduce the uncertainty such as H2 global, which uses tenders to seek price information on the supply and on the demand side. Also, the price gap varies by region. In order to minimise subsidy needs it makes sense to start at locations where the gap is smallest.
Closing the cost gap: 3 mechanisms
Three mechanisms are proposed to close the cost gap:
- Raise the cost of grey hydrogen
- Lower the cost of renewable hydrogen through technology innovation
- Lower the cost of renewable hydrogen through financing innovation
It is uncertain when the cost of renewable hydrogen will fall below that of grey hydrogen. It depends how quickly the cost of renewable hydrogen fall and how quickly the cost of grey hydrogen will rise. But as the cost of renewable hydrogen declines, the cost of grey hydrogen will likely increase.
Natural gas prices are hard to predict. The concentration of supply in a few countries and the Russia sanctions have resulted in a price spike worldwide. It is likely that in the longer term, LNG will set the gas price in many regions of the world. The move from regional pipeline gas markets to a global LNG market means that natural gas prices will converge worldwide at a higher level.
Imposing emission pricing for grey hydrogen
One way to make clean hydrogen more affordable is to impose greenhouse gas (GHG) emission pricing for grey hydrogen, thereby closing the competitiveness gap between green and grey hydrogen. There is an increasing recognition that grey hydrogen production is an important source of greenhouse gases, both methane and carbon dioxide (CO2). CO2 emissions of around 10 kilograms per kilogram of hydrogen translate at today’s European Emission Trading System price into a cost of $1per kilogram of grey hydrogen. Methane emissions from natural gas production and transportation can double the total greenhouse gas impact, but these methane emissions vary and they are case specific. If these greenhouse gas emissions are properly priced, this can eliminate the price gap. ECDMs will be subject to European carbon pricing for conventional ammonia, steel and other carbon intensive products as the Carbon Border Adjustment mechanisms come into force in coming years. Products produced from clean hydrogen will not be subject to the same border fees.
Falling price of renewable hydrogen
The good news is that renewable hydrogen production costs are projected to fall rapidly to $2-$3 per kilogram by 2030. A combination of economies of scale and technology innovation will reduce the cost of renewable hydrogen. The cost of renewable power is projected to continue to fall as will the costs of electrolysers. The drivers are economies of scale in manufacturing and project size, as well as technology innovations that bring down the equipment cost. For example, significant efforts are aimed at the reduction of precious metal loads in PEM electrolyser manufacturing. Also, the automation of electrolyser manufacturing is projected to reduce manufacturing cost as today’s are largely hand made.
The learning effects will be significant for electrolyser stacks. By the end of 2022 only 1-2 GW of hydrogen electrolysers had been installed. Each doubling of installed capacity will reduce cost by 15 percent to 20 percent; five to nine doublings can be achieved in this decade. Proton Exchange Membrane electrolyser stacks and Solid Oxide electrolyser stacks have significant learning potential. However, for the balance of plant costs such as rectifiers, gas cleaning and drying, the savings potential will be limited. Also learning effects will be less significant for mature solar PV and wind technologies.
Cost of capital
As investors become more comfortable with renewable hydrogen, the cost of capital will fall. Because of the capital intensity of renewable hydrogen production this will directly translate into falling cost of renewable hydrogen. One way this will happen is through a rising debt/equity ratio as technology matures, as was the case for solar and wind. Debt is cheaper than equity because it carries less risk.
The cost of capital depends on perceived risk. Different types of risk exist. Hydrogen offtake risk is currently seen as the main challenge. Technology risk is also significant as limited experience with hydrogen production exists at scale. Many other types of risk are not hydrogen specific such as construction risk, political risk, currency risk, and the solidity of the contracting parties. Risk mitigation and insurance mechanisms exist to deal with these, such as the Multilateral Investment Guarantee Agency, part of World Bank. Also, commercial insurers can play a role for certain types of risk. Nevertheless, all these risk management mechanisms add costs that are often not included in project cost analysis.
Another proposed strategy is to split projects into high risk and low risk components, with the use of long-term capital for the low-risk elements. For example, the project operation phase is less risky than the project development stage. So, refinancing projects with pension funds and sovereign wealth fund capital once they are operational can be a cost reduction strategy.
Blended finance refers to the use of public finance to crowd in private financing. It can be a form of risk mitigation, for example where public funding is used for the risky project initiation and development stage. When blended finance leverages long term capital such as pension funds, it helps to reduce the total financing cost. This is a role that MDBs such as World Bank often play, and the Energy Sector Management Assistance Program has been set up especially for this purpose. The use of blended financing has stagnated in recent years, at a level of around $50 billion across all themes, with 7 percent of that volume being energy. One of the reasons is the complexity of such financing structures and the high management costs that come with it. Given the financing needs, a massive ramp-up would be needed.
Whereas concessional financing and grants can take many forms such as subordinated debt and equity, in the end it is all subsidies. Commercial parties are interested in maximising subsidies whereas the public sector must try to maximise leverage. A balance needs to be struck, and complex structures that stack all kinds of subsidies should be avoided. A basic principle is that concessionality should be minimised while meeting the desired objective. At the same time simplicity is needed. But the devil is in the detail and only real-world experience will show which mechanisms yield the best results.
Financing the cost gap
Countries have pledged significant subsidies. In the US, the Inflation Reduction Act (IRA) and hydrogen hub subsidies have been announced, as well as various other RD&D subsidies totaling more than $25 billion (and some estimates are much higher). In Europe, the International Projects of Common European Interest account for more than $20 billion, along with programs in individual countries such as Germany, France, Italy, the Netherlands, and Denmark, which add up to more than $50 billion. China has announced around $22 billion in subsidies. Japan is considering setting aside $113 billion in public and private sector funding. So in total, existing and planned subsidies worldwide exceed $100 billion.
Given an investment need of around $30 billion per Mt of hydrogen, this is sufficient funding for more than 3 Mt of hydrogen production per year. If private sector funding matches government funding, it may be enough to fund 6 Mt of hydrogen manufacturing capacity. To put it otherwise, World Bank analysis suggests between $25 billion and $200 billion will be needed for electrolyser technology learning investments to “buy down” technology cost. This is quite a wide range reflecting uncertainty, however the amounts on the table today are of the same order of magnitude.
Developing countries’ options
Developing countries cannot match the subsidies in developed countries. One way to deal with this is to wait until the costs have come down due to technology learning elsewhere. Another approach is to use the hydrogen locally to make a product with higher value added. If green steel can earn a premium and the additional costs are limited, this may be viable.
For example, the production of a tonne of green steel requires less than 80 kilograms of hydrogen then the product price premium is less than $200 per tonne of steel. If the steel that is used to make a car costs $20,000, the price premium for that car is 1 percent. It is therefore no surprise that several of these projects are going forward in countries such as Oman and UAE. If the processing takes place close to the ore mine, transportation costs can also be reduced. For example, Mauritania is looking into this option. The potential is important with 8 percent to 10 percent of global CO2 emissions coming from steel production.
The first projects in developing countries will require assistance from abroad. For example, Europe and Germany are very active in fostering renewable hydrogen development abroad. But there is a limit to the availability of such funds. For example, H2Global, a German vehicle to guarantee offtake prices for 10 years, has a volume of around $5 billion. These funds can sustain around 0.2 Mt of hydrogen production per year. The fact that funding is only provided for ten years provides a partial solution for projects with a life span of two of three decades. Once the projects come onstream valuable insights will be gained.
Development Financing Institutions (DFIs) have a key role to play, channeling funds from developed to developing countries. As climate gains a higher place on the development agenda, hydrogen financing is growing rapidly. But these funds are not infinite: MDB climate financing amounted to $82 billion in 2021. While there may be headroom in the balance sheets to increase climate financing, there are many other urgent development needs. One instrument that has gained remarkable traction is the IMF Resilience and Sustainability Trust, which also has an energy transition dimension.
Financing hydrogen is an important topic that is moving to the top of the priority list. The World Bank is providing guidance through the preparation of a new flagship hydrogen financing report that is being prepared in cooperation with partners, in support of the Breakthrough Agenda. The preparations are ongoing, and the report is due at COP28.