It is estimated that the cheapest green hydrogen (H2) production in 2030 would come from Latin American countries. The latest data on hydrogen levelized costs shows: 1) a decrease of 13% in the 2030 green H2 forecast, compared to the previous outlook; 2) by 2030, green hydrogen should be cheaper than blue hydrogen in many markets and it will be competitive with natural gas by 2050, without considering carbon price; and 3) the costs of the most attractive green hydrogen projects will be almost three times cheaper than in some hydrogen importing markets, such as South Korean and Japan. Green hydrogen will be cheaper than blue and gray hydrogen in some of the key importing markets.
Why does it matter for Latin America and the Caribbean?
First, we will discuss the meaning of the hydrogen levelized cost update. In chapter 9 of the book “From Structure to Services”, we discussed the underestimation of the adoption of renewables in forecasts during the last two decades. The costs of renewables decreased much faster than was previously expected and, as consequence, the adoption has been much quicker than anticipated. It can be seen because of many effects. Challenges associated with predicting the development of innovative technologies are one of them. Most of the models are somehow based on historical data.
In the context of innovation, we do not know exactly how it will happen, but we know that it will not follow the behavior of historical data. It is at the coeur of the innovation definition. Looking at the evolution of the green hydrogen cost forecast, it seems that will follow the same tendency as what we observed in renewables. Green hydrogen will be adopted quicker than predicted. It makes sense as renewable energy represents around (or more than) 60% of its total cost.
Second, let us discuss how quickly green hydrogen will be competitive. Nowadays, green hydrogen is more expensive than grey and blue and, as consequence, they are strongly dependent on policy incentives. These incentives usually aim to accelerate the energy transition, enabling early adoption of technology in order to internalize the value chain earlier and aggregate value. These strategic choices, however, tend to be costly. Cost and benefits should be carefully analyzed by policymakers as part of their informed decision-making process.
The region competitiveness for green hydrogen
If green hydrogen will be competitive with other forms of hydrogen by 2030 and with natural gas by 2050, policymakers should decide their strategies with a relatively short time horizon. They should start their strategy as quickly as possible, especially when considering big infrastructure investment decisions, both in hydrogens and also other competitive markets, such as natural gas.
Third, the Latin American and Caribbean (LAC) position in this context. Renewable endowment in Latin America is well known for being not one of the most cost-effective, but also one of the most promising. This is not just because of the extent of available wind and sun, but due to their combination and stability. The rich endowment can be analyzed in some specific places or countries, but also as a regional value. According to BNEF estimates, the most cost-effective green hydrogen projects in the world are in Latin America. Likewise, even if there is uncertainty about what will be the main technology for hydrogen shipping, in most cases, distance will probably have a small impact on the total cost of this potential international trade. In other words, many LAC countries have a real comparative advantage in the green hydrogen industry. This comparative advantage should be considered when analyzing the cost and benefit for policy strategies, designs, and incentives.
Now, what is some of the key challenges and opportunities for policy design?
Hydrogen economies have some similarities with natural gas: the transportation costs the cost of long distance, the diversity of use, and the lack of captive demand.
If we think about how the natural gas international market developed (pipelines and LNG), it was basically based on long-term contracts with two characteristics: take or pay clauses with netback price. It was a way to share the risk (volume and price) and guarantee that the natural was competitive in throughout the major markets.
Similarly, for the green hydrogen market to flourish, it will be also necessary to have long-term contracts and risk-sharing clauses.
However, we will not be able to use the same logic. The substitute’s netback price (if not considered CO2 costs) in most markets is not enough to pay for green hydrogen, at least nowadays. Green hydrogen, for now, just makes economic sense if it is compared with other technologies with net zero emission, which is not reflected in prices yet. For that, some kind of CO2 or green hydrogen/ammonia certification and pricing need to be developed.
What could we learn from the development of other technologies?
When thinking about national policies, especially for renewables, we can benefit from some lessons learned from solar and wind. In both cases, in addition to all the policies associated with supply-side Research and Development subsidies, the key to massify the use of the technology was the demand-side policy. First, in the format of Feed-In tariffs (FIT), which can be thought of as a kind of take or pay arrangement with a pre-established price. The government assures to buy whatever volume, by a determined price (this policy can better or worse be designed). After that, in some countries, people start to use another demand-side policy: namely auctions. The incentives are not that different from the Feed-In mechanism. The key difference is that the price of the long-term contract is defined through competitive bids. However, in both cases, a policy strategy takes place through the electricity system, in which the risk somehow is allocated through captive electricity consumers. The question is: could the same logic of renewables policy design be applied for hydrogen?
To some extent, yes. But not completely. Many green hydrogen projects to be economically efficient and scalable should be associated with diverse hydrogen uses. In another sector, there are no captive consumers and most of them have access to very competitive markets, such as fuels for transportation, ammonia, iron, and steel. Besides, electricity market captivity may be changing in the next decades because of the increasing use of distributed energy. As consequence, it is important on one hand to look at how the electricity policies can play a role, such as auctions, areas that the region has a long and successful experience. On the other hand, it is important also to identify the complementary industries that might be interested in and what kind of incentives they would be interested in. Green certifications can be a non-intrusive incentive that can be interesting, especially for companies that have already announce net zero emissions targets, which is expected to become more common as we approach the middle of the century.
To discuss all these opportunities and more that IDB invited specialists from the private and public sector, from financing, consulting, and research institutions to debate in several roundtables how to benefit from the future of hydrogen in LAC. At the Bank, we know that for an innovative industry in the embryonic stage such as green hydrogen to flourish, two key elements are essential: coordination between the main stakeholders involved (public and private sector, academia, international organizations, etc.), as well as creation/dissemination of relevant information and knowledge. At the Bank, we will continue to be committed to that agenda.
 According to BNEF, cost fall well below $2/kg by 2030
 According to OFGEM “The FIT scheme is a government program designed to promote the uptake of small-scale renewable and low-carbon electricity generation technologies. … Once you’re accredited, a tariff will be assigned to your installation based on a number of factors including but not limited to technology, Total Installed Capacity (TIC), and your position in deployment caps. For more information, see Feed-in Tariffs deployment caps reports.” Feed-In Tariff (FIT) rates | Ofgem