The rapid expansion of renewable energy sources has brought a fundamental technical challenge for grid operators worldwide: how to balance the intermittency of solar and wind generation with the constant demand for electricity. As countries advance towards their decarbonization goals, hydrogen emerges as a multidimensional solution capable of integrating energy storage, operational flexibility, and emissions reduction into a single system.
The global hydrogen market reached between USD 224 and 282 billion in 2025, with projections of USD 557 billion by 2034, according to data from Precedence Research. Although grey hydrogen (produced from natural gas via steam reforming) still represents 97.62% of the world's production of approximately 97 million tons annually, cost convergence with low-emission alternatives is closer than one might imagine.
Cost dynamics and the competitiveness of green hydrogen.
Analysis of levelized hydrogen costs reveals a clear trajectory of competitiveness. Gray hydrogen remains cheaper globally, ranging from USD 0.98 to 2.93 per kilogram. Blue hydrogen, which incorporates carbon capture and storage, is priced between USD 2.80 and 3.50 per kilogram. Green hydrogen, produced by electrolysis powered by renewable sources, currently costs between USD 4.50 and 7.00 per kilogram on average globally.
Brazil stands out in this scenario. According to data from the National Center for Research in Energy and Materials and analyses by Thymos Energia, regions of Northeast Brazil, especially Bahia and Ceará, are already producing green hydrogen for USD 2.35 to 3.74 per kilogram, taking advantage of solar electricity costs between USD 15 and 25 per megawatt-hour. This competitiveness positions the country among the five most advantageous markets globally, alongside China and Morocco.
Bloomberg NEF projections indicate that green hydrogen will reach cost parity with gray hydrogen in eight markets by 2030, expanding to most global markets by 2035. This movement fundamentally depends on two variables: a 35% to 50% reduction in the capital cost of electrolyzers and a continued decline in renewable energy prices.
Reducing curtailment: The first tangible economic value
One of the most immediate benefits of hydrogen for electricity grids is the reduction of curtailment (waste of renewable energy when generation exceeds transmission capacity or instantaneous demand). Recent data shows that California wasted 738,000 MWh in just the first four months of 2024, with an annual projection of 2.2 million MWh. Spain recorded 11% solar curtailment in July 2025, while Northeast Brazil reached 21% in the first half of the same year.
Flexible electrolysis offers a proven technical solution. PEM electrolyzers respond to generation variations in 0.5 to 2 seconds, absorbing surplus energy and converting it into storable hydrogen. Conservative models indicate an 8% to 13% reduction in curtailment with the gradual implementation of 5 to 8 gigawatts of installed capacity by 2030. In Texas, where curtailment reaches between 3 and 5 terawatt-hours annually, this reduction would represent savings of between USD 7 and 33 million per year in recovered energy alone, without considering avoided redispatch costs.
The limitation of this range to 8% to 13% reflects practical constraints: only 60% to 70% of renewable generation will have electrolyzers established in the short term, and not all curtailed energy is economically viable to capture, especially when spot prices exceed USD 10 per megawatt-hour.
Seasonal storage: balancing energetic summers and winters
While lithium-ion batteries dominate short-term storage (up to 8 hours) with efficiencies of 85% to 90%, hydrogen occupies a strategic niche in seasonal storage, from weeks to months. This role becomes critical in systems with high renewable penetration, where the variation between peak and trough generation can reach 200% to 400% between summer and winter, depending on latitude and energy mix.
Underground salt caverns represent the most mature technology for geological storage. Germany operates 40 commercial caverns, with a capacity equivalent to 20 to 30 terawatt-hours. The Underground Sun Storage 2030 project in Austria commercially validated the concept by storing 500,000 cubic meters of hydrogen in a depleted sandstone cavern, with a recovered purity exceeding 99%.
Brazil has an estimated potential of 30 to 50 gigatons in pre-salt salt caverns, sufficient capacity for seasonal storage to complement the natural 60 gigawatt-hours of hydroelectric reservoirs. However, this infrastructure remains underdeveloped, requiring a pilot investment of USD 500 million to 1 billion to demonstrate two to three caverns.
The efficiency of the complete cycle (electrolysis, compression, storage and reconversion via gas turbine) reaches 32%, lower than the 85% of batteries, but competitive for durations exceeding one week, where alternatives become economically unviable.
Flexible dispatch and gradual decarbonization through hybrid turbines.
Integrating hydrogen into conventional gas turbines offers a pragmatic transition path. Validated tests in June 2025 by Georgia Power, using a Mitsubishi M501GAC turbine, demonstrated sustained operation with 50% hydrogen at full and partial load, reducing CO₂ emissions by 22% and maintaining a response time of 15 to 20 minutes.
Hydrogen blends of 20% to 30% are already an industry standard, with manufacturers such as Siemens and GE offering validated commercial turbines. Retrofitting a 600-megawatt plant to operate with 30% hydrogen costs between USD 50 and 80 million, with emission reductions of 28% to 32% and an estimated payback period of 10 to 12 years under carbon pricing of USD 80 to 100 per ton.
Perspectives for Brazil: a three-phase structure
Brazil has an established industrial demand of 5.2 million tons of grey hydrogen annually, distributed among Petrobras refineries, ammonia production for fertilizers, and the steel industry. Replacing 50% to 80% of this hydrogen by 2030 represents a domestic market opportunity even before exports.
Thymos Energia projects a three-phase development schedule: consolidation between 2025 and 2028, with an investment of USD 3 to 5 billion and operationalization of anchor projects such as the Pecém hub; scaling between 2028 and 2035, expanding capacity to 10 to 15 gigawatts of electrolysis and production of 8 to 15 million tons per year; and global leadership between 2035 and 2050, with 30 to 40 gigawatts installed.
Structural challenges persist: capital costs of 5% to 8% per year compared to 1% to 3% in developed markets, transmission bottlenecks between the Northeast and Southeast regions, and regulations still being finalized by the ANP (National Agency of Petroleum, Natural Gas and Biofuels). The 2024 Hydrogen Law, which foresees R$ 18.3 billion in tax credits, represents significant progress, but long-term viability depends on predictable regulatory frameworks for at least ten years.
The integration of hydrogen into electricity grids transcends mere fuel substitution. It is a systemic architecture that combines curtailment absorption, seasonal storage, and flexible dispatch, enabling the next phase of the global energy transition, with Brazil strategically positioned in this projected USD 557 billion market for 2034.
