Blue hydrogen production involves making hydrogen (H2) from fossil fuel feedstocks while using carbon capture and storage (CCS) to reduce CO₂ emissions from the production process. The captured CO₂ is concentrated, compressed, and permanently stored underground. Blue hydrogen is more expensive than gray hydrogen, the predominant hydrogen production method, but less expensive than zero-emissions green hydrogen. Blue hydrogen production could facilitate the expansion of hydrogen infrastructure and the development of the global hydrogen economy. However, current adoption is low, its effectiveness at reducing GHG emissions is variable, and it could compete with technologies that offer greater climate benefits. Because of its reliance on fossil fuels for both feedstock and energy, the expansion of blue hydrogen production would perpetuate and potentially expand the use of fossil fuels. Based on this risk, we conclude that producing blue hydrogen is “Not Recommended” as a climate solution.
Based on our analysis, blue hydrogen is feasible and ready to deploy, but there is little real-world evidence for its effectiveness or ability to scale. The expansion of this technology to replace current gray hydrogen production or to support the transition to a global hydrogen economy will perpetuate and possibly expand the use of fossil fuels. Because of this risk, we conclude that producing blue hydrogen is “Not Recommended.”
| Plausible | Could it work? | Yes |
|---|---|---|
| Ready | Is it ready? | Yes |
| Evidence | Are there data to evaluate it? | Limited |
| Effective | Does it consistently work? | No |
| Impact | Is it big enough to matter? | No |
| Risk | Is it risky or harmful? | Yes |
| Cost | Is it cheap? | Yes |
Blue hydrogen production is an industrial process that produces hydrogen (H2) from fossil fuels – either natural gas or coal – combined with carbon capture and storage (CCS) technology to reduce CO₂ emissions produced during the process. Today, most hydrogen is gray hydrogen made from natural gas without any CCS. The addition of CCS prevents the release of some of the CO₂ generated during the hydrogen production process; capturing, concentrating, and then storing it permanently underground.
The technologies for making hydrogen from natural gas, predominantly steam methane reformation (SMR), are well established and have been used to produce hydrogen for close to a century. CCS technology is also available and currently deployed in multiple industrial and power generation applications. The SMR hydrogen production process generates GHG emissions from two sources: methane leaks from the gas used as feedstock and fuel used to power the production process, and GHG emissions from both the SMR process and combustion of gas (or other fuels) for energy, including CO₂, methane, nitrous oxide, and black carbon. CCS can be applied to capture CO₂ produced during the SMR process, for post-combustion capture of CO₂ from the plant’s energy use, or for both. Incorporating CCS to capture emissions from the hydrogen production process adds costs and increases energy use, but it could theoretically reduce CO₂ emissions by more than 90%. However, current adoption of blue hydrogen is very low – less than 1% of global hydrogen production – and there is little real-world evidence to support its effectiveness and scalability. The few commercial facilities currently in operation capture only about 60% or less of the emitted CO₂. Because CCS is energy-intensive, it requires more fuel to power the blue hydrogen production plant. This can also increase fugitive methane leaks due to increased gas-powered energy consumption. If implemented adequately, carbon storage can be permanent. The captured CO₂ can also be used as a chemical precursor for the manufacture of other products or for enhanced oil recovery; however, these post-capture uses of CO₂ emit GHGs, thereby reducing or eliminating the emissions reduction efficacy of CCS. Currently, only ~8% of CO₂ captured from blue hydrogen production is injected into dedicated geological storage, with the rest used in industry, enhanced oil recovery, and other applications.
Hydrogen can be combusted as a zero-emissions fuel, used to store energy to produce electricity, or deployed as a feedstock in industrial, transportation, and energy systems. The production of any hydrogen type – blue, gray, or green hydrogen – could facilitate the expansion of hydrogen infrastructure and the development of the global hydrogen economy, which is an important step in scaling hydrogen. Blue hydrogen is more technologically ready and cheaper than green hydrogen, which is made from water using electrolysis powered by renewable energy. Blue hydrogen is more expensive to produce than gray hydrogen, but the cost per metric ton of CO₂ removed could be relatively low. Estimates range from US$60–110/t CO₂, although these costs are uncertain and, with lower CCS effectiveness, they could increase to ~US$260/t CO₂. If implemented with low fugitive methane emissions and high CCS efficiencies, blue hydrogen could substantially reduce emissions compared to current gray hydrogen production. The climate impact of scaling blue hydrogen could be high. Estimates and targets for blue hydrogen production by 2050 range from ~30–85 Mt hydrogen. At that scale, even modest emissions savings relative to gray hydrogen would have a climate impact above 0.09 Gt CO₂‑eq/yr by 2050. However, achieving this depends on the quality of the infrastructure and rate of technology scaling, both of which are unproven.
Currently, 6% of the world’s natural gas and 2% of its coal are used to make hydrogen. As hydrogen production ramps up, blue hydrogen – even though it reduces production emissions compared to gray hydrogen – would perpetuate and could even increase the global market for fossil fuels. If the future implementation of green hydrogen is set back, blue hydrogen could create a long-term dependence on fossil fuels. Furthermore, any hydrogen produced from natural gas leads to methane leaks, regardless of whether CO₂ is captured. Methane is a potent short-lived GHG, meaning its impact on climate warming is stronger in the near-term. This is why reducing methane emissions is an urgent emergency brake climate action. Building and expanding a new industry that relies on natural gas as both a feedstock and fuel, and which inevitably leaks methane, is counterproductive to solving the climate crisis.
If and when there is a transition to a global hydrogen economy, blue hydrogen is a less effective climate solution than green hydrogen. Although this technology could be a transitional solution between gray and green hydrogen, blue hydrogen risks diverting resources away from green hydrogen development or ready-to-deploy renewable energy technologies, such as onshore wind or distributed solar PV. Expert opinions are mixed regarding the realistic level of avoided emissions that blue hydrogen may reach. Additionally, there is uncertainty around whether CCS can meet its technical potential at a reasonable cost.
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In this solution, green hydrogen replaces fossil fuel–based hydrogen for use as a feedstock in the production of more complex molecules such as ammonia for fertilizers and methanol for the production of other commodity chemicals. Green hydrogen production in this solution uses on-site renewable electricity or off-site renewable electricity that directly supplies the facility. It replaces hydrogen produced from fossil fuels. This solution does not include the use of green hydrogen as a fuel or as a feedstock in the production of hydrogen-based fuels.
Green hydrogen in this solution is hydrogen produced from water by electrolysis using renewable electricity generated on-site or directly supplied from an off-site location. It can reduce emissions when replacing hydrogen made from fossil fuels as an industrial feedstock.
Today, most hydrogen is produced through a chemical reaction of methane or coal with water that generates hydrogen and CO₂. Green hydrogen, made by splitting water into hydrogen and oxygen using electricity generated from renewables, accounts for less than 1% of current production (International Energy Agency [IEA], 2025a). The process of making green hydrogen generates no direct GHGs. Therefore, replacing fossil fuel–derived hydrogen with green hydrogen avoids all direct GHGs from the hydrogen production process.
Hydrogen prolongs the lifespan and abundance of GHGs in the atmosphere when it leaks, and so can indirectly contribute to climate change. However, because this solution substitutes one source of hydrogen for another, it will have little to no effect on this indirect climate impact.
The manufacture of industrial hydrogen from fossil fuels for all applications was responsible for 680 Mt of emissions in 2023 (IEA, 2024), nearly all of which could be eliminated by substituting green hydrogen.
In 2023, roughly 60% of industrial feedstock hydrogen was used to produce ammonia, a vital ingredient in nitrogen fertilizers while 30% was used to produce methanol (IEA, 2024), an ingredient in the manufacture of a wide range of chemicals, including plastics, building materials, and car parts (International Renewable Energy Agency [IRENA] & Methanol Institute, 2021). Although alternative low-carbon pathways exist for ammonia and methanol, these are difficult to scale, still under development, or reliant on biomass, which is a finite resource associated with potential land-use change and competing demand (IRENA & Methanol Institute, 2021; Rodriguez, 2025).
While there are other ways to make low-carbon hydrogen, none has demonstrated potential to cut emissions from hydrogen production as effectively as this solution. For example, harvesting naturally occurring hydrogen is a nascent industry with lots of uncertainties (The Royal Society, 2025), and hydrogen made from biomass must compete for biomass with other hard-to-abate sectors.
The greatest hurdle to green hydrogen deployment is cost. Green hydrogen is one-and-a-half to six times more expensive to produce than hydrogen from fossil fuels (IEA, 2024). Regulatory and demand uncertainty, licensing and permitting issues, and challenges with operational scale-up are also barriers to green hydrogen projects (IEA, 2024). Nevertheless, production capacity has started to grow: installed electrolyzer capacity doubled in 2023, supported by policies and incentives (Pavan et al., n.d.).
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Heather McDiarmid, Ph.D.
Ruthie Burrows, Ph.D.
James Gerber, Ph.D.
Daniel Jasper
Alex Sweeney
Nina-Francesca Farac, Ph.D.
James Gerber, Ph.D.
Amanda D. Smith, Ph.D.
Our analysis showed that replacing hydrogen made from fossil fuels with green hydrogen made using renewable electricity can reduce 0.012 t CO₂‑eq /kg hydrogen (20-yr and 100-yr basis, Table 1).
This analysis does not include the emissions associated with manufacturing and installing electrolyzer equipment or the energy and emissions impacts of storing or transporting hydrogen if needed.
Table 1. Effectiveness at reducing emissions.
Unit: t CO₂‑eq /kg green hydrogen, 100-yr basis
| 25th percentile | 0.010 |
| Mean | 0.014 |
| Median (50th percentile) | 0.012 |
| 75th percentile | 0.016 |
Our estimates put the levelized cost of making hydrogen (LCOH) from coal and natural gas without any form of carbon emissions capture at US$1.90/kg hydrogen, while we estimated the LCOH of green hydrogen from renewable electricity at US$3.60/kg green hydrogen. LCOH represents the average cost to make a kilogram of hydrogen over the facility’s lifetime and includes all installation, operating, and equity costs. These values are in line with the IEA’s estimate that renewable hydrogen costs one-and-a-half to six times more than unabated fossil-fuel based production (IEA, 2024), with most of the higher cost attributed to the upfront costs (IEA, 2025a).
The LCOH for green hydrogen shows significant variability, ranging from US$1.40/kg for hydrogen from solar in Chile (Vartiainen et al., 2022) to US$10.60/kg for hydrogen from solar in Italy (Ademollo et al., 2025). This reflects geographic differences in renewable energy generation potential and costs as well as differences in electrolyzer technologies, financing terms, and project scales (Kim et al., 2025; Li et al., 2025). Variation also arises from how renewable electricity is produced. Some modeled green hydrogen LCOH values may be underestimates due to the higher cost of operating electrolyzers at less than full capacity when intermittent renewable generation is used (Ademollo et al., 2025).
We do not report the cost per climate impact because most of our cost data are based on theoretical values, not real projects, and because LCOH values do not include revenues.
Our data show a median learning rate of 18% for the electrolyzer technologies used to make green hydrogen (Table 2) based on five studies. In other words, for every doubling of electrolyzer capacity, the equipment costs decrease by 18%. This is a median value for many electrolyzer types, each of which varies in its technological maturity and rate of cost decline. Research is ongoing to reduce the capital cost of electrolyzers, improve the energy efficiency of the process, and increase operational lifetimes of the equipment (U.S. Department of Energy, n.d.). While these studies consistently indicate declining electrolyzer costs with cumulative electrolyzer capacity, IEA (2025a) reported that costs have recently risen, largely due to inflation.
The basic technology for splitting water into hydrogen and oxygen using electricity was developed more than 230 years ago (Smolinka et al., 2022). The process is simple enough that it is used in high school science classes around the world, but more complex equipment is needed to make and collect hydrogen on an industrial scale.
The production of green hydrogen requires additional equipment beyond electrolyzers, such as renewable power generators, water purification plants, and equipment to process hydrogen, all of which have their own learning rates.
Table 2. Learning rate: drop in cost per doubling of installed electrolyzer.
Unit: %
| 25th percentile | 15 |
| Mean | 20 |
| Median (50th percentile) | 18 |
| 75th percentile | 24 |
Speed of action refers to how quickly a climate solution physically affects the atmosphere after it is deployed. This is different from speed of deployment, which is the pace at which solutions are adopted.
At Project Drawdown, we define the speed of action for each climate solution as emergency brake, gradual, or delayed.
Deploy Industrial Green Hydrogen Feedstock is a GRADUAL climate solution. It has a steady, linear impact on the atmosphere.
This analysis defines green hydrogen as hydrogen made through electrolysis using onsite renewable electricity. However, many sources only provide data for electrolytic hydrogen, clean hydrogen, or low-carbon hydrogen. Each of these includes green hydrogen but may also include electrolytic hydrogen made using grid electricity, hydrogen made from biomass, or hydrogen made from fossil fuels with carbon capture and storage. We have clearly labeled when the data refer to the more generalized low-carbon electrolytic hydrogen rather than green hydrogen.
Adoption of green hydrogen as a feedstock depends on policy support for green hydrogen, regulations to drive demand for low-carbon end products made from hydrogen (Odenweller & Ueckerdt, 2025), and standardized certification for green hydrogen, including methodologies for GHG emissions monitoring (IEA, 2025a). Regulation and permitting issues can also delay green hydrogen projects and increase overall costs.
We assumed that manufacture of methanol, ammonia, and other industrial products currently using hydrogen as a feedstock will not shift to new processes (e.g., biological) for their production. We also assumed that naturally occurring hydrogen (sometimes called white hydrogen) and other forms of very-low-carbon hydrogen will not compete with green hydrogen for use as an industrial feedstock.
Green hydrogen requires a supply of purified water. Removing impurities, minerals, and ions from water has a carbon footprint (Henriksen et al., 2024); that cost is not included in this analysis.
Based on IEA (2025c), we estimate that operational projects are currently making 130 million kg of green hydrogen for use as an industrial feedstock per year (Table 3). This represents less than 1% (55 Mt) of all industrial hydrogen demand in 2024 (IEA, 2025a). It may be an underestimate because we only included projects that we were able to confirm to use on-site renewable electricity or off-site renewable electricity that directly supplies the facility.
The higher cost of green hydrogen relative to hydrogen made from fossil fuels is a major barrier to adoption, along with uncertain demand and regulatory environments (IEA, 2025a).
Table 3. Current (2025) adoption level of green hydrogen as feedstock.
Unit: kg green hydrogen/yr
| Estimate (from IEA (2025c)) | 130,000,000 |
The IEA (2025a) has historical data on the production of low-carbon hydrogen using electrolysis for industrial applications; this includes green hydrogen but could also include hydrogen made from grid electricity. The data give an average annual rate of increase of 8.1 million kg/yr electrolytic hydrogen for use as an industrial feedstock and are likely an overestimate for purely green hydrogen (Table 4). Much of the added industrial low-carbon hydrogen from electrolysis was produced in China (IEA, 2025a).
This rate of adoption is slower than expected; only 7% of anticipated 2023 projects have materialized, owing in part to high costs, limited demand, and lack of supportive policies (Odenweller & Ueckerdt, 2025). However, while there has been a decline overall in hydrogen offtake agreements, more than half of agreements signed are dedicated to the manufacture of ammonia and methanol, the two main industrial products that rely on hydrogen as a feedstock (IEA, 2025a). Between March 2025 and September 2025, the estimated production volume from operational industrial green hydrogen feedstock projects increased from 32 million kg/yr to 130 million kg/yr (data extracted from IEA, 2025b, 2025c).
Table 4. Low-carbon electrolytic hydrogen as feedstock, 2021–2024 adoption trend.
Unit: kg low-carbon electrolytic hydrogen/yr/yr
| Estimate (from IEA 2025a) | 8,100,000 |
Current demand for hydrogen as an industrial feedstock is 50 billion kg/yr (Table 5), all of which technically could be supplied with green hydrogen. This value is based on the IEA (2025a)’s estimate of 2024 industrial hydrogen demand, with 90% allocated to its use as a feedstock for ammonia and methanol production. Since demand for industrial hydrogen for ammonia production increased by 3.4% and for methanol production by 2.0% in 2023 (IEA, 2025a), the actual adoption ceiling will increase as the production of industrial hydrogen increases.
Table 5. Green hydrogen as a feedstock adoption ceiling.
Unit: kg green hydrogen/yr
| Estimate (from IEA 2025a) | 50,000,000,000 |
We estimated that 26–50 billion kg/yr of fossil-based hydrogen could be replaced with green hydrogen as an industrial feedstock by 2050, which is 53–100% of today’s total demand (Table 6).
The Achievable – Low adoption level is an average of McKinsey & Company and Wood Mackenzie’s estimated percent of hydrogen supplied by “clean” or “low-carbon” hydrogen in 2050, which presumably includes hydrogen made from fossil fuels with capture of carbon emissions (Douglas et al., 2025; Gulli et al., 2024). Wood Mackenzie projects that only 33% of traditional carbon-intensive hydrogen will be replaced with low-carbon hydrogen, while McKinsey & Company expects at least 73% of hydrogen demand to be met with clean hydrogen. These estimates may be low, given that the EU has committed to deriving 42% of industrial hydrogen from renewable sources by 2030 and 60% by 2035 (European Parliament & Council of the European Union, 2023).
The Achievable – High adoption level is set at 100% of today’s industrial feedstock hydrogen, consistent with McKinsey & Company’s upper-end projection that all hydrogen demand could be met by clean hydrogen by 2050 (Gulli et al., 2024).
Table 6. Green hydrogen as a feedstock range of achievable adoption levels (kg hydrogen/yr).
Table 6. Green hydrogen as a feedstock range of achievable adoption levels.
Unit: kg green hydrogen/yr
| Current adoption | 130,000,000 |
| Achievable – low | 26,000,000,000 |
| Achievable – high | 50,000,000,000 |
| Adoption ceiling | 50,000,000,000 |
Current adoption of green hydrogen as an alternative is too low to have a globally meaningful climate impact (less than 0.002 Gt CO₂‑eq/yr estimated on both 20- and 100-year basis). We estimate that green hydrogen could reduce 0.31 Gt CO₂‑eq/yr (100- and 20-year basis) of emissions at the Achievable – Low level and 0.60 Gt CO₂‑eq/yr (100- and 20-year basis) at the Achievable – High level (Table 7). This outcome is closely aligned with the IEA’s estimate that in 2023, industrial hydrogen use was responsible for 680 Mt CO₂‑eq/yr, 90% (0.61 Gt CO₂‑eq/yr ) of which is used as a feedstock for ammonia and methanol production (IEA, 2024).
Table 7. Green hydrogen as a feedstock climate impact at different levels of adoption.
Unit: Gt CO₂‑eq/yr, 100-yr basis
| Current adoption | 0.00 |
| Achievable – low | 0.31 |
| Achievable – high | 0.60 |
| Adoption ceiling | 0.60 |
Research on the direct linkages of green hydrogen with employment is limited; however, the development and adoption of this technology is expected to create jobs (Anand et al., 2025). One study of the expansion of green hydrogen in Europe projected that by 2050, shifting to low-carbon hydrogen would directly create 18,000–50,000 jobs (Ganter et al., 2024). This is mostly driven by the higher labor demand of the electrolysis process. Some jobs associated with green hydrogen are in the construction sector and would not be permanent (Irarrazaval et al., 2026).
Reducing air pollution by switching from fossil fuels to renewable energy decreases exposure to pollutants such as lead and fine particulate matter generated when hydrogen is made from fossil fuels, thereby improving the health of nearby communities (Cho et al., 2022; U.S. Environmental Protection Agency [U.S. EPA], 2025). These pollutants have been linked to increased morbidity from cardiovascular and respiratory disease, asthma, infections, and cancer (Gasparotto & Martinello, 2021) and to increased risk of premature mortality (Henneman et al., 2023).
Green hydrogen production is more water-efficient than most other types of hydrogen production, but water resource benefits can vary based on geography and renewable energy source (IRENA & Bluerisk, 2023; Du et al., 2024).
Displacing fossil fuel–based hydrogen with renewable energy–based hydrogen will reduce climate and air pollutants associated with burning higher-carbon fuels, such as CO₂, nitrogen oxides, methane, lead, and fine particulate matter (Anand et al., 2025; Cho et al., 2022; Paardekooper et al., 2020; U.S. EPA, 2025).
Investments in green hydrogen policies and programs to support its use as a feedstock can also support its use as a fuel. Many potential applications for green hydrogen as a fuel, however, are less practical, cost-effective, and efficient than direct electrification, and investments in green hydrogen infrastructure risk diverting efforts away from these better alternatives (Johnson et al., 2025).
Green hydrogen production requires a water supply. Many existing and planned green hydrogen projects are in water-stressed regions, including China, India, the Gulf States, and parts of the European Union (IRENA & Bluerisk, 2023). However, hydrogen production by other processes also requires a water supply and can exceed the water demand for green hydrogen (Henriksen et al., 2024).
Methanol made from industrial green hydrogen could compete with biomass-derived methanol, a product of the Deploy Low-Emission Industrial Feedstocks solution, thereby reducing that solution’s impact.
kg of hydrogen produced
CO₂ ,CH₄, N₂O, BC
There are embodied emissions associated with manufacturing and installing any industrial equipment, including the equipment used to make hydrogen of all kinds and renewable energy. Such emissions are not included in the analysis here, but they can be significant and their value depends on a variety of factors (Hermesmann & Müller, 2022; Iyer et al., 2024, National Renewable Energy Laboratory [NREL], 2021).
Consensus of effectiveness in reducing emissions: High
Green hydrogen that replaces fossil fuel–based hydrogen is widely regarded as an important approach for reducing emissions from this industrial feedstock. Blue hydrogen, made from fossil fuels with carbon capture and storage, competes with green hydrogen as a feedstock. However, incomplete carbon capture alongside methane leaks from natural gas extraction and transportation give blue hydrogen a notably higher carbon footprint (IEA, 2023).
The IEA publishes an annual report on global hydrogen, including updates to global demand for hydrogen by sector, production routes, trade, investments, and policies (IEA, 2024, 2025a). These reports highlight how low-carbon electrolytic hydrogen production is increasing, albeit at a slower pace than previously expected. With 65 countries now having a hydrogen strategy and new policies being implemented in key regions, low-carbon hydrogen demand is expected to grow, with most new investments focused on low-carbon hydrogen as an industrial feedstock.
Accelerating this growth is critically important to meet established GHG emission targets. Odenweller and Ueckerdt (2025) highlighted how plans for green hydrogen should focus on hard-to-electrify sectors, including industrial hydrogen feedstocks. They also emphasized the need for policymakers to use demand-side policies such as quotas and mandates along with developing plans to transition subsidies to market mechanisms such as fixed pricing mechanisms for green hydrogen and contracts for difference.
The results presented in this document summarize findings from four reviews and meta-analyses, two databases, three reports, and 11 original studies reflecting current evidence from 10 countries, primarily China and the United States. We recognize this limited geographic scope creates bias, and hope this work inspires research and data sharing on this topic in underrepresented regions.
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