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Blue hydrogen

Blue hydrogen hydrogen colours natural gas CCS methane emissions Carbon footprint Industry

Blue hydrogen is hydrogen that is usually produced from natural gas. Part of the carbon dioxide generated in the process is captured, transported and permanently stored in geological formations. The abbreviation CCS (Carbon Capture and Storage) is commonly used for this chain. Technically, this is usually done via steam reforming of methane or via autothermal reforming. The carbon in the natural gas is not avoided in the process. Instead, part of it is removed afterwards from the process gas or the flue gas. Blue hydrogen is therefore not renewable hydrogen but a fossil pathway with CO₂ capture and storage. In EU law, the closest equivalent is the term "low-carbon hydrogen". However, this category is technology-neutral and tied to an emissions threshold, not to a colour.

The colour does not describe a physical property. A hydrogen molecule from natural gas cannot be distinguished from one produced by electrolysis or from biomass. The hydrogen colours only classify the production route. This is practical for political debates, but it invites oversimplification. Anyone speaking of blue hydrogen should always keep in mind: Where does the natural gas come from? Which process is used? What is the actual capture rate across the whole plant? How much additional energy does the process require? And how reliably do the transport and storage of the CO₂ work?

Production: steam reforming and autothermal reforming

In steam reforming, methane reacts with steam at high temperatures to form synthesis gas, a mixture of hydrogen and carbon monoxide. The heat required is supplied by a burner outside the reactor tubes, which is usually also fired with natural gas or residual gases. In the downstream water-gas shift reaction, carbon monoxide reacts with steam to form further hydrogen and carbon dioxide. CO₂ is thus generated in two places: concentrated and under pressure in the process gas, where it is comparatively easy to separate, and diluted in the flue gas of the firing, where capture is more complex and more expensive. If only the process gas stream is captured, a considerable share of the emissions remains unabated. High overall capture rates require that the flue gas is also treated.

In autothermal reforming, part of the natural gas is converted with oxygen in the reactor itself. The process heat is therefore generated internally, and the CO₂ arises predominantly in concentrated form in the process gas. This facilitates higher capture rates. In return, the plant needs an air separation unit to supply oxygen, which in turn requires electricity. Both processes continue to depend on natural gas and require additional infrastructure for CO₂ compression, transport and geological storage.

Distinction from grey, green and turquoise hydrogen

Grey hydrogen is produced from natural gas using the same processes, but without CO₂ capture. The process-related emissions are released entirely into the atmosphere. Blue hydrogen therefore does not differ in its raw material, but in the additional step of capturing as large a share of the CO₂ as possible and storing it permanently.

The difference from green hydrogen is more fundamental. It is produced by electrolysis using electricity from renewable sources. No fossil carbon is converted in operation. Its climate balance depends mainly on the origin of the electricity, the efficiency of the electrolysis and the use of scarce renewable generation. With blue hydrogen, natural gas extraction, gas transport and the fossil carbon source remain part of the balance.

Turquoise hydrogen is produced by methane pyrolysis. In this process, methane is split into hydrogen and solid carbon instead of forming CO₂. Whether this is advantageous for the climate depends on the energy used, on methane losses in the upstream chain and on the permanent retention of the carbon. The colours do not replace a life cycle assessment. They merely mark the starting point for a closer examination.

Climate balance and system boundaries

The climate balance depends on several variables. The first is the capture rate of CO₂ capture, i.e. the share of the CO₂ generated that is actually captured. A plant with a high capture rate on the process stream can still have significant residual emissions, for example if flue gases from the firing are not captured or if electricity and heat for capture and compression come from fossil sources. What matters is therefore not a percentage figure from a sub-process, but the emissions per unit of energy or per kilogram of hydrogen across the entire supply chain. The EU methodology also requires that the actual capture rates and the emissions from the energy supply for CCS operation be taken into account.

The second variable is methane emissions. Natural gas consists predominantly of methane, and in the short term methane has a far stronger effect on the climate than CO₂. According to common IPCC values, the global warming potential of fossil methane is about 80 times that of CO₂ over 20 years and around 30 times over 100 years. Leaks during extraction, processing, liquefaction, transport and distribution can therefore considerably worsen the balance. This applies particularly to long supply chains, for example via LNG, and to weak measurement and regulation. A low CO₂ emission at the plant site says little if the upstream chain is not properly accounted for.

The third variable is storage integrity. The captured CO₂ must remain permanently in suitable geological formations. This requires permits, monitoring, liability rules and an allocation of responsibility over very long periods. CCS is therefore not merely additional equipment on an industrial plant, but an infrastructure of pipelines or ship transport, storage sites, measurement systems and institutions. Without this chain, blue hydrogen remains a promise of later emission reductions. In addition, hydrogen itself can have an indirect climate effect in the event of leaks. The EU methodology has so far not taken any value into account for this, because the global warming potential of hydrogen has not yet been determined precisely enough.

Legal framework in the EU

Legally, the EU does not speak of blue hydrogen but of low-carbon hydrogen. The basis is the Internal Gas Market Directive (EU) 2024/1788. The calculation method is set out in Delegated Regulation (EU) 2025/2359 of 8 July 2025, published in the Official Journal on 21 November 2025. According to it, low-carbon hydrogen must achieve greenhouse gas savings of at least 70 percent over its life cycle compared with a fossil comparator. This comparator corresponds to that for renewable fuels of non-biological origin, i.e. 94 g CO₂ equivalent per megajoule. This results in an upper limit of 28.2 g CO₂ eq/MJ. Based on the lower heating value of around 120 MJ/kg, this is about 3.4 kg CO₂ equivalent per kilogram of hydrogen.

  • System boundary: Inputs, processing, transport and distribution as well as end use are counted, minus the savings from CCS or from permanent chemical binding of CO₂. Emissions from the construction of the plants are excluded.

  • Methane: Upstream methane emissions are calculated on the basis of the reports under the EU Methane Regulation (EU) 2024/1787, and for imports on the basis of the information provided by importers. Default values apply only if data are missing.

  • CCS: Only CO₂ that is permanently stored in a geological storage site counts as a reduction. Storage outside the EU is possible if the law there ensures equivalent detection and remediation of leaks.

  • Assessment period: The emission intensity may be averaged over a calendar month at most.

The regulation is a calculation and certification framework. It creates neither demand nor funding. Whether a specific plant complies with the threshold depends on its measured data, not on the label "blue".

Legal framework in Germany

In Germany, permanent CO₂ storage was practically permitted only for research and demonstration purposes until 2025. With the amendment of the Carbon Dioxide Storage Act (Kohlendioxid-Speicherungsgesetz), which since then has been called the Carbon Dioxide Storage and Transport Act (Kohlendioxid-Speicherung-und-Transport-Gesetz, KSpTG), CO₂ pipelines and storage on an industrial scale have been possible since 28 November 2025. Onshore storage applies only where a federal state permits it by way of an opt-in. The focus is on storage beneath the seabed. Further legislative decisions followed in early 2026 for the export of CO₂ by sea and offshore storage in the Exclusive Economic Zone. The framework thus creates, for the first time, the prerequisites for domestic CCS chains. However, it does not yet say anything about whether and when storage capacity will actually be available for hydrogen plants.

Significance for industry and the energy system

Blue hydrogen is discussed above all where large quantities of hydrogen are needed in the short term and green hydrogen is still scarce: in refineries, in ammonia and methanol production, in steelmaking, for certain high-temperature processes and, prospectively, in parts of the chemical industry. There, hydrogen serves as a feedstock or as an energy carrier. What then matters is which hydrogen entails which emissions, costs and dependencies.

For the electricity system, blue hydrogen is relevant only indirectly. It does not compete directly for renewable electricity, because it uses natural gas as its feedstock. However, it needs electricity itself for air separation, compression and capture. It can also influence how quickly electrolysis capacity grows, which hydrogen networks emerge and which industries prepare for a later switch to green hydrogen. If the infrastructure can be used regardless of the production route, blue hydrogen can temporarily supply volumes while electrolysers and renewable generation are expanded. If, on the other hand, contracts, plants and subsidies are tied to natural gas and CCS in the long term, there is a risk of path dependency.

This path dependency is not a technical detail. Reforming plants, CO₂ pipelines, storage rights and gas supply contracts have terms of decades and create interests in high utilisation. A transitional pathway can thus become a permanent structure economically. Whether blue hydrogen is a bridge or a dead end is decided by contract terms, emission limits, transparency obligations and the question of whether the infrastructure can later actually be converted to climate-neutral hydrogen.

Typical misconceptions

  • "Blue hydrogen is climate-neutral." That is not correct. Even with high capture rates, residual emissions remain from CO₂ streams that are not captured, from the energy supply and from the methane upstream chain. They can be significantly lower than for grey hydrogen, but they do not disappear. Even the EU threshold for low-carbon hydrogen allows emissions of up to 30 percent of the fossil comparator.

  • "90 percent capture means 90 percent lower emissions." A capture rate often refers only to one CO₂ stream or one part of the plant. Without specifying the reference basis and system boundary, values of 90 or 95 percent are hardly comparable. For the climate impact, the life cycle emissions per kilogram or per megajoule of hydrogen are what count.

  • "Blue hydrogen simply replaces natural gas." Hydrogen has different physical properties and places different demands on pipelines, storage, compressors, burners and safety technology. Its production involves conversion losses. Where direct electrification, efficiency measures or renewable heat are technically available and economically sensible, it is usually not the first choice.

  • "Blue hydrogen secures supply." It can increase supply volumes as long as natural gas is available and the CCS chain works. At the same time, it creates dependencies on gas imports, CO₂ storage sites and cross-border transport chains. For security of supply, the resilience of the entire supply chain is what counts.

Economic and institutional questions

Economically, blue hydrogen depends on natural gas prices, CO₂ prices, investment costs for reforming and CCS, charges for the transport and storage of CO₂, and the willingness of customers to pay. Rising CO₂ prices improve its position relative to grey hydrogen, while rising gas prices worsen it. Green hydrogen has different cost drivers: electricity price, electrolyser costs, utilisation and access to renewable generation. Cost comparisons without temporal and spatial context therefore quickly lead to wrong conclusions.

Institutionally, blue hydrogen needs verifiable rules: emission measurement, methane monitoring, evidence of permanent storage and clear criteria for funding and accounting. With the Methane Regulation and the methodology for low-carbon fuels, the EU has created essential building blocks. How robust data, certification and control are in practice will only become apparent with implementation. Without such rules, plants with very different climate impacts would be traded under the same colour label. An objective assessment requires measurable emissions per unit of product, clear system boundaries and rules that do not let residual emissions disappear behind a colour.

Sources

Related glossary entries

Edited by eCMS on 11.11.2026 16:06

© 2026 Erik Schmidt. All rights reserved. Quotations with a link to the source are welcome.