Hydrogen technologies in industry – applications, infrastructure and limitations

Hydrogen has been used in industry for decades, but that does not mean every “hydrogen technology” is now a mature and cost-effective way to supply an industrial plant. The most established applications are those in which hydrogen is used as a feedstock, reagent or reducing agent – above all in refineries and in ammonia and methanol production. In 2025, global hydrogen demand exceeded 100 million tonnes and, according to the IEA, remained concentrated almost entirely in traditional industrial and refining applications. Low-emissions hydrogen accounted for just under 1 million tonnes.

For a typical company, a more important question than “how much does a kilogram of hydrogen cost?” is: what does the entire chain from primary energy to the useful effect in the process look like? Only once that chain is mapped can hydrogen be compared with direct electrification, gas, biomass, heat recovery, a heat pump, energy storage or a change to the process itself.

Hydrogen is not an energy source – it is an energy carrier or a feedstock

In an energy analysis, hydrogen should be treated primarily as an energy carrier and as a substance used in chemical processes. If it is produced in an electrolyser, the energy has first been supplied as electricity. Some of that energy is then consumed by gas conditioning, compression, storage, transport, pressure reduction and final conversion.

A sound comparison should therefore cover at least six stages:

1. energy source or hydrogen procurement route – grid electricity, renewables, a PPA, externally supplied hydrogen or hydrogen available as a by-product;
2. hydrogen production – e.g. alkaline, PEM or high-temperature electrolysis;
3. conditioning – purification, drying, cooling and, where required, compression;
4. storage – a process buffer, pressure vessels, larger-scale storage or an intermediate carrier;
5. transport and distribution – pipeline, tube trailer, cylinders, cryogenic liquid or local on-site use;
6. end-use process – a burner, furnace, chemical reactor, fuel cell, turbine or another end-use device.

Auditor’s comment: if the comparison stops at electrolyser efficiency or the price of hydrogen “at the gate”, it is usually not yet a comparison of technologies, but only of one component of the installation.

How can hydrogen be supplied to an industrial plant?

Hydrogen purchased from an external supplier

The simplest technology option for a company is to purchase ready-to-use hydrogen. The plant then does not need an electrolyser, a water-treatment system or a large electrical connection dedicated to H₂ production. However, costs and requirements remain for unloading, storage, pressure reduction, metering, safety and matching gas quality to the process.

This option can make sense where consumption is low or moderate, hydrogen is needed as a process gas and a reliable supplier is available nearby. At higher flow rates, logistics begins to become one of the main constraints.

On-site production by electrolysis

An electrolyser uses electricity to split water into hydrogen and oxygen. In industrial applications, three technology groups are most commonly considered:

In the DOE technical-target table for PEM electrolysis, the 2022 system status is 55 kWh/kg H₂ (61% LHV), while the 2026 technology target is 51 kWh/kg (65% LHV). These are benchmark and development-target values, not evidence that every system available in 2026 achieves 51 kWh/kg. In the examples below, 55 kWh/kg is used only as an explicit screening assumption; an actual project should use manufacturer data for the specific unit at the planned load, outlet pressure and operating conditions.

The chemical reaction itself also requires approximately 9 kg of water per 1 kg of hydrogen and produces approximately 8 kg of oxygen. Actual plant water consumption is higher because water treatment, reject streams from water preparation and auxiliary needs must also be included. Oxygen can improve the project balance only if the plant has a genuine, simultaneous use for it that also meets the required quality specifications.

An electrolyser contains electrodes and an electrolyte or membrane. This should not, however, be confused with the hydrogen electrode used in electrochemistry as a reference electrode – that is a separate subject from an industrial hydrogen-production installation.

The economics of on-site green hydrogen production should be analysed separately, because the cost of producing H₂ alone does not determine the efficiency of the entire hydrogen-use chain.

Whole-chain efficiency matters more than electrolyser efficiency

The lower heating value of hydrogen is approximately 33.3 kWh/kg. If a screening calculation assumes 55 kWh of electricity per kilogram of H₂ – the 2022 system-status value from the DOE table – around 61% of the input energy remains in the hydrogen after the first conversion on an LHV basis. This is not a statement of typical market efficiency in 2026.

For example:

• 100 MWh of electricity at a consumption of 55 kWh/kg can produce approximately 1,818 kg H₂;
• the chemical energy of this hydrogen is approximately 60.5 MWh LHV;
• only then is the next stage supplied from this energy: a burner, boiler, fuel cell, turbine or chemical process;
• auxiliary equipment also consumes energy, including compressors, drying, cooling and safety systems.

If the objective were to generate electricity again, the losses would increase further. In its comparison of fuel-cell technologies, the DOE gives an electrical efficiency of around 60% LHV for a PEM fuel cell supplied directly with hydrogen. Multiplying 61% for the assumed electrolysis benchmark by 60% for the fuel cell gives approximately 36.6%. This is only an illustrative electricity → H₂ → electricity conversion level: the actual efficiency of the complete installation depends on the specific electrolyser and fuel cell as well as compression, storage and auxiliary loads.

This does not mean that hydrogen has no role in energy storage. It means that there must be a reason to accept such a chain of losses – for example, very long storage duration, no technically viable route for direct electrification, the need for a chemical reagent, or an application in which hydrogen does more than simply replace electricity.

Why does the hydrogen price in PLN/kg tell us so little?

The hydrogen price is only one parameter. Two plants buying hydrogen at the same price can have very different final process costs if they differ in required pressure, purity, storage capacity, delivery frequency or end-use efficiency.

At a minimum, a technology comparison needs:

• the purchase price or production cost of H₂ at the specified quality and pressure;
• electricity consumed by the electrolyser and auxiliary equipment;
• the hourly operating profile and annual utilisation of the electrolyser;
• the cost and energy consumption of compression, cooling and drying;
• buffer capacity and the required installation autonomy;
• the cost of transport or a pipeline;
• losses and energy use associated with changing the carrier, e.g. liquefaction or conversion to ammonia;
• the efficiency and operating characteristics of the end-use equipment;
• the cost of adapting the process, controls and safety systems;
• the value of by-products, if they can genuinely be used;
• available electrical connection capacity and the cost of increasing it;
• environmental, safety and permitting requirements.

The IEA notes that, in international trade in pure hydrogen, logistics alone can become a very significant part of the balance. In routes that require liquefaction or conversion to a carrier followed by recovery of H₂, energy consumption can exceed 10 kWh/kg H₂. That is more than 30% of the energy contained in the hydrogen itself.

Hydrogen storage: a process buffer is not the same as energy storage

The most mature method of physical hydrogen storage is compressed-gas storage. Very high pressures are used in transport and mobility applications, but an industrial installation should not automatically copy the parameters of a hydrogen refuelling station. Pressure should be selected for the end user, the required amount of energy in the buffer, delivery frequency, available footprint and compression cost.

Liquid hydrogen has a higher volumetric density, but requires cryogenic temperatures close to 20 K, or about –253°C. Liquefaction, insulation, boil-off management and specialist logistics make it a far more complex solution than gaseous buffer storage for a typical industrial plant.

Another option is the use of chemical carriers such as ammonia, methanol or LOHC solutions. They can make it easier to transport large quantities of energy, but if the final process requires pure H₂, reconversion, purification and the associated losses must be included.

What about hydrogen pipelines?

A pipeline can be a very efficient solution where flow is high and stable and the location is suitable. The issue is that this type of infrastructure is not yet widely available at industrial sites.

The IEA reports that announced hydrogen pipeline projects exceed 40,000 km by 2035, but only around 9% of that length is operational or has committed investment. This should not automatically be treated as an FID for every project. For a company, this means that a future pipeline should not be treated like an existing gas connection until its schedule, parameters, tariffs and access rules have been genuinely confirmed.

What does an industrial hydrogen installation consist of?

The scope depends on whether hydrogen is produced on site or delivered. A typical assessment of an industrial hydrogen installation should include the following blocks:

In practice, the biggest mistake is selecting an electrolyser before the hydrogen demand profile has been defined. If the end user requires a constant flow while the electrolyser is intended to operate mainly during periods of low electricity prices or high PV generation, the difference must be covered by storage, another supply route or flexibility in the process itself.

Hydrogen applications with a clear technological rationale today

1. Hydrogen as a feedstock or reagent

This is the most mature group of applications. Hydrogen has long been consumed in refineries and in the production of ammonia and methanol, among other uses. In these cases it does not compete solely with another energy carrier – it performs a specific chemical function.

For a plant, the question is therefore often not “should hydrogen be used?” but “where should the hydrogen come from, what quality is required, and how can emissions from its production or supply be reduced?”

2. Iron ore reduction

Hydrogen can act as a reducing agent in direct reduced iron technology. This is one of the most important potential routes for decarbonising primary steelmaking, but it requires large scale, access to suitable feedstock, very large quantities of low-emissions H₂ and a transformation of the entire production chain.

This is a viable technology for a specific branch of heavy industry, not a universal investment for a typical factory.

3. High-temperature processes and burners

Hydrogen combustion can provide high-temperature process heat. However, this does not mean that an existing gas burner can always simply be “switched” to 100% H₂ without further analysis.

Hydrogen differs from natural gas in characteristics including flame speed, flammability range and flame behaviour. The burner, chamber geometry, safety system, heat transfer to the product and NOx emissions must be verified. The DOE notes that nitrogen oxides can form when hydrogen is burned at high temperatures; limiting NOx requires appropriate combustion design and, where necessary, additional measures.

For furnaces, direct electric solutions should be assessed in parallel, because a high process temperature alone does not establish an advantage for hydrogen. Selection of a hydrogen burner should follow from an analysis of the specific furnace and product, rather than from a general claim that the fuel is “zero-emission”.

4. Hydrogen as a process gas

In some processes, hydrogen is required because of a reducing atmosphere, chemical composition or product-quality requirements. Purity, dew point, pressure, flow stability and the risk of product contamination then become critical.

In such applications, comparison with electrification alone may not be meaningful because energy is not the only function performed by hydrogen.

5. Fuel cells, backup power and cogeneration

A fuel cell can generate electricity without combusting hydrogen, and some systems also allow useful heat to be recovered. Technically interesting applications can include facilities that require high-quality power, long-duration autonomy or already have access to hydrogen.

However, if hydrogen must first be produced from electricity, stored and then converted back into electricity, the overall balance should be compared particularly carefully with batteries, backup generation and grid-based solutions. In a typical plant, the ability to store energy does not automatically compensate for conversion losses.

In practice, whether hydrogen is justified depends primarily on whether the process genuinely requires H₂ and what infrastructure is needed to deliver and use it safely.

Where is hydrogen still difficult to justify in a typical company?

Particular caution is required when treating hydrogen as a universal substitute for gas or as a way to use every surplus of renewable electricity.

The following are particularly challenging in a typical plant:

• producing H₂ from PV only to generate electricity from it later – low electrolyser utilisation and repeated conversion losses can significantly increase the required source capacity;
• replacing a conventional gas boiler with hydrogen without first assessing a heat pump, electric boiler, heat recovery and thermal storage;
• large hydrogen storage facilities on site – spatial, safety, pressure-equipment and procedural requirements all increase;
• liquid-hydrogen deliveries or imported hydrogen carriers for low demand – the logistics infrastructure can be disproportionately complex;
• designing around a future pipeline whose parameters and delivery date have not yet been definitively confirmed;
• fuel substitution without process analysis – in a furnace, not only the energy cost changes, but also flame characteristics, radiation, flue-gas flow, atmospheric moisture and the potential impact on the product.

Which process parameters can justify the use of hydrogen?

Before selecting a technology, it is worth preparing a process data sheet. It should determine whether hydrogen addresses a genuine problem at the plant.

Auditor’s comment: process temperature matters, but it is not sufficient on its own. A 1,000°C process can sometimes be electrified using induction or an electric arc, while a much lower-temperature process may require hydrogen for chemical reasons.

When should direct electrification be assessed first?

If the end product is heat or electricity, direct electrification should be one of the baseline options. It avoids the stages of producing, storing and reconverting H₂.

The IEA notes that large industrial heat pumps are commercially well established for temperatures up to around 150°C, while electric boilers can provide steam at up to around 350°C and 70 bar. Higher-temperature solutions are also subject to continued technology development. Resistance heating, induction, electric arc furnaces, microwaves, infrared and thermal energy storage add further options, so a rule such as “above this temperature, only hydrogen” should not be used.

Direct electrification should be assessed first where:

• the process requires heat only;
• the required temperature and heat flow can be achieved electrically;
• adequate grid connection capacity exists or can be obtained;
• the plant can use a heat pump or heat recovery;
• no special reducing atmosphere is required;
• hydrogen would be produced from the same electricity that could supply the end user directly.

Hydrogen, in turn, may gain a technical advantage where electrification would require an unacceptable process rebuild, hydrogen performs a chemical role, very long-duration energy storage is needed, or the plant has access to inexpensive by-product hydrogen or infrastructure that does not need to be built from scratch.

Example: 1 MW of useful heat for 8,000 hours per year

Assume a process requiring an average of 1 MW of useful heat for 8,000 hours per year, i.e. 8,000 MWh of useful heat. This is not a detailed engineering design, but a quick screening calculation showing the impact of the conversion chain.

Option A – electric boiler

Assuming 98% efficiency – consistent with the value used by the IEA in heat-technology comparisons – the annual electricity demand is approximately:

8,000 / 0.98 = 8,163 MWh of electricity per year.

Option B – hydrogen from electrolysis and a 90%-efficient end user

Assuming 90% efficiency for final heat generation, approximately the following amount must be supplied:

8,000 / 0.90 = 8,889 MWh of H₂ chemical energy.

At an LHV of 33.3 kWh/kg, this corresponds to approximately 267 tonnes of H₂ per year. If 55 kWh/kg is used for screening – explicitly as the DOE’s 2022 system-status value, not as a 2026 market average – producing this amount of hydrogen alone requires approximately:

14,681 MWh of electricity per year.

This is around 80% more electricity than in the simplified electric-boiler option – before adding compression, storage, drying and auxiliary losses.

This example does not prove that an electric boiler will always be better. It does show why a hydrogen project needs an additional technological or system-level rationale. If both options provide the process with exactly the same heat and both can operate on the same electricity supply, hydrogen starts the comparison with a significant conversion penalty.

Safety: hydrogen requires the entire system to be engineered, not just the storage vessel

Hydrogen is non-toxic and, when released, rises and disperses quickly, but it has a wide flammability range and low ignition energy. The DOE therefore highlights the importance of ventilation, leak detection and – because the flame can be difficult to see – appropriate flame detection. Material compatibility must also be considered, as some metals can be susceptible to hydrogen embrittlement.

In an industrial project, the assessment should routinely include, among other things:

• leak scenarios and a method for safely venting H₂;
• natural or mechanical ventilation;
• placement of gas detectors;
• classification of hazardous areas with an explosive atmosphere;
• selection of electrical and non-electrical equipment for hazardous areas;
• isolation valves, ESD and emergency logic;
• compatibility of materials, seals, valves and fittings;
• safety of pressure vessels and pipelines;
• start-up, shutdown, inerting and maintenance procedures;
• personnel training and access rules.

Which regulations need to be checked in Poland?

For a plant in Poland, referring only to the names of EU directives is not sufficient. Depending on the installation configuration, the applicable Polish national regulations implementing or supplementing these requirements should be checked first:

• Polish Regulation of the Minister of Development of 6 June 2016 (Journal of Laws 2016, item 817) – requirements for equipment and protective systems intended for use in potentially explosive atmospheres; implements ATEX Directive 2014/34/EU;
• Polish Regulation of the Minister of Economy of 8 July 2010 (Journal of Laws 2010, No. 138, item 931) – minimum occupational health and safety requirements related to the possibility of an explosive atmosphere occurring in the workplace;
• Polish Regulation of the Minister of Development of 11 July 2016 (Journal of Laws 2016, item 1036) – requirements for pressure equipment and assemblies; its principal scope covers equipment with a maximum allowable pressure exceeding 0.5 bar, subject to the exceptions specified in the regulation;
• Polish Regulation of the Minister of Development of 29 January 2016 (Journal of Laws 2016, item 138) – for hydrogen (CAS 1333-74-0), it specifies thresholds of 5 Mg for a lower-tier establishment and 50 Mg for an upper-tier establishment. Classification must, however, take account of all substances at the establishment and the applicable aggregation rules, so the H₂ inventory alone is not always sufficient to determine the establishment’s status.

This is still not a complete administrative pathway for a specific investment project in Poland. Fire protection, technical inspection, construction law, environmental requirements, transport of dangerous substances and requirements specific to the process and location must also be verified separately.

How should an industrial hydrogen project be approached step by step?

The safest sequence does not begin with selecting an electrolyser manufacturer.

1. Define the process need. Determine whether hydrogen is to serve as an energy carrier, reagent, reducing agent, shielding gas or storage medium.
2. Build an hourly profile. Minimum, maximum and average flow rates, operating hours, shutdowns and the required autonomy time are needed.
3. Assess the direct option. For heat and electricity, compare electrification, heat recovery, thermal energy storage and other available technologies.
4. Define H₂ quality and pressure. Without this, purification, compressor, storage and delivery cannot be selected correctly.
5. Compare at least two supply chains. On-site production should usually be compared with purchased hydrogen; in some cases a third option based on by-product hydrogen or a future pipeline is also required.
6. Calculate the energy use of the entire chain. Include not only the electrolyser, but also auxiliary equipment, storage, transport and the final end-use equipment.
7. Perform a safety and siting screening. Check hazardous areas, space, delivery routes, ventilation options and the mass of hydrogen stored.
8. Only then select equipment and installation capacity. Otherwise, it is easy to oversize the electrolyser or build storage that compensates for a poorly matched operating profile.

A hydrogen project should form part of the company’s broader energy strategy rather than being assessed independently of other energy users, sources and planned upgrades.

When does hydrogen technology make sense?

The strongest signal is not a high energy price or a large photovoltaic installation. More compelling reasons include:

• hydrogen is required as a feedstock, reagent or reducing agent;
• the process requires properties that simpler electrification cannot provide;
• there is stable and substantial H₂ demand;
• the plant has access to a suitable hydrogen source or very favourable conditions for on-site production;
• logistics can be reduced by producing and consuming hydrogen on site;
• H₂ storage solves a genuine long-duration flexibility problem that lower-cost technologies do not address;
• sufficient space and appropriate safety conditions are available;
• the entire chain, not just the electrolyser, has an acceptable balance of energy, cost and emissions.

If these conditions are absent, hydrogen may remain technically feasible, but it will not necessarily be the best first investment option.

FAQ

Is hydrogen technology energy-efficient?

This cannot be answered with a single efficiency figure. Electrolysis itself has a defined efficiency, but the process also includes compression, storage, transport and final conversion. If hydrogen is produced from electricity and the final output is electricity again or ordinary heat, direct electrification usually has a much shorter conversion chain.

Can hydrogen replace natural gas in an existing furnace or boiler?

Sometimes, but a 1:1 substitution should not be assumed. The burner, flow rates, flame dynamics, heat transfer, materials, controls, safeguards and NOx emissions must be assessed. In many applications, an electric option should be calculated in parallel.

Does a technical hydrogen installation require special safeguards?

Yes. The scope depends on pressure, the quantity of H₂, the installation location and the process, but typical assessments cover leak detection, ventilation, ATEX zones, materials, valves and fittings, emergency isolation, gas venting and pressure equipment.

Is hydrogen well suited to energy storage?

It can be valuable for long storage durations and large quantities of energy, particularly where other technologies are difficult to apply. For short-duration energy shifting, however, conversion losses and infrastructure costs should be compared with batteries and thermal energy storage.

What are the main benefits of hydrogen energy in industry?

Its greatest value is the ability to deliver the H₂ molecule where it is chemically required, together with its potential use in some processes that are difficult to electrify. The benefits nevertheless depend on the hydrogen source, infrastructure and the function of H₂ in the process; they do not arise automatically from simply changing the energy carrier.

Summary

Industrial hydrogen technologies involve far more than an electrolyser and a storage vessel. A real project includes the energy source, H₂ production or supply, gas conditioning, compression, storage, distribution, safety systems and the final end-use equipment.

Hydrogen has strong, specific applications today primarily where it performs a chemical function or solves a problem that is difficult to address through direct electrification. In conventional heat and energy applications, however, it should be compared with shorter technological pathways because every additional conversion means energy losses, another installation and new safety requirements.

If a company is considering hydrogen, a sensible first stage is a pre-investment assessment based on the actual process profile: temperatures, loads, operating hours, gas quality and pressure, available electrical capacity, required autonomy and siting options. Only on this basis can the technology be selected responsibly and it be determined whether hydrogen genuinely solves the problem better than the alternatives.

If a company wants to move from a general concept to pre-feasibility, it should start with a process balance and technology options rather than a request for quotation for an electrolyser. The scope of available support can be reviewed on the Energy Trend services page or discussed via the contact page.

Sources

• International Energy Agency, Global Hydrogen Review 2026 – Demand: https://www.iea.org/reports/global-hydrogen-review-2026/demand
• International Energy Agency, Global Hydrogen Review 2026 – Trade and infrastructure: https://www.iea.org/reports/global-hydrogen-review-2026/trade-and-infrastructure
• International Energy Agency, Global Hydrogen Review 2026 – Cost acceptability: https://www.iea.org/reports/global-hydrogen-review-2026/cost-acceptability
• International Energy Agency, Renewables for Industry: https://www.iea.org/reports/renewables-for-industry
• U.S. Department of Energy, Hydrogen Production: Electrolysis: https://www.energy.gov/cmei/fuels/hydrogen-production-electrolysis
• U.S. Department of Energy, Technical Targets for Proton Exchange Membrane Electrolysis: https://www.energy.gov/cmei/fuels/technical-targets-proton-exchange-membrane-electrolysis
• U.S. Department of Energy, Hydrogen Storage: https://www.energy.gov/cmei/fuels/hydrogen-storage
• U.S. Department of Energy, Hydrogen Delivery: https://www.energy.gov/cmei/fuels/hydrogen-delivery
• U.S. Department of Energy, Comparison of Fuel Cell Technologies: https://www.energy.gov/cmei/fuels/comparison-fuel-cell-technologies
• U.S. Department of Energy, Safe Use of Hydrogen: https://www.energy.gov/cmei/fuels/safe-use-hydrogen
• U.S. Department of Energy, Does the use of hydrogen produce air pollutants such as nitrogen oxides?: https://www.energy.gov/cmei/fuels/does-use-hydrogen-produce-air-pollutants-such-nitrogen-oxides
• Polish ELI, Journal of Laws 2016, item 817 – ATEX equipment and protective systems: https://eli.gov.pl/eli/DU/2016/817/ogl
• Polish ELI, Journal of Laws 2010, No. 138, item 931 – minimum occupational health and safety requirements for explosive atmospheres: https://eli.gov.pl/eli/DU/2010/931/ogl
• Polish ELI, Journal of Laws 2016, item 1036 – pressure equipment: https://eli.gov.pl/eli/DU/2016/1036/ogl
• Polish ELI, Journal of Laws 2016, item 138 – lower-/upper-tier establishment thresholds, including 5/50 Mg for hydrogen: https://eli.gov.pl/eli/DU/2016/138/ogl
• EUR-Lex, Directive 2014/34/EU (ATEX): https://eur-lex.europa.eu/eli/dir/2014/34
• EUR-Lex, Directive 2014/68/EU (PED): https://eur-lex.europa.eu/eli/dir/2014/68/oj
• EUR-Lex, Directive 2012/18/EU (Seveso III): https://eur-lex.europa.eu/legal-content/PL/TXT/?uri=CELEX:32012L0018