Comparing Costs: Process Heat from High-Temperature Heat Pumps and Hydrogen

Two commercially available technologies dominate the public discussion around the decarbonization of process heat: industrial heat pumps and hydrogen. Both have an important role to play in industrial decarbonization, but that does not mean they are comparable technologies. They differ fundamentally in how they work, their efficiency, their cost structures, and their availability. As a result, broad comparisons between hydrogen and industrial heat pumps often miss important distinctions. A project-specific assessment, however, reveals clear application areas for each technology.

In this article, we take an objective look at both solutions, compare their economics based on reliable data, and show why there is no one-size-fits-all answer.

Process heat is the thermal energy required for industrial manufacturing processes, ranging from drying and evaporation to sterilization, melting, and firing. Accounting for more than 20% of Germany’s total final energy consumption and approximately two-thirds of final energy consumption in industry, process heat is the single largest energy consumer in German industry.^[1]

The temperature requirements vary widely. Paper drying, for example, can take place at temperatures below 200°C, while firing and melting processes in the metals, glass, and cement industries require temperatures well above 1,000°C. This article focuses on the 100°C to 200°C range because this is where industrial heat pumps and hydrogen compete directly.

Today, the vast majority of industrial process heat is still generated using fossil fuels.^[2] But the status quo is coming under increasing pressure. Scheduled increases in CO₂ prices, the upcoming European ETS 2 emissions trading system, the phaseout of free emissions allowances, geopolitical shifts in supply chains, excessive dependencies, and sustainability initiatives are all making the cost-benefit equation for fossil fuels increasingly unfavorable.

Two specific approaches are at the center of the discussion. The first is the direct electrification of process heat using industrial heat pumps. These systems recover waste heat from existing production processes and raise it to the temperature required by the process. The second is the use of green hydrogen, which can be burned directly in place of natural gas or other fossil fuels.

Other options for decarbonizing industrial process heat include energy sources and technologies such as biomass, electric boilers, solar thermal energy, geothermal energy, and direct electrification combined with high-temperature thermal energy storage. Each has its own, in some cases broad, range of applications. Biomass, for example, is well established in the paper, wood, and food industries. Electric boilers are considered a standard solution for peak loads and for making electricity consumption more flexible, for example by taking advantage of negative wholesale electricity prices. Solar thermal energy is considered a promising energy-saving option, particularly in sunnier southern regions, while high-temperature thermal storage is becoming increasingly important as a complementary technology for direct electrification.

This article, however, focuses specifically on industrial heat pumps and hydrogen because these two approaches feature most prominently in public and policy discussions and compete directly on economics in the 100°C to 200°C temperature range. Accordingly, Fraunhofer ISE estimates that, depending on the future scenario considered, high-temperature heat pumps could account for 44% to 64% of process heat generation at temperatures up to 200°C, while hydrogen and gas boilers could account for 7% to 18% in the same temperature range.^[3]

A closer look: Generating process heat with hydrogen

There are two basic approaches to generating process heat with hydrogen. The more common approach is direct combustion in adapted burners that use green hydrogen or hydrogen-natural gas blends instead of natural gas. In principle, many existing burners could be converted to operate on hydrogen. Doing so, however, requires modifications to safety, measurement, and control systems, as well as additional integration work, such as installing new piping.

The second approach is electrochemical conversion, primarily used in hydrogen-powered vehicles. Here, hydrogen is converted back into electricity in a fuel cell. For economic reasons, however, this approach does not play a meaningful role in industrial process heat generation.

Hydrogen also varies significantly depending on how it is produced. Common categories include gray, blue, and green hydrogen. Gray hydrogen is produced from natural gas through steam reforming and is therefore not carbon-neutral. It is currently the least expensive form of hydrogen. Blue hydrogen is also produced from natural gas, but the resulting CO₂ is captured and stored using carbon capture and storage (CCS). Because it still depends on fossil fuels, blue hydrogen is generally considered a transitional solution.

Green hydrogen, produced through electrolysis using renewable electricity, is the only widely used form of hydrogen that is carbon-neutral across the entire production chain. It is therefore the only form of hydrogen that is compatible with the long-term decarbonization of industrial process heat generation.

Achievable temperature levels

Hydrogen burns at temperatures of up to approximately 2,000°C. Depending on the burner and its design, significantly higher temperatures can also be achieved. In theory, this means that hydrogen can be used for highly demanding high-temperature processes, including melting furnaces in steel production. The high flame temperatures achievable through hydrogen combustion make it particularly attractive for applications where direct electrification reaches technical or economic limits.

Availability, infrastructure, and cost

Over the long term, green hydrogen could offer promising prospects, particularly for demanding high-temperature processes. The current situation, however, is much less encouraging. According to leading economic research institutes, the expansion of hydrogen infrastructure is progressing significantly more slowly than originally planned.^[4]

Electrolysis capacity, storage, pipelines, and import infrastructure all remain bottlenecks. Renewable electricity generated in Germany or neighboring countries is primarily consumed directly or temporarily stored in large-scale batteries rather than converted into hydrogen. At the same time, large-scale hydrogen import corridors from high-solar-resource regions such as North Africa or southern Spain are not expected to be established before the early 2030s at the earliest.

Even then, hydrogen comes with specific transportation and storage requirements that increase costs and may require existing natural gas infrastructure to be retrofitted.

According to a discussion paper by the FfE Forschungsstelle für Energiewirtschaft (Research Center for Energy Economics), commissioned by the German Federal Ministry for Economic Affairs, the production cost of green hydrogen in 2025 is 9.80 € per kilogram,^[5] or approximately 294 €/MWh, based on a higher heating value of approximately 39.4 kWh per kilogram. For comparison, the higher heating value of natural gas is approximately 11.8 to 13.9 kWh per kilogram.

Electricity accounts for approximately 50% of total hydrogen costs. Longer-term projections put production costs at around 7.40 € per kilogram, or approximately 222 €/MWh, in 2040. This would represent a significantly smaller price decline over this period than is often expected. Even when considering production costs alone, green hydrogen would therefore remain considerably more expensive over the long term than natural gas is today. The final price paid by industrial customers for natural gas in 2026 is approximately 55 to 80 €/MWh.

In its Global Hydrogen Review 2024, the IEA cites a range of $2 to $9 per kilogram. However, this assumes its Net Zero Emissions Scenario, which requires a substantially accelerated global scale-up that has not materialized to date. Supply is further constrained by the fact that only very limited quantities of green hydrogen are currently available.

Assessing the actual purchase prices paid by large industrial customers is difficult under current market conditions. A February 2026 study^[6] by Fraunhofer ISE and consulting firm LBST notes that there is currently no liquid, tradable market for green hydrogen and therefore very little publicly available pricing information for Germany.

Data from the European Energy Exchange, voluntarily submitted by companies based on offers and completed transactions, indicate average hydrogen prices of 7.50 to 8.60 € per kilogram, or 225 to 258 €/MWh, between May and July 2025. It remains unclear, however, which companies contributed data, how many participated, and what volumes were represented. The study also notes that the hydrogen involved was likely not primarily renewable hydrogen of non-biological origin.

For industrial investment planning, this means that if the hydrogen market does scale up as expected, buyers will likely need to plan for several years of comparatively high and volatile prices, along with significant regional differences in availability.

Generating process heat with industrial heat pumps

Industrial heat pumps use available waste heat from sources such as production processes, cooling circuits, and exhaust air as a heat source for process heat generation. In a closed thermodynamic cycle, the heat pump uses refrigerants and compression to raise this heat to a higher, usable temperature level before supplying it as process heat or process steam.

When the required temperature lift between the heat source and heat sink is particularly large, systems often use two-stage compression with two separate refrigerant circuits. This configuration makes it possible to achieve demanding temperature lifts.

Achievable temperature levels

Modern industrial heat pumps such as the ThermBooster™ can provide process steam at temperatures of up to approximately 200°C. Target temperatures of up to 180°C are considered particularly attractive from an economic standpoint and cover a large share of industrial applications.

In addition to compressor technology and heat exchangers, selecting the appropriate refrigerant is a key factor in system performance and efficiency. Synthetic refrigerants typically cover temperature ranges up to approximately 165°C, while hydrocarbons are often used as refrigerants at higher temperatures. We explain the selection criteria in detail in our separate article on refrigerants for industrial heat pumps.

Commercial readiness and competitiveness

Industrial heat pumps are already commercially available for applications between 100°C and 200°C, as demonstrated by the growing number of reference systems operating in production environments across a wide range of industries.

In many applications, they are also already cost-competitive with energy sources such as natural gas, which for many years had few economically viable alternatives. A well-founded total cost of ownership (TCO) analysis that considers the system’s full operating life and realistically accounts for rising CO₂ prices further strengthens the economic case for industrial heat pumps.

Compared with green hydrogen, industrial heat pumps can operate significantly more economically in many applications. One key reason is the level of efficiency they can achieve, which we examine in more detail below.

Assumptions Used for the Comparison

Important: Some values are intentionally used as modeling assumptions and are not taken directly from a specific source.

System boundary for the energy comparison: 100 kWh of electrical final energy at the site. Upstream electricity grid losses are not included because they apply equally, in principle, to electrolysis, direct electrification, and heat pumps.
Hydrogen: All H₂ energy values are based on the lower heating value (LHV). A reference efficiency of 65% LHV is used for PEM and alkaline electrolysis. The H₂ boiler is assumed to operate at 90% efficiency on an LHV basis. Losses associated with conditioning, compression, storage, and transportation can vary considerably depending on the supply pathway; an illustrative value has therefore been assumed.
Direct electrification: Electric boiler/electric heater with an efficiency of 98%, based on the 98% efficiency value also used by the IEA for industrial electric boilers.
High-temperature heat pump: COP range of 2 to 5, with a reference COP of 3. The additional useful heat is supplied by industrial waste heat or another heat source.

The graphic is based on a graphic published by the German Environment Agency (UBA), which uses an efficiency range of 51–83% for hydrogen production, 90% for gas/H₂ boilers, and an SPF of 3 for an air-source heat pump. It illustrates that using H₂ or synthetic methane requires approximately four to five times as much electricity.
U.S. DOE – PEM electrolysis: System efficiency on an LHV basis: 61% current status, 65% target, and 72% ultimate target. We use 65% LHV as the reference value.
U.S. DOE – alkaline electrolysis: Comparable range. DOE data support approximately 60–70% LHV as a reasonable range for alkaline systems at the system level.
U.S. DOE – SOEC/high-temperature electrolysis: Relevant to the upper end of the efficiency range. SOEC can achieve significantly higher electrical efficiency but requires an external high-temperature heat input. We therefore use 65% LHV as the reference value here.
IEA – industrial electric boilers: The IEA assumes an efficiency of 98% for industrial electric boilers.
IEA Heat Pumping Technologies, Annex 58 – high-temperature heat pumps: Annex 58 specifically addresses industrial high-temperature heat pumps (HTHPs) operating above 100°C, including applications up to approximately 200°C. Based on our practical experience, we see applications with COPs ranging from 2 to 6. We use a reference COP of 3 in the graphic.
COP 2–5 in our graphic: This is intentionally a broad illustrative range rather than a range taken from a single study. A COP of 3 is a reasonable reference value for the graphic. COP 2 represents challenging applications with large temperature lifts, while COP 4–5 represents more favorable heat-source conditions and smaller temperature lifts. For typical applications in the 100–200°C range, this is scientifically more defensible than using a blanket COP of 6.
H₂ conditioning / transportation / storage = 95%: This is currently our assumption. The associated energy requirements can vary considerably depending on factors such as pressure level, pipeline or trailer transportation, storage method, and distance.

Outlook: Market scale-up, price trends, and policy

Hydrogen scale-up in Europe, China, and the United States

Policy targets for both electrification and the expansion of the hydrogen economy are ambitious. While electrification efforts are lagging behind their targets, the hydrogen economy is facing even greater challenges.

Germany’s National Hydrogen Strategy calls for 10 GW of domestic electrolysis capacity by 2030.^[7] Currently, however, installed electrolysis capacity stands at only approximately 181 MW.

An analysis by the Institute of Energy Economics at the University of Cologne (EWI) concludes that Germany is likely to miss its 2030 target.^[8] If all projects announced through 2030 are included, and assuming every one of them is actually completed, total electrolysis capacity would reach 8.7 GW. Among the projects analyzed, however, more than 20 were announced for commissioning in 2026, and 14 of those had not yet received final financing commitments. Several major hydrogen projects have since been postponed or canceled.

This does not necessarily mean that Germany’s hydrogen scale-up will fail. It does suggest, however, that the expansion is likely to proceed much more slowly and unevenly than initially projected.

The development of electrolysis capacity across the EU relative to policy targets requires a more nuanced analysis than can be covered in this article. Broadly speaking, however, the trend is similar to that in Germany.

As part of its hydrogen strategy, the EU has set a target of 40 GW of electrolysis capacity by 2030. Data on currently installed capacity across the EU remain limited, but according to Germany’s Federal Institute for Geosciences and Natural Resources,^[9] installed capacity in the EU-28 amounted to 859 MW in 2023. According to Fraunhofer ISI,^[10] other analyses indicate that approximately 120 GW of electrolysis capacity would actually be required to meet European hydrogen production targets. Reaching that level would require installed electrolysis capacity to increase by nearly a factor of 900.

The United States also established ambitious targets for expanding green hydrogen under the Inflation Reduction Act. Those targets came under pressure following the change in administration in 2025. The elimination or restructuring of key incentive programs has led to project cancellations and a broader slowdown in capacity additions.

China, by contrast, dominates the global electrolyzer market. According to the IEA’s Global Hydrogen Review 2025, approximately 1.3 GW of electrolysis capacity was installed in China by the end of 2024, representing around 65% of global capacity. Producing the least expensive green hydrogen in China costs approximately 40% to 45% less than in Europe or the United States. This is primarily due to lower electricity prices resulting from lower capital expenditures and financing costs for renewable energy projects.

Hydrogen and electricity: Expected price trends

Given the slow pace of hydrogen market development, it is not surprising that projected green hydrogen prices span an unusually wide range. This is true even though electricity accounts for approximately 50% of hydrogen production costs and relatively robust electricity price forecasts are available.

While the most optimistic scenarios suggest that hydrogen prices of 2 to 3 € per kilogram could be achievable from 2030 onward, more realistic analyses project significantly higher levels. The FfE, for example, concludes that the complex installation of electrolyzers, project development costs, stack replacements, and regulatory requirements governing electricity procurement are generally more costly than many optimistic analyses assume.

As a result, the number of economically viable applications for green hydrogen decreases. This, in turn, reduces total hydrogen production volumes and is likely to place further upward pressure on prices. When planning investments, companies should therefore ideally work with hydrogen price ranges rather than isolated price points. A project-specific analysis is also essential.

The economics of heat pumps likewise depend directly on the energy source they use—in this case, industrial electricity prices. Over the medium to long term, there are reasons for cautious optimism. The continued and increasingly rapid expansion of renewable energy is reducing the marginal cost of electricity generation. On-site power generation, which is becoming increasingly economically attractive, and long-term power purchase agreements (PPAs) can also reduce energy costs substantially.

At the same time, the electrification of numerous industrial sectors, transportation, and heating will require significant investment in the power grid, including investments aimed at avoiding costly redispatch measures during periods of excess renewable generation. Overall, however, electricity prices offer more realistic opportunities for cost stabilization, with significantly narrower ranges of uncertainty.

Policy framework

Policy over the coming years is placing a much stronger emphasis on electrification. Key elements include Germany’s Federal Funding for Energy and Resource Efficiency in the Economy (EEW), the European Union’s heat pump strategy, and the Heat Auction.

Hydrogen is also supported through instruments such as Germany’s Carbon Contracts for Difference. The central challenge, however, is likely to be less about supply-side support and more about the combination of limited or weak demand, high costs, and delays in infrastructure development.

There is another important consideration: Even if green hydrogen becomes available in larger quantities and at more attractive prices, it is likely to be prioritized for sectors that simply cannot be decarbonized through other means, including parts of the chemical, cement, and steel industries.

For applications in which industrial heat pumps are technically viable, heat pumps are therefore likely to remain the preferred option from both a policy and economic perspective.

Comparing the Cost of Process Heat: Figure 2 compares the cost of generating process heat using hydrogen and high-temperature heat pumps under the specified conditions. In both cases, the price of electricity is a key cost factor.

Sources and Assumptions

Industrial electricity prices in Europe: Eurostat, dataset nrg_pc_205. In H2 2025, the EU average for non-household customers in the 500–2,000 MWh/year consumption band was €183.7/MWh. Finland was at €74.8/MWh, while Ireland was at €255.2/MWh. These figures support our illustrative electricity price range of €80–200/MWh.
Direct electrification: The IEA assumes an efficiency of 98% for industrial electric boilers.
Hydrogen production costs: FfE, “From Theory to Practice: Why Green Hydrogen Is More Expensive Than Expected.” The analysis estimates more realistic production costs of approximately €9.80/kg in the near term and €7.40/kg in 2040.
Hydrogen plausibility check: ACER estimates current average production costs for renewable hydrogen in Europe at approximately €8/kg.
Hydrogen network: Germany’s Federal Network Agency (Bundesnetzagentur) has set a ramp-up tariff of €25/kWh/h/year for firm annual capacity on the hydrogen core network.
€5/kg H₂: This is not a current market price, but our deliberately optimistic low-cost scenario at the plant gate. It is below ACER’s current estimated production costs and should be explicitly identified as such.

Conclusion: Meaningful comparisons require project-specific design

Despite the assumptions underlying our example calculations, the overall picture is clear: As an energy carrier for industrial process heat, green hydrogen is inherently less efficient than a high-temperature heat pump. When the entire energy conversion chain is considered, overall efficiency clearly favors the heat pump.

But what does this mean for the actual cost of heat? Green hydrogen price forecasts continue to span a wide range because many key questions surrounding availability and production costs remain unresolved. According to our calculations, however, the variable cost of heat from hydrogen remains higher than that of a heat pump even when deliberately unfavorable assumptions are used for the high-temperature heat pump and deliberately optimistic hydrogen prices are assumed.

Ultimately, however, a meaningful comparison requires project-specific system design. Process temperatures and load profiles, heat-source conditions, site-specific factors, and other variables affecting cost and efficiency determine how economically viable a solution will actually be.

This is exactly where we come in. We advise and support industrial partners on the path toward economical, future-ready process heat generation—from the initial assessment and technical system design through to a fully operational system.

Comparing Costs: Process Heat from High-Temperature Heat Pumps and Hydrogen

Industrial heat pumps or hydrogen: The current landscape

A closer look: Generating process heat with hydrogen

Generating process heat with industrial heat pumps

Hydrogen vs. heat pumps: Efficiency and cost of process heat generation

Outlook: Market scale-up, price trends, and policy

Conclusion: Meaningful comparisons require project-specific design

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