There is no universal winner. An industrial heat pump can deliver substantially more heat than the electricity it consumes when a suitable waste-heat source is available and the required temperature lift is moderate. A boiler remains the practical baseline where steam pressure is high, heat sources are unsuitable, electricity is expensive or carbon-intensive, grid capacity is limited, or an existing fuel system is difficult to replace.
The right comparison is site-specific: required steam conditions, hourly demand, source-heat temperature, operating hours, electricity and fuel tariffs, carbon factors, installed cost, grid work, and process-integration risk. Equipment nameplate efficiency alone cannot answer whether electrification will save money or emissions.
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What is actually being compared?
“Heat pump versus boiler” can describe several different systems. A mechanical industrial heat pump upgrades heat from air, water, exhaust, condenser water, or another source and delivers it at a higher temperature. A boiler adds heat by burning fuel or using electricity. The useful comparison is the cost and emissions of steam delivered to the process boundary, not the efficiency printed on one piece of equipment.
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- Steam pressure and saturation temperature at the process connection.
- Required steam flow by hour, including minimum, normal, peak, and startup loads.
- Condensate return temperature and rate.
- Hours per year, seasonal variation, and planned shutdowns.
- Available heat sources, their temperature, flow, contamination, and operating schedule.
- Electricity tariffs, demand charges, fuel prices, taxes, network charges, and carbon costs in the relevant region and year.
- Existing boiler, steam-distribution, water-treatment, electrical, and backup infrastructure.
A heat pump may supply all steam, preheat boiler feedwater, or cover a stable base load while a boiler handles peaks. Those hybrid arrangements often produce a more realistic answer than an all-or-nothing equipment swap.
How an industrial heat pump can make process steam
The vapor-compression cycle
A mechanical heat pump evaporates a refrigerant at the source temperature, compresses the vapor, condenses it at a higher temperature, and expands it back to low pressure. The compressor consumes electricity; the condenser releases both the recovered source heat and the compressor’s input as useful heat. Because it moves heat rather than creating all of it from electricity, its coefficient of performance (COP) can be greater than one.
For a simple system, COP = useful heat delivered ÷ electricity consumed. A COP of 3.5, used by the International Energy Agency (IEA) in a 2025 illustrative economic analysis, means 1 unit of electricity is modeled as delivering 3.5 units of heat. That is an assumption for that analysis, not a guaranteed result for a particular plant. Actual COP changes with source temperature, delivery temperature, refrigerant, compressor, heat exchangers, part-load operation, defrosting, pumps, fans, and control strategy.
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Temperature lift is the gap between the useful source temperature and the required delivery temperature. A small lift generally supports better COP and lower delivered-heat cost. A large lift raises compression work, can reduce capacity, and may require multistage compression, a cascade, or a different refrigerant and heat-exchanger arrangement.
The IEA’s 2025 Renewables for Industry executive summary describes large-scale industrial heat pumps as well established up to 150°C. The IEA’s 2022 The Future of Heat Pumps overview describes current large systems supplying approximately 140–160°C. These are broad technology ranges, not a promise that every unit can produce every steam pressure. Steam saturation temperature rises with pressure, so a feasibility study must match the proposed heat pump’s certified leaving temperature and pressure to the process requirement.
Where the source heat comes from
Good sources are continuous, sufficiently warm, and available when the process needs heat. Examples include warm wastewater, cooling-water loops, condenser heat, compressor aftercoolers, dryer exhaust, flue-gas recovery after appropriate treatment, and low-temperature process streams. A source that is intermittent, fouling, corrosive, contaminated, or far from the steam plant can make the integration expensive even if its theoretical heat content is attractive.
The source must also be measured. A short campaign of temperature and flow logging can reveal that a stream is hot only during one production campaign or that its flow falls below the heat pump’s minimum turndown. Conversely, a modest but steady source can support a valuable base-load system.
How boilers perform as the baseline
Fuel-fired boilers
A fuel-fired boiler transfers combustion heat to water and generates steam directly. Its strengths are familiar operation, dispatchability, rapid response, and compatibility with existing steam headers. It can usually meet high pressure and temperature requirements without a separate source-heat circuit. The relevant efficiency is fuel energy converted to useful steam energy after accounting for stack losses, blowdown, radiation, distribution losses, and auxiliary electricity.
Boiler economics depend on delivered fuel price, boiler efficiency, maintenance, emissions charges, water treatment, and the cost of keeping fuel storage and handling systems compliant. A new boiler may also require burner, stack, permitting, gas connection, water-treatment, and safety work. An existing boiler can have a lower incremental capital requirement, but its remaining life and future carbon costs should be included rather than treating it as free infrastructure.
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Electric boilers
An electric resistance boiler converts electricity directly to heat and can respond quickly. It does not have the source-temperature constraints of a heat pump, but it does not multiply heat with a COP above one either. In the IEA’s 2025 regional analysis, electric boilers were more expensive to operate than heat pumps in the compared cases because of their lower efficiency; thermal storage could improve their economics by shifting electricity use to cheaper periods. That finding depends on local tariffs, load timing, and the assumptions used in the analysis.
Efficiency: compare useful steam, not COP with boiler efficiency
COP and boiler efficiency have different denominators. A heat-pump COP includes recovered ambient or waste heat in the numerator; a boiler efficiency compares useful heat with fuel input. Neither number alone tells you the cost per tonne of steam.
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|---|---|---|---|
| Input energy | Electricity for compressor, pumps, fans, controls, and auxiliaries | Fuel plus auxiliary electricity | Metered or quoted energy at the plant boundary |
| Core performance | COP varies with source and delivery temperatures and part load | Thermal efficiency varies with firing rate, excess air, blowdown, and stack conditions | Seasonal useful-heat output divided by total input |
| Temperature effect | Higher lift generally lowers COP and may reduce capacity | Required steam conditions mainly affect boiler and distribution design | Hourly performance at actual pressure and return conditions |
| Recoverable heat | Can include source heat that otherwise would be rejected | May recover economizer or condensate heat, but combustion remains the primary source | Net useful heat after source-side and distribution losses |
| Part-load behavior | Depends on compressor turndown, cycling, and controls | Depends on burner turndown, cycling, and standby losses | Annual simulation using the real load profile |
For a fair calculation, model each hour or representative operating period. Include source-side pumps, cooling fans, feedwater pumps, water treatment, blowdown, steam traps, condensate return, and distribution losses. A system that looks efficient at full load may be expensive if it cycles for most of the year.
Efficiency work should precede equipment sizing. The IEA states that “Prioritising efficiency therefore maximises the impact of subsequent electrification efforts and strengthens the business case for switching from fossil fuels.” In practice, insulation, leak repair, steam-trap maintenance, condensate recovery, pressure optimization, and process controls can reduce both fuel consumption and the size of a future heat pump.
Cost: why a heat pump can be cheaper—or not
Operating cost formula
For a heat pump, a simplified delivered-heat cost is:
Electricity price ÷ seasonal COP + auxiliary electricity cost + maintenance + demand and network charges.
For a boiler, the equivalent is:
Fuel price ÷ seasonal boiler efficiency + auxiliary electricity + water and maintenance costs + emissions charges.
These formulas are starting points, not investment cases. They must use the same currency, year, operating boundary, and useful-heat output. Include startup fuel, standby losses, minimum-load operation, planned outages, and any revenue or penalty associated with carbon emissions.
What the IEA regional analysis found
The IEA’s 2025 analysis examined industrial heat-pump costs in several European Union member states and reported a range of 41–74 EUR/MWh. The range reflects differences in electricity prices and in how energy taxes and network costs are treated. It is not a universal tariff, quotation, or payback result. The analysis used 2024 average energy prices, assumed a COP of 3.5, and applied an 8%–12% weighted average cost of capital range. Grid-connection costs were excluded, so the figures are not complete project estimates.
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The same analysis found industrial heat pumps economically attractive against existing gas boilers in some of the examined countries, while electric boilers were more expensive to operate in those cases. A site with high electricity demand charges, expensive reinforcement, low annual utilization, or a cheap fuel contract can reach a different conclusion.
Capital and integration costs
Heat-pump capital cost includes the machine, source-side heat exchangers, pumps, filters, controls, refrigerant systems, steam-side equipment, civil works, electrical switchgear, transformers, grid connection, and commissioning. If the source stream is dirty or corrosive, cleaning and materials selection can dominate the budget. Long pipe runs between source and process add both capital and heat loss.
Boiler capital cost may be lower when a compliant boiler house, fuel connection, stack, water treatment, and steam header already exist. A replacement project still needs installation, demolition, controls, permitting, and outage planning. Comparing a new heat pump with only the boiler purchase price is not an equivalent basis.
Emissions: state the boundary and the electricity mix
A heat pump has no combustion at the process site, but its operating emissions depend on the electricity used. A simple operational estimate is:
Heat-pump emissions = electricity consumed × grid or contract-emission factor.
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For a boiler:
Boiler emissions = fuel consumed × fuel-emission factor + relevant upstream or lifecycle emissions.
The result depends on geography, year, fuel, operating profile, and whether the boundary is direct combustion only, purchased-energy emissions, or full lifecycle emissions. Grid factors change as generation changes, and a heat pump that runs during high-carbon or high-price hours may perform differently from one scheduled around cleaner, cheaper electricity.
The IEA reports nearly 3 gigatonnes of direct energy-related CO₂ emissions in 2023 from the low-temperature industrial sectors discussed in its 2025 analysis. That figure describes those sectors overall; it is not an emissions figure for heat pumps or boilers. The IEA’s 2026 Heat Pump Monitor says commercially available systems could technically serve up to around 20% of global industrial heat demand, mainly in low- and medium-temperature processes. “Technical potential” is not the same as deployed capacity or guaranteed emissions reduction.
Refrigerant choice and leakage may matter in a lifecycle assessment. Ask suppliers for refrigerant type, charge, leak-detection provisions, recovery arrangements, and expected service practices rather than counting only electricity-related emissions.
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Process fit: the questions that decide feasibility
What steam pressure is required?
Pressure determines saturation temperature and therefore the required heat-pump leaving temperature. A process needing low-pressure steam may be an excellent candidate for recovered heat. A high-pressure header may require a cascade, steam recompression, a hybrid arrangement, or continued boiler service for part of the load. Do not infer suitability from a supplier’s maximum water-temperature rating; ask for steam conditions, capacity, COP, and operating limits at the exact design point.
Is the source hot enough and available long enough?
Measure source temperature and flow during production peaks, normal operation, cleaning, weekends, and seasonal changes. Calculate the heat available after minimum source outlet temperature, approach temperature, fouling allowance, and heat-exchanger pinch. A source that cannot sustain the required flow during the process’s critical hours may support preheating but not full steam production.
Can the electrical system support it?
Obtain a utility study for connection voltage, transformer capacity, protection, power quality, demand charges, reinforcement requirements, and lead time. The IEA’s regional levelized-cost analysis excluded grid-connection costs; at an individual site those costs can materially change payback and schedule.
Can production tolerate interruption?
Steam is often a critical utility. Retain boiler capacity, thermal storage, or another backup source if a compressor trip could stop production. Define black-start behavior, maintenance intervals, spare parts, remote monitoring, bypass arrangements, and the time required to return to full steam output.
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- Document the load. Install or validate steam-flow, pressure, temperature, condensate-return, fuel, and electricity meters. Build an hourly or sub-hourly load profile that includes startup and peak events.
- Map heat sources. Record source temperature, flow, contaminants, operating schedule, minimum usable temperature, and physical distance from the steam plant.
- Set the design point. Specify steam pressure, temperature, mass flow, turndown, ramp rate, annual hours, and acceptable backup percentage.
- Screen temperature lift. Compare source and delivery temperatures. Flag high-lift cases for multistage, cascade, hybrid, or preheat configurations rather than assuming a single compressor will meet the duty.
- Reduce avoidable demand. Repair leaks, test steam traps, improve insulation, recover condensate, tune controls, and reduce excessive pressure before sizing new equipment.
- Request comparable supplier data. Require capacity, COP, electricity draw, source-side flow, leaving temperatures, part-load performance, sound, refrigerant, maintenance, and warranty at the site’s actual design conditions.
- Model hourly economics. Apply local electricity and fuel prices, taxes, network costs, demand charges, carbon prices, maintenance, financing, and planned outages. Use the same useful-steam boundary for every option.
- Price integration and grid work. Include heat exchangers, piping, controls, transformers, protection, civil works, permits, commissioning, downtime, and contingency. Do not rely on equipment-only quotes.
- Calculate emissions transparently. State geography, year, grid or contract factor, fuel factor, operating versus lifecycle boundary, and assumptions about renewable electricity or certificates.
- Test resilience. Simulate compressor trips, source loss, grid interruption, cold weather, production surges, and maintenance. Define the role of boilers and storage before selecting final capacity.
- Approve with measured risk. Use a pilot, temporary metering, or staged installation when source data or process integration is uncertain. Set performance guarantees around useful steam delivered, not only COP.
When each option is usually the better fit
| Site condition | Likely first option to investigate | Reason |
|---|---|---|
| Continuous low- or medium-temperature waste heat and moderate steam pressure | Industrial heat pump | Recovered heat can produce a COP above one and displace fuel steadily. |
| Very high steam pressure or temperature with no high-grade source | Boiler or hybrid | The temperature lift may reduce heat-pump performance or require costly multistage equipment. |
| Strong electricity prices at off-peak hours and space for storage | Heat pump or electric system with storage | Storage can shift electricity use and reduce peak-demand exposure. |
| Limited grid capacity or long connection lead time | Existing boiler, efficiency retrofit, or staged hybrid | Electrical reinforcement may dominate schedule and capital cost. |
| Cheap, reliable fuel and low annual operating hours | Existing boiler or hybrid | Low utilization can make it difficult for a capital-intensive heat pump to recover its cost. |
| High-carbon electricity and a relatively efficient boiler | Efficiency work, cleaner electricity, or hybrid | Electrification emissions depend on the actual electricity mix. |
| Critical process requiring uninterrupted steam | Heat pump plus boiler backup | Redundancy protects production during source, compressor, or grid failures. |
Hybrid systems, storage, and staged electrification
A hybrid plant can assign each technology the duty it performs best. The heat pump can cover a steady base load when source heat and electricity economics are favorable. A boiler can provide peak, startup, high-pressure, or emergency steam. Controls can dispatch equipment by steam demand, electricity price, source temperature, carbon intensity, and storage state.
Thermal storage can decouple heat production from process demand. A hot-water tank, pressurized vessel, phase-change system, or steam accumulator may allow a heat pump or electric boiler to run during lower-cost or lower-carbon periods. Storage adds capital, space, heat loss, controls, and safety requirements, so it must be modeled with the actual load profile.
Staging can also reduce risk: begin with steam-system efficiency, condensate recovery, and a heat pump for a measured base load; retain the boiler for peaks; then expand as operating data confirms source availability and economics. This approach avoids oversizing a heat pump for rare peaks while preserving production continuity.
Common mistakes and how to correct them
Comparing COP directly with boiler efficiency
Problem: A COP of 3.5 is presented as “350% efficiency” and compared with a boiler percentage without matching boundaries. Correction: Convert both systems to seasonal useful heat delivered per unit of purchased energy, including auxiliaries and distribution.
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Using a regional cost range as a project quote
Problem: The IEA’s 41–74 EUR/MWh range is copied into a business case without local tariffs or connection costs. Correction: Treat it as regional modeled evidence; replace it with current site prices, installed quotes, financing, taxes, network charges, and grid scope.
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Ignoring temperature lift
Problem: A warm-water source is assumed to produce high-pressure steam at the same performance. Correction: obtain supplier data at the exact source and delivery temperatures, then test cascade, hybrid, or preheat alternatives.
Counting theoretical waste heat that cannot be collected
Problem: A process stream’s peak heat content is used even though it is intermittent, contaminated, or physically inaccessible. Correction: meter the source over representative operating periods and subtract exchanger approach, fouling, transport, and minimum-temperature constraints.
Leaving grid work out of the schedule
Problem: The compressor is available but the transformer or utility connection is not. Correction: obtain written capacity, protection, reinforcement, cost, and lead-time information before selecting the project date.
Assuming electrification automatically lowers emissions
Problem: Direct combustion is compared with zero at the site while purchased electricity is treated as emission-free. Correction: publish the electricity factor, fuel factor, geography, year, operating profile, and lifecycle boundary.
Removing all boiler capacity
Problem: A single compressor trip becomes a production outage. Correction: retain backup, add storage, or stage capacity and define a tested failure mode before decommissioning boilers.
What a defensible investment recommendation should contain
A board-ready recommendation should show the required steam service, measured load profile, source-heat evidence, design-point performance, installed capital cost, grid scope, annual operating cost, emissions boundary, financing assumptions, maintenance plan, outage risk, and sensitivity to electricity and fuel prices.
Include at least three scenarios: a baseline boiler case, a heat-pump case, and a hybrid or staged case. Test low and high electricity prices, fuel prices, COP, annual operating hours, carbon factors, grid-connection cost, and project delay. Report simple payback only alongside net present value or another stated financial method; payback alone can hide replacement timing, residual value, and long-term operating risk.
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Finally, specify what is guaranteed. A supplier may guarantee compressor power or rated COP under laboratory conditions, while the plant needs guaranteed tonnes per hour of steam at a stated pressure across a seasonal operating range. Contractual acceptance tests should use calibrated meters and the process boundary that drove the investment decision.
Bottom line
Choose an industrial heat pump when measured waste or ambient heat is available, the temperature lift is manageable, the process runs enough hours to use the equipment, electricity and grid conditions are favorable, and integration costs fit the project. Choose a boiler—or retain one in a hybrid system—when high-temperature steam, fast dispatch, backup capability, fuel economics, or grid constraints outweigh the heat pump’s efficiency advantage.
The most reliable sequence is to reduce steam demand first, measure sources and loads, model useful heat at the process boundary, price grid and integration work, and compare emissions using an explicit electricity mix and accounting boundary. That method can identify where electrification creates real value without assuming that either technology wins everywhere.
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