The Bill for the End of Coal Will Come Through the Pipes

Energy, heat & public money

A heating bill usually contains one line: heat. Behind it sit fuel, a power plant, pipes, loans, emission allowances, and subsidies. The end of coal will therefore not arrive as one invoice. Its cost will be divided among several accounts—and some may not appear until the first conversion is already ageing.

1. One Gigajoule Passes Through Several Accounts

A resident of an apartment block sees the price of delivered heat on the bill. They cannot see whether a particular gigajoule was produced in a coal boiler, gas-fired cogeneration unit, waste-to-energy plant, biomass boiler, or large heat pump. Nor can they see how much of the price is fuel, depreciation of the pipes, maintenance, interest, or an emission allowance.

This does not mean a supplier may simply put every expense into the price. In the Czech Republic, the price of heat is subject to cost-based regulation. The rules work with economically justified costs and a reasonable profit, but the structure varies by location, technology, network size, and production method. There is therefore no single nationwide “price of ending coal”.^[1]

2. The Year 2033 Is Not a Statutory Off Switch

Czech strategic documents contain a goal of ending coal mining and combustion by 2033. In everyday debate, this easily becomes the sentence “all coal boilers will be switched off in 2033”. That is not an accurate description of the legal position.

The updated National Energy and Climate Plan works with a target and a trajectory, not with one date on which a standalone law shuts down every installation. The document itself says that it does not create new obligations for private entities. The actual end of an operation will therefore depend on permits, economics, the condition of the plant, allowance prices, and the owner’s decision.^[2]

For an investor, the distinction is crucial. If a new source has a thirty-year life while the government model assumes a substantial decline in fossil-gas use after 2030, its return cannot be calculated from the first few years alone. Every conversion also needs an answer to what happens in the final third of the asset’s technical life.

3. Today’s District Heating Is Not Only Coal

The Energy Regulatory Office reported that in 2025 energy consumption in district-heating systems rose by 3.4 percent to 68.2 petajoules. Total heat production reached roughly 137 petajoules. Lignite accounted for about one third, with its use falling by 0.6 percent year on year. Natural-gas use, by contrast, rose by 8 percent and biomass by 11.1 percent.^[3]

These figures must be read carefully. Consumption in district-heating systems, heat generated, heat delivered to buildings, and useful heat inside homes are not the same quantity. The differences include network losses, the plant’s own consumption, and whether a statistic describes primary energy or useful output.

It would likewise be wrong to turn one third of production into the claim that “one third of households heat with coal”. A single heat source may serve thousands of flats, while another household uses its own boiler, electricity, or gas. Production technology and a household’s heating method are two different statistical questions.

4. Why Gas Is Placed Between Coal and Emission-Free Heat

Gas plants have several properties that put them into transition plans. Their output can be controlled as demand changes, they can supply high power during a freezing peak, and cogeneration can produce electricity at the same time. A heating company can also retain part of an existing district-heating system instead of replacing it with dozens of local boiler rooms.

Lower carbon intensity at the point of combustion is often cited as an advantage. Using emission factors for energy in the fuel, the direct emissions from natural gas are about 43 percent lower than those from lignite. That is not a statement about the full life cycle, price, efficiency, or methane emissions during extraction and transport. Gas emits less when burned under the stated assumptions; it is not automatically a zero-emission technology.

The main risk arises when a temporary bridge becomes an investment depreciated as though it were a permanent answer. The plant may then still be repaying the source when legislation, allowance prices, or fuel availability require another conversion. The label “hydrogen-ready” does not by itself prove that low-emission hydrogen will be available in the required quantity and at an affordable price.

5. The Government Scenario First Raises Gas Use, Then Leaves It Behind

A Ministry of Industry and Trade study on decarbonising district heating models a peculiar transition paradox. Between 2022 and 2030, heat supplied from coal and coal products falls in its scenario from 44,606 to 4,696 terajoules. Gas rises from 21,607 to 27,214 terajoules. Total district-heat supply declines slightly, from 82,070 to 77,510 terajoules.

Gas rises in the model from 26.3 to 35.1 percent of the mix. Yet the same scenario reduces fossil-gas heat to 7,688 terajoules in 2040 and zero in 2050. This is not a forecast that knows the future decision of every heating company. It is a scenario showing how gas can be important in the short term and inadequate in the long term.^[4]

6. Coal Does Not Have a Single Successor

A large heat pump can use waste heat from industry or a wastewater-treatment plant, but it needs electricity and an appropriate temperature source. Biomass can replace part of coal, but its availability is local and combustion is not impact-free by definition. Waste-to-energy works where a suitable waste stream exists and the facility complies with emissions and waste rules. Geothermal energy can be stable, but exploration is uncertain. Nuclear heat operates on a different timescale from a gas boiler.

The question “coal or gas?” is therefore too narrow. The decisive mix may combine low-temperature networks, building renovation, storage, waste heat, and a controllable peak source. Each option must be assessed not only by its capital cost, but also by operating hours, dependence on a single fuel, spatial constraints, and its capacity to change later.

7. The First Bill: Plants and Networks

The ministry study estimates the cost of decarbonising district heating by 2030 at roughly CZK 200 billion. About CZK 10 billion of that is for converting steam networks to hot-water systems. For 2030–2040, it gives at least another CZK 70 billion in 2023 prices, including roughly CZK 18 billion for network infrastructure.

This is not one approved invoice. It is a model estimate combining heat sources, pipes, substations, and technical assumptions. Some projects will happen earlier, others later; some will change and some will never be built. Dividing CZK 200 billion by the number of households produces an impressive but invalid figure: it does not identify which households are connected, how much support will be granted, or how costs will be recovered.

8. A Subsidy Does Not Erase the Bill; It Changes Who Pays It

Public support can reduce the share of an investment that would otherwise be financed by the owner or by heat customers. It does not make the project free. The Modernisation Fund is financed by revenues from the EU Emissions Trading System, and support is awarded under the conditions of a specific programme.

A Ministry of the Environment document listed CZK 74.934 billion in approved support under the HEAT programme as of 15 October 2025. The word “approved” matters. It does not automatically mean an amount already paid, a completed project, or the final cost of all projects.^[5]

A decision on a new source should therefore show four pockets: the subsidy, equity, debt, and the future heat price. Only then can we judge whether support truly reduced the burden or shifted part of it from customers’ bills to a wider public system.

9. The Second Bill Runs Through the Gas Network

The regulated component of the gas price does not pay for the commodity itself. It finances the operation and development of networks that must continue to function as consumption changes. For 2026, the Energy Regulatory Office reported an average regulated price before tax of CZK 508 per megawatt-hour for households and small customers, and CZK 234 for medium and large customers. This is neither the total bill nor the fuel price of a particular heating plant.^[6]

An uncomfortable paradox appears here. When consumption falls, fixed network costs may be spread over a smaller volume of energy. When consumption rises in the short term, the network gains volume, but customers buy more of the commodity. Without the tariff structure, the period considered, and the investment requirement, the effect cannot be assigned one direction.

10. How Billions Become the Price of One Gigajoule

The heat price includes fuel and transport, production efficiency, emission allowances, staffing, maintenance, depreciation, interest, distribution losses, and the amount of heat actually sold. In cogeneration, electricity revenue may offset some costs. In a network selling fewer gigajoules, the amount charged per unit may rise even while a household consumes less overall.

A model example: an investment of CZK 100 million can have a very different impact in a network selling 100,000 GJ per year from one selling 40,000 GJ. It is not a real tariff; it is a reminder that the same investment has different unit costs depending on volume and service life. A public comparison should therefore show CZK/GJ, the total household bill, and the assumed sales volume.

11. ETS1 and ETS2 Are Not a Second Allowance for the Same Chimney

Large combustion installations with a total rated thermal input above 20 MW fall under ETS1. A gas-fired heating plant is therefore not automatically outside the carbon market. Allowance costs may form part of the economics of producing heat, although the precise pass-through depends on procurement, efficiency, and any allocation rules.

After changes to European legislation, ETS2 is due to begin in 2028. The regulated entity is the fuel supplier, not a household buying an allowance on an exchange. A cost may pass into the fuel price, but it cannot be described as a second mechanical allowance for a source already covered by ETS1. The figure of EUR 45 in 2020 prices is a trigger for a market-stability mechanism, not a guaranteed hard price cap.^[7]

12. A More Efficient Building Can Make One Gigajoule More Expensive

An insulated building may buy less heat and its residents may pay less in total. The heating network must still maintain pipes, substations, dispatching, and peak capacity. If fixed costs do not fall as quickly as consumption, the unit price per gigajoule can rise.

The ENERGO 2021 survey identified purchased heat as the main heating source for 1,704,065 households and natural gas for 1,683,055. These figures must not be added as a count of unique households, and the survey does not describe today’s situation.^[8]

13. Lower Emissions at the Chimney Are Not the Whole Life Cycle

Natural gas remains a fossil fuel. Its life cycle includes extraction, processing, transport, and methane leakage. Without knowing the supply chain, no single universal percentage can honestly describe every delivery. The European Union is therefore tightening the monitoring and reporting of methane emissions from fossil fuels.^[9]

The accurate sentence is: under the stated emission factors, gas has lower direct combustion CO₂ emissions than lignite. The inaccurate sentence is: gas is always a clean solution. The difference is too large for a short headline, but not for an investment decision.

14. How to Recognise a Conversion We Will Not Pay for Twice

Every publicly supported project should disclose its total cost, subsidy, depreciation period, expected operating hours in 2030, 2040, and 2050, and the sensitivity of the heat price to gas and allowance prices. It matters just as much whether it has a plan for waste heat, storage, a low-temperature network, renewable sources, or another genuinely evidenced successor.

A sensible transition does not merely say what will replace coal. It also says how many years the new source will be used, who bears the risk of lower demand, and how households least able to invest in savings will be protected. If these answers are absent, the problem is not only the price of gas. The problem is that nobody knows exactly what the bill is paying for.

Who Bears the Risk of a Warm Winter

Fuel prices are often discussed as though they were a heating company’s only variable. In reality, a system has costs that remain almost unchanged whether winter is long or mild: maintenance of the boiler house, staff, inspections, pumping stations, dispatching, and the pipes themselves. When households buy fewer gigajoules in a warm winter, those costs are spread over a smaller volume. Savings on the bill therefore need not match the fall in consumption.

The same applies when buildings are renovated. Lower demand is good for household budgets and emissions, but it does not automatically remove the network. The heating company still needs enough capacity for freezing days. If network investments are recovered from a smaller sales volume, the price per gigajoule can rise even while the household’s total bill falls. That is not a contradiction; it is the difference between a unit price and a total price.

The most vulnerable people are those who cannot quickly change their home, heat source, or heating regime. A tenant usually does not decide which boiler house serves the building, and a low-income household has no reserve for a heat pump or advanced controls. Social protection cannot therefore be only an energy discount. It must also include accessible efficiency measures, fair cost allocation, and a clear timetable for how the change reaches the price.

Five Questions Before a Project Is Approved

The first question is which problem the project solves. Does it genuinely replace a source that would otherwise close, or merely add capacity where maintenance and peak management would suffice? The second concerns service life: will the equipment remain economically useful when allowance prices, gas availability, or emission requirements change?

The third question is sensitivity. The investor should show what happens with more expensive gas, cheaper electricity, lower demand, and a construction delay of several years. The fourth concerns stranded assets: what happens to the old boiler, pipes, and loan if the new source runs fewer hours than the model assumed? The fifth is public: how will the change be explained to people who do not read energy models but pay monthly advances?

Without these answers, the debate breaks into two equally inaccurate claims. One promises that the transition will be cheap because a subsidy will arrive. The other says every new source automatically makes heat more expensive. The truth is less comfortable: the price is set by the combination of investment, operation, utilisation, networks, financing, and who bears the risk when the plan is wrong.

Heat Is Also a Public Contract

Buying heat differs from buying an ordinary product. A household cannot select another supplier each week, and pipes cannot be moved according to a comparison website. The relationship among the heating company, municipality, building owner, and customer is therefore a long-term public contract even when its legal form is commercial. Whoever decides on a source today determines part of the costs and options for many years.

Public debate should disclose not only the project price but also its contractual logic: who guarantees demand, who secures the loan, how the price changes when consumption falls, and whether customers can leave. Without this layer, the investment looks like a technical question even though it also distributes risk between public budgets and households.

That is why three decisions that often merge in practice should be separated: when coal ends, what bridges the gap, and what the final emission-free system will look like. Each has a different time horizon, different investors, and different risk. When they are discussed as one package, it is easy to miss that the transitional solution may need its own expiry date.

Gas can help close coal. Without a clear date and an economic plan for its own decline, however, we risk paying first for the pipes that take us away from coal and then for a second conversion away from gas.

— Jiný Kontext