Материал: The_Future_of_Hydrogen-IEA-2020

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corresponding to four times the United States’ current hydrogen demand – would require almost 100% of its technical biomass potential, but only 6% of its wind power, and less than 1% of its solar power potential (Ruth, Jadun and Pivovar, 2017). Combining hydrogen production from biomass with carbon capture and storage could, however, be an option to create so-called “negative emissions”, which may have a role to play in the future.11

Comparison between alternative hydrogen production pathways

In the near term – that is, until 2030 – the cost advantage of fossil fuels is likely to continue in most places, with hydrogen from natural gas without CCUS costing in the range of USD 1–2/kgH2, depending on local gas prices.12

Except in the case of hydrogen produced from coal, fuel costs are the biggest single component of hydrogen production costs (Figure 16). Future hydrogen costs will therefore largely be influenced by electricity and gas costs, or parameters influencing these costs such as conversion efficiencies. Electrolysis production costs can also be sensitive to CAPEX requirements, in particular if plants are operating at low full load hours.

Figure 16. Hydrogen production costs for different technology options, 2030

Notes: WACC = weighted average cost of capital. Assumptions refer to Europe in 2030. Renewable electricity price = USD 40/MWh at 4 000 full load hours at best locations; sensitivity analysis based on +/-30% variation in CAPEX, OPEX and fuel costs; +/-3% change in default WACC of 8% and a variation in default CO2 price of USD 40/tCO2 to USD 0/tCO2 and USD 100/tCO2. More information on the underlying assumptions is available at www.iea.org/hydrogen2019.

Source: IEA 2019. All rights reserved.

In the near term, hydrogen production from fossil fuels will remain the most cost-competitive option in most cases.

11By combining the use of bioenergy and CCUS, CO2 formed during bioenergy conversion processes can be captured and injected into long-term geological storage. This provides the possibility to effectively remove CO2 from the atmosphere while producing energy.

12Just taking into account the LHV energy content of 1 kgH2, i.e. ignoring any later uses of hydrogen, a cost of USD 1/kgH2 corresponds to USD 30/MWh, or in barrels of oil equivalent to almost USD 50 per barrel (bbl).

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The CO2 impact of different hydrogen production technologies varies widely (Figure 17). The carbon intensity of hydrogen from natural gas without CCUS is roughly half that of coal without CCUS. The CO2 intensity of electrolysis depends on the CO2 intensity of the electricity input. The conversion losses during electricity generation mean that using electricity from natural gas or coal power plants would result in higher CO2 intensities than directly using natural gas or coal for hydrogen production. This means that for electrolysis to have the same or lower CO2 intensity as hydrogen production from natural gas without CCUS, the CO2 intensity of electricity has to be below 185 grams of carbon dioxide per kilowatt hour (gCO2/kWh), just above half the emissions of a modern combined-cycle gas power plant.

Figure 17. CO2 intensity of hydrogen production

Notes: Capture rate of 56% for natural gas with CCUS refers to capturing only the feedstock-related CO2, whereas for 90% capture rate CCUS is also applied to the fuel-related CO2 emissions; CO2 intensities of electricity taking into account only direct CO2 emissions at the electricity generation plant: world average 2017 = 491 gCO2/kWh, gas-fired power generation = 336 gCO2/kWh, coalfired power generation = 760 gCO2/kWh. The CO2 intensities for hydrogen also do not include CO2 emissions linked to the transmission and distribution of hydrogen to the end users, e.g. from grid electricity used for hydrogen compression. More information on the underlying assumptions is available at www.iea.org/hydrogen2019.

Source: IEA 2019. All rights reserved.

The CO2 intensity of hydrogen directly from natural gas is half of that from coal and nearly half that from gas-fired electricity; the CO2 intensity of electrolysis depends on the CO2 intensity of the electricity.

Low-carbon hydrogen produced with CCUS or from renewable electricity is in most cases currently more costly than hydrogen generated from unabated fossil fuels. The cost of hydrogen produced from natural gas is generally around USD 1.5–3/kgH2, while for hydrogen generated from renewable electricity (solar PV or onshore wind) it is generally around USD 2.5–6/kgH2. Making hydrogen from natural gas with CCUS in the Middle East competitive with unabated fossil fuel hydrogen production would require a CO2 price of around USD 50/tCO2, or an equivalent cost benefit for the CCUS option.

The future competitiveness of low-carbon hydrogen produced from natural gas with CCUS or from renewable electricity (from solar PV or onshore wind) mainly depends on gas and electricity prices. At low gas prices, renewable electricity must reach a cost range below USD 10/MWh for electrolysis to become cost-competitive with natural gas with CCUS. Higher gas prices would make higher-cost renewable electricity cost-competitive: at a gas price of USD 11/MBtu, renewable electricity would be competitive at up to around USD 30–45/MWh (Figure 18).

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Figure 18. Comparison of hydrogen production costs from electricity and natural gas with CCUS in the near term

Notes: More information on the underlying assumptions is available at www.iea.org/hydrogen2019.

Source: IEA 2019. All rights reserved.

Depending on local gas prices, electricity at USD 1040/MWh and at full load hours of around 4 000 hours are needed for water electrolysis to become cost-competitive with natural gas with CCUS.

The impact of renewable electricity and gas costs on hydrogen production costs becomes apparent when looking at specific countries (Figure 19). In countries with good renewable resources, but dependent on natural gas imports, in particular in the form of liquefied natural gas, producing hydrogen from renewables may be cheaper than producing it from natural gas, while production from natural gas with CCUS may be the cheaper option in regions with cheap domestic gas resources and CO2 storage availability.

Other factors are also relevant to the choice between alternative low-carbon hydrogen production options. For hydrogen production from fossil fuels in combination with CO2 storage, the geological availability and public acceptance of CO2 storage are prerequisites. For water electrolysis, access to adequate supplies of water is a prerequisite, even if the costs for water treatment (e.g. seawater desalination) are only a small fraction of the total hydrogen production costs. Countries could also consider importing hydrogen or hydrogen-based products if they are available at a lower price than domestic alternatives, as discussed in more detail in Chapter 3.

From an investment viewpoint, the scale of investment is also relevant. While CCUS plants require a certain scale to justify the investment in CO2 transport and storage infrastructure, electrolysers operate at a smaller scale using more modular technology, which can be gradually expanded and adjusted to demand. For example, the H21 North of England project in the UK plans to produce hydrogen from twelve ATR units with CCUS, each with a capacity of around 1 350 MWH2 and requiring an investment of around USD 945 million per unit, whereas the largest electrolyser module offered today is 20 MWe (14 MWH2), requiring investment of around USD 18 million (or USD 280 million for 220 MWH2).

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