01 POWER ISLAND / 02 H2+NH3 / The_Future_of_Hydrogen-IEA-2020

Total cost of ownership (USD/km)

80

70

60

50

40

30

20

10

0

Synthetic fuel (air capture)

Synthetic fuel (best case)

Delivered hydrogen / ammonia

Fossil fuel

Infrastructure

Storage

Fuel cell / engine

Base ship

50 This value would be higher for a charterer looking for three-year payback (charterers currently oversee more than half of container fleet operations (Global Ship Lease, 2019).

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IEA. All rights reserved.

51 This could also help to decrease demand through price elasticity or shift between transport modes. It has been estimated that a fourfold increase in fuel prices in Europe could result in almost 60% higher ticket prices and 30% less demand (Murphy et al., 2018).

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Hydrogen as a fuel for heat in buildings

The global buildings sector accounts for 30% of global final energy use, nearly three-quarters of which is used for space heating, hot water production and cooking. Including traditional use of solid biomass in developing countries, related energy demand was around 2 200 Mtoe in 2017. Nearly half of this was produced directly from fossil fuels, with natural gas accounting for 620 Mtoe. Most of the rest came from conventional electric equipment (for example electric resistance radiators and cookstoves) and commercial heat (e.g. district heating), around 85% of which was produced using fossil fuels in 2017. Overall, nearly 28% of global energy-related CO2 emissions result from energy use in buildings.

Replacing heat provision with low-carbon alternatives and reducing heat demand through improving buildings is challenging. Decision-making for energy use in buildings is complex and depends on building type, location, ownership, customer preferences, equipment costs, energy prices and overall convenience, amongst other factors. This plurality of variables means that various energy sources and technologies are likely to co-exist in the future, from natural gas boilers to electric heat pumps, district heating and solar thermal heating. Hydrogen has the potential to contribute to the energy transition (e.g. through blending or methane production) and to long-term strategies for decarbonising heat (e.g. pure hydrogen production from renewables) (Table 6). In doing so, it can make use of existing building and energy network infrastructure to provide both flexibility and continuity.

*Current ENE-FARM installations are running on natural gas or liquefied petroleum gas, mainly targeted at cost reduction.

**The programme includes fuel cell applications in buildings.

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How does the buildings sector use hydrogen today?

Hydrogen is very little used as a source of energy in the global buildings sector today, although various potential uses are now being trialled. There are currently 37 demonstration projects examining hydrogen blending in the gas grid (see Chapter 3 for more information). In the United Kingdom, where high heating demands have focused attention on heating solutions, H21 North of England is the largest project and is proposing to supply 100% hydrogen by pipeline to buildings. This project targets hydrogen supply of 180 ktH2/yr by 2025 and 2 MtH2/yr by 2035, following studies in 2016 confirming the feasibility of reusing the existing pipeline network (Northern Gas Networks, 2018).

There are in addition micro co-generation and fuel cell hydrogen demonstration projects in Europe and Asia, notably the ENE-FARM project in Japan (Box 14). In Europe, the ene.field demonstration was launched in 2012 and has installed more than 1 000 small stationary fuel cell systems for residential and commercial buildings in 11 countries, with plans to increase this to 2 800 units (Ravn Nielsen and Prag, 2017). In Germany, consumers can access government funding to offset the extra cost for fuel cell appliances in buildings (KfW, 2018). Projects are also being prepared for the demonstration of digital systems to facilitate renewables integration with the storage and supply of electricity and heat in one or multiple buildings, for example in the United Kingdom.

Box 14. The ENE-FARM programme in Japan

ENE-FARM is a large scale fuel cell demonstration and commercialisation programme aiming to deliver efficient and affordable fuel cell technologies for building applications. The first system was introduced in a residential building in 2009 and close to 300 000 units are expected to be in operation by 2020. The programme aims to install 5.3 million units by 2050. At present ENE-FARM units reform natural gas or liquefied petroleum gas in situ to feed a fuel cell with hydrogen. The use of fossil fuels leads to limited CO2 reduction benefits, but aids delivery of cost reductions that will help to pave the way for low-carbon hydrogen distribution once it becomes economically attractive. The initial cost per unit has come down by 75% in almost 10 years (from more than USD 35 000 to around USD 9 000 in 2018 (Nagashima, 2018).

Source: Nagashima (2018), Japan’s Hydrogen Strategy and Its Economic and Geopolitical Implications.

Potential for future hydrogen demand in buildings

Hydrogen will not make sense for all building applications, and numerous factors will influence eventual hydrogen demand in buildings, including existing natural gas infrastructure, heat densities, other building energy needs and safety considerations. There are barriers related to cost and consumer acceptance, and a variety of policy design challenges, which is why hydrogen use is currently limited to localised operations and larger-scale demonstrators such as those programmes described above. But there are lots of opportunities as well, which are centred around two main options. The first is hydrogen blending in existing natural gas networks. The second is direct use of hydrogen for heat production in buildings. Hydrogen could also be used indirectly to heat or cool local district energy networks that then supply buildings.

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These potential applications could be attractive in a wide range of countries where the provision of heat is important and where it is has to be provided in large part to existing buildings. Buildings that are more than 25 years old (and that typically have energy-intensive heating loads) represent around three-quarters of the total buildings stock in the European Union, for example (FCH 2 JU, 2019), while around two-thirds of buildings in the United States and Canada were built before 1990 (OEE, 2018; EIA, 2015; EIA, 2012). Existing buildings, many of them decades old, will continue to represent a sizeable share of the overall buildings stock in the future (Table 7). This means that a certain level of heat demand is already largely “locked in” for several decades to come.

One major advantage of hydrogen blends, direct hydrogen use and indirect hydrogen use for district heating and cooling is that they can make use of existing infrastructure. While technically feasible, other potential solutions would require major new infrastructure, which would inevitably be very costly.

Another major advantage is that hydrogen use in buildings could potentially find synergies with the wider energy system that make it attractive in terms of the overall system cost of lowcarbon transitions. Other potential solutions might find this a tougher challenge. For instance, full electrification of heat, even using high-efficiency heat pumps, could lead to large seasonal imbalances in power demand, especially if major building energy efficiency improvements are not delivered in parallel (IEA, 2019c). This would potentially require large-scale peak power or energy storage capacity. Partially or entirely replacing natural gas with biomethane also has limitations: in the European Union, for example, natural gas use for heat in buildings represented around 90 times biomethane production in 2016 (EBA, 2017). Global biogas production would need to increase 20-fold to meet current natural gas demand in the buildings sector.

* Indicates markets with major heating demand as a share of total final energy consumption in the buildings sector. Russia = the Russian Federation; China = the People’s Republic of China.

Notes: m2 = square metre. Excludes traditional use of solid biomass and does not include natural gas use in production of commercial heat.

Source: IEA 2019. All rights reserved.

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Blending hydrogen into natural gas for heating

In major heating markets like Canada, the United States and Western Europe, blending low shares of hydrogen – 3–5% hydrogen by volume – into supplied natural gas would have little impact on end-use equipment such as boilers and gas cookstoves. As described in Chapter 3, 20% blend shares in 14 buildings in Ameland (the Netherlands) found no problems with leakage, flame stability, back firing or ignition, nor were there problems with pipes or heating equipment at 30%. Other projects around the world have tested specific pieces of equipment, with similar conclusions.

Rigorous testing to ensure system safety, efficiency and environmental performance in the long run would nonetheless be required as the general tolerance of domestic appliances at higher blends cannot be assumed, especially for older equipment. In parallel, it would make sense to ensure that any infrastructure or equipment upgrades were compatible with a possible switch to higher shares of hydrogen.

Blending hydrogen can create dependable demand for hydrogen through its early deployment phase, but managing the cost impacts is a key challenge for policy makers. Taking an illustrative example, if hydrogen were blended into all natural gas use around the world at just 3% by volume, this would boost clean hydrogen demand by close to 12 MtH2/yr. This would be a significant scaleup of hydrogen supply, equivalent to about 17% of current global dedicated hydrogen production. This could potentially have a major impact on the costs of hydrogen supply technologies through expansion of manufacturing and installation, but would add around 3–15% to natural gas supply costs. Many markets are currently close to the tipping point between gas and electricity prices that could trigger a switch to higher-performance heat pump technologies – including hybrid or gas thermal heat pumps – where they are appropriate, especially for new construction (Figure 59). Increases in gas prices resulting from blending mandates or incentives would risk losing gas customers, something to be considered in policy design.

Figure 59. Spread of energy prices, performance and operational costs for gas and electric heating equipment in IEA countries, 2017

Notes: kWh-eq = kilowatt hour equivalent. Prices are residential prices, including taxes, in USD 2017 using purchasing power parities. Source: IEA 2019. All rights reserved.

Relative gas and electricity prices are finely poised in many countries between levels that would make heat pumps or gas boilers the most cost-effective for new installations.

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IEA. All rights reserved.

It will not necessarily be enough for a product to offer lower running costs over time if it is more expensive at the outset. Consumers often give more weight to upfront purchase prices than to overall lifetime costs. Heating equipment costs vary substantially depending on factors such as unit capacity, brand, availability in local markets and overall size of product demand. In addition, consumer preference will also matter on issues such as safety and ease of installation. Moreover some types of building will be better suited to the use of hydrogen than others. Large-scale co-generation, for example, may be more cost-effective in terms of both capital and operational expenditure for large commercial buildings than for small-scale residential ones. Similarly, large-scale fuel cell co-generation may be well-suited to the supply of renewable electricity to buildings adapted with high-performance heat pumps and clean district heat (as a replacement for hard-to-convert gas-based systems), but less well-suited to other types of buildings.

If 100% hydrogen is ultimately able to compete in terms of capital and operational costs in some markets, the market potential in buildings is very large indeed. Heat demand will inevitably remain central to energy demand in buildings, even in a low-carbon context. In a Paris-compatible pathway, heat demand would be expected to represent more than half of global building energy consumption in 2030, with about 500 Mtoe of natural gas used for space and water heating in buildings annually. Of this, theoretical potential hydrogen demand might be on the order of 12–20 MtH2/yr in key markets (Canada, the United States, Western Europe, Japan, Korea, the Russian Federation [“Russia”] and China) if all gas boiler equipment installed or replaced at expected stock turnover rates between today and 2030 were hydrogen-ready (Table 8). Combining this with low-concentration hydrogen blends in the wider natural gas grid gives an upper bound of 14– 24 MtH2 global hydrogen demand in 2030.

Table 8. 2030 natural gas demand for heat in buildings and indicative theoretical hydrogen demand in selected regions

Notes: Natural gas demand is for space heating and hot water production and takes account of building envelope improvements under a Paris-compatible pathway. Indicative demand assumes that hydrogen production, transmission and distribution is within the competitive range shown here and does not include potential hydrogen demand for hydrogen-based fuels. Excludes natural gas use in production of commercial heat. Western Europe includes France, Germany, Italy and the United Kingdom. Indicative of direct hydrogen use in buildings. The indicative demand takes into account typical lifetimes of existing heating equipment in buildings and does not assume early retirement of equipment.

Source: IEA 2019. All rights reserved.

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IEA. All rights reserved.

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IEA. All rights reserved.