Is there a place for LNG in Europe?

By Anouk Honore – Oxford Institute for Energy Studies

In 2018, the European market(s) represented almost 16 per cent of the global LNG market (GIIGNL 2019 Report). Volumes imported to the region vary greatly from one year to another. This is because Europe is acting as the swing market for LNG.

As a result, the region is expected to help balance the market at times of high Asian demand, as seen after 2011 following the Fukushima disaster, but also help to absorb any LNG surplus coming on to the market, as expected in the 2020s. With regasification terminals only being used at about 28 per cent of their capacity, Europe could import a lot more LNG relying only on its existing infrastructure. But is there a place for LNG in Europe, especially up to 2030?

Europe is not an LNG market per se–it is a market with a demand for gas, which can come in the form of indigenous production, imports via pipelines, or LNG. After a continuous decline between 2010 and 2014, natural gas demand in Europe started to rise again in 2015–17. This was due to a combination of colder than average months in winter (higher energy consumed for heating), economic recovery, and increasing gas deliveries to the power sector because of coal-to-gas switching.

In addition, low hydropower in the south and limited nuclear availability in France created a set of special circumstances, which enhanced the use of gas-fired power plants in the generation mix. With the normalization of these special circumstances and milder temperatures, natural gas demand in Europe (35 countries) declined in 2018 for the first time in three years and reached 536 billion cubic metres (bcm).

Gas and climate change policies

The future place of natural gas in Europe’s energy system will determine the need for imports, including of LNG. But this future faces major uncertainties as a result of climate change policies.

The decarbonization of energy systems is a major part of the European Union’s (EU’s) policy agenda; it is committed to reducing its greenhouse gas (GHG) emissions to 80–95 per cent below 1990 levels by 2050. The decarbonization of the electricity sector through the integration of renewables has been regarded as the first step in a wider strategy. Between 2007 and 2017, the share of renewables grew from 5 to 18 per cent (excluding hydro), with the largest increase in the form of onshore wind and solar. Both are intermittent sources of power generation, and one of the key challenges posed by this rapid evolution was how to integrate a large and growing share of intermittent generation into the power system.

This approach has catalysed disruptions in the traditional structure of the electricity sector, and by extension the role of gas in the electricity mix. While in the past, combined cycle gas turbines (CCGTs) were traditionally run on baseload power, they are increasingly required to provide backup for variable renewable resources. New projects involve smaller and more flexible plants; and as plants that back up renewable plants run for fewer hours, this may also result in lower and more unpredictable gas demand.

Decline of coal

Nonetheless, the role of natural gas in European power generation could increase in the late 2010s and early 2020s, thanks to the expected decline of coal in the generation mix. With tightening legislation on GHG emissions, increasing carbon prices, a ban on subsidies on all coal plants from 2025, and their prospective phase-out at the EU and/or national level, generators will soon have to make decisions about the future their coal plants. Options include retrofitting control technology and continuing to operate within the new limits, applying for derogation (if possible), limiting their operating hours to less than 1,500 annually (the threshold below which emissions limits are less stringent), and shutting down.

All these measures suggest a sharp decline in coal generation in the early to mid 2020s. Of course, not all coal plants will be replaced, and certainly not all by natural gas; but if the closure of a large number of coal plants happens quickly, there may be no time for alternative plants or grid extensions to be built, and gas-fired plants may be called back into the mix at both peak and baseload times.

Nuclear phase-out in Germany by 2022 and in Belgium by 2025, other potential limits placed on existing (or new) nuclear plants, and delays in construction will also provide some opportunities for natural gas, at least until further low-carbon capacities are developed in Europe.

So far, the electricity sector has been the main focus of low-carbon policies; but if Europe is to meet its objectives, decarbonization efforts will need to expand to other sectors, including the heating and cooling sector. This sector is the largest energy user in Europe; in 2015 it represented about 50 per cent of the final energy demand.4 Although the sector is moving towards low-carbon energy, about two-thirds of its energy demand is still met through the direct combustion of fossil fuels, and over 40 per cent from natural gas alone. The main focus of EU decarbonization policies for heating and cooling production so far has been on two main types of measures: energy efficiency and the promotion of renewables (essentially for final energy demand, although some work is also being done on district heating systems). The implementation of low-carbon options faces critical energy challenges with few simple answers, and neither the impacts nor the time frames are likely to be uniform across Europe.

In the building sector, the main options include efficiency improvements (upgrading boilers, developing combined heat and power (CHP) and fuel cells, and switching to more efficient heating systems, all of which could potentially still include natural gas as an input), raising the renewables share (replacing fossil fuels with renewables, installing hybrid systems –which may include gas– and repurposing the gas network for hydrogen), electrifying the heating sector from a zero-carbon electricity supply, and expanding heat networks. Active policies promoting low-carbon options in buildings only started in the early 2010s, and the effects may take time to materialize in the European market, where buildings are old and not energy-efficient.

Nonetheless, some efficiency gains –through thermal refurbishments and minimum energy efficiency requirements for new buildings– may start to lower demand for space heating in the second half of the 2020s.

Reducing carbon emissions in the industrial sector and reaching the 2050 targets will essentially depend on a mix of energy efficiency, electrification of heat (and heat recovery techniques), fuel switching (to biomass or hydrogen as feedstock and/or fuel), and carbon capture utilization and storage (CCU/CCS). The heterogeneity across subsectors and energy uses will be one of the main challenges in designing a framework to decarbonize the sector and some subsectors will be more complex to decarbonize than others. For example, cement, steel, ethylene, and ammonia are characterized by high emissions from feedstock and high-temperature heat processes. Because not all technologies and fuels are capable of achieving high temperatures, fossil fuels, including natural gas, can be more easily displaced by traditional renewable energies for low- temperature applications than for high-temperature applications. As a result, only natural gas used in low-temperature applications (about 48 bcm) could realistically be replaced by low-carbon sources in the 2020s (provided that these can meet both commerciality and acceptability requirements). In addition, energy (including gas) demand in the industrial sector may increase slightly due to favourable economic conditions and fewer options to improve energy efficiency than in the residential sector, especially in energy-intensive industries.

In decarbonized form

To summarize, natural gas demand in the three main sectors which make up about 80 per cent of the European market –power, residential, and industrial– is expected to remain high at least in the first half of the 2020s and maybe up to 2030. Use of gas in the transport sector may also expand if adequate support is provided for public entities and businesses to use LNG and compressed natural gas (CNG) in road and maritime transport to improve air quality, and for the use of LNG as a bunkering fuel in European ports. Important growth rates are expected in this sector, but starting from a very low base, with limited effects on the regional total.

Following on from this, there are several reasons to be carefully optimistic about gas demand in Europe in the next five and maybe even 10 years. It will not return to the strong growth seen in the 2000s, but it is likely to remain fairly high. However, natural gas is a fossil fuel, and efforts will need to be made towards decarbonization (by developing CCS and increasing the production of green gas such as biomethane or hydrogen) sooner rather than later if it is to maintain a share in the energy mix, certainly after 2030 but potentially even before. As part of the EU long-term strategy ‘A Clean Planet for All’, gas will contribute to the decarbonization of the energy sector, but its role in the EU energy mix will increasingly be in its decarbonized form.

There will be a place for LNG in Europe in the 2020s?

In 2018, indigenous production covered about 46 per cent of Europe’s needs, while imports via pipeline accounted for 41 per cent and LNG for 13 per cent.5 One of the main uncertainties concerns the pace and scale of the region’s conventional production decline due to resource depletion and/or political decisions –especially in the Netherlands, where the government decided in March 2018 to phase out production from the giant Groningen field as quickly as possible, and no later than 2030. There are reasons to believe that, if more earthquakes occur like the one in May 2019, production could be reduced even faster than expected. This would alleviate some of the LNG glut in Europe for 2020 and 2021 and help balance the market, but it would then add to the tightening of the market in 2023/2024, when Nord Stream 2 could be needed, depending on Asian LNG demand trends.

After 2025, demand for natural gas (especially unabated gas) may start to soften as a result of decarbonization policies. Nonetheless, indigenous production of biomethane and hydrogen from electrolysis is unlikely to exceed 15–25 bcm by 2030. This will not replace the decline of conventional production which this author’s estimates at about 113 bcm in this timeframe (compared to 2018 in a Europe of 35 countries including Norway). Therefore, gas imports will be the key to meeting regional needs, and Russian gas and LNG are likely to be the main sources competing to provide these. Therefore, the main challenges for LNG in Europe in the 2020s will be the dynamics in other markets, especially in Asia, where LNG can potentially be sold more profitably, and the competition with Russian gas, but Europe will welcome the diversification of gas supply sources and routes provided by a growing and ever more flexible global LNG market.

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