This article is taken from World Energy (WE) number 47 – The world to come

The immediate impact of the COVID-19 crisis on global gas markets remains unclear, other than that it is likely to be less severe than for oil or coal. The International Energy Agency has projected that global gas demand in 2020 could fall by four percent (compared with nine percent for oil and eight percent for coal) before increasing at 1.5 percent per annum up to 2025. Prior to the crisis, the global gas supply surplus resulted in regional and international prices converging at historic lows. By reducing demand, the crisis forced prices even lower, resulting in strong incentives for short-term switching from coal and oil to gas where possible, but in the power sectors of many countries, this will be tempered by gas-to-renewables switching. To the extent that switching to gas is possible in non-power (especially industrial) sectors, where use of renewables may be more complicated, air quality improvement will be a powerful incentive. But widely anticipated national and global recessions means it is possible that any strong rebound of gas demand may be delayed. The impact of the energy transition on gas is also likely to be less severe, because of its lower carbon dioxide emissions compared with other fossil fuels. But fuel switching is a longer-term option in only a few countries— mostly in Asia—and will depend on whether much larger gas and LNG imports are considered acceptable in relation to energy security, and whether gas prices remain affordable in rapidly industrializing countries. Moreover, until methane emissions from pipeline and LNG value chains are measured with greater accuracy and independently certified, the greenhouse gas (GHG) footprint of natural gas will remain open to question. Gas prospects will be strongly related to the details of how individual countries and regions will be impacted by, and choose to adapt to, both the health crisis and the energy transition. This in turn will be determined by a combination of economic and policy impacts. The former will be principally governed by the price and availability of imported gas and LNG, and the latter by the priority which governments give to environmental issues: meeting netzero carbon-reduction targets which are more stringent than those set at COP21 (the 2015 UN climate summit), as well as targets for improvement of urban air quality. This article considers the crisis-related impacts on gas demand and international trade and investment, particularly in LNG projects, as well as longer-term transition impacts in relation to the major national and regional gas markets.

Since the COVID-19 pandemic began, the European Union Parliament and many member state governments have expressed continued commitment to the Green Deal, which dictates net zero emissions by 2050 and increases emission-reduction targets for 2030, and to the use of recovery funds to fulfill these aims. But Green Deal policies may encounter delays, and the immediate emphasis of recovery programs seems more likely to be on the power and transport sectors (acceleration of renewables and support for electric vehicles and associated infrastructure), which would have more immediate impacts on coal and oil demand. Retrofitting buildings for efficiency and lower-carbon energy would have a greater impact on gas demand, but probably on a longer time scale. Prior to the crisis, natural gas was seen as part of the transition by many European governments, but it was to be progressively replaced by “green gases” (biogas, biomethane and hydrogen) as those technologies evolve and their costs fall. Investments in green gas, particularly hydrogen-related technologies, are likely as part of recovery packages, but will have no significant impact on energy balances before 2030 (and may still be modest even by 2040). Increased carbon-based prices or taxes, which consumers may not resist (or may notice less) given current fossil fuel price levels, are likely to have a more immediate impact and become popular with governments needing additional revenues. The introduction of national, and eventually EU, border taxes on GHG (carbon and methane) content would create significant problems for gas imports with high methane emissions in the value chain (or which are unable to provide independent certification of their emissions). Indigenous gas production (Norway excepted) has been in long-term decline, and Europe will become increasingly dependent on imports. Some countries have used low-cost LNG to accelerate their drive to reduce dependence on Russian gas imports for political and security reasons, but the majority are allowing commercial logic to dictate their supply choices. Prices in 2020 have created even more bad news for European gas producers, who were already under pressure following the 2018 price downturn. This will accelerate the decline of UK gas production. Norwegian gas production and exports will reduce somewhat due to oil production cuts (as part of the OPEC+ agreement), and low prices will also delay new developments. In the Mediterranean, gas developments which looked marginal even at pre-2019 price levels will only progress if their destination can be regional countries (rather than European Union or global LNG markets). Outside Europe and some other OECD countries (particularly parts of North America and possibly Japan), the policy focus of the energy transition in relation to GHG emissions will be significantly less urgent given the crisis-related fall in emissions. Immediate reactions will be based more on the historically low international gas prices in 2020, which look set to continue into at least 2021. There will be no change to the US energy dominance and self-sufficiency policy. However, with Joe Biden’s election, federal policy on GHG emissions could change. In any case, state and city initiatives to pursue GHG reductions will continue. Meanwhile, coal to-gas switching, particularly in power, is supporting gas demand but, as elsewhere, this will be limited by growth in renewables. Investment in shale gas production has fallen sharply but will quickly pick up if gas and oil prices recover. In China, low-cost gas imports are helping to accelerate market liberalization, raising the possibility of third-party access to pipelines and LNG terminals. Tensions with the US have prompted a greater focus on domestic gas production and clean coal, but the crisis will highlight security-of-supply concerns around import dependence and how to maintain domestic production at a time of very low import prices. For India, low import prices are a particular benefit, since energy security is very much about minimizing fiscal deficits. In both countries, but especially in China, renewables are making significant progress, but coal development is also continuing, and the past two years have been negative for decarbonization. Indian private-sector gas production, which has been in long-term decline at low prices, is likely to collapse, while production by state-owned companies will fall, but not so dramatically. Air quality will also remain very important to promote gas, particularly for India, as coal-to-gas switching is already well advanced in China, and in both countries vehicle emissions may be an equally important focus. In summary, COVID-19 will cause a significant reduction in global gas demand in 2020, but a return to a range of 1.5–2.0 percent for the next several years is possible. The key region on which gas demand recovery depends is Asia—not just China and India but also Southeast Asia, which will be the principal locations of most coal-to-gas switching, and the Middle East, where switching to gas will be from liquids. The main immediate impact has been coal-to-gas switching due to low prices, but this was already the case before the crisis. Some of this switching may be temporary, depending on relative coal and gas prices, but in countries where the coal-fired power fleet is very old, it may be permanent.

The fall in gas prices and demand during the crisis means that all producing companies will have less money to invest in new developments. The fall in gas prices started well before the COVID-19 crisis and well before the fall in oil prices. Moreover, while it seemed possible by mid-2020 that the worst of the crisis’s impact on oil prices had passed, for the gas sector 2020 price levels for US Henry Hub (HH), European spot (TTF) and Asian spot (JKM) could continue for several years. This raises two interesting prospects: in Europe, that major suppliers (Russia, Norway, Qatar, and Algeria) may contemplate an informal arrangement to control volumes, particularly if European gas prices turn negative when storage becomes full; and in Asia, that a protracted global LNG surplus and very low spot prices could accelerate a move away from oil-linked long-term contract prices. The fall in prices combined with reduced demand expectations means that, Qatar excepted, investments in gas production and new projects will also fall, possibly very substantially, as projects are deferred. LNG projects which are under construction may be delayed for both logistical and financial reasons. Final investment decisions (FIDs) for new projects will be stalled until the demand and price outlook provides greater clarity. This is most likely to impact the many US (and some Canadian) LNG export projects, yet to reach FID, which may need to make significant changes to their business models to attract buyers and secure financing. In Australia, the crisis has caused A$80 billion of investments in gas and LNG projects to be deferred, although where there is co-production of oil or an expectation of selling LNG at oil-linked prices, some of these decisions may be more directly related to oil price levels. Some existing Australian projects need additional gas to maintain current export levels, and consequently exports may decline modestly in the early 2020s. The government has stated that it will not support climate policies that harm the economy or put jobs at risk, and as a result, it has expressed support for the expansion of the domestic gas market. Decarbonization has not been a significant policy driver in the Gulf countries. Although renewable-energy development is increasing (albeit from a low base in all countries other than the United Arab Emirates), the major impacts are likely to be seen after 2030. The crisis appears to have had little impact on Qatar’s plans for a huge expansion of LNG export capacity, although delays, principally for logistical reasons, are possible. A protracted period of low prices could create incentives to increase regional exports, but this would require improved regional political relationships, specifically a resolution of the rift between Qatar and its Gulf Cooperation Council neighbors. Other Gulf countries will reduce gas investments, with the possible exception of those building LNG receiving terminals to take advantage of low prices. In Russia, the government may use oil and gas investment support as a driver of general economic recovery, and rouble devaluation will soften some of the financial impact. Pipeline gas projects under construction will be completed, but the crisis could delay new Russian pipelines to China, while US sanctions are having a similar impact on the Nord Stream 2 pipeline to Europe. Extremely low European prices in 2020 resulted in sales to the Russian domestic market becoming more profitable than exports. But domestic prices have been frozen to support industry and prevent protests, and payment obligations for consumers have been relaxed as a way of absorbing excess domestic production. Although an official national strategy for low-carbon development to 2050 should be submitted to the Russian government later this year, the current draft suggests it will have minimal impact, and the economic and health crises will most likely further weaken any initiatives. In Russia, India, and Qatar, national oil and gas champions are likely to maintain and even increase their importance as private-sector and foreign investors pull back, leaving national companies as the major gas project investors using their govern ments’ reserve and stabilization funds. We can expect these governments to protect their national companies and use them to promote economic recovery. In China, new domestic private and international companies are likely to be allowed to enter the gas sector and may choose to do so given that demand is continuing to increase. In relation to longer-term strategies, the share of gas in the reserve portfolios of many national and international oil companies (IOCs) has increased over the past decade, and both groups of companies may see future gas investments as less risky than oil (given the potentially less certain future of oil demand under the energy transition). This can be represented as diversification until large-scale investments in non-fossil energy sectors become attractive. Portfolio players with large balance sheets will be able to progress new LNG projects without reliance on external finance. But the current global surplus and a potentially prolonged period of low gas prices may change the perceived attractiveness of such investments, particularly for IOCs experiencing much lower than anticipated returns on very large LNG projects which started operation in the second half of the 2010s. Aside from investments by energy companies and governments, it is unclear whether banks and hedge and pension funds will still be interested, and have sufficient liquidity, to invest in gas projects. Their decision-making criteria in relation to risk and return may favor expansion of existing, rather than new greenfield, projects. But it is possible that price volatility and politicization may increase the risk profile of projects to the point where the sector is no longer seen as an attractive future investment. The strategy of global LNG purchase and sale, which was highly successful in a market with significant regional price spreads, has far fewer commercial advantages in a market where regional prices are uniform and low. Until it can be anticipated that prices will increase significantly, and unless regional differentials then re-emerge, there will be very limited arbitrage gains from moving LNG around the world. This means that companies will need to “trade smarter” using sophisticated financial instruments that are more usual in oil markets. However, it also suggests that the globalization of gas will slow down and international trade, particularly of LNG, will not increase to the extent anticipated before the crisis.

Prior to the COVID-19 crisis, most models showed that under COP21 targets, global gas demand would continue to increase into the 2030s, and then fall increasingly rapidly to 2050. For countries that adopt netzero targets, the decline of natural gas, unless it can be decarbonized with carbon capture utilization and storage (CCUS), would need to start in the 2020s. In both cases natural gas could be considered a transition fuel, but net-zero targets dictate that the transition should start soon and have a much shorter duration. The question now is whether the COVID-19 crisis has changed the longer-term outlook. As we have already indicated, answers will differ significantly between countries and regions, and depend not just on gas but also on the development of zerocarbon alternatives and technologies. But the COVID-19 crisis will only significantly change the post-2030 outlook for gas if government recovery packages are directed towards the development of hydrogen or electrification at the expense of gas, to a greater extent than was already anticipated. In countries that already have a gas market, most studies find that a mix of electrification and gas will be a much lower-cost option to achieve decarbonization targets than electrification alone. Lowest cost will probably mean maintaining gas network infrastructure even if this needs to be converted to carry hydrogen, which will need to be available at scale for use in the industrial—and in some countries the residential, commercial, and electricity—sectors. In order to scale up rapidly, hydrogen will need to be derived from reformed natural gas with CCUS, with the anticipation that these will be replaced by large volumes of hydrogen from electrolysis of renewable energy after 2040. A key question is when the global supply/demand balance will tighten and create signals for the next price cycle. With most new international gas and LNG projects having delivery costs of at least $6/MMbtu (and a profitability comfort zone of closer to $8/MMbtu), investments particularly in new greenfield projects will be a significant problem. In addition, with only 20–30 years before it needs to be phased out (depending on policy commitments), large new natural gas infrastructure may not be feasible unless it is hydrogenready. Initially this will be fossilbased hydrogen plus CCUS, but if it is to become a large-scale energy source, the majority of hydrogen will need to come from renewable electricity. This is particularly important for large-scale pipeline exporters to European countries committed to net zero emissions, where new infrastructure investments will need to be either amortized prior to phaseout or converted to decarbonized gas, a transition which needs to start by 2030. LNG exporters will have greater market flexibility, but those planning new projects need to be aware that an energy transition which meets even COP21 targets would mean that, by the 2040s, they would face similar demands from the majority of their customers.

Tatiana Mitrova is Director of the Energy Center of Skolkovo Business School, Senior Research Fellow in the Oxford Institute for Energy Studies, and Scientific advisor at the Energy Research Institute of the Russian Academy of Sciences.

Jonathan Stern, Distinguished Research Fellow of the Natural Gas Research Programme, founded the OIES Natural Gas Research Programme in 2003 and was its Director until October 2011 when he became its Chairman and a Senior Research Fellow. He became a Distinguished Fellow in October 2016.