2020: Meltdown

Uncharted macroeconomic territory

The coronavirus (Covid‑19) pandemic has triggered an unprecedented macroeconomic shock. At the time of writing (early June 2020), the World Health Organization reported over 6.2 million confirmed cases, affecting almost 200 countries and territories to varying extents. Governments across the world have been reacting to the situation by enforcing different degrees of restriction on most social and economic activities. As a consequence of the containment efforts to slow the spread of the virus, 4.2 billion people or 54% of the global population, representing almost 60% of global GDP, has been subject to complete or partial lockdown. Nearly all the global population is affected by some form of containment measure.

The restrictions represent a challenging combination of macroeconomic shocks in both supply and demand. The supply shock component arises from the intentional constraints on economic activity: restaurants, shopping malls and, in some countries, factories are closed down to prevent the spread of the virus which have caused historically unprecedented spike in unemployment in every country. The demand-side shock is arising from the impact on mobility as well as on consumer disposable income and corporate investment activity. Overall, estimates suggest that economies can expect a 20–40% decline in economic output during the lockdown phase, depending on the share of the most-affected sectors and the stringency of measures. At the global level, this translates into a 2% drop in expected annual GDP for each month of containment measures.

This report uses the scenario-based approach developed in the IEA Global Energy Review 2020 report. A base scenario quantifies the impact on natural gas demand of a widespread global recession caused by multi-month restrictions on mobility and social and economic activity. This base scenario – where recovery is only gradual and accompanied by a permanent loss of economic activity – is broadly in line with the “pessimistic scenario” of the IMF World Economic Outlook April 2020 update, where the world struggles with a prolonged first outbreak period leading to a global GDP contraction of 6%.

Global annual change in real gross domestic product (GDP), 1900-2020


European gas markets are facing a perfect storm…

European gas markets have been facing a perfect storm since the beginning of 2020. The successive impacts of mild temperatures, strong wind generation and Covid‑19 induced nationwide lockdowns have depressed natural gas consumption, which fell by 7% y‑o‑y in the first five months of the year.

Under the weather

Europe experienced a mild winter in 2019/20: heating degree days fell by over 5% across its main gas-consuming regions compared with a year earlier, consequently cutting space-heating requirements. Gas demand in the residential and commercial sectors decreased by more than 3% y‑o‑y during Q1 2020.

Falling gas prices supported further coal-to-gas switching in Europe’s power sector during the first quarter, with the share of gas-fired generation in thermal generation increasing from 45% to 49% at the expense of both coal and lignite. However, strong wind power generation during Q1 weighed on thermal generation requirements, including gas-fired power. Preliminary data suggests that while wind power output increased by over a third (or 30 TWh) y‑o‑y, gas-fired generation fell by 10 TWh, depressing gas demand by an estimated 2.5 bcm. Contrary to the rest of Europe, Turkey’s gas-fired power generation grew by an impressive 35% in January and February, amid falling lignite-fired power generation and lower hydro output, before plummeting by over 40% in March as hydro recovered. 

Under the lockdowns

The implementation of nationwide lockdowns in several European countries resulted in a sharp drop in natural gas consumption, falling by 11% between the start of the lockdowns (11 March) and end of May, translating into a 10 bcm drop in absolute terms.

This drop has been primarily due to lower demand from the industrial and power generation sectors, while distribution network consumption was less affected – residential consumption benefitted from colder temperatures in the second half of March, but declined in April and May due to lower heating degree days and decreasing activity in the service sector.

European electricity consumption decreased by 12% between 11 March and end of May, severely weighing on gas-fired power generation, which fell by over 20%, equivalent to an estimated 5 bcm of lost gas use. This has been largely driven by Europe’s two largest consumers of gas-fired electricity, Italy and the United Kingdom, where gas-fired generation dropped by 25% and 36% respectively between early March and end of May. In Turkey, where electricity consumption fell by 15% during April and May, gas-fired power generation practically halved during that period.

Industrial gas demand in the countries imposing stricter lockdown measures (Belgium, France, Italy, Spain and the United Kingdom) fell by over 15% y‑o‑y (above 1 bcm) from March to May.

…with consumption declining by 7% in the first five months of 2020

Y-o-y change in natural gas consumption per sector for a selection of European countries from first day of lockdowns until end of May, 2020


Evolution of European natural gas consumption, 2019 and 2020


Consumption remains resilient in North America, thanks to US coal-to-gas switching in power generation

US natural gas consumption decreased by 2.8% y‑o‑y for the period from January to May 2020. This was a rather limited decline in spite of mild temperatures throughout the first quarter and the imposition of lockdown measures in most states in March. Adjusting for temperatures, consumption grew slightly at 0.4% for the same period.

Warmer than average temperatures during winter 2019/20 had a strong impact on heating demand, resulting in a 14% y‑o‑y drop in natural gas consumption in the residential and commercial sectors for the first quarter. Lower heating demand also hit electricity consumption, which declined by about 5% over the same period. However, natural gas-fired power generation increased during the winter in spite of lower demand, helped by low fuel prices and additions of new combined-cycle capacity in 2019. Natural gas-fired generation grew at the expense of coal, with fuel switching occurring even in traditional coal-driven markets such as the Midwest, where the share of natural gas rose to the same level as coal during the first quarter, and became the dominant source of electricity generation in April.

The outbreak of Covid‑19 led to the imposition of lockdown measures in most US states, enacted during the second half of March. At the end of April only five states had few to no restrictions, states progressively reopening in May (some 31 states had lifted most of their restrictions as of end of May). In spite of the substantial impact of lockdowns on economic activity, natural gas demand remains relatively resilient, increasing slightly by 0.5% between mid-March and end of May compared with 2019. Consumption in the industrial sector, which was comparable to 2019 until mid-March, declined by 3.6% y‑o‑y in between mid-March and mid-May. This decline was offset by the power generation sector, up by 3.4% y‑o‑y over the same period, and by some gains in residential and commercial use (up 1.5%).

Natural gas demand in Mexico fell by an estimated 5% y‑o‑y during the first quarter, impacted by slow economic activity that drove down demand from the industrial and power generation sectors. Pipeline flows from the United States – the largest source of imports – grew by 6.5% y‑o‑y over the first five months. The introduction of nationwide emergency measures in April coincided with a slowdown in pipeline imports (up by 2% in April following an increase of 15% in March, y‑o‑y, and down 4% in May). LNG imports halved over the first five months of the year compared with the same period in 2019.

Y-o-y change in US natural gas consumption per sector since 1 January, 2020


Evolution of weekly US natural gas consumption, 2019 and 2020


Apparent consumption continued to grow in most Asian markets over Q1 2020, but impacts have started to become visible

In spite of reduced economic activity, the impact of the Covid‑19 crisis on demand growth remained limited for major Asian gas importers during the first quarter of 2020. However, stable or growing imports in some cases compensated for declines in domestic production or added to a build-up in storage levels.

China experienced sluggish growth in gas demand in the first months of 2020, negatively affected by mild temperatures in January and the introduction of lockdown measures in February. According to the National Reform and Development Commission (NDRC), apparent gas consumption increased by 1.6% y‑o‑y in the first quarter of 2020. The progressive restart of industrial activity in March and April had a limited impact on gas use as lockdowns in other parts of the world sharply reduced demand for exported goods. Preliminary data from the Chongqing Oil and Gas Exchange suggest that after a rebound in March, demand grew by 3.8% y‑o‑y in April, principally thanks to city gas demand (up 15.8% y‑o‑y). Consumption in the industrial sector decreased by 6.7% y‑o‑y. First estimates for May indicate a limited y‑o‑y demand increase, close to 1%.

Japan, the world’s largest LNG importer, saw its imports decrease by close to 5% y‑o‑y over the first five months of 2020, affected by warmer than usual weather, slower economic activity and the decreasing share of natural gas in the country’s electricity mix.

Korea’s LNG imports increased by about 14% y‑o‑y during the first five months of 2020, though state-owned incumbent KOGAS reported a 4% drop in domestic sales over the first quarter, and a 17.4% fall in April. However, the impact of reduced economic activity was partly offset by gains in power generation in March, supported by temporary shutdowns of 60 coal-fired plants to reduce air pollution. KOGAS reportedly asked for deferral of LNG cargoes scheduled for the second quarter, citing high inventory levels due to reduced domestic demand caused by Covid‑19 impacts on economic activity.

Natural gas consumption in India rose by an estimated 10% y‑o‑y during the first quarter of 2020. However, the introduction of a nationwide lockdown on 25 March led to a sharp and immediate decrease in demand. Preliminary data indicates that gas consumption was down by 25% yoy in April, with small industry and CNG distribution for transport being the hardest hit, while gas-fired generation was up 14% in spite of a 24% fall in electricity demand, as cheap imported natural gas was used to meet peak demand. The progressive lifting of restrictions in May has allowed chemical plants, factories and downstream industries to restart, leading to a rebound in gas consumption. State-run operator GAIL reported a 50% jump in sales in between the first week of lockdown and mid-May, although still below pre-lockdown level. Demand for fertilisers, the largest component of India’s natural gas consumption, started to recover gradually ahead of the sowing season, with some plants restarting since late April.

LNG imports into other Asian markets collectively increased by 7% y‑o‑y during the first five months of 2020. However, this growth may also mask supply-side adjustments. In Bangladesh, state-owned Petrobangla reported cuts to domestic production in April to offset an average 30% drop in consumption since the implementation of a nationwide lockdown.

Pakistan is one of the few emerging Asian markets where LNG imports actually declined over the first five months of 2020, falling by almost 14% y‑o‑y. Network operating companies reported a 50% drop in daily consumption as of early April compared to monthly operational forecast. A number of factors contributed to this sharp decline, including lower electricity demand and higher hydropower production which cut gas-fired power generation by half. As well, plant closures reduced industrial gas demand by 50% relative to the forecast, and restrictions on transport pushed CNG demand to 65% below projected levels.

The Covid‑19 outbreak hit domestic demand in major gas-producing countries across Asia. Indonesia’s state electricity company PLN estimated that consumption has fallen on average 9.7% y‑o‑y for year 2020 to date, and the government introduced a cap on natural gas prices for electricity generators and several industrial sectors in early April to support economic activity. In Thailand, where natural gas accounts for 60% of electricity generation, the government introduced a range of electricity bill subsidy measures to support electricity consumption in late April. These relief measures were introduced retroactively for three months to the end of May 2020. Malaysia has also introduced an electricity bill discount scheme for six months, eligible to both residential and industrial customers.

Natural gas consumption in major Asian markets


2020 is on its way to experiencing the largest recorded demand shock in the history of global natural gas markets

Global natural gas demand could fall by about 150 bcm/y or 4% y‑o‑y in 2020, based on our broad assumptions for the year and latest market observations. The decline in demand has been revised from the initial 5% estimate published in the Global Energy Review 2020 report, and is based on revised Q1 data and market observations from the two first months of Q2.1 The magnitude of the impact remains however unprecedented: this would be the largest recorded annual decrease in consumption since the natural gas market developed at scale in the second half of the 20th century, and the drop would be twice bigger than the latest downturn in 2009, when natural gas demand fell by 2%. Natural gas consumption is expected to fall in every sector and region in 2020, but most of the declines are in mature markets and power generation.

Geographically, the bulk of consumption decline is expected in mature markets across Europe, North America, Eurasia and Asia, which would together account for 75% of total demand loss in 2020. These markets concentrate most of the loss in residential and commercial consumption, resulting from the joint impact of lower space heating needs in the first months of the year, followed by the implementation of lockdowns weighting on consumption from the commercial sector. Gas-fired generation is particularly hit in Europe, squeezed in between lower electricity demand and growing renewable output. The volumetric impact is less important in emerging markets, due to the lower share of natural gas in power generation (apart from the Middle East) and marginal role of space-heating use.

Sector wise, our projection sees consumption for power generation drop by around 5% y‑o‑y, accounting for half of the decrease in global demand. Gas use in the residential and commercial sector falls by close to 4% globally – mainly in the abovementioned mature markets – and accounts for 20% of total consumption loss. The industrial sector also accounts for close to 20% of the global decrease, dropping by about 4% y‑o‑y in 2020. In addition to the direct impact of reduced activity during lockdowns, natural gas demand from industry is further dampened by the slowdown in consumer spending for manufactured goods, which affects gas use in export-driven economies (especially in Asia). The energy sector itself accounts for around 10% of the fall in global gas demand, dropping by 4% y‑o‑y. This reflects the overall decline in global supply, which reduces gas needs for upstream operations, as well as for energy transformation (refining) and transportation (pipeline gas compression). 

Demand loss could reach 150 bcm, hitting mainly mature markets and power generation

Natural gas demand decline per sector, 2019-2020


Natural gas demand decline per region, 2019-2020


The impact of lower demand is not (yet) fully visible in supply indicators

Supply-side indicators are sending mixed signals on the initial months of 2020, with US domestic gas production and global LNG supply still increasing compared to 2019, while Russian production and European imports show some decline.

US natural gas production increased by 5.3% y‑o‑y on average from January to the end of May in spite of lower domestic consumption, which dropped by 2.8% over the same period due to the joint impacts of warmer than average temperatures and the introduction of lockdowns in multiple states. This relative resilience in domestic production was offset by adjustments to the US gas trade balance: net pipeline imports from Canada declined by 11.1% y‑o‑y January to May, while pipeline exports to Mexico grew by 6.6% and LNG exports almost doubled. At end of May, daily dry gas production was close to its previous year level.

Russian gas production fell by over 9% y‑o‑y (or 30 bcm) in in the five first months of 2020. This results from lower pipeline export volumes to Europe, and lower domestic consumption amidst a particularly mild winter (heating degree days were down by 15% y‑o‑y through the heating season).

LNG trade volumes remained high in the first five months of 2020, up 8.5% y‑o‑y. Europe continues to play the role of balancing market in a context of loosening supply, accounting for two-thirds of incremental LNG imports since the beginning of the year, amid subdued demand growth in Asia. Asian imports fell in April close to its 2019 value, as the sharp drop in Indian imports caused by the country’s lockdown further exacerbated the traditional lower demand from Japan and Korea at the end of the heating season – this being partly offset by a uptick in China’s imports after two months of lower LNG demand. China and India’s imports grew in May, supporting the modest m‑o‑m increase in global LNG trade as European flows remained stable.

In spite of its plummeting gas demand, European LNG imports increased by above 20% y‑o‑y over the first five months of the year to 60 bcm, thanks to its ample regasification capacity and flexible pipeline supply sources. The United States became the largest source of LNG supply to Europe, overtaking Qatar and Russia, and accounting for over 25% of Europe’s LNG imports. The LNG influx into Europe primarily weighed on the import flows of traditional pipeline suppliers: imports from Russia and North Africa both decreased by about 25% and Norwegian flows fell by 4% y‑o‑y in the first five months of the year. Overall, natural gas flows to Europe (including both LNG and pipeline gas, notably Norwegian pipeline flows) fell 9% y‑o‑y in the first five months of 2020.

Supply-side indicators are sending mixed signals about the initial months of 2020

Russian dry gas production, January to May, 2018-2020


US dry gas production, January to May, 2018-2020


European gas imports, January to May, 2018-2020


Global LNG trade, January to May, 2018-2020


Global gas benchmark prices are searching for new lows…

The combination of continued strong supply growth, mild winter temperatures and the imposition of Covid‑19 related lockdowns pushed natural gas prices to lows not seen in over a decade across all major consuming regions.

In the United States, Henry Hub prices in Q1 2020 fell by over 33% y‑o‑y to an average of USD 1.9/MBtu, its lowest quarterly price level since 1999. Prices continued to face downward pressure from growing supply (7% y‑o‑y) and subdued demand due to mild weather conditions, falling to an average of USD 1.75/MBtu in May.

In Europe gas prices on TTF more than halved compared to last year, averaging at USD 2.60/MBtu during the first five months of 2020, impacted by plummeting demand and strong LNG influx.

Since the imposition of the first lockdowns at the beginning of March, prices on TTF fell further to USD 1.50/MBtu in May – their lowest monthly average since the Dutch hub was established in 2003 – with day-ahead prices seen trading below the USD1/MBtu mark during mid-May.

Asian LNG spot price assessment halved y‑o‑y during the first five months of the year to an average of USD3/MBtu. Following the imposition of the lockdowns in India, Pakistan and Bangladesh in March, spot prices have fallen to new historical lows, with month-ahead contracts trading at an average of USD 2/MBtu.

The tightening price spreads between global gas benchmarks is practically closing the opportunity for any inter-regional arbitrage and potentially resulting in negative netbacks for certain suppliers.

Natural gas prices are expected to remain depressed through the summer, amid a bleak demand outlook, high storage levels and continued growth in LNG supply from newly commissioned liquefaction projects. The current forward curve suggests that TTF could trade at a discount to Henry Hub through the summer months, reflecting an expected persistent oversupply. Prices are expected to start to recover at the beginning of the heating season, as increasing demand tightens the market and eventually leads to a renewed decoupling of global spot prices.

It is important to highlight that oil-indexed LNG contract prices did not experience large falls during the first quarter of the year. Given their predominance in the import portfolios of Asian LNG buyers, the weighted average LNG import price of China, Japan and Korea only decreased by just over 15% y‑o‑y in the first four months of 2020, to USD 8.8/MBtu.

However, the persistence of low oil prices since early March should have a significant impact on oil-indexed LNG contracts prices by Q3/Q4 of the year, as low oil prices filter through the price-setting reference period, usually between 3 and 6 months ahead. Current forward curves suggest that oil-indexed LNG prices could halve by the beginning of Q4 to a range of USD 4-5/MBtu. European supply is much less impacted by oil price dynamics as most of its pipeline and LNG imports are indexed on hub prices.

…tightening up price spreads and weighing on arbitrage opportunities

Evolution of main spot and forward gas prices, 2020


Strong storage build-up reduces injection needs during 2020 summer season

The growth in supply outpaced incremental gas demand through 2019, resulting in a particularly strong storage build-up. In the United States strong net injections during April–October (36% above the 5-year average) and low withdrawal rates through the winter resulted in inventory levels 19% (or 12 bcm) higher than their 5-year average at the end of May. Europe saw strong injections through the summer, combined with an unseasonably mild winter and continuation of strong LNG influxes. This led storage sites to close the heating season 55% full and
25 bcm above their 5-year average.

As of end of May, European working gas storage capacity was over 70% full, with less than 30% remaining spare capacity. Should injection rates continue at the same pace as observed in April and May, incentivised by seasonal price spreads, European storage capacity could be saturated before the end of the injection season. Strong LNG supplies resulted in an LNG storage build-up in Japan and Korea, with closing stocks standing 17% above their 5-year average at the end of March.

European underground storage inventory, 2017-2020


US underground storage inventory, 2017-2020


Japan and Korea LNG storage inventory, 2017-2020

  1. These include among other higher fuel switching in power generation and greater resilience of industry consumption in the United States, a lesser than expected impact on European total consumption during the lockdown phase, and lower downturn in China’s demand during and after the lockdown phase.