Demand - After a 4% drop in 2020, natural gas demand is expected to progressively recover in 2021 as consumption returns close to its pre-crisis level in mature markets, while emerging markets benefit from economic rebound and lower natural gas prices. The impact of the 2020 crisis is, however, expected to have repercussions on the medium-term growth potential, resulting in about 75 bcm of lost growth over the forecast period, 2019 to 2025. This forecast expects an average growth rate of 1.5% per year during this period.

The Asia Pacific region accounts for over half of incremental global gas consumption in the coming years, driven principally by the development of gas in China and India. While the prospects of natural gas remain strong for these two markets, the outlook is highly dependent on China’s and India’s future policy direction and recovery path in the post-crisis environment. In spite of the current economic headwinds and uncertainty, natural gas still benefits from strong policy support in both countries, with ongoing reforms to increase the role of gas in the energy mix. Future growth in the industry sector, which constitutes the main driver of incremental gas demand in both countries, will however highly depend on the pace of economic recovery, both for domestic and export markets for industrial goods.

Supply – If almost all regions are expected to contribute to the growth in natural gas production in the next five years, half of the net increase in supply comes from North America and the Middle East. The US shale industry, the main driver of global gas output growth over the recent years, is particularly vulnerable in the current crisis context – the IEA report World Energy Investment 2020 estimates that upstream spending on shale tight oil and gas is set to decline by 50% y‑o‑y in 2020. The sector’s ability to rebound in a post-crisis environment will be pivotal to deliver the incremental gas production needed by the US market to replace its declining conventional production and supply its additional LNG export capacity under development. Production growth in the Middle East is driven by the ramping up of large conventional projects in Saudi Arabia, Iran, Israel, Iraq and Qatar – for which the oil price collapse and uncertainty represent a substantial downside risk in the first years of the forecast. Gas production in Russia, the other large contributor to incremental supply, is almost entirely driven by export-oriented projects; while most of the additional production is expected for the second half of the forecast, shorter-term uncertainty on demand growth could negatively impact its development schedule. 

Trade – LNG remains the main driver of international gas trade, as the 2018-19 wave of investment in liquefaction projects delivers additional export capacity in North America, Africa and Russia. However slower growth in gas demand post-2020 results in liquefaction capacity additions outpacing incremental LNG import through 2025, thus limiting the risk of a tight LNG market over the forecast period. China, India and emerging Asian markets account for most of the growth in future LNG imports, while Europe should return to its pre-2019 levels after reaching record levels as a balancing market. Additional pipeline trade comes principally from the progressive ramp-up of export infrastructure from Eurasia (TANAP and TAP to Europe, and Power of Siberia to China).

We have adjusted this year’s forecast to account for Covid‑19 resulting in expected global natural gas demand reaching over 4 370 bcm annually in 2025, or an average annual growth rate of 1.5% per year for the 2019-25 period, compared to initial forecast which assumed an average growth rate of 1.8% per year over the same period.

Even if most of the 2020 losses are to be recovered in 2021, the Covid‑19 crisis has longer-lasting impacts on natural gas demand growth. This results in about 75 bcm/y of lost growth over the forecast period – more than the equivalent of incremental demand for 2019.

Most of the gas demand lost in 2020 is expected to be recovered in 2021, supplemented by growth from the Asia Pacific region, as China and Asian emerging markets recover economically and benefit from attractive gas prices. Mature markets in Europe, Eurasia and North America, which were the hardest hit in 2020, are expected to recover most of their consumption losses in 2021 as demand from the industrial and power generation sectors gradually returns. Some marginal gains are also expected from coal-to-gas switching, helped by low gas prices and ample supply, while residential heating demand is assumed to return to normal after an exceptionally mild winter in 2019/20. Additional growth comes from faster-growing markets in the Asia Pacific region (and to a lesser extent in the Middle East), fostered by the economic rebound and competitive gas prices. The return to growth in global gas and oil demand also drives consumption from the energy sector in gas-producing and exporting regions (such as Eurasia, the Middle East and North America).

Further growth during the 2022-25 period is mainly driven by fast-growing Asian markets. The Asia Pacific region accounts for over half of incremental consumption from 2022, led by China and India. Additional demand in the Middle East (about a quarter of the total increase) is primarily driven by large gas-producing markets such as Saudi Arabia and Iran. Most of the residual growth occurs in Africa and North America, coming from domestic market needs and export-driven energy sector demand.

Our outlook sees Asia remaining the primary driver of global demand growth, with China, India and emerging Asia together accounting for over half of the net increase in 2019-25. China is the single largest contributor, led by the industrial sector. India’s post-2020 growth is fuelled by a combination of supportive government policies and improved infrastructure, while emerging Asia’s demand expansion is power sector-driven, underpinned by the addition of 15 GW of gas-fired generation capacity across the region.

Gas consumption in North America grows at just 0.4% annually in the forecast period, mostly thanks to growth in industrial consumption in the United States. Mexican gas consumption grows at a moderate clip of 1.3% annually, in line with new gas-fired power generation. Canadian demand grows at similar rates annually, largely a result of an increase in industrial consumption for process energy and for use as a feedstock. Despite Canadian coal phase-outs, the forecast presents limited growth in gas-fired power generation due to increases in renewable generation.

European gas demand is expected to remain stable through the forecast period. In the power sector, the gradual phase-out of over 50 GW of nuclear-, coal- and lignite-fired power generation capacity creates additional market space for gas-fired power plants. However, growth is limited by the rapid expansion of renewable power generation, set to increase by almost 30% over the medium term. Natural gas demand in industry is expected to recover to its pre-crisis levels, while further growth potential remains limited.

Natural gas demand in Eurasia grows by 0.5% per year between 2019-25, limited by the modest economic growth prospects of the region and the already very high gas-intensity of those economies. The industrial sector alone will account for almost half of incremental gas demand, driven primarily by chemicals and fertilisers, benefitting from the relatively low feed gas costs in the region. Energy industry own use is expected to grow at an average rate of 3% per year, driven by the region’s export-oriented growth in gas production.

Middle East gas demand increases by nearly 100 bcm/y and reaches almost 660 bcm/y by 2025. The largest increments come from Iran and Saudi Arabia (accounting for up to 70% of the total consumption increase), supported by growing domestic supply availability. More than 60% of the net demand increase in the region is from the power and water desalination sectors.

Natural gas consumption in Central and South America is expected to grow at an average annual rate of 0.6% over the forecast period, adding about 5 bcm/y by 2025. Demand growth is led by the power sector, both in terms of volume and rate of growth, with an annual growth rate of 1.1%, driven by growing electricity demand and fuel switching.

African natural gas consumption grows at an average of 3.3% per year to reach almost 195 bcm in 2025. It remains primarily driven by industrial and power generation needs in North Africa’s major markets of Algeria and Egypt, followed by Nigeria. The development of domestic production in West African countries drives the sub-region, which sees an average 6% growth rate per annum (excluding Nigeria), but the overall size of the market remains limited at about 14 bcm per year in 2025.

Gas consumption by industrial uses is the main contributor to demand growth to 2025, increasing at an average rate of 2.5% per year and accounting for 40% of incremental consumption. Additional demand for gas as a fuel for industrial processes principally comes from China, India and other Asian markets, while demand for gas as a feedstock is driven by gas-rich countries and regions such as the United States, Russia, North Africa and the Middle East, for manufacturing fertilisers and petrochemicals for both exports and domestic markets.

Growth from the power generation sector is expected to average 1.3% per year during the forecast period (much lower than the average 2.6% observed over the past decade). Demand growth loses speed in mature markets as additions of renewables capacity further reduce the space for thermal sources, while the bulk of coal-to-gas switching has already taken place. In faster-growing markets, the role of gas in power generation remains challenged by fuel cost competition as well as the emergence of renewables.

In the residential and commercial sectors, higher demand from the development of city gas distribution is seen in a handful of countries – China, India, Russia, Iran and Algeria. This is partly offset by structural decline in mature regions and lack of growth potential in most emerging areas where heating needs are limited.

Gas as a transport fuel is expected to grow at an average rate of 2.6%, principally driven by Asia with the growing use of LNG for trucks and river transport. This forecast assumes a tenfold increase in LNG as an international maritime fuel, reaching over 10 bcm by 2025, principally for us in container ships.

Industrial consumption of gas for chemical feedstock application is forecast to increase at an annual rate of 3.4%, thanks mostly to new fertiliser and methanol projects.

Gas-to-chemicals projects manufacture specialised products, including methanol, ammonia, ammonium nitrate, urea and other high-value chemicals. Fertiliser represents the greatest growth sector among feedstock uses over the forecast period, increasing by 3.5% annually to reach over 100 bcm in 2025. Production in India shows the largest increase, with urea production rising to 30.1 Mtpa by 2025, supported by government subsidies for the fertiliser sector and the objective of reducing dependence on imported urea. Fertiliser growth in Pakistan and Bangladesh also support this trend.

The United States leads growth in feedstock use for methanol. Developers have been attracted by low US gas prices following the country’s rapid increase in production. Globally, consumption for methanol feedstock represents over 30% of the growth in this industrial sub-sector.

Eurasia accounts for 15% of global gas consumption in the petro- and agrochemical sectors. Around half of the region’s industrial demand is consumed as a feedstock, also benefitting from relatively low gas prices (below USD 2/MBtu in 2019). In our forecast, gas demand in the chemical sectors grows at a rate of 3% per year, primarily led by Russia, which accounts for over 60% of the region’s growth.

Biomethane production is expected to continue to grow at an impressive rate of 12% through the forecast period to reach 10 bcm by 2025. Reflecting the pipeline of biomethane projects, this growth is primarily driven by Europe and North America, which benefit from well-developed and interconnected gas grids.

Global biomethane production, 2019-2025

The Covid‑19 outbreak triggered an unprecedented oil demand shock, resulting in a 40% decline in oil prices over the first quarter of 2020. Operators report oil production curtailment in excess of 1 million barrels per day in May and June 2020, mostly from the Permian and Bakken producing areas. US crude production is estimated to fall by 2.4 mb/d by year-end compared with 2019. The risk prolonged curtailment poses to gas production depends on the characteristics of the producing wells. In 2019 almost 30% of US gas production (230 bcm) was produced as a secondary product from oil wells in areas such as the Permian basin. Just over 20% of this gas comes from wells with a break-even price above USD 30/bbl WTI (December 2020). At USD20/bbl WTI, only 55% (126 bcm) can be produced economically.

Revisions to 2020 CAPEX guidance show oil and gas operators have responded to changing market conditions, where we estimate a y‑o‑y fall in investment of around one-third. This has already triggered an increase in borrowing as well as the likelihood that restrained spending will continue well into 2021. Prior to the oil demand shock, the gas play horizontal rig count in the United States had already plummeted by almost 50% versus its June 2019 peak, all in the midst of weak gas prices.

With a protracted low oil price, producers will need to look beyond the Permian basin to make up for a shortfall in associated gas production to service domestic demand and export need. In the short term, plays like the Appalachian basin and Louisiana’s Haynesville shale would need to compensate with a production increase, depending on greater domestic price strength. Even so, a period of rapid growth may test constraints of infrastructure, labour and capital, which had seemed sufficient before the fundamentals shifted. In these conditions, a geographic shift in gas production and operator strategy may be observed if gas demand remains steadfast. At higher prices, a recovery in associated gas in the Permian and other locations could be rapid, but a considerable portion of the short-term projected growth in gas production from the play has been discounted. 

Although details concerning short-term outcomes of this reduction are uncertain, by 2025 annual US production is forecast to reach over 1 030 bcm, increasing by 1.2% annually over the period. Additional supply is mostly needed to service new LNG export capacity set to enter service over the coming years.

Russia is expected to be the second-largest source of incremental gas supply, after the United States, through the forecast period, accounting for just over one-fifth of global growth between 2019 and 2025. Production growth, at a rate of 1.7% per year, is almost entirely driven by export-oriented projects, further solidifying Russia’s position as the world‘s largest natural gas exporter. This is accompanied by continued diversification away from Russia’s traditional gas-producing region, Nadym‑Pur‑Taz, caused by its maturing and gradually depleting fields.

In Western Siberia, Gazprom continues to develop the Yamal production centre, with the giant Bovanenkovo field expected to reach its nameplate capacity of 115 bcm/y by 2022 and with the start-up of the Kharasavey field in 2023, reaching 32 bcm/y production by 2026. Supplies via the Bovanenkovo–Ukhta pipeline corridor are due to supply both domestic consumers and the European export market.

The Arctic LNG-2 project reached FID in September 2019, with a total nameplate capacity of bcm/y. The first two trains are expected to be commissioned in 2023 and 2024, supplied with feedgas from the Utrenneye field, located in the northern part of the Gydan peninsula.

In Eastern Siberia, the Power of Siberia pipeline system started commercial deliveries into China in December 2019 and should reach the full contracted capacity of 38bcm/y in 2025. Gas supplies are scheduled to be supported by the Chayandinskoye and Kovytka fields located in East Siberia, which reach their 25 bcm/y nameplate capacity by 2024 and 2025 respectively.

Global LNG trade is expected to reach 585 bcm/y by 2025, an increase of 21% compared to 2019. Emerging Asian markets remain the driving force behind the expansion of LNG imports, led by China and India, while the United States accounts for almost all of the net growth on the export side. LNG trade is expected to increase at a slower rate than liquefaction capacity additions, thus limiting the risk of a tight market over the forecast period. 

The Asia Pacific region further increases its share of total LNG imports, from 69% in 2019 to 77% by 2025. China alone accounts for 22% of total LNG demand in 2025, contributing almost 40% of growth in total imports over the forecast period. India also leads LNG growth accounting for about 20% of incremental trade, and sees its imports increase by 50% between 2019 and 2025 to support strong growth in demand. Bangladesh and Pakistan, two more recent LNG buyers, also experience strong import growth rates to support their increasing consumption and offset the decline of domestic production. South East Asian markets also increase their imports to supply the development of new import capacity in Thailand and Viet Nam.

Europe remains the main importing market after Asia, as LNG offers a source of diversification of supply in the context of declining domestic production. After reaching record levels in 2019, the region having played the role of balancing market to absorb oversupply, European imports are expected to return to an average of 90 bcm/y throughout the forecast period (25% above the average import level of the past five years). Contributions from other regions – Africa, Central and South America, the Middle East and North America – are expected to remain stable.

On the supply side North America is almost the sole source of growth, accounting for close to 80% of additional exports between 2019 and 2025. North American exports are expected to almost triple in the next five years, driven by the wave of recently sanctioned US liquefaction projects, as well as the commissioning of Canada’s first export project by the end of the forecast period.

Africa accounts for most of the residual growth in exports, sourced from projects under development in Mozambique (Coral FLNG, Mozambique LNG), capacity expansion in Nigeria (NLNG train 7) and a cross-border offshore project in Mauritania and Senegal (Tortue FLNG).

Russia’s LNG exports are set to increase by almost 20% by 2025, driven by capacity development from the Yamal peninsula. Supply from the Middle East should remain stable based on Qatar’s current1 export capacity, as are LNG exports from the Asia Pacific region, with Australian exports plateauing and output from traditional exporters such as Indonesia and Malaysia decreasing slightly.

FIDs taken in the recent years lead to a strong uptick in LNG liquefaction projects, which is expected to add up to 120 bcm/y of export capacity in between 2020 and 2025 – or an increase of 20%. Slower growth in natural gas demand is likely to weight on average utilisation rates of liquefaction plants, creating a situation of overcapacity as liquefaction growth outpaces incremental LNG trade, thus limiting the risk of a return to a tight market before 2025. Such a situation would leave some LNG players with growing net selling positions and sunk costs, which would in turn exacerbate competition among suppliers – both in the context of renewal of expiring contracts and for the development of new markets in emerging regions.

China to cement its position as the largest natural gas importer

China widens its lead as the world’s largest natural gas importer during the forecast period, with combined pipeline and LNG imports increasing from 134 bcm/y to 210 bcm/y in 2019-25. The country also overtakes Japan as the world’s largest LNG market within the next five years: China’s LNG imports are projected to reach 128 bcm/y by 2025 thanks to the continuing expansion of the country’s regasification capacity. Its pipeline gas imports also increase by more than 30 bcm/y due to the scheduled ramp-up of Russian deliveries through the Power of Siberia system and additional flows from Central Asia.

India’s LNG imports could increase by half by 2025

India’s LNG imports increase by 16 bcm/y and reach 48 bcm/y by the end of the forecast period. With the recent addition of the Ennore and Mundra terminals and the expansion of the Dahej facility, effective regasification capacity stands at 53 bcm/y. After the completion of five new terminals and a breakwater facility at Dabhol, which are already under construction, India’s import capacity could increase by another 31 bcm/y, implying an average utilisation rate of 57% in 2025, a slight decrease from 69% in 2019. This – combined with improving downstream connectivity – could enable the county not only to bridge its widening supply gap, but also to take advantage of favourable market conditions during periods of low spot prices. Our forecast envisages no pipeline imports into India through 2025.

Japanese LNG imports set to decrease with nuclear restarts and steady renewables 

Japan imports LNG as part of a diverse energy mix. The country relied on LNG for 34% of its power generation in 2019 due to the slower than planned restart of nuclear reactors. Japan imported 105 bcm of LNG in 2019, and the volume is set to decline by an estimated 10 bcm/y to 2025 as scheduled nuclear reactors restart and increased renewable capacity reduces the share of gas in power generation.

Korean LNG imports to ease with additions of coal and nuclear

After reaching a peak at 60 bcm in 2018, Korea’s LNG imports are expected to weaken in the 2019-25 period with the addition of long-planned nuclear (5.6 GW) and coal-fired (7.3 GW) generation capacity by 2023. Those new plants – with their higher efficiency – will be among the lowest-cost sources of generation, putting pressure on LNG-fuelled power plants. The country's LNG demand is likely to rise in the longer term. The draft version of the government’s 9th Basic Plan for Electricity Supply and Demand, which was published in May, recommends the shutdown of 30 ageing coal-fired power plants (15.3 GW) by 2034, of which 24 will be converted to LNG-fired units (12.7 GW). However, the final plan, which will be released later in 2020, is not expected to alter the medium-term outlook, as any change in Korea’s generation mix is likely to be gradual rather than immediate.

Europe’s import requirements are expected to increase by over 10%, or 45 bcm/y, in the next five years, despite stagnant demand. This is driven by a rapidly declining domestic production in northwest Europe.

Norwegian pipeline supplies to the rest of the continent remain stable. The relative proximity of its production assets – including swing fields such as Troll and Oseberg – allow Norway to play a key role in providing flexible gas supplies to an increasingly import-dependent European market.

Europe’s growing import requirements and progressive expiry of existing long-term supply contracts create market opportunities for both traditional and emerging pipeline suppliers, as well as for LNG.

The start of commercial deliveries via the Trans-Adriatic Pipeline in October 2020 should allow Azeri gas supplies to increase by 8 bcm/y through the forecast period. Pipeline imports from Russia are expected to fluctuate in a range of 170-200 bcm/y, supplied through a combination of long-term contracts, short-term auctions and direct spot sales to the European hubs. 

Following a record of 115 bcm of LNG imports in 2019, we expect Europe to continue to play a key role in balancing the global gas market – providing access to its spare regasification capacity, ample storage space and liquid pricing hubs. LNG imports are expected to oscillate in a range of 90-110 bcm/y through the medium term.