2021 is anticipated to see a 3.2% y-o-y increase in global gas demand (about 125 bcm). On this basis the recovery would offset losses seen in 2020 and even result in some net growth above 2019 levels. However, as mentioned in our previous quarterly report, this is likely to be a fragile and rather asymmetric recovery, as sectors and regions that have suffered the largest losses may not see the biggest gains. Moreover, the prospect of a prolonged impact of the pandemic on the global economy adds further uncertainty to the pace of short-term gas demand growth.

Consumption in the industrial sector, which remained resilient in 2020 with an estimated 1.2% annual decline, is expected to take the lead in 2021 with 5.4% y-o-y growth (close to 55 bcm). China, India and emerging Asian markets are set to be the main drivers behind this increase. Higher gas demand from industrial buyers hinges on a consumption rebound in both these large Asian economies and their main export markets. The IMF World Economic Outlook in April 2021 projects annual growth of 6% in global output and 8.4% in trade volume.

Gas demand from the power generation sector is facing a more challenging environment. Gas consumption for power generation was already the most affected segment in 2020, accounting for an estimated 45% of the total annual decline, despite favourable fuel-switching dynamics in North America and Europe. 2021 is expected to see limited growth in electricity demand, strong competition from increasing renewable capacity and lower cost-competitiveness against coal as natural gas prices recover from their 2020 lows. This forecast therefore expects a 1.2% increase in natural gas for power burn in 2021, not sufficient to offset the estimated 2.1% y-o-y drop seen in 2020.

A cold start to 2021 provided support for heating demand after a tough year for gas demand in the residential and commercial sectors, which fell by 2.4% y-o-y in 2020. This reflected the joint impacts of unusually mild winter temperatures for residential and widespread lockdowns for commercial. The return to more average winter temperatures and retail activity, together with the expansion of gas connections in China, support a strong 4.9% anticipated increase in gas demand for 2021.

Although gas demand is expected to recover globally, regional disparities remain, with the most mature markets in Europe, Eurasia, North America and Asia seeing slower growth – with only partial recovery for some. Meanwhile, faster-growing economies in Asia, the Middle East and Africa are projected to go beyond simply bridging the 2020 gap in 2021.

Natural gas consumption in the United States declined by an estimated 3.8% y-o-y during the past heating season (October 2020 to March 2021 inclusive) in spite of cold temperatures driving up heating demand. The decline reflected gas-fired electricity generation losing ground on higher fuel prices (gas burn for power generation was down 7.5% y-o-y over the winter). Gas consumption by industrial customers remained stable and comparable by volume with the previous winter. Wide temperature variations remained the main driver of gas demand over the heating season.

In the third quarter of 2020, average weather conditions in October were followed by an exceptionally mild November that erased most of the recovery made over the summer. The advent of colder temperatures in December pushed monthly residential demand slightly above its 2019 level, while gas-fired generation was hampered by recovering prices, declining 5% y-o-y against a 2% increase in electricity demand and an 8% rebound in coal-fired generation. The first quarter of 2021 was marked by colder weather, culminating in mid-February with extremely low temperatures leading to rising heat and electricity needs while also hampering gas production with well freeze-offs, resulting in rolling power cuts in several US states and a drop in gas exports to Mexico. US gas demand fell in March (down 4% y-o-y) on lower use for power generation and milder temperatures.

In Canada gas demand slightly decreased by 1% y-o-y in the fourth quarter of 2020, principally due to lower retail sales (down 6%), while wholesale customers in power generation and industry saw their consumption increase by 3%. Gas demand in January was stable at slightly below January 2020, whereas several provinces reported record daily consumption levels in early February as temperatures fell sharply. US production constraints led to a jump in Canadian pipeline exports, which increased by 22% compared to February 2020 – and were still up by 13% y-o-y in March. Mexico’s apparent natural gas consumption remained stable y-o-y during the October to January period. In mid-February, Mexico turned to LNG to compensate for lower pipeline imports, but was still faced with supply cuts to wholesale customers.

This forecast expects power generation to play a central role in North American gas demand trends for 2021 – downward in the United States and Mexico on a mix of limited electricity demand growth, growing renewable capacity and rising gas prices, and upward in Canada principally thanks to coal-to-gas conversions in Alberta. Other sectors are set to progressively return to their 2019 levels on a combination of industrial recovery and a return to average temperatures. As a result, North American gas demand would be almost stable in 2021, with an annual increase of less than 1%.  

European gas consumption rose by over 5% y-o-y during the 2020/21 heating season, driven by colder winter temperatures, a higher gas burn in the power sector and a gradual recovery in gas demand in industry.

Heating degree days averaged 10% higher compared to the 2019/20 heating season across Europe’s main gas-consuming regions. Distribution network consumption increased by an estimated 6% y-o-y, supported by the higher space heating requirements in the residential sector. Demand growth was particularly strong during January and February, which faced several cold spells. The sharp drop in temperatures during the first half of February, together with lower wind generation, propelled European daily gas demand to a high of 2.4 bcm/day on 12 February, topping the daily gas consumption levels seen during the “Beast from East” of March 2018. The sharp increase in demand did not lead to price spikes, as supply remained stable, supported by a combination of larger storage withdrawals, a ramp-up in pipeline supplies and greater LNG send-out.

Gas-to-power demand increased by an estimated 4% y-o-y during the 2020/21 heating season. The decline in nuclear power output (down 2% y-o-y), together with lower wind generation (down 6% y-o-y), created additional market space for thermal generation, most of which was captured by gas-fired power plants. Coal- and lignite-fired generation remained subdued, and increased by a mere 1% y-o-y. Turkey accounted for the majority of incremental gas-to-power demand in Europe, with its gas-fired power output increasing by 55% y-o-y driven by lower coal- and lignite-fired generation (down by 5.5% y-o-y) and plummeting hydro availability (down 29% y-o-y). Germany was the second-largest contributor to additional gas burn in the power sector, where lower wind power generation (down 18% y-o-y) together with a drop in nuclear output (down 10% y-o-y) supported both gas-fired power plants (up 15% y-o-y), and coal- and lignite-fired generation (up 18% y-o-y).

Gas demand from industry remained resilient in major economies during the heating season, increasing by 3% y-o-y in Italy and averaging at pre-crisis levels in France, whilst down by 3% in both Belgium and Italy. Industrial gas demand was particularly strong in Turkey, where it rose by 12% y-o-y during the period October-January.

Following strong growth in Q1, European gas demand is expected to increase by 3% in 2021, recovering to its pre-crisis levels. The sharp increase in carbon prices is expected to support additional gas burn in the power sector through the summer, while industrial gas demand is expected to continue its recovery amid improving economic conditions. 

Asia’s gas demand recovery showed a mixed picture last heating season. Northeast Asian economies saw strong y-o-y increases between December and February, driven by colder-than-average temperatures, nuclear maintenance in Japan and limits on coal-fired generation in Korea, while a number of emerging economies in South and Southeast Asia saw their gas consumption decline amid record-high spot LNG prices.

In 2021 total gas consumption in Asia is expected to grow by 5% thanks to a strong rebound in economic activity and expanding gas infrastructure across the region. China accounts for 56% of the net demand growth in Asia, followed by India with a 14% share. A group of emerging Asian economies together make up 28% of the net demand increase, while expected declines in Japan are completely offset by consumption growth in the rest of Asia.

China’s gas consumption registered double-digit y-o-y growth rates throughout the last heating season, driven by a robust recovery in the industrial sector, new residential connections and high heating demand. Total consumption increased by 15% y-o-y in Q4 2020 and growth was especially strong during the cold spell in December and January, when y-o-y rates were up by 17% and 20% respectively. Monthly gas consumption (at nearly 40 bcm) reached an all-time high in December. Gas use in February was up by 21% y-o-y due to the low base in February 2020 (when China’s Covid-19 epidemic was at its peak), but demand in February was actually 28% lower than January as warmer temperatures and the Lunar New Year holiday moderated consumption.

In 2021 total gas demand is projected to increase by 8% in China, fuelled by strong GDP growth, continuing coal-to-gas conversions and expanding gas infrastructure. The industrial sector remains the primary growth driver, accounting for nearly 40% of China’s demand expansion due to ongoing coal-to-gas conversions and recovering industrial activity. Power generation contributes about a quarter of the 2021 growth thanks to the continuing expansion of the gas-fired generation fleet. Residential and commercial users make up more than a fifth of the net demand growth, driven by new grid connections (and further boosted by a cold start to the year).

India saw a reversal of a tentative recovery that started in October 2020, and consumption growth rates registered y-o-y declines of 5%, 9% and 12% in December, January and February respectively. Falling demand was largely due to the steep rise in Asian spot LNG prices, which prompted price-sensitive users – especially in the refining and petrochemicals sector – to curtail gas consumption. In 2021 demand is set to rebound sharply and increase by 10% on the back of a strong economic recovery, new gas connections, improving infrastructure, growing domestic supply and a supportive policy environment. Nearly two-thirds of the net demand growth is expected to come from industrial users, while new city gas connections and growing compressed natural gas (CNG) consumption in the transport sector will account for the remaining increase. Barring a collapse in spot LNG prices in the rest of 2021, power sector gas consumption is likely to decrease from last year’s elevated levels.

Japan’s gas demand was relatively sluggish at the start of the heating season, posting negative y-o-y growth rates in both October and November, but demand received a strong boost in December and January when a cold blast – coupled with low nuclear and solar availability – increased gas use in the power sector. Gas consumption in December was up by 5% y-o-y, and LNG imports registered a 14% y-o-y increase in the period between December 2020 and February 2021. Despite the strong start to the year, gas demand in 2021 as a whole is projected to decrease by 3% as nuclear restarts and Japan’s second state of emergency from January present headwinds to consumption growth in the remainder of the year.

Korea’s gas consumption continued to recover during the heating season, increasing by 7% y-o-y in Q4 2020. This was underpinned by the government-mandated shutdown of several coal-fired power plants and cold winter temperatures in December. Early indications suggest that consumption growth remained robust in early 2021 as well. Domestic gas sales by Kogas (which excludes private company sales to power generators) increased by a remarkable 20% y-o-y in January, while LNG imports jumped by 19% y-o-y in February according to preliminary shipping data. In 2021 Korea’s gas demand is expected to increase by 5%, driven by coal-to-gas substitution in the power sector. This outlook is underpinned by the temporary closure of up to 28 coal plants (around half of the total) for the month of March, following the government-mandated shutdown of up to 16 coal-fired units between December and February to reduce air pollution. The addition of 3 GW of new coal-fired capacity this year will be offset by lower utilisation of coal plants in general.

Emerging Asia’s gas demand recovery remained subdued in Q4 2020 as high LNG prices dented consumption in price-sensitive markets across the region, a dynamic that continued into early 2021. Pakistan and Bangladesh, for example, experienced gas shortages as sky-high LNG prices forced both countries to cancel spot LNG tenders during the winter. In 2021 total consumption is set to increase by 5%, which is just enough to push gas use above the 2019 level across the region. This increase is supported by a rebound in economic activity and continuing strong growth in electricity demand. Small-scale LNG import terminals in Indonesia and Viet Nam, which are entering service in 2021, could unlock additional demand in these countries throughout the year.

After three consecutive years of growth, US gas production decreased in 2020, but remained resilient compared to the decline in domestic demand – gross output was down just 1% and dry gas production fell by 1.6%. This is attributable to the net positive contribution of trade, with exports increasing by 13% y-o-y while pipeline imports from Canada declined by 7%.

The Appalachian Basin, the main source of shale gas, which also accounts for almost 35% of total US dry gas production, saw its output grow by 4.9% y-o-y in 2020 in spite of reduced drilling activity. A monthly average of 70 new wells were drilled in 2020 against 112 in 2019. Output increased thanks to productivity gains and higher completion rates from previously drilled and uncompleted wells. The Permian Basin’s oil-driven shale gas production bounced back in the second half of 2020 to reach an annual 15% increase. Both basins kept growing over the final months of 2020, reaching record levels of production in December at 29 bcm and 11 bcm respectively – their combined output accounting for almost half of total US dry gas production. Total dry gas production in January observed a slight 2% decline compared to December.

The extremely cold temperatures observed throughout North America in mid-February caused well freeze-offs that negatively affected natural gas production capacity. The South Central region was the worst affected, with gas output in Texas almost halving on 17 February compared to the previous week’s average, causing shortages and rotating power cuts. The impact was less important in northern US production areas, where the proportion of liquids is lower (and hence less prone to freeze-offs) and where production infrastructure is usually winterised. Dry gas production in continental United States fell by an estimated 15% in February compared to January, reaching its lowest monthly level since February 2018.

US dry gas production is projected to stabilise in 2021 with a 0.1% decline. Dry shale gas is expected to provide limited growth, slowing from an annual increase of 3.3% in 2020 to 2.5% in 2021, thus echoing the prudent strategies outlined by Appalachian producers to keep spending flat and reduce debt. This growth will not be sufficient to offset declines from other sources. Output from the Permian and other associated shale gas plays is expected to slightly decline by about 2% in 2021, reflecting oil production forecasts in the IEA Oil Market Report: 11.3 mb/d in 2020 and 11.1 mb/d in 2021. Production from conventional gas fields is also expected to decline due to depletion and limited investment.

Following the steep drop during the first half of 2020, Eurasian gas production losses moderated in the second half of the year and returned to growth in Q1 2021, largely driven by higher gas output in Azerbaijan and Russia. Overall, the region’s gas production increased by a mere 2% y-o-y during the heating season.

Russia’s gas production grew by 2.6% (or 10 bcm) y-o-y during the 2020/21 heating season, with most of the increase concentrated in Q1 2021 (6.4% y-o-y). The recovery has been partly supported by higher exports. Pipeline deliveries to Europe rose by over 6% y-o-y during the heating season, with strong gains recorded in Q1 2021 (up by 18% y-o-y). Pipeline deliveries to Turkey increased particularly strongly, more than doubling in Q1 2021 compared to last year. Exports to China via the Power of Siberia pipeline continued to ramp up and reached close to 4 bcm during the heating season. Flows increased almost threefold in Q1 2021, in line with contractual arrangements and with most of the additional volumes going to the Beijing-Tianjin-Hebei region. Russia’s LNG exports rose by less than 1% during the heating season, with a pronounced shift towards Asia. The widening price spread between Asian spot LNG and TTF incentivised higher exports towards the Northeast Asian market, increasing by
17% y-o-y, while flows towards Europe declined by 11% y-o-y.

Central Asian pipeline exports to China remained subdued during the heating season, down by close to 9% y-o-y in the October-February period. This was despite the strong demand increase in China during the December/January cold spell. In Uzbekistan, where gas production fell to its lowest level since 1996, electricity and gas supply cuts to the domestic market were reported over the winter. In Azerbaijan gas production increased by
5% y-o-y during the October-February period. This was largely driven by the ramp-up of pipeline exports via the TANAP and TAP pipeline systems, with deliveries to the European markets soaring by an impressive 40%. Exports via TAP to the European Union totalled over 1 bcm. In Ukraine gas production fell by 3.5% during the heating season, with February output plummeting to a 5-year low.

Eurasian gas production is expected to continue to recover, growing by over 6% y-o-y during 2021, close to 2019 levels. This would be largely supported by the ramp-up of exports via new and traditional export corridors. Pipeline exports from Russia to Europe and from Central Asia to China are expected to increase by over 10%. Exports via the Power of Siberia pipeline are set to reach 10 bcm in 2021. Azeri pipeline deliveries are set to increase by over 15%, with 8 bcm destined for Turkey and over 5 bcm for other European markets. Russian LNG exports are set to increase by about 1 bcm, with the start-up of Train 4 at Yamal LNG in Q2 2021.

Despite the colder weather, LNG import flows to Europe fell by almost 30% (or 20 bcm) y-o-y during the 2020/21 heating season. Competition from pipeline imports and a greater storage draw reduced the demand for LNG. The widening price spread between Asian spot LNG and European hub prices have been driving LNG cargoes away from European shores to Asia since the beginning of September 2020. European LNG imports fell by close to
50% y-o-y in January to their lowest level since September 2018. Cargoes were increasingly diverted to Northeast Asia, which faced a particularly harsh cold spell when Asian LNG spot prices climbed to a record level of USD 30/MBtu. European LNG imports remained subdued in February (down 30% y-o-y), before recovering close to last year’s levels in March. Northwest Europe’s LNG imports declined the steepest, plummeting by 37% y-o-y, while southern and eastern European markets faced a more moderate decline of 20% y-o-y over the heating season. 

Non-Norwegian domestic production continued to decline, falling by an estimated 10% y-o-y. This was largely driven by the Netherlands, accounting for almost 40% of the net decline as a result of both lower Groningen output and lower production from its small fields. Norwegian pipeline deliveries remained broadly
flat y-o-y, with lower deliveries to Germany compensated by higher flows via Emden to the Netherlands and via the Langeled pipeline to the United Kingdom.

Russian net exports to Europe had recovered to above 2019 levels by the end of 2020, and averaged 18% higher compared to last year during Q1 2021. Pipeline imports from North Africa rose by over 55% y-o-y during the heating season, and Azeri gas deliveries increased by close to 40% y-o-y during October-February as flows via the TANAP and TAP systems continued to ramp up. Storage withdrawals increased by over 50% y-o-y during the heating season to meet higher gas demand. They accounted for almost 20% of total supply (up from 13% during the same period last year).

Europe’s gas import requirements are expected to increase by close to 10% in 2021, driven by demand recovery (3% y-o-y), lower domestic production and higher injection needs to replenish storage inventories, which stood 25 bcm lower than last year at the beginning of April 2021. Higher import requirements will benefit traditional pipeline suppliers, which are expected to recover close to their pre-crisis levels. LNG imports are projected to remain close to their 2019 record levels. Azeri deliveries are set to increase by over 15% as supplies via TAP ramp up to over 5 bcm.

In Q1 2021 global LNG trade (net of re-exports) expanded by 1% y-o-y. LNG import flows were dominated by the cold blast (and resulting price spikes) across Northeast Asia in January, which led to a 17% y-o-y jump in the combined LNG imports of China, Japan and Korea during the first quarter. Even though winter temperatures turned warmer in February, LNG inflows into the three Northeast Asian countries remained elevated in February and March, most likely as a result of delayed cargo deliveries dispatched during the cold spell. The Asia Pacific region as a whole saw a 11% y-o-y increase in LNG imports in Q1, while European imports dropped by 27% y-o-y, almost perfectly balancing the demand spike in Asia. Southeast Asia, where winter is a low season due to a lack of heating demand, also provided emergency supplies for Northeast Asia; in January Indonesia and Thailand completed their first-ever LNG re-exports to China and Japan, respectively.

LNG export growth in Q1 2021 remained subdued at 1.5% y-o-y due to ongoing capacity outages in Australia and Norway, gas supply availability issues in Trinidad and Indonesia, and a temporary disruption of LNG production at US Gulf Coast terminals during the power outages across the southern United States in February.

In 2021 global LNG trade is projected to expand by 4%, a slower pace relative to the 2015-2019 average annual rate of 10%. Growing pipeline gas flows and – in the case of China and India – growing domestic production will present short-term headwinds to a more rapid rebound in LNG demand.

LNG import growth is set to be driven solely by the Asia Pacific region, which is expected to see a 7% increase in LNG inflows, while all other regions are poised to see declining imports. Despite the steep drop in Q1, LNG influx into Europe is expected to remain relatively strong in 2021, albeit below the 2019 and 2020 levels. Sustained high European imports are supported by stronger injection needs, lower indigenous production and recovering demand through the summer.

North America remains the primary engine of LNG export growth in 2021. LNG output in the United States is set to increase by a third, driven by the addition of new liquefaction capacity at Corpus Christi Train 3 and the Calcasieu Pass terminal, as well as by higher utilisation of existing plants. In the rest of the world, small increases in Africa (thanks to recovering output in Egypt), Central and South America and the Middle East are more than offset by declines in Asia Pacific and Europe, the latter due to the fire-related outage at the Hammerfest LNG terminal in Norway.

This winter illustrated – for the first time – that the Panama Canal can present a bottleneck for the global LNG trade, particularly for US LNG cargoes dispatched to Asia. During the cold spells in Northeast Asia, unscheduled spot LNG cargoes faced wait times of up to 12 days to cross the Panama Canal, or had to take longer journeys via the Suez Canal or around the Cape of Good Hope in Africa to reach buyers in Northeast Asia, who offered a steep premium to attract additional LNG amid a growing fuel shortage. The congestion on the Panama Canal contributed to the market tightness and record-high spot LNG prices in Asia, and exposed the inherent limitations of this vital LNG shipping route.

The Panama Canal Authority (PCA) currently offers only two of the eight available reservation slots per day to LNG carriers, either both for northbound transit from the Pacific to the Atlantic Basin, or one in each direction. Cruise ships and container ships take priority for the remaining spots for large Neopanamax vessels. The PCA has taken steps in recent years to increase throughput capacity for LNG shipments by easing navigation rules, lifting night-time restrictions and introducing an auction process for unused transit slots after last-minute cancellations. With these measures in place, the Panama Canal is occasionally able to transit three LNG carriers in a day, and on a handful of occasions (when demand from higher-priority vessel types allowed) it managed four LNG transits in a single day. At its current capacity, the canal can handle LNG flows from the United States (as well as from Trinidad, Peru and West Africa) in normal market conditions, when the majority of US cargoes remain in the Atlantic Basin, or when US terminals run significantly below capacity, as happened in the summer of 2020. However, in market conditions like the winter of 2020/21, when surging demand in Asia prompts most US LNG to flow into the Pacific Basin, the Panama Canal can only accommodate a fraction of LNG traffic in a timely manner.

Insufficient transit capacity on the Panama Canal prompted US LNG cargoes to take longer routes to Asia in December 2020 and January 2021, which led to sharp increases in US export flows via both the Suez Canal and around the Cape of Good Hope compared to the previous winter. This, in turn, boosted tonne-mile demand, propelled LNG charter rates to record highs, and lengthened the time for LNG shipments to reach buyers across Asia. If the current capacity constraints persist, the Panama Canal may become a recurring bottleneck for US LNG exports, which could exacerbate price volatility and fuel shortages in periods of regional market tightness, and lead to US cargo cancellations for logistical rather than economic reasons. US LNG offtakers reportedly had to cancel up to ten cargoes for February 2021 delivery due to limited shipping availability.

LNG spot charter rates displayed strong volatility during the 2020/21 heating season: after soaring to record highs in January 2021 on high tonne-mile demand, charter rates plummeted below last year’s levels at the beginning of March on improving availability of shipping capacity.

Spot charter rates opened the heating season by averaging 25% below last year’s levels during October and November. This was partly driven by incremental LNG carrier capacity (up 4% y-o-y) exceeding global LNG trade growth. In addition, tonne-mile demand (tonnage of cargo multiplied by shipping distance) declined by close to 4% y-o-y, depressing further LNG charter rates.

Colder winter temperatures in Northeast Asia in December and early January, together with lower nuclear availability in Japan, prompted strong LNG demand growth, with imports rising by over 12% y-o-y in January and December. The increase in demand for LNG imports in Northeast Asia coincided with a number of outages at regional liquefaction plants (including in Australia, Indonesia and Malaysia). This, in turn, led to a sharp increase in LNG imports from the US to Northeast Asia, rising more than twofold compared to the previous year during December and January. Higher LNG shipments from the US, combined with congestion issues on the Panama Canal, increased tonne-mile demand by 37% in January 2021 compared to September 2020. Consequently, spot charter rates had climbed to historical highs at more than USD 230 000/day by the beginning of January, with one cargo reportedly awarded at USD 350 000/day. The reduced shipping availability and high charter rates allegedly prompted several LNG cargo cancellations by US LNG buyers expecting deliveries in February and March.

Spot charter rates plummeted by 70% in February and fell below last year’s levels in March to an average of USD 33 000/day. Lower LNG shipments from the United States to Northeast Asia –contracting to a quarter of those in January – depressed tonne-mile demand, which has fallen by 17% from its January highs according to data from Kpler. In addition, 20 new-build LNG carriers started commercial operations in Q1 2021 (against 4 in Q1 2020), further improving vessel availability and weighing on spot charter rates.

Global LNG shipping capacity is expected to increase by close to 10% y-o-y in 2021, with the delivery of an additional 30 vessels in Q2-Q4 2021. Forward curves suggest that charter rates will average above last year’s levels over the summer, with higher LNG exports from the US supporting tonne-mile demand. Charter rates are set to strengthen in Q4, albeit remaining on average 15% below last year’s levels on improved vessel availability.

Spot prices recorded strong gains across all main gas-consuming regions during the 2020/21 heating season, driven by tightening supply-demand fundamentals, while sporadic cold spells in Northeast Asia and the United States propelled regional spot prices to historical highs.

In the United States, Henry Hub prices averaged 40% above the 2019/20 heating season’s price levels at USD 3.05/MBtu, as domestic production continued to fall while higher LNG exports (up by 28% y-o-y) kept gas demand resilient. The February 2021 cold spell propelled regional hub prices to historical records, as higher gas demand coincided with plummeting domestic production due to wellhead freeze-offs. Henry Hub averaged USD 5.49/MBtu in February 2021, its highest monthly value since February 2014. Prices returned to their seasonal norms on improving supply-demand fundamentals during the second half of February. Stable US production combined with a strong growth in LNG exports through the rest of the year are expected to support continued price recovery through the rest of 2021. Forward curves at the end of March indicate Henry Hub prices averaging 32% above last year’s levels during Q2-Q4 2021.

In Asia, spot LNG prices rose by 80% compared to the 2019/20 heating season, driven by higher LNG demand from Northeast Asia (up by 12% y-o-y) and lower-than-expected LNG supply due to a variety of planned and unplanned outages at regional liquefaction plants. Tight market conditions during the December/January cold spell culminated in Asian spot LNG prices soaring to a record USD 30/MBtu in early January and reaching their highest monthly average since April 2014. Despite the strong growth in spot prices, average import prices in Northeast Asia declined by 20% y-o-y during the period between October-February, as buyers benefited from lower oil-indexed LNG prices. Forward curves indicate a strong recovery through the rest of the year, with LNG spot prices expected to be almost 70% above last year’s levels in Q2-Q4 2021. The recovery in oil prices (up by 60% since October 2020) is set to support oil-indexed prices to above spot levels in Q2-Q3 2021. 

In Europe, TTF averaged 60% above the 2019/20 heating season’s price levels, supported by demand recovery (up by over 5% y-o-y) and plummeting LNG imports (down 30% y-o-y). Forward curves indicate that the recovery is set to continue through the rest of 2021, with TTF prices expected to double compared to last year’s levels in Q2-Q4. Price spreads with Asian spot LNG are expected to remain tight through the summer – indicating a potentially higher LNG influx into Europe. Forward curves suggest a price spread with Henry Hub averaging close to USD 4/MBtu in Q2-Q4, limiting the risk of cargo cancellations in 2021.

Cold winter temperatures and lower primary gas supply prompted strong storage draws across the main gas-consuming regions during the 2020/21 heating season.

In the United States, storage sites started the gas winter in November with inventory levels 5% above their 5-year average. Mild temperatures and lower natural gas demand depressed withdrawal rates to below injection levels in November, resulting in a slight increase in working storage by the end of the month. As heating degree days edged higher, storage draws started to gain strength in December and remained well above the levels seen during the last heating season. The cold spell in mid-February triggered the second-largest weekly storage withdrawal ever reported by the EIA, with storage sites supplying 10 bcm of natural gas to the market during the week ending 19 February 2021. The sharp increase in weekly demand coincided with a steep fall in weekly dry gas production, primarily due to wellhead freeze-offs.

In these circumstances, storage facilities played a critical role in supplying the market, accounting for 38% of total gas supplies during the peak day of 15 February. Altogether, storage draws rose by 24% (or 12 bcm) y-o-y during the November-March period. Inventory levels fell to 2% (or 1 bcm) below their 5-year average and 11% (or 6 bcm) below their level last year by end of March 2021. In Canada, storage sites opened the heating season 30% above their previous year’s levels. Storage withdrawals rose by over 50% y-o-y on colder temperatures and higher net pipeline exports to the United States. Canadian gas inventories were just 6% above last year’s levels by the end of March 2021.

In Europe, gas storage sites started the heating season with inventory levels 12% above their 5-year average. Recovery in gas demand (by over 5% y-o-y) and the steep decline in LNG inflows (down by 28% y-o-y), supported higher storage draws, soaring by 55% compared to last year and accounting for close to 20% of total gas supply during the heating season. Consequently, European storage inventories had fallen to 10% (or 3.7 bcm) below their 5-year average and 44% (or 24 bcm) below last year’s levels by the end of March. Low inventory levels could translate into higher gas injections through the summer of 2021, providing additional market space both for LNG and pipeline suppliers.

In Japan and Korea, LNG inventories were 7% below last year’s levels in October 2020. The tight supply-demand conditions between mid-December and early January resulted in low intra-monthly storage levels. This prompted strong LNG imports during the second half of January and February (up by 16% y-o-y), which allowed LNG inventories to ramp back up to 6% below last year’s levels by the end of February.