Jan 2021

Trend of Natural Gas and LNG Prices

Short-term trend

  • The assessed spot LNG price JKM for near-month delivery to Northeast Asia spiked up since early December because of several supply disruptions, rapid demand increases in Northeast Asia, increased freight rates, as well as congestion at the Panama Canal. The price rose sharply in December and further after the New Year holidays, reaching an all-time high of USD 32.5 per million Btu on 12 January 2021 (for delivery in February 2021). However, as some LNG supply facilities which had supply problems are now resuming production, and the temperature is expected to rise gradually in Northeast Asia, JKM for later delivery are expected to be stabilised down. In fact, JKM for delivery in March dropped to below USD 9 after 19 January. The average spot LNG price published by METI was USD 6.8 for December delivery (USD 0.3 higher than November).
  • The Henry Hub price for delivery in the following month has been stable between the range of USD 2.4 to USD 2.8 in January because of the mild weather in the United States. The expanded price gap between HH and Asian LNG led to an increase of LNG exports in December, which is expected to continue keeping high facility utilization rate in January. Furthermore, in addition to the lower natural gas production, the temperature in the first quarter of 2021 is expected to be lower than in the same period of 2020, which would result in higher HH price.
  • The TTF price for delivery in the following month began to increase in early December and exceeded USD 7 on 4 January, the first business day of 2021, hovered around the USD 7 level in January. Natural gas demand increased, and gas storage utilization rate decreased in high rate because the temperature was lower in Europe than in 2020. Furthermore, the spiked Asian LNG price also affected the gas price in Spain which relies more on LNG imports for its gas supply than other European countries. Although the temperature is expected to rise in Europe, the TTF price is still expected to remain at the same level at least throughout the winter, due to a shortfall in LNG procurement to the European region in February, lower pipeline gas flows from Norway and continued disbursement of underground storage. However, the overall demand outlook is still uncertain as some of the regions are facing another wave of COVID-19 spread and the re-introduction of lockdown measures.
  • Based on the preliminary figures from Japan's customs statistics of the Ministry of Finance, the country's average LNG import price was USD 7.16 in December 2020. The average landed prices of LNG in Japan from the ASEAN region in the month were USD 6.82. On the other hand, the average landed price of LNG in Japan from the United States was USD 8.18, higher than the overall average. The relative value of the Japan’s average LNG import price (USD 7.16) against the Northeast Asian average spot LNG price (USD 6.90) was 104% in December narrowing down from 400% at a time. Japan imported 7.722 million tonnes of LNG in December 2020, 13.4% higher than 2019 and the highest for a month in the past two years. Japan imported 74.46 million tonnes in 2020, 3.7% lower than 2019, with an annual average import price of USD 7.77.

LNG and Spot Gas Prices, 2019-2020

Mid- to long-term trend

  • Most of the long-term LNG contract prices in Japan are linked to oil prices except for the LNG from the United States. Japan's average LNG import price has been declining for the past 10 years, peaking at USD 18 in 2012, falling to USD 5 in August - October 2020, the lowest level since January 2005, due to the collapse of international crude oil prices since March 2020, but rising USD 6s in November as crude oil prices recovered. As the crude oil prices have been on an upward trend since then, the average import price is also expected to rise for the next few months.
  • JKM was around USD 6 in winter 2019, but started to decline from January 2020, reaching an all-time low of USD 1.83 at the end of April 2020; it started to rise from August 2020, surging from USD 6 in November 2020 to over USD 10 in December 2020 and reaching an all-time high of USD 32.5 in January 2021. This rise, as well as the fall, was unprecedented and remarkable.
  • In recent years, Asian LNG spot prices had been in the range from European spot gas prices to the crude oil equivalent level and had remained near the lower end, close to European spot prices since 2019 until recently. However, the spread between Asian LNG spot prices and TTF started to widen in the middle of October 2020. Asian LNG spot prices have been even higher than the oil equivalent prices since December 2020.
  • The Asian LNG spot price was significantly lower than Japan's average LNG import price from the beginning of 2019 to September 2020. The reason for this trend is believed to be that the declining demand from Japan and Korea due to COVID-19, abundant supply from the United States and the rest of the world, as well as the high level of inventories all contributed to the low demand for spot LNG cargoes.
  • The combined LNG imports by Japan, Korea, and Chinese Taipei in 2020 were 132.8 million tonnes, decreased year-on-year by 1.5%, or 1.98 million tonnes, and were less by 7.5%, or 10.84 million tonnes than 2018. Although Japan and Korea imported a few percentage point smaller volumes, Chinese Taipei increased LNG import by nearly 10%. Meanwhile, China’s LNG imports were 67.13 million tonnes in 2020, increasing year-on-year by 11.4% or 6.88 million tonnes despite the pandemic.

LNG and Spot Gas Prices, 2010-2020

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Henry Hub price: NYMEX Futures and Options, CME Group
NBP price: ICE Futures Europe, Intercontinental Exchange
TTF price: ICE Futures Europe, Intercontinental Exchange
JKM: LNG Japan/Korea Marker© 2021 by S&P Global Platts, a division of S&P Global Inc.
METI spot price: Spot LNG Price Statistics, Ministry of Economy, Trade and Industry
Japan’s average LNG import price: Trade Statistics of Japan

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Trend of Natural Gas and LNG Inventories


  • Japan's LNG inventories as of the end of September 2020 stood at 4.13 million tonnes, an increase of 6.0% or 0.23 million tonnes from the preceding month, and a decrease of 2.9% from one year earlier. The LNG inventories significantly decreased in August 2020. Since then, they have remained at about the same level as the five-year average.
  • The LNG inventories for city-gas supply in September were 1.97 million tonnes, 2.3% higher than September 2020, and 18.4% lower than September 2019. LNG consumption for city-gas stood at 2.28 million tonnes, increasing by 0.8% year-on-year in September 2020. City-gas companies received 2.33 million tonnes of LNG in September, which is a decline year-on-year of 13.1%. LNG consumption for city-gas increases in September for the first time since March 2020 on a year-on-year basis, owing to the recovering industrial demand of almost the same level in September 2019. The LNG inventories increased in September as the receipts were more than the consumption but still were much lower than September 2019.
  • The LNG inventories for power generation in September 2020 were 2.17 million tonnes, increasing by 9.6% from August 2020 and 17.3% higher than September 2019. The monthly gas-fired power generation output of September 2020 was almost equal to the previous year, but the LNG receipts of September were much higher than September 2019, resulting in an increase of 0.20 million tonnes in LNG inventories from August 2020.
  • According to the Japan Meteorological Agency's forecast, the La Niña phenomenon will likely continue. The average temperature between January and March is expected to be lower than in previous years in the Eastern Japan and Western Japan regions. The LNG inventories were at a high-level in winter one year ago as a result of a mild winter nationwide and sluggish demand for city-gas and power generation. This winter has been marked by frequent cold spells across the country since mid-December, combined with delays in LNG imports, resulting in widely reported shortages of LNG inventories.

Japan end of month LNG inventory, 2019-2020

Japan end of month LNG inventory, 2010-2020

Compiled based on data from Gas Business and Thermal Power Generation Statistics, Ministry of Economy, Trade and Industry.As the inventory data is available for the period only after January 2008, the five-year average is applicable only after January 2013.

United States

  • As of 15 January 2021, working gas in underground natural gas storage in the United States was 3.01 Tcf, a 15.8% decrease from the previous month, according to the U.S. Energy Information Administration (EIA). Gas inventories were 2.1% higher than those at the same time in 2020 and were higher than the past five-year average of 1.98 Tcf. The inventories are within the five-year range since November 2020.
  • According to the monthly Short-Term Energy Outlook released by the EIA in January 2021, EIA forecasts higher-than-average inventory withdrawals in the first quarter of 2021 based on an assumption of cooler-than-normal weather and decline in natural gas production in the January–March period. EIA forecasts that total inventories will be 1.62 Tcf at the end of March 2021, which would be 12% lower than the five-year (2016 – 2020) average.
  • For the 2021 April–October inventory injection season, EIA forecasts that natural gas injections will slightly exceed the five-year (2016-2020) average rate as higher natural gas prices will limit the consumption of natural gas for power generation during the summer of 2021. However, EIA expects that inventories will reach 3.58 Tcf at the end of October 2021, which would be 5% lower than the previous five-year (2016-2020) average and 9% lower than the end of October 2020.

U.S. Natural Gas Underground Storage, Jan 2020 - Jan 2021)

U.S. Natural Gas Underground Storage, 2011-2021

Compiled based on data from the U.S. Energy Information Administration (EIA)


  • As of 22 January 2021, the stored volume of natural gas in European underground storage facilities operated by the Aggregated Gas Storage Inventory (AGSI +) member companies of the European Union (EU) and the United Kingdom was 640 TWh. The inventories were 25.7% down from the previous month and 24.8% lower year-on-year, and 2 TWh higher than the five-year (2016-2020) average. The inventories were at record highs in 2019, and in the first half of 2020 were even higher than 2019 levels. But since September, the inventory levels started to decrease year-on-year, and by the middle of January 2021, the inventory level was lower than the five-year (2016–2020) average for the first time since August 2018. On 22 January 2021, the working gas volume in storage represented 57% of the capacity, staying within the range of 48% - 77% in the same period over the past five years.
  • The natural gas inventories in European underground storage facilities have declined sharply since the beginning of January 2021. It is presumed that the average temperature in the first half of January in Europe was lower than usual, which resulted in more natural gas demand for power generation and space heating and prompted more inventory withdrawals. From 1 to 16 January, inventory withdrawals were 144 TWh, 72% higher year-on-year.

European Natural Gas Storage, Jan 2020 - Jan 2021

European Natural Gas Storage, 2011-2021

Compiled based on data from Gas Infrastructure Europe, Aggregated Gas Storage Inventory (AGSI). As the inventory data is available for the period only after January 2011, the five-year average is applicable only after January 2016.

Latest Developments in Major Natural Gas and LNG Projects


  • At the beginning of the new year, the global LNG industry had a shockwave of extremely high spot cargo prices. Meanwhile, in the long-term LNG supply front, deals were arranged to process third-party gas through the North West Shelf project facilities in Australia in late 2020.


Asia and Oceania

  • China's Huaying Natural Gas announced on 19 December 2020 that it had started construction of the largest private-owned LNG terminal in the country with a capacity of 6 million tonnes per year in the port city Chaozhou in Guangdong province. The first phase is expected to start operations in 2023.
  • CPC Corporation, Taiwan, announced on 10 January 2021 that it had started receiving LNG from Cheniere Energy under a 25-year deal signed in 2018, and will get around 2 million tonnes in 30 cargoes per year. CPC said the vessel carrying the LNG, from the Corpus Christi, Texas, LNG plant, had arrived at the LNG terminal in Taichung.
  • India's Reliance Industries Limited (RIL) and bp announced on 18 December 2020 the start of production from the R Cluster, ultra-deep-water gas field in block KG D6 off the east coast of India. The companies are developing three deepwater gas projects in block KG D6 - R Cluster, Satellites Cluster and MJ - which they expect could meet up to 15% of India's gas demand by 2023.
  • Shell Energy India announced on 19 January 2021the inauguration of its first small-scale LNG supply infrastructure, a truck loading unit at its LNG terminal in Hazira.
  • Australia's Woodside announced on 23 December 2020 that the North West Shelf (NWS) project participants had executed gas processing agreements (GPAs) for processing third-party gas through the NWS facilities with Woodside Burrup Pty Ltd, in respect of gas from the Pluto fields, and with subsidiaries of Mitsui & Co Ltd and Beach Energy Limited, in respect of the Waitsia Gas Project Stage 2.
  • Western Australia's Department of Water and Environmental Regulation (DWER) revealed on 21 December 2020 that it had determined to reduce the duration of the licence to operate the Gorgon LNG Project from 20 years to 10 years with the expiry date amended to 29 July 2028, based on WA environment minister's decision on 6 November 2020.
  • Santos, as an operator of the Bayu-Undan Joint Venture, announced on 5 January 2021 a Final Investment Decision (FID) for the Phase 3C infill drilling program at the Bayu-Undan field in the Timor Sea, offshore Timor-Leste. The program comprises three production wells (two platforms and one subsea) and will develop additional natural gas and liquids reserves, extending field life as well as production from the offshore facilities and the Darwin LNG plant. Production from the first well expected in 3Q 2021.


North America

  • DOE announced on 31 December 2020 that it had extended the terms of five long-term LNG export authorizations through 2050. The term extensions extend terms for the Southern LNG export facility operating in Georgia, the Cameron LNG export facility operating in Louisiana, the Annova LNG project proposed in Texas, and Eagle LNG's two small-scale facilities in Florida, including the Maxville facility currently in operation. Long-term LNG export authorizations with export terms through 2050 are now held by 18 U.S. LNG export projects, as well as the Costa Azul project in Mexico.
  • Commonwealth LNG, in association with Gunvor Group, announced on 18 January 2021 the launch of a formal process to solicit bids to reserve offtake from its planned 8.4 million tonnes per year LNG facility in Cameron, Louisiana. LNG will be made available under tolling, free on board (FOB), or delivered at place (DAP) offtake agreements. Gunvor has committed to take up to 3 million tonnes per year of LNG offtake from the project. In addition, as part of the tender, Gunvor will enable the offering of DAP basis to customers. Furthermore, the utilization of Gunvor's LNG portfolio will allow the offering to provide firm LNG supply obligations, which will mitigate greenfield project supply risk and/or allow deliveries of LNG prior to the start-up of the Commonwealth LNG project to buyers who require earlier supplies.
  • Kinder Morgan, Inc. (KMI) announced on 4 January 2021 that the Permian Highway Pipeline (PHP) began full commercial in-service on 1 January. PHP delivers natural gas from the Waha to Katy, Texas area, with connections to the U.S. Gulf Coast and Mexico markets. Fully subscribed under long-term contracts, PHP provides approximately 2.1 billion cubic feet per day of incremental natural gas capacity, helping to reduce Permian Basin natural gas flaring, KMI said.


Europe and Russia

  • Following the start of commercial operations on 15 November 2020, the Trans Adriatic Pipeline (TAP) AG confirmed on 31 December 2020 the commencement of gas flows from Azerbaijan. The operator said that it planned to launch the second phase of its market test in summer 2021, which would enable the future expansion of TAP, doubling the pipeline's capacity to 20 bcm per year.
  • Gazprom announced on 6 January 2021 that in 2020 Sakhalin Energy produced and shipped a record amount of LNG or more than 11.6 million tonnes. Due to technical improvements and upgrades, together with weather and temperature factors, the factual production has been increased by 20% from its original design capacity of 9.6 million tonnes per year.


Other regions

  • Qatar Petroleum (QP) launched its new Sustainability Strategy on 13 January 2021. The strategy stipulates deploying dedicated Carbon Capture and Storage (CCS) facilities to capture more than 7 million tonnes per year of CO2 in Qatar. The strategy also acts as a clear direction towards reducing the emissions intensity of Qatar's LNG facilities by 25% and of its upstream facilities by at least 15% and reducing flare intensity across upstream facilities by more than 75%. In addition, it sets out a target to eliminate routine flaring by 2030, and limit fugitive methane emissions along the gas value chain by setting a methane intensity target of 0.2% across all facilities by 2025.
  • Spain's Reganosa announced on 7 January 2021 that it had been awarded the contract to operate and maintain an LNG regasification terminal in Tema, Ghana. Both the storage (FSU) and regasification (FRU) units are floating. Tema LNG is the first offshore LNG receiving terminal in sub-Saharan Africa. LNG will be supplied under a long-term contract with Shell.
  • New Fortress Energy (NFE) announced on 21 December 2020 that it had signed two long-term LNG supply agreements to supply its natural gas and electricity businesses in Puerto Rico, Mexico, and Nicaragua. The company said that with these purchases and the previous purchases of LNG for the Jamaican operations, NFE had purchased LNG volumes equal to about 80% of its expected needs across its current portfolio of terminals and assets.
  • NFE announced on 13 January 2021 that it had entered into agreements to acquire Hygo Energy Transition (Hygo), and Golar LNG Partners, LP (GMLP). With the acquisition of Hygo, NFE will acquire an operating floating storage and regasification unit (FSRU) terminal and a 50% interest in a 1500 MW power plant in Sergipe, Brazil as well as two other FSRU terminals with 1200 MW of power in advanced stages in Brazil. Hygo's fleet consists of a newbuild FSRU and two operating LNG carriers. NFE will also acquire GMLP's fleet of six FSRUs, four LNG carriers, and a 50% interest in Trains 1 and 2 of the Hilli, a floating liquefaction vessel.
  • Gás Natural Açu, a joint venture of bp, Siemens AG and Prumo Logística, controlled by EIG Global Energy Partners, completed the receipt of the first cargo of LNG at its regasification terminal, in Porto do Açu, Brazil, GNA said on 6 January 2021.