Trend of Natural Gas and LNG Prices
Assessed spot LNG prices in Northeast Asia (JKM) for delivery in the next month fell to its new record low of USD 2.622 per million Btu on 30 March 2020, undercutting the previous low of USD 2.713 on 14 February 2020, and further declined to USD 2.263 on 1 April 2020. After only brief recovery, further declined to another record low of USD 1.925 for delivery in June on 24 April 2020. They have been below USD 2.5, in the historically low level. In early March, increasing import volumes by India and recovering economic activities in some areas in China had led to gradual recovery of JKM. However, as India’s government implemented the lockdown to stop the spread of the COVID-19 starting on 25 March and some Indian companies declared force majeure on LNG cargo deliveries, spot LNG prices turned to plunge. It should be noted that assessed prices do not always reflect actual deals, therefore careful observation is essential. The average spot LNG price was not published by METI because only less than two companies reported such prices. (USD 5.5 in February 2020).
- While the Henry Hub price in the United States for delivery in next month went down by USD 0.04 in March 2020 to USD 1.64 at the end of the month. It has been below USD 2 since 20 January. On 2 April, it settled at USD 1.552, the lowest in the past decade. The higher average temperature than normal (higher than the average from 1981 to 2010), steady gas production, which has been in a historically high level (33-straight-month year-on-year increase until January), and uncertainty of gas demand due to worldwide travel restriction and lockdowns amid COVID-19 spread, have resulted in historically low prices. Meanwhile the TTF price in the Netherland for delivery in the next month went down by USD 0.64 in March 2020 to USD 2.22 equivalent at the end of the month. The TTF price had been around USD 3 from early to middle of March, and then stayed in low of USD 2s in early April 2020 and fell to USD 1.83 on 24 April 2020. The lockdowns implemented in Europe to stop the spread of COVID-19 have caused a stagnation in economy, leading to the very low natural gas prices.
- Japan's average LNG import price of USD 9.53 in March 2020 was 2.71 times as high as JKM for delivery in March 2020 (assessed between mid- January 2020 and mid-February 2020) at USD 3.52. The gap was higher than 1.76 of February. The average landed prices of LNG to Japan from the United States and ASEAN region in March were USD 8.92 and USD 9.38, respectively to undercut the overall average of USD 9.53. Meanwhile, most of long-term contract prices to buy LNG in Japan link to oil index except for LNG from the United States, therefore, the collapse of crude oil prices, especially after 9 March, is expected to affect long-term contract LNG prices. As the crude oil prices imported into Japan are generally reflected in LNG contract prices three months later, the lower LNG prices are expected from July.
Mid- to long-term trend
- During the last 10 years, Japan's average LNG import price fell from the peak in USD 18s in 2012, largely due to the downward trend in crude oil prices, to which long-term contract LNG prices are pegged. Except in August 2019, when it rose to USD 10.13, the average price has since April 2019 largely stayed below USD 10.
- JKM declined from around USD 10 for January in 2019 delivery to the middle of USD 4 for July - October 2019 delivery. After JKM for delivery from November 2019 to January 2020 briefly stayed at around USD 6, JKM declined dramatically to the early USD 2s for May 2020 delivery. This is a historically remarkable decline to also a historically low level. JKM, which in recent years moved in the range between European spot gas prices at the lower end and crude oil equivalent at the higher end, stayed near the lower end in 2019. In addition, since June 2019 the JKM has largely been at the historic lows.
- Japan's average LNG import price was 1.6 - 2 times higher than the average JKM for delivery in each month in the second quarter of the year (assessed between one-and-half and half-a-month prior to delivery), and was more than two times higher than the JKM from July to October, representing the largest relative gap between the two since 2011. This seems to be due to ongoing massive LNG supply capacity expansions mainly from the United States, weaker appetite for LNG in Asia, particularly from the traditional three LNG markets in Northeast Asia, and uncertainty of gas demand amid COVID-19 spread. Combined LNG imports by Japan, Korea and Chinese Taipei during the first quarter of 2020 increased year-on-year by 3.9%, or 1.43 million tonnes, they were still smaller by 9%, or 3.66 million tonnes, than those during the same months in 2018.
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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© 2020 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 inventory as of the end of December 2019 stood at 4.53 million tonnes, a decrease by 11.9% from the preceding month and by 8.2% from one year earlier. The inventories are lower than last year's inventories, which were the largest since the start of statistics in 2008. But they remain above the last five-year average. LNG consumption for city-gas stood at 3.04 million tonnes, increasing by 24.6% month-on-month in December 2019, and exceeded 2.75 million tonnes received by city-gas companies by 0.29 million tonnes. As a result, the LNG inventory for city-gas supply in the month was 2.3 million tonnes, 11.6% lower than November 2019 and 1.0% higher than December 2018. The LNG inventory for incumbent electric power utility companies in December 2019 was 2.44 million tonnes, decreasing by 12.1% from November 2019 and 16.1% lower than December 2018, as gas-fired power generation output by incumbent electric power companies increased by 25.3% month-on-month in December 2019.
- Domestic LNG inventories over the past decade have been on an increasing trend. Due to the restart of nuclear power plants and the increase in renewable energy, LNG imports and consumption decreased from the peak in FY2014, and LNG inventory temporarily decreased. But it started to increase again in FY2018 and have been at record levels since the start of statistics. Nuclear power plant restarts and a decrease in heating and cooling energy demand seems to be the main cause of the increase in the inventories. However, as imported LNG without destination clauses from the United States and other countries has been gradually increasing, Japan's energy companies may not be only stockpiling LNG voluntarily for the stability of gas supply but also gradually using LNG terminals in Japan as a cushion for their trading activities.
- Japan's LNG inventory levels have been generally high relative to the country's LNG consumption levels, as the country is almost entirely dependent on imported LNG for its natural gas supply. In Europe and the United States, there are many underground gas storage facilities, LNG inventory levels are relatively low compared to Japan. Assuming that LNG cargoes heading to Japan are counted on, additional 1.5 million tonnes should be added to the inventory volumes.
- Moreover, more than 60% of LNG is used by electric power companies, who also have different sources of power production and use LNG more or less as backup sources to adjust gaps or surplus of their total power generation. In recent years, operational performances of the country's nuclear power reactors, as well as increasing power supply from renewable energy sources, have dramatically changed the operation of LNG inventories. This is the one of the main reasons why the total inventory levels at the end of November 2018 and 2019 reached almost 5 million tonnes.
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.
- As of 17 April 2020, working gas in underground natural gas storage in the United States was 2,140 Bcf, an 7.8% increase in one month, according to data from the U.S. Energy Information Administration (EIA). As the demand period for heating has ended, gas inventories have increased since the previous week, and it is expected that gas inventories will increase hereafter in view of the trend for the past five years. Gas inventories on 17 April 2020 increased by 60%, 801 Bcf compared to the same period in 2019. And they were 364 Bcf higher than the past five-years average of 1,776 Bcf.
- According to the Short-Term Energy Outlook released by the EIA in early April 2020, the EIA forecasts that the working natural gas in storage will be 3.9 Tcf increased by 1.9 Tcf at the end of October 2020.
- The maximum inventory of working gas in underground natural gas storage in the United States over the past 10 years has been around 4 Tcf. However, according to the EIA database, natural gas production increased by more than 20%, natural gas consumption increased by more than 14%, and natural gas exports increased by more than 45% between 2017 and 2019 in the country, changing gas supply and demand dynamics dramatically. In addition to the temperature trends in the winter heating period, various factors including domestic natural gas prices and LNG exports are expected to have more impacts on natural gas inventories.
- Underground natural gas storage facilities in the country generally inject more gas in summer starting in April and send out more gas in winter starting in November. Those trends have been created by the need to use more gas in heating in winter and by commercial motivations to buy gas cheap in lower demand periods between April and October and sell at higher prices in winter peak demand periods. Those trends have in recent years, however, to some extent been moderated by increasing use of natural gas in power generation, particularly in summer peak periods, increasing LNG exports, and increasing gas exports by pipeline to Mexico, with the inventory peak declining in 2017 and 2018. In 2019, LNG storage volumes have increased as growth in domestic gas production has offset increasing consumption and exports.
Compiled based on data from the U.S. Energy Information Administration (EIA)
- As of 25 April 2020, 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) was 673 TWh or 10.3% higher than one month ago. The gas inventory had been increasing since 2 April and it was still 162 TWh or 31.8% higher than one year earlier, and 312 TWh higher than the five-year average, and the highest in the history. The stored volume represented 60.8% on 25 April 2020 of the working capacity, still staying significantly higher than the past five-year range of 19% - 42% at the time of the year.
- As the storage capacity of European natural gas in the last 10 years increased by approximately 80% from 600 TWh to 1,100 TWh, the maximum of gas inventory has been increasing accordingly. The maximum stored volume from 2016 to 2018 was approximately 1,000 TWh. However, in 2019, due to the rapid increase in natural gas imports and the warm winter in Europe, gas inventory reached a record high of 1,084 TWh. The gas inventory at the end of the winter heating at the end of March should be usually the lowest for the year, while the gas inventory at the end of March 2020 was approximately 600 TWh.
- Those storage facilities generally inject more gas in summer starting in April and send out more gas in winter starting in November, with storage levels going up to 80% or more than 90% of the working capacity at the end of injection period. Storage levels go down to 20% - 30% at the end of the withdrawal period. However, in recent couple of years, fluctuations in stored volumes have increased partly because of extreme weather conditions as well as commercial motivations of shippers of those gas storage facilities. The extreme winter cold of early part of 2018 drove down the total storage level to 18% at the end of March that year. The flood of LNG volumes imported into the region starting from the latter half of 2018 has increased volumes in gas storage in summer and autumn 2019, to nearly full capacity. The occupancy rate continued being high even during the winter withdrawal season.
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
- Operating companies of existing LNG production projects have made great efforts to ensure stable operations amid COVID-19 outbreak. Slowing down in investment activities for future LNG projects has been already apparent, as many companies revise down their capital expenditure plans. It is essential for those projects that have been already reached investment decisions and under construction to proceed with maximum emphasis on safety and health of people involved. As restrictions in goods, equipment and service procurements are anticipated for those projects, the industry has to keep vigilant eyes on project schedules and expected LNG supply capacity from the projects.
- The Federal Energy Regulatory Commission (FERC) granted authorization in the middle of March to construct and operate the Jordan Cove LNG project and the associated Pacific Connector gas pipeline project.
- Energy Transfer announced on 30 March that it will take over development of the Lake Charles LNG export project following Shell's announcement that it has decided not to invest in the project. Energy Transfer will evaluate alternatives to advance the project, including the possibility of bringing in other equity partners and reducing the size of the project from three trains (16.45 million tonnes per year of LNG capacity) to two trains.
- Sempra Energy announced on 3 March that Port Arthur LNG and Bechtel Oil, Gas, and Chemicals have signed a fixed-price engineering, procurement and construction (EPC) contract for the Port Arthur LNG liquefaction project. However, Sempra revealed that it no longer commits to a third quarter investment decision on the project.
- Sempra Energy's Energía Costa Azul LNG liquefaction-export project, in Baja California, Mexico, signed a fixed-price, lump-sum, turn-key engineering, procurement and construction (EPC) contract for the phase 1 with Technip FMC in March 2020. Energía Costa Azul LNG is targeting a final investment decision in the second quarter of 2020, a one-quarter delay to its earlier schedule.
- In late March, Dominion Energy of the United States acquired small-scale LNG specialist company Pivotal LNG from Southern Company. Dominion assumes 100% ownership of Pivotal's LNG facility in Trussville, Alabama and a 50% ownership of the JAX LNG facility in Jacksonville, Florida.
- Shell Australia announced a final investment decision on 17 April to develop the first phase of Surat Gas Project in Queensland, Australia, owned by Arrow Energy which is a joint venture between Shell and PetroChina. The phase will produce up to 90 billion cubic feet (1.87 million tonnes) per year of gas at peak production, which will flow to QGC to be sold locally and exported through its plant on Curtis Island. First gas is expected in 2021.
- Woodside revealed on 27 March that it has deferred targeted final investment decisions for Scarborough, Pluto Train 2 and Browse in Australia to 2021.
- Santos revealed that a final investment decision on the Barossa project, which will backfill Darwin LNG, will be postponed beyond 2020. The acquisition of assets in Northern Australia including a controlling interest in Darwin LNG and Bayu-Undan from ConocoPhillips is expected to complete in the first half of 2020 (previously scheduled in the first quarter).
- Spain's gas trading platform operator MIBGAS launched on 1 April the trading of LNG spot products in a single point or virtual tank where all the transactions, that until now were carried out individually in each of the six regasification terminals, are grouped.
- Spain's competition regulator CNMC approved a new system to allocate capacity in LNG regasification terminals, the transmission grid and underground gas storage. The process will be done through auctions between the different operators interested in contracting capacity in the gas system and will be implemented from October 2020.
- On 1 April, Höegh LNG applied for an LNG infrastructure ownership, operations and development license in Cyprus. The plan envisages an FSRU to be able to start LNG import operations during the second half of 2021.
- Brazil's State Government of Pernambuco and Golar Power signed on 13 March a Protocol of Intentions to develop an LNG import terminal in the Port of Suape, northeast of Brazil, with operations to start in the second half of 2020. Golar will work in partnership with the local gas distribution company Copergás. The project is to use an existing LNG carrier, permanently docked at the port.
- In the middle of April, Qatar Petroleum announced the start of the development drilling campaign for the North Field East Project (previously known as the North Field Expansion Project). This phase will increase Qatar's LNG production capacity from 77 to 110 million tonnes per year. The second phase North Field South Project will further increase capacity from 110 to 126 million tonnes per year.
- Golar LNG revealed on 7 April that the company had received notification of a force majeure claim from BP relating to the Greater Tortue Ahmeyim project. BP claims that it is not able to be ready to receive the floating LNG facility "GIMI" on the target connection date in 2022. BP’s partner company in the project, Kosmos Energy announced that restrictions arising from the coronavirus have had an impact on time-critical workstreams, including the construction of the breakwater and the project timeline is expected to be delayed by 1 year, with first gas now expected in the first half of 2023.
- ExxonMobil revealed on 7 April that it is reducing its 2020 capital spending by 30% and a final investment decision for the Rovuma LNG project in Mozambique has been delayed beyond 2020.