Trend of Natural Gas and LNG Prices

Short-term trend

• The assessed spot LNG price JKM for delivery to Northeast Asia was temporarily under USD 6.5 per million Btu in the middle of November due to the modest winter temperature in the month and concerns over a drop in demand caused by strengthened measures to contain further spread of Covid-19. However, by 15 December (for delivery in January 2021), the price rose to USD 12.4, twice as much as the previous month. It was the first time to surpass USD 12 since September 2018. This was contributed by several factors: the concerns over frequent supply disruptions, the cold weather in Northeast Asia increasing demand for cargoes, Korea’s plan to stop some coal-fired power plants during winter, increasing freights, as well as congestion at the Panama Canal. Then, as of December 23, the JKM for delivery in January 2021 was USD 11.6. The average spot LNG price published by METI was USD 6.5 for November delivery (USD 1.6 higher than October).
• The Henry Hub price for delivery in the following month was at USD 2.68 as of 15 December 2020. The price rose to above USD 3 in late October and hovered around the level in early November contributed by the domestic heating demand in winter and modest natural gas production, as well as increasing LNG exports. However, natural gas demand did not increase much as the temperature was higher for the season with mild weather in November and early December, resulting in a rapid fall of the price in early December. The expanded price gap between HH and Asian LNG is expected to further stimulate LNG exports from the United States. Furthermore, as the natural gas production in December is expected to be lower than in November with demand increasing in winter, the HH price is forecasted to increase.
• The TTF price for delivery in the following month was at USD 6.2 as of 23 December. On 15 December, the price broke the USD 6 mark for the first time since February 2019. It was at above USD 5 and had been staying around USD 5 since late October, and it started to increase from 10 December, reflecting the increase of demand for winter and soaring Asian LNG prices. As the European gas storage utilization decreases and demand increase further, the TTF price is expected to remain at the level for the next couple of months. 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 6.41 in November 2020. The average landed prices of LNG in Japan from Asia and the Middle East in the month were USD 6.22 and USD 6.05, respectively, which were below the country’s overall average of USD 6.41. On the other hand, the average landed price of LNG in Japan from the United States in the same month was USD 6.93, higher than the overall average. Also, the gap between Japan’s average LNG import price (USD 6.41) and JKM’s average delivery price (USD 5.15) narrowed from 300% at a time to 24% in November. In addition, the average spot LNG price published by METI surpassed the average LNG import price for the first time since November 2018. Japan imported 6.019 million tonnes of LNG in November 2020, 4.0% lower than the previous year and the lowest for November in the past ten years.

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.
• The JKM price for delivery between November 2019 and January 2020 briefly stayed at around USD 6 and declined dramatically to below USD 2 in late April for delivery in June 2020. This is a remarkable decline to a historically low level. In recent years, the JKM price was within the range between the lower end of European spot gas prices and the higher end of crude oil equivalent prices and has remained near the lower end of European spot prices since 2019. However, the spread between JKM and TTF started to widen since the middle of October 2020, and JKM further increased to USD 12 in December 2020, which was even higher than the oil equivalent prices.
• Japan's average LNG import price had been significantly higher than the JKM price. The reason for this trend is believed to be that a high percentage of LNG was procured under long-term contracts. Also, 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 high levels of inventories all contributed to the low demand for spot LNG cargoes.
• The combined LNG imports by Japan, Korea, and Chinese Taipei from January to November of 2020 decreased year-on-year by 2.1%, or 2.52 million tonnes, and were less by 8.6%, or 11.18 million tonnes than those during the same period in 2018.

Trend of Natural Gas and LNG Inventories

Japan

• Japan's LNG inventories as of the end of August 2020 stood at 3.90 million tonnes, a decrease of 21.6%, 1.08 million tonnes, from the preceding month, and a decrease of 5.4% from one year earlier. This is the first time that the inventories decreased by more than 1 million tonnes from the previous month since the start of statistics in 2008. The inventories of July 2020 were the highest in July since the start of statistics in 2008, but the inventories of August were roughly equal to the average in the past five years.
• The LNG inventories for the city-gas supply in August was 1.92 million tonnes, 9.3% lower than July 2020, and 4.1% lower than August 2019. LNG consumption for city-gas stood at 2.35 million tonnes, decreasing by 0.9% year-on-year in August 2020. City-gas companies received 2.03 million tonnes of LNG in August, which is a decline year-on-year of 10.4%. LNG consumption for city-gas was lower than the previous year since April 2020 due to Covid-19 but recovered almost the same level year-on-year in August 2020 because of increased demand from residential and other sectors. The LNG inventories declined in August as the consumption was more than the receipts.
• The LNG inventories for power generation in August 2020 were 1.98 million tonnes, decreasing by 30.8% from July 2020 and 6.6% lower than August 2019. Monthly gas-fired power generation output increased from the previous year for the first time in the year in August, mainly because of the impact of rising space cooling demand from the heat weave. As a result, the LNG inventories for power generation decreased by 0.88 million tonnes from July 2020.
• According to the Japan Meteorological Agency's forecast, the La Niña phenomenon will likely continue. The average temperature between December and February is expected to be at the same level or lower than previous years in the southern region of Tohoku. 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. However, the LNG demand would increase, and the inventories could be lower than those in 2019/2020 winter if the forecast remains the same. On the other hand, there are also concerns that demand for gas may slump again due to the re-emergence of COVID-19 in the country, which could push up LNG inventories.

United States

• As of 18 December 2020, working gas in underground natural gas storage in the United States was 3.6 Tcf, a 9.3% decrease from the previous month, according to the U.S. Energy Information Administration (EIA). Gas inventories were 10.0% higher than those at the same time in 2019 and were higher than the past five-year average of 3.5 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 December 2020, EIA estimated that natural gas inventories in October 2020 were about 4.0 Tcf, 5% more than the five-year (2015 - 2019) average and the second-highest end-of-October level on record. EIA estimates that natural gas inventories fell by 20 Bcf in November, lower than a five-year average November withdrawal. The lower-than-expected withdrawal is the result of warmer-than-normal November temperatures that reduced natural gas use for space heating.
• EIA forecasts that the natural gas production in 2020/2021 winter is expected to be lower than 2019/2020 winter and so that the inventory withdrawals will outpace the five-year average during the heating season with inventories ending March 2021 at 1.6 Tcf, 15% lower than the 2016 - 2020 average.

Europe

• As of 22 December 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 863 TWh. The inventories were 15.5 % down from the previous month and 12.9% lower year-on-year, and 67 TWh higher than the five-year average. The inventories were at record highs in 2019, and in the first half of 2020, the inventory levels were higher than one-year-earlier levels. But since September, the inventory levels turned negative year-on-year, with inventories declining at a faster rate, especially from late November. On 22 December 2020, the working gas volume in storage was 77 % full, staying within the range of 71% - 90% in the same period over the past five years.
• LNG spot prices in Asia have soared because of three factors: a decline in LNG supply due to troubles with multiple LNG plants; an increase in LNG imports due to China's economic recovery; and the lower-than-expected temperatures in December 2020 in Northeast Asia including Japan. As a result, the working gas volume in storage in Europe is expected to remain at a lower level than in 2019.

Latest Developments in Major Natural Gas and LNG Projects

December Highlights

• Several binding and preliminary LNG sales and equity participation deals have been announced recently in different parts of the world, underwriting increasing importance of portfolio sales arrangements and utilisation of existing infrastructure in developing new LNG supply projects.

 

Asia and Oceania

• Russia's NOVATEK announced on 1 December 2020 that Novatek Gas & Power Asia Pte. Ltd. and Saibu Gas had completed their first joint trial delivery of LNG in ISO containers to China's Tiger Gas for subsequent sales of LNG in China. The LNG was delivered by sea in Tiger Gas-owned ISO containers from the Japanese Hibiki container terminal to Shanghai.
• Russia's Gazprom said on 2 December 2020 that the company kept ramping up its gas exports to China via Power of Siberia and for a second consecutive month, gas was being supplied in excess of the planned amounts. The aggregate amount of gas supplied in November totalled 113.6% of the planned volume for that month. The daily average volumes for November exceeded those for October by 16.2%. During the first year of Power of Siberia, a total of 3.84 bcm of gas was supplied to China via the trunkline.
• INPEX announced on 4 December 2020 that it had signed a memorandum of understanding (MOU) with PT Perusahaan Gas Negara Tbk (PGN) concerning the domestic LNG supply from the Abadi LNG Project. The company said that the project is expected to contribute to the use of domestic resources in Indonesia, where demand for gas is expected to grow, and to make a significant contribution to the economy of the eastern part of the country.
• Tokyo Gas announced on 26 November 2020 that its Tokyo Gas Asia subsidiary acquired 33.4% of the shares of an Indonesian gas distribution company, PT Super Energy Tbk (SE) from its parent company PT Super Capital Indonesia on 25 November 2020. On 24 November, Tokyo Gas Asia acquired approximately 18% of the shares of PT Energy Mina Abadi, a subsidiary of SE which also operates gas distribution business. SE is a gas distribution company group mainly based in Java that refines and compresses unutilized gas such as associated gas produced from oil wells and natural gas from small-scale gas fields, and supplies the gas in the form of compressed natural gas (CNG) to industrial customers.
• Energy Capital Vietnam (ECV), a U.S.-based project holding and development company established in 2015 to serve as a platform for private investment into Vietnam, announced on 8 December 2020 the formation of a Joint Venture (JV) with Gunvor International BV (Gunvor). An ECV-led consortium is developing an LNG-to-power project in Mũi Kê Gà, Bình Thuận Province, in Southeast Vietnam. In addition, Gunvor will supply LNG to the JV on a long-term basis. The fully private, multi-phase power project will connect via subsea pipeline to an offshore Floating Storage and Regasification Unit (FSRU) to import LNG. Phase I of the project is targeting Final Investment Decision (FID) in late 2021 and Commercial Operational Delivery (COD) by 2025. The project will consume approximately 1.5 million tonnes per year of LNG.
• India's H-Energy announced on 2 December 2020 that it had entered into a binding commitment with Höegh LNG for the supply of its Floating Storage and regasification Unit (FSRU) Höegh Giant under a 10-year agreement, for deployment at its LNG regasification terminal project located at Jaigarh Port in Ratnagiri district of Maharashtra, India. The FSRU will be delivered to the Jaigarh project in the first quarter of 2021. The FSRU will deliver regasified LNG to the 56 km Jaigarh-Dabhol pipeline connecting to the National Gas grid and will also deliver LNG onshore for LNG truck loading facilities. The FSRU is also capable of reloading LNG onto other LNG vessel's for providing bunkering services. The LNG terminal will become India's first FSRU based LNG regasification terminal.
• LNG Easy said in its statement on 27 November 2020 that it had signed a memorandum of understanding (MOU) with Karachi Port, Pakistan Railways and an international oil company. Karachi Port will allot fitting berths for a virtual pipeline project. It will also make arrangements for the transportation of LNG via ISO tanks via Pakistan Railways infrastructure. LNG Easy is responsible for regasifying the (LNG) at customers' site and providing gas storage units.
• Australia's Viva Energy provided on 7 December 2020 an update on its project to develop an LNG regasification terminal at the site of its Geelong refinery. The company has selected and entered into Memorandums of Understanding (MOU) with two partners in relation to the development of the project and the related capacity at the terminal. The partners comprise two consortiums, the first being a partnership between ENGIE Australia & New Zealand and Mitsui & Co., Ltd. and the second between Vitol and VTTI. An FID could be taken by mid-2022, with gas supply in 2024.
• Australia's Santos announced on 7 December 2020 that it had signed a binding long-term LNG Supply and Purchase Agreement (SPA) with Diamond Gas International Pte Ltd (DGI), a wholly-owned subsidiary of Mitsubishi Corporation, for the supply and purchase of 1.5 million tonnes per year of Santos equity LNG from Barossa for a period of ten years with extension options, at a price based on the Platts Japan Korea Marker (JKM). An FID on Barossa is targeted for the first half of 2021.

 

North America

• According to a rule by the U.S. Department of Energy (DOE) published on the Federal Register on 4 December 2020 "National Environmental Policy Act Implementing Procedures", DOE will stop conducting environmental reviews of LNG export and import projects effective 4 January 2021. LNG projects still would require environmental reviews for construction and operating permits conducted by the Federal Energy Regulatory Commission (FERC) under the National Environmental Policy Act (NEPA).
• DOE extended on 10 December 2020 the terms of seven long-term LNG export authorizations through 2050, following 10 LNG export term extensions in October pursuant to an export term policy statement DOE finalized in July. Terms were extended for the Golden Pass facility currently under construction in Sabine Pass, Texas, as well as the Texas LNG project proposed for Brownsville, Texas, the proposed Magnolia and Driftwood projects in Louisiana, and the Delfin LNG export project proposed for offshore Louisiana. The approvals also include an extended export term for Sempra Energy's Costa Azul project in Mexico.
• Cheniere Energy announced on 8 December 2020 that its first commissioning cargo for CCL's (Corpus Christi Liquefaction) Train 3 and also CCL's 200th cargo was loaded onto the La Mancha Knutsen.
• Venture Global LNG announced on 23 November 2020 that KBR had been awarded the engineering, procurement and construction (EPC) contract as lead contractor for Phase 1 of the Plaquemines LNG export project in Plaquemines Parish, Louisiana.
• On 17 December 2020, FERC approved a plan by Marathon Petroleum Corp’s Trans-Foreland Pipeline Co LLC unit to convert the Kenai liquefied natural gas (LNG) export plant in Alaska into an import terminal. Trans-Foreland said the facility would import up to four tanker loads of LNG per year to deliver imported gas to the adjacent Kenai Refinery. The Kenai LNG export plant entered service in 1969. It has not exported LNG since 2015.
• LNG Canada revealed on 27 November 2020 that the local health authority had confirmed positive COVID-19 cases among the LNG Canada workforce.
• Sempra LNG and Infraestructura Energética Nova, S.A.B. de C.V. (IEnova) announced on 9 December 2020 that their joint venture, ECA Liquefaction (ECA LNG), had signed an equity investment agreement to finalize Total's participation in the ECA LNG Phase 1 LNG export project, to be located in Baja California, Mexico. Total has acquired a 16.6% equity stake in ECA LNG Phase 1, while Sempra LNG and IEnova will each retain 41.7% ownership. Earlier in 2020, Total signed a 20-year sale and purchase agreement for approximately 1.7 million tonnes per year of LNG from the export facility.

 

Europe and Russia

• According to the European Commission (EC) website on 23 November 2020, major players in the oil and gas industry agreed to report methane emissions with a new, much higher level of transparency - the new OGMP2.0 framework. The Oil and Gas Methane Partnership (OGMP) is a Climate and Clean Air Coalition (CCAC) initiative led by the UN Environment Programme (UNEP), the European Commission (EC), and the Environmental Defense Fund (EDF). Already 62 companies, with assets on five continents representing 30% of the world's oil and gas production, have joined the partnership. In order to support the realization of global climate targets, OGMP 2.0 aims to deliver a 45% reduction in the industry's methane emissions by 2025, and a 60-75% reduction by 2030. The OGMP 2.0 includes not only a company's own operations, but also the many joint ventures. According to the announcement, the OGMP 2.0 framework applies to the full oil and gas value chain, not only upstream production, but also midstream transportation and downstream processing and refining - areas with substantial emissions potential that are often left out of reporting today.
• Fluxys said on 30 November 2020 that the Open Season for additional regasification capacity at the Zeebrugge LNG terminal had been successful. Fluxys plans to take an FID in February 2021 at the latest.
• Russia's NOVATEK announced on 1 December 2020 that Novatek Green Energy had launched its first carbon-neutral LNG fueling station in Rostock, Germany. Carbon neutral offsets from a selected portfolio of emission reduction projects, including wind generation projects in developing countries, will be used to compensate for the LNG's carbon footprint. The certification of emission reduction projects will be performed in accordance with the authoritative international standard VCS, Novatek said.
• Spain's Endesa announced on 18 November 2020 a plan to adapt its port terminal in Los Barrios, in Algeciras (Cádiz) to supply LNG to ships. It will be the largest LNG bunkering terminal in Spain.
• LNG Croatia announced on 1 December 2020 that the FSRU vessel 'LNG CROATIA' had arrived at the location of the terminal. The terminal is scheduled to start commercial operations on 1 January 2021.
• Russia's Gazprom announced on 30 November 2020 that net sales of gas to Europe and other countries decreased by RUB 748.850 billion, or 40 %, to RUB 1,135.130 billion for the first nine months of 2020 compared to the same period of the prior year. The company said that volumes of gas sold to Europe and other countries decreased by 10%, or 17.0 bcm (to 154.4 bcm from 171.4). At the same time average prices denominated in the US Dollar decreased by 40%.
• Russia's NOVATEK announced on 25 November 2020 that the overall progress of the Arctic LNG 2 project was estimated at 29%, with concrete casting of the first GBS platform estimated to be 67% completed. The modules fabrication progress for the first GBS is estimated at 46%. 17 production wells have already been drilled at the Utrenneye field with three (3) drilling rigs in operation. Two (2) more drilling rigs are expected to be mobilized before year end 2020.

 

Other regions

• Eni announced on 1 December 2020 that it had signed a series of agreements with the Arab Republic of Egypt (ARE), the Egyptian General Petroleum Corporation (EGPC), the Egyptian Natural Gas Holding Company (EGAS) and the Spanish company Naturgy, which pave the way for the restart of the Damietta liquefaction plant in Egypt by the first quarter of 2021, the amicable settlement of the pending disputes of Unión Fenosa Gas and SEGAS with EGAS and ARE and the subsequent corporate restructuring of Unión Fenosa Gas itself. The liquefaction plant's owner is the company SEGAS, which is 40% owned by Eni through Unión Fenosa Gas (50% Eni and 50% Naturgy). The plant has a capacity of 7.56 bcm per year, but has been idle since November 2012. The participation of Unión Fenosa Gas in the Damietta plant (80%) will be transferred 50% to Eni and 30% to EGAS. The resulting shareholding of SEGAS will therefore be Eni 50%, EGAS 40% and EGPC 10%. Eni will also take over the contract for the purchase of natural gas for the plant and will receive corresponding liquefaction rights, which will be available on an FOB basis, with no destination restrictions.