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LNG demand: buyers’ strategies in Asia and the Middle East, 2020-2030

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This article is the second in what will be a three-part series. The previous article, LNG Markets: the race for supply, 2020-2025, explained how the 120 – 150 Mtpa of extra LNG capacity expected by 2024 is likely to break down by supplier.

This follow up piece examines which of the world’s Asian and Middle Eastern LNG consumers will absorb these additional volumes, and how buyers’ strategies are likely to evolve over the coming decade.

Global LNG demand can be divided among countries according to the history of LNG penetration into their energy mix:

  1. Traditional Asian utilities in Japan, Korea and Taiwan
  2. New big LNG buyers in China and India
  3. Consumers in emerging economies around the globe
  4. Middle-Eastern countries
  5. European energy players.

This article will restrict itself to LNG demand from consumers located “East of Suez” – i.e. the Asian and Middle Eastern buyers.

These buyers imported 75% of total shipped LNG in 2018 according to GIIGNL and IGU’s annual reports.

The one-million-dollar question addressed by this article is as follows: How and where will the LNG produced from 2020 onwards find its way to market?

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Traditional Asian Utilities

A rough estimate of the need just for renewing current contracted LNG quantities in Japan, South Korea and Taiwan ranges between 40 and 43 Mtpa. Let’s see how LNG purchasing may develop, country by country.

Japan

The Japanese Utilities were instrumental to the first wave of LNG development in the 70’s in Asia. They are still the world’s largest LNG buyers, even if 2018 marked the lowest level of imports since 2011 (the year of the Fukushima disaster).

The recent liberalisation initiatives in the domestic markets for natural gas and power, coupled with the Fukushima disaster, have had a transformative effect on the regional utilities.

Once exclusively “buyers”, these utilities have evolved into active international actors which compete with their historical partners (the “shoshas”, or trading companies) to get a foot into upstream gas reserves and trading activities.

By the same token, the government-sponsored upstream companies Inpex and Japex have turned into natural gas providers competing with the big utilities in Japan.

A snapshot of 2018 shows a total contracted quantity of 90 Mtpa of LNG distributed among Japanese buyers. This breaks down into 34.5 Mtpa for JERA, 15 Mtpa for Tokyo Gas, 10 Mtpa for Osaka Gas, 8.5 Mtpa for Kansai EPC, 3.6 Mtpa for Tohoku EPC, 3 Mtpa for Kyushu EPC and the remaining 7 Mtpa scattered among smaller regional gas or power distribution companies (Saibu Gas, Hiroshima Gas, Hokkaido Gas, Chugoku EPC, etc…), a steel maker (Nippon Steel), the main shoshas plus Inpex and Japex.

It is worth noting that actual Japanese imports in 2018 totalled 83.3 Mton according to IGU, 7 Mton less than contractual commitments.

The future trends of LNG consumption in Japan have been commented on ad nauseum and nobody really knows what Japan’s future energy mix might look like.

However, the main actors are positioning themselves according to this uncertain future through strategic changes like: i) building a sound trading team (JERA), ii) signing shorter-term contracts and/or buying FOB contracts from US LNG developers (JERA, Osaka Gas, Tokyo Gas), iii) investing abroad both in the upstream sector (Mitsubishi, Mitsui, Sumitomo and Inpex) and in LNG terminal ventures (Mitsubishi, Tokyo Gas, JERA), etc.

By 2025, 28 Mtpa of current long-term contracts would have to be extended or renewed, should internal demand in each sector remain constant. Of this volume, JERA would account for 14Mtpa, Tokyo Gas for 5Mtpa, Kansai EPC for 2.6Mtpa, Osaka Gas for 2.5Mtpa, Tohoku EPC for 1.5Mtpa and Kyushu EPC for 1.3Mtpa.

The new landscape for Japanese LNG companies should, however, incorporate the need for utilities to “go abroad” and invest in downstream future projects, like Tokyo Gas is doing in Vietnam and the Philippines and JERA in South Australia.

In other words, investment overseas means that Japanese LNG buyers could purchase more LNG than they need domestically. The role of Mitsubishi, Mitsui, Sumitomo, Itochu and other shoshas is therefore to provide their traditional national partners with LNG from the projects they have been investing in, be they in the US, Canada or Mozambique.

Finally, the LNG industrial complex in Japan is such a high national stake across different sectors - including construction companies (JGC, Chyoda) and shipping companies (Mitsubishi, Kawasaki Heavy Industries, NYK, etc) – that we should not discard Japan too quickly from the future landscape for LNG.

South-Korea

The Korean LNG landscape has changed from being dominated by a sole importer (KOGAS, who contracted 32.7 Mtpa of LNG in 2018) into a more diversified and competitive market with many new buyers.

These include the refiner GS-Caltex (1.9 Mtpa), steel maker POSCO (0.6 Mtpa), and power producers like the Korea Electric Power Company, KEPCO (0.4 Mtpa), SK E&S (1.4 Mtpa) and Korea Midland Power, KOMIPO, who recently signed an MOU with LNG trader Vitol.

For 2018, on top of the 37 Mton of LNG contracted by Korean buyers, 7 Mton have been imported into the country on a spot basis, representing 16% of the total of 44 Mton of LNG imported.

Knowing that 2 Mton of LNG could have been supplied under the KOGAS contract with Yemen LNG, and knowing that some quantities have already been contracted long-term from the US (Freeport LNG), it is worth speculating whether there will be new long-term contracting activity from Korean LNG actors to make-up for the spot quantities.

Actual demand for LNG-to-power will always be a function of the availability of nuclear plants, which is not always predictable. Moreover, new demand for bunkering is still difficult to quantify.

Nevertheless, there will be a need to renew long-term contracts from Brunei and Malaysia which terminate by 2024, for about 3 Mtpa at least.

But the bulk of quantities to be extended or replaced by 2025 for KOGAS and its competitors consists of 4.2 Mtpa from the current contract with Oman plus 4.9 Mtpa from Qatar (Rasgas).

In other words, more than 12 Mtpa are to be contracted in the time frame under consideration. However, KOGAS’s 5% share in LNG Canada and its 10% share in Rovuma LNG will certainly reduce the need for new contracts with third-parties, as they would give priority to their “equity” LNG.

Like in Japan, the stakes are high for the LNG shipping industry in Korea, by far the foremost provider of new-built LNG tankers, including the now famous Arctic-7 icebreaking tankers needed for the Arctic LNG plants of Novatek in the Yamal peninsula.

Taiwan

Still the sole importer of LNG into Taiwan, CPC (the China Petroleum Corporation) imported 16.8 Mton of LNG in 2018 through its two southern terminals in Kaohsiung, Taichung & Yung-An. The company will have to extend or replace a 2 Mtpa contract it has with Petronas by 2024.

The current long-term LNG providers to CPC, apart from Petronas (Malaysia), are Rasgas (Qatar), Ichthys-LNG (Australia), PNG-LNG (Papua New Guinea) and portfolio players like Shell and Engie (now Total).

CPC has plans to build a new terminal in the north, atTaoyuan. The gas will be used by Tai-Power for power generation starting in 2023, with a first operational phase of 3 Mtpa.

In August 2018, CPC contracted 2 Mtpa from Cheniere for 25 years, starting in 2021. The contract was notable for achieving a change in pricing (to a Henry Hub indexed arrangement) and political diversification.

Taiwan’s long-term strategy is to build 30 Mtpa of regas capacity. CPC have said that they will count on Russia, through the Sakhalin LNG project, and the US through Alaska LNGto contract LNG on long-term basis. Shorter contracts may not be excluded if necessary.

New Big LNG Buyers in China and India

China

After a first phase in which 21 LNG terminals (67 Mtpa of regas capacity) were built by the Big Three national gas companies (CNOOC, CNPC’s Petrochina and SINOPEC) based on long-term contracts, the Chinese gas industry is now diversifying its LNG usage.

Smaller regional companies have started building terminals (like ENN at Zhejiang) and/or buying from the Big Three and distributing LNG and natural gas over the country by a range of means - including trucks, trains and river barges.

The big increase in imports from 2017 (39 Mton) to 2018 (54 Mton) has been commented on at length by analysts as proof that the future of LNG demand will rely on China.

Three new LNG terminals totalling 9 Mtpa in regas capacity are currently under construction, and there are rumours of a plan to increase that number by fifty terminals for a new total of 250 Mtpa of regas capacity.

Notwithstanding planned terminal additions, the current view from analysts is that 2019 will witness an increase in imports half the size of last year’s increase.

Rosy estimates of Chinese demand growth should be tempered with a more moderate view of energy competition within China.

First-of-all, long-term planning by the Big Three was based on investment decisions by the Chinese authorities, and did not necessarily reflect actual end-users demand. Thus there is a discrepancy between long-term contractual commitments with international LNG sellers and the ability of regional natural gas markets to absorb both volumes and prices.

Further top-down incentives to replace coal with LNG could lead to huge theoretical demand for LNG. Limitation on coal imports would do the same.

China has the potential to absorb huge quantities of LNG planned by suppliers around the world. But we should not forget that the US was deemed the final destination for a number of LNG projects launched in the late 90’s (Qatar, Nigeria, Angola, Yemen, etc) that ended up being diverted to Japan instead after the shut down of its nuclear fleet.

India

India also has big plans for LNG usage, but the actual capacity for burning natural gas downstream of the existing import facilities has been slow to materialize.

The operational regas capacity as of 2018 was 27 Mtpa, primarily on the Western coast. recent inauguration of the Indian Oil Company (IOC) Ennore terminal adds 5 Mtpa to the 2018 figure. This target is to increase the total regasification capacity to 57 Mtpa by 2025.

According to GIIGNL, India imported around 19.3 Mton of LNG in 2017. A 20% increase can be gleaned from official statistics for 2018 (23.3 Mton according to IGU). And various analysts are predicting another 10% increase in imports for 2019, essentially subject to price level.

The main actors in Indian LNG are big national companies like Petronet and GSPC as front-runners, as well as IOL, GAIL, BPCL and ONGC. These companies are in competition with private-sector players like Reliance, Shell, Total and BP for the growing end-user market, including the fertilizer and steel industries. Power generation is currently less of a consideration as coal currently occupies the lion’s share.

On the supply side, Rasgas in Qatar and Austria began long-term first flows of LNG to India through the Dahej terminal in Gujarat. Meanwhile Shell and Total were assuring mid-term and spot deals to the local market thanks to their terminal venture in Hazira, Gujarat.

Russia, the US and Mozambique will become more and more pertinent to Indian imports thanks to a slew of contractual arrangements. These include pure sale-and-purchase contracts with Gazprom and Cheniere, and upstream participation in Mozambican exploration blocks which will lead to stakeholders’ off-takes from the Rovuma LNG project on an equity basis.

The price-sensitive Indian LNG market is also attracted to dealing with LNG Traders around the world, be it International Oil Companies’ LNG portfolios or pure trading firms like Vitol, Gunvor, Trafigura, etc.

The deciding factors for India’s potential to swallow big chunks of LNG remain its capacity to build and operate LNG terminals and associated downstream pipelines, as well as access to flexible LNG at a price convenient to switch from naptha, coal or other fuels that still make up the lion’s share of Indian energy mix.

Emerging economies’ LNG consumers (East of Suez)

The search for new LNG markets has seen initiatives from the big suppliers to promote power generation in developing economies around the LNG-to-Power concept. Examples include Myanmar, Ghana, Côte d’Ivoire, Indonesia, South-Africa, Brazil, The Philippines, and others.

The emergence of FSRUs has also successfully paved the way for Middle-Eastern countries/emirates like Abu Dhabi, Kuwait, Fujairah and Bahrain to import LNG. Israel and Egypt also numbered among these countries before achieving natural gas self-sufficiency.

More recently, Pakistan and Bangladesh joined the pack and are currently importing LNG via FSRUs. These two economies do represent probably the biggest potential for a substantial increase in world-wide LNG demand in the 2020 – 2030 timeframe.

Pakistan

Long-awaited FSRU’s are now operating in the Channel of Karachi. According to GIIGNL Pakistan imported 6.86 Mtons in 2018, although long-term commitments from the national Pakistan State Oil company amounted to 5 Mtpa.

The difference has been imported through tenders with several LNG players who originated their cargoes from eight different countries - Trinidad & Tobago, Angola, Algeria, Oman, the US, Norway and two countries in West Africa.

With two FSRU’s in operation and at least three different known projects planned for the future, Pakistan is definitely on track to become a substantial buyer of LNG.

For the immediate future Qatar will remain the main “baseload” supplier of Pakistan LNG Limited, even if price levels from its long-term contracts are higher than those of competitors like ENI and Gunvor (which were the result of a tendering process) for obvious geopolitical reasons.

Saudi Aramco’s recent offer to supply Pakistan with LNG they don’t yet produce proves that Saudi Arabia wants a share in its ally’s future supply – and that they don’t want to leave Pakistan’s supply security in the hands of Qatar.

However, as the gas industry develops in Pakistan, we could see private investors take internal market risks and import LNG from international suppliers. This will above all be the case when the LNG suppliers have also been involved in establish terminal projects, as with Mitsubishi, ExxonMobil, Shell, Total and others.

Bangladesh

Hopes for new domestic gas production in Bangladesh have been fading. This has led to the decision to import LNG in the Chittagong area, which lacks fuel to sustain the power demand increase brought about by its local industries.

There are also plans to add LNG receiving terminals to the current two FSRUs in the Cox Bazar area, which could lead to greater LNG import volumes in the future, provided that there is sufficient infrastructure for natural gas to be used in the wider area.

As with many new and developing markets, pricing is of the essence, and future demand for the fuel is highly linked to affordability.

It is Interesting to note that a supply route from India could in theory also feed the need for natural gas in the Dhaka area. But this can only happen if and when the Kolkata terminal in India materializes, and if the relationships between the two countries take a positive turn.

The Middle-East FSRUs

Bahrain LNG’s Hidd LNG terminal will be the latest FSRU to be commissioned in the Gulf countries in May this year.

Kuwait, Jordan and UAE are currently the main importers of LNG in this region, totalling 6.86 Mton in 2018 (9.12 Mton in 2017) through their respective FSRUs.

Any future trend in natural gas consumption in this politically sensitive region is very difficult to predict. Affordability levels at least will not be the key issue, as sellers know there is less risk of demand curtailment as a result of higher prices.

However, the recent announcements and contractual moves by ADNOC and Aramco concerning their future natural gas policy point to a substantial revamp of the region’s supply-demand scheme.

Preference will be given to domestic production in the long-term while these national companies are entering the LNG trading business to satisfy their short-term needs and prepare for the future.

One objective for buyers will be to try to circumvent Qatar as a main LNG supplier in the region over short-term. Another will be to build an LNG position to remain relevant in the future, as players in the region understand that crude oil will not remain politically acceptable over the long-term.

LNG-to-Power in South-East Asia

Contracts have been signed in Myanmar, Vietnam, the Philippines and Indonesia to help develop LNG-to-Power projects involving LNG actors like Pertamina, Total and Tokyo Gas, who will leverage their LNG portfolios to ensure supply.

Government-to-government approaches in Sri Lanka are targeting the same objective: to displace coal and/or fuel oil from power generation in developing economies. Partial coal indexation in LNG pricing for that purpose makes sound commercial sense.

Each case takes place in a different geopolitical context, and it would be presumptuous to draw any solid conclusion as to whether these projects will swallow a sizeable chunk of new LNG supply given the level of uncertainty involved.

Preliminary conclusions

As demonstrated above, there is huge potential for increased LNG demand East-of-Suez in the years to come. The LNG eventually produced will find its way to end-markets provided prices are reasonably attractive to end-users. Oil linkage in LNG pricing may not persist through to the time of contractual termination for the historical LNG buyers.

The 75/25 ratio between East-of-Suez and Atlantic basin end-users may also change when Europe awakes and absorbs more LNG than it used to do. Extended price parity between the two basins is not far away.

The next post in this series will tackle European LNG penetration, and could bring some positive surprises concerning LNG final consumption.

About Guy Broggi

Guy Broggi, retired from TOTAL since 1/1/2018, entered the company in 1978 as an expert in data treatment for geosciences after he graduated from “Ecole des Mines” (Nancy, France) and after serving a two-year position as Professor at IAP, Algeria (Algerian Petroleum Institute). He works now as an independent consultant on LNG markets and can work in three languages: English, Spanish and French, his mother tongue. In 2011 he was appointed Senior Advisor to the LNG Director in Total’s Paris Headquarters after having been in charge of the LNG Supply for the group LNG portfolio. (2006-2011). A member of the IGU LNG committee, he was active also as a member of Governing Bodies of the main international LNG and European gas conferences. Before that, he held several commercial positions related to the development of TOTAL LNG business in Jakarta and Tokyo (1988-1995), Commercial Director for TOTAL E&P subsidiaries in Argentina (1998-2001) and the UK (2002-2006) where he helped create TOTAL LNG desk in London. His first assignment at E&P Division at TOTAL was dedicated to data treatment for geosciences first and economic evaluations after his return from a one-year sabbatical in 1985.

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