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Tangguh LNG plant (Image credit:

OPINION: Dynamics of LNG Global Market and Its Implications for Indonesia

By Sampe L. Purba*

Sampe L. Purba

In the midst of general industrial disruption wave, the LNG (Liquefied Natural Gas) business is, too, affected. In the 1980s LNG producers enjoyed a very comfortable industrial position. After gas was discovered, cross-country gas sales contracts were set for the long term (up to 20-30 years) and since then LNG plants have been actively built. The process of gas discovery until the first LNG shipment took no more than 5 years. Indonesian gas producers enjoyed such a comfortable position when the Arun Aceh gas field and the offshore Kalimantan gas field were discovered in the 1970s. At that time, Indonesia was the largest LNG producer in the world, with major buyers coming from Japan. In fact, most of the funds for the construction of the LNG plant came from financial institutions and corporate groups that were the main buyers of LNG (known as Western buyers). Gas producers practically did not face any market risk (in terms of volume and price) or difficulties in financing the construction of an LNG plant.

As technology advances and many gas fields are found in other countries such as Australia, Qatar and Russia, LNG products start to flood the global market. In addition, due to the availability of various other alternative energy sources, the convenience of LNG producers in the world market is reduced. This can be seen from the following facts.

First, on long and medium term contracts (3-5 years), there are relaxations of commercial terms/conditions. The average new LNG contracts and their extension now contain several clauses that are more favorable for buyers. Among these are that the price is no longer fully linked/indexed to the price of crude oil, Price Review is carried out more often within short periods, multi-destination contracts can be transferred to other destinations or buyers, the quantity of annual cargo pickup commitment is not too large(far below 1 million tons/year), buyers can drop the commitment to take cargo within a year without significant penalties, and buyers who cannot take the agreed cargo are subject to lighter and easier clause hardship excuse.

Second, short-term spot contracts are abundant. Traditionally, there are three major groups that have become benchmarks for LNG prices. European markets refer to the National Balancing Point (NBP), which is the price index on the UK Future market; the Asia Pacific market is indexed with crude oil (dominated by Japan Korea Marker – JKM for spot); while the United States market refers to the Henry Hub pipeline gas price index.

In spot/middle/retail gas contracts, such patterns are no longer found. Even though the volume of LNG traded by spot is very large, sensitive spot prices are influenced by factors that are not fundamental, such as plans to build an LNG facility (FID – Financial Investment Decision), gas bunkering capacity, weather, political tension and others. This will pose a high risk of uncertainty to business people.

Currently at early February, when the world is under the threat of the corona virus spread in the plains of China, the price of LNG spot drops to its lowest point, which is $3,512/mbtu, while the price of long-term contracts is still perched at 11% – 13% of JCC (Japan Crude Cocktail) crude oil prices. JCC is a traditional reference for long-term LNG contracts in Asia.

LNG Prices

In general, 1 barrel of crude oil is equivalent to 6-7 mbtu of gas. Taking into account the cost of LNG processing, transportation elements, insurance and gas regasification per mbtu at the receiving terminal, the LNG price of 11%-14% of crude oil in the normal case is a reasonable proxy for equilibrium prices.

Graph: LNG prices against crude oil

Source: Reuters 2020

Third, there is uncertainty in monetizing gas fields and making investment decisions (Final  Investment Decision – FID).

When a gas field has been declared commercial but its production is delayed for a long time, then it is an indication that the gas field operator is not yet convinced of the monetization of the gas it has found. In general, FID is a milestone that is believed to be a sign that a gas field will be developed. With the FID, it means that the marketing issues (price, volume and buyers) have been resolved. Likewise with the funding scheme, whether it will use corporate funds, loans on the money market or from project finance (loans with collateral repayment of debt from project results).

There are three main risks that have been calculated and can be accepted when FID is made. The first is the risk of subsurface/gas reserves, where there is a possibility that the potentially produced gas misses significantly from the estimated reserves. While in fact, these reserves are the basis for building large refinery capacities, binding purchase contracts, shipping and so on.

Second is the risk of cost overrun in an LNG plant development. This risk can generally be mitigated as soon as the refinery construction contract (EPCI – Engineering, Procurement, Construction, and Installation) is signed. If the field operator (sponsor) delays the start of construction, for example because the main buyer (anchor buyer) has not been found or has low credibility, then the financial risk is that the EPCI contractor will sue the refinery owner/sponsor to compensate for the financial losses incurred.

In some cases, if the local government appears to be very interested in the realization of an LNG plant construction, operators/interest holders in the field will use this as a bargaining position so that some of the cost overrun risk is borne by the government. Diplomacy, subtle bluffing and a sense of fairness in business are absolutely needed by negotiators representing the state/government. Depending on the EPCI contract, the risk of a cost overrun can arise due to a delayed project development schedule, significant changes in major components, such as steel or turbine prices, and major contract change orders or large reimbursable components.

The last is financial risk. The construction of an LNG plant that relies on external financing, whether in the form of corporate debt, bonds or project finance, will be exposed to financial risk, especially if the loan interest rate is a floating rate. The financial credibility of the main sponsor or the parent, as measured by the credit rating, largely determines the terms/clauses and conditions of the loan. This includes whether the sponsor has historically had operatorship experience, a broad portfolio, or the support of its country’s government. In general, creditors (investment banking and credit syndication) have their own risk appetite in measuring the credibility of operator, anchor buyers, tenors (loan term) and regulatory stability in the host country.

Current LNG Market Landscape

The current LNG producer map based on the State is as follows:

Source: US Energy Information Administration

A joint study by the International Energy Agency and the Korea Energy Economics Institution (EIA and KEEI) shows that the LNG business will still grow rapidly to meet the high demand in the Asian market. The growth is mainly in the Chinese and South Korean markets. The Japanese market will be a little stagnant because its nuclear reactor has been reactivated gradually after the Fukushima earthquake in 2011.

More than 100 billion cubic meters of new LNG capacity will enter the market between 2018 and 2023. A narrow market share, plus diversification of energy sources, including the flow of gas pipelines and LNG from Russia to the Asian region, will encourage producer countries to compete tightly in exploiting this narrow gap. Australia, Qatar, Senegal and Canada entered this competition arena by offering more flexible commercial terms.

The following chart shows the trend of increasing LNG contracts, which is more flexible, while fixed contracts are decreasing.

Source: EIA Study – KEEI, 2019

The tight competition in the LNG market was confirmed by Dr. Fesharaki, a global energy consultant, who was also very closely following the development of the oil and gas sector in Indonesia.

In an international symposium at the end of January 2020, he clearly showed the graph (below), how more than 70% of LNG projects in the world had dared to conduct FID without having an LNG purchase contract by a third party. In addition to courage, of course it was also a calculation to secure energy supplies and maintain a position in an increasingly crowded market niche.

Sources: F. Fesharaki, Facts Global Energy 2020

Indonesia’s LNG

At present Indonesia’s LNG production is around 2,000 BBTU/day, the majority of which is processed from the Bontang and Tangguh Papua refineries with a relatively balanced proportion. Bontang LNG export contracts with Japan will expire in the next 5 years. The future of the Bontang LNG plant is highly dependent on the supply of gas from the fields of the Italian company ENI and Indonesia’s own Pertamina Mahakam, as well as the ability to penetrate the export market.

Around 50% of Tangguh Papua’s field production is currently allocated to the domestic market with PT PLN as the anchor buyer. It is then distributed to various power plants throughout the archipelago (multi domestic destination). This can mean two things, that domestic use is increasing, or Indonesia fails to penetrate the export market. The real ability to extract gas allocated to PT PLN is highly dependent on national economic growth which creates additional demand for gas-based electricity.

The third hope lies in the Abadi gas field operated by INPEX Masela in the Abadi field, near the Australian border, at the southern end of the Arafura Sea in the Tanimbar islands – Maluku.

The Abadi gas field contains a very large gas reserve of 18.5 TCF and condensate of 225 million barrels. The field is projected to start production at the end of 2027, with a capacity of 10.5 million metric tons per year (9.5 mtpa LNG) and 150 mmscfd of gas.

Several things deserve attention, including:

The findings in this gas field were declared commercial at the end of 2008, but to date it has not been classified as FID. One of the reasons for this is the change in the field development scenario – what was previously planned as floating LNG (FLNG) processed at sea, was changed into a fixed gas purification facility at sea but with LNG processing/refinery on land. According to what we read in the paper, these changes were made to get a greater added value.

Indonesia should learn a lesson or two from its experience with Bontang and Tangguh Papua. In Bontang, for example, there was no need to wait 5 years since the gas field was declared commercial to realize the first shipment of LNG as it was successfully done in August 1977. President Suharto – the Father of Development – was very visionary and firm. To get foreign exchange, expensive gas was sold in the form of LNG, while for domestic needs, gas was sold cheaply to the fertilizer and petrochemical industries. Bontang forest was transformed into a modern industrial area and we still enjoy this legacy of his to this day.

The Tangguh Papua LNG Plant was built on land. However, to date no LNG has been used in Papua, even though the Government has provided allocations. The use of local gas certainly requires infrastructure such as the LNG receiving terminal and regasification. High electricity demand or local industry growth is needed to utilize gas as fertilizer and petrochemical feedstock.

To turn gas from the Abadi field into reality, it needs integrated and synergistic cooperation from all parties. Among these are the provision of locations by the government and local communities, easy fiscal permits and facilitation, the establishment of industrial estates by the Central Government complete with electricity and other public facilities, industrial development that can utilize domestic gas allocations, and open export markets. What is more important (or perhaps most important) is the seriousness and courage of the operators to immediately make FID, without having to ensure an export contract. As shown in the chart above, the current trend in the world is that operators of gas fields and LNG refineries dare to make FID by concurrently acting as an off taker (main buyer) of the generated products.

Figure: Gas Field around the Masela Block on the Australian border

Source: Google Map

For Indonesia, the Abadi gas field is not only economically valuable. The field has a strategic meaning, geopolitically and geostrategically strengthening the integrity and security of the area at the southern border. That is also the justification for the Abadi project to be included in the National Strategic Project.

Indonesia must catch up with Australia. The country, at about the same time, discovered a gas field in Evan shoal, Gorgon, Bay Undan, which is next to the Abadi field. Thanks to the gas monetization from the field, Australia soon realized the Ichthys LNG plant. Ichthys LNG Plant was built with the concept of floating LNG (FLNG) without noise. Interestingly, Inpex is one of the main interest holders there. Thanks to the Itchys refinery and other LNG plants such as Darwin, Gorgon and Wheatstone LNG, Australia became one of the five largest LNG exporters in the world along with Qatar, Malaysia, the United States and Russia.

Figure: Growth in Australian LNG refinery capacity

Source: US Energy Information Administration

Indonesia needs to show and maintain its presence in the world LNG market, to get a strategic energy and geo-economic diplomacy position in the Asian region, especially for the economic welfare of the Indonesian people. (*)

Jakarta, February 2020

*The author is a Global Energy Professional – Doctoral Student in Indonesia Defense University

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