Indonesia seeks a balance [NGW Magazine]
In common with other southeast Asian countries, Indonesia is ramping up its gas use, to satisfy economic growth while using cleaner fuel than coal. But there are difficulties of geography as most Indonesians live in the west of the country, primarily Java and Sumatra; while the major gas reserves lie in the east. There are not the pipelines to bring all the gas to where it is needed. To bridge the demand-supply gap, Indonesia had to import LNG in 2017.
To meet demand in the west, over $24bn will have to be spent on pipelines as well as liquefaction and regasification facilities by 2030, according to a report published by DBS Group early July. In the meantime, the lack of gas has resulted in greater reliance on diesel and coal.
“Indonesia’s robust economic growth outlook should bode well for the consumption of energy, including LNG. However, demand growth is expected to be mainly focused in Java and Sumatra (the western part of Indonesia), whose LNG consumption is currently limited by supply availability,” the report said.
The rising gas demand in Indonesia means that gas output will be redirected to the domestic market. Exports used to be the key sales avenue for LNG producers, as the prices in northeast Asia were higher and there were problems affecting local sales, including the abovementioned lack of delivery routes.
“With gas supply visibility for the next decade, Indonesia should be able to plan and execute its infrastructure requirements – encompassing pipeline, liquefaction, regasification, and power plant connection facilities for central and east Indonesia,” the report said.
At present, Indonesia’s gas infrastructure and pipelines are fragmented by the islands and the previous focus on other energy sources such as coal and oil. As the government shifts its focus to cleaner energy sources and reduces its dependence on oil imports, the feasibility and attractiveness of gas infrastructure projects have improved significantly.
Indonesia’s key LNG production units, such as Tangguh LNG as well as the planned Abadi LNG and Senoro Matindok LNG, are in east Indonesia. Early in July, Indonesia’s energy ministry approved Inpex’s revised plan of development (POD) for the Abadi LNG project. The revised POD is based on an onshore LNG development scheme with an annual LNG production capacity of 9.5mn metric tons/year. The project involves developing the Abadi gas field in the Masela Block, in the Arafura Sea. Inpex sees it coming on line no earlier than the end of the next decade, it said as it announced regulatory approval July 16.
"For Indonesia, making progress on Abadi is critical. Domestic LNG demand is expected to rise to 13mn mt/yr by 2030 as gas demand grows and production declines,” Wood McKenzie said in a separate report.
Feed gas potential from Kutai and Bintuni basins
Indonesia has been an LNG producer for the past 35 years and the industry was largely driven by the Arun and Bontang gas fields before Tangguh came online in 2004. Arun has now been converted into an LNG import terminal as the field was depleted but demand for gas was strong. Despite the decline in Indonesia’s existing capacity, according to the report, the country has several projects in the pipeline to sustain its gas and LNG output.
More than 60% of Indonesia’s reserves are in the eastern part of the archipelago. Kalimantan, Sulawesi, Maluku and West Papua are the gas- rich regions which, according to the report, are set to become the feed-gas points for the gas liquefaction plants.
In Kalimantan, Kutai Basin has the world’s largest gas field. The major production-sharing contract (PSC) there is the offshore Mahakam PSC with a total gas supply potential of 2.5bn ft3/day for Bontang LNG, albeit its production has declined in the past few years. Last year Pertamina took over the operatorship of Mahakam block from French Total and Japanese Inpex. The Mahakam block is one of the largest gas producing areas in Indonesia with 695 wells in operation. At the end of December 2017, Mahakam block production was 1.286bn ft3/d of gas.
The Bintuni basin started production in 2009 and has a peak production of 1bn ft3/d and serves as a feed-gas point for Tangguh LNG. Tangguh LNG train 3 is now under construction and will add 4mn mt/year to the Tangguh complex.
The DBS Group report believes that in the short term, Indonesia’s gas production will be supported by Medco Energi’s Block A Aceh which came online in March 2018. Other projects under development include the Abadi field and Indonesia Deep Water Development (IDD) Phase 2.
“This development is positive for Indonesia’s gas industry as the field is expected to bring about 150mn ft3/d of gas under DMO [domestic market obligation] and feed a 9.5mn mt/yr onshore liquefaction plant. For IDD Phase 2, the POD is nearly completed and construction is targeted to commence this year with Chevron as the contractor. The project has the potential to deliver 1.2bn ft3/d of gas,” the report said.
Key growth drivers
The key primary drivers of Indonesia’s gas production are power plants, fertiliser producers and industry. Industry is mostly concentrated in the west part, mainly in Java and Sumatra, where the infrastructure is most developed.
Indonesia’s LNG demand is set to grow faster up to 2030, owing to the start-up of gas-fired power plants. About 8 or 9 GW of the 35 GW of new power plant capacity will be gas-fired, the report said. Gas-fired power plants will gain prominence as part of the government’s efforts to promote cleaner energy, on top of renewable and geothermal power plants.
In April this year, Asian Development Bank (ADB) said it is providing $305mn for construction of Jawa-1, which will be Indonesia’s largest gas-fired power plant. The project will be developed by a special purpose company called Jawa Satu Power, owned by Indonesia’s state Pertamina and two Japanese firms, Marubeni and Sojitz. Pertamina and Marubeni each hold a 40% stake in the joint company while Sojitz owns the remaining 20%. The overall cost of the project is expected to be $1.8bn, Pertamina said last year. The power plant will supply energy to Perusahaan Listrik Negara (PLN), Indonesia's national power utility. BP’s Tangguh natural gas liquefaction facility is a likely source of LNG for Jawa-1, ADB said.
Last December, Japanese shipbuilder Mitsui OSK Lines (MOL) signed a deal for supervision, maintenance and operation services of a floating storage and regasification unit (FSRU) that will be integral to the Jawa-1 plant. The 170,000 m³ FSRU will be 14 km offshore in the Cilamaya Sea.
Also, recently Indonesia has commissioned the Jawa-2 project, an 880-MW plant comprising CCGT power generation systems. Jawa-2 is at Tanjung Priok, a port city about 10 km northeast of central Jakarta.
“We estimate that there are 2.5 GW-3 GW of gas-fired power plants in the construction stage currently,” the DBS Group report stated.
Besides power plants, the other demand driver of gas consumption in the country is the fertiliser sector. According to the report, the government is supportive of the fertiliser industry and recognises that it needs Indonesian gas.
The report is not very optimistic about gas demand in the household sector in Indonesia. The household demand will be immaterial unless there is programme for mandatory household gas pipelines, it argued.
The ministry of energy and mineral resources (MEMR) initiated a household gas pipeline programme in 2017 that involved an outlay of $200mn in some major cities around Indonesia. However, the programme has not been very successful as it is covering only 220,000 customers.
“We have decided to remain conservative about this segment’s growth potential unless the household gas pipelines are made compulsory going forward,” the report said.
Regulated gas prices
However, there is an important caveat to this discussion about gas supply and demand: the gas price in Indonesia is regulated by the government. This factor is relevant for analysing demand and for investors planning their capital commitment for any project.
According to the report, for manufacturing companies in the fertiliser, petrochemical and steel sectors, the gas price is capped at $6/mn Btu, while the cap for a power plant can vary depending on its location, the energy consumption and availability. There is a ceiling of around $9.75/mn Btu. Power plant operators can pass on the gas price escalation risk to PLN through a long-term power purchase agreement which includes the input costs of generation. The government gives priority to fertiliser and ceramic tile producers by providing more affordable gas prices to ensure their competitiveness vis-a-vis imported products.
Similarly, the government controls gas prices for industrial end-users through energy ministry regulation. The gas pricing control is set and monitored by limiting the profitability of distributors and traders.
“This regulation strives to ensure price and profit stability for traders and distributors by eliminating the speculative activities of gas traders that do not have any ownership of infrastructure – the lack of which is one of the key reasons behind Indonesia’s uncompetitive gas prices,” the DBS Group report said.
Gas distributors that own pipeline infrastructure are entitled to a maximum distribution margin of 7% or a maximum internal rate of return on a given project of 11%. The regulation ensures that distributors with a pipeline utilisation rate of 60% earn enough to cover their capital and operating costs.
Meanwhile, according to an energy ministry regulation on gas allocation mechanism, domestic gas should prioritise the domestic market obligation (DMO). According to the report, the pricing is pretty much a business-to-business affair that revolves around the operators’ long-term contracts with buyers such as gas traders. The upstream contractors’ work scope is stipulated in the PSC with the Indonesian government. Upstream gas pricing takes into account several factors such as the required capital investment and field characteristics. Hence, upstream gas selling prices may vary between $4-$7/mn Btu on average across Indonesia, the report said.
Move towards greater consolidation
The report believes that in order to achieve better pricing and availability of gas, consolidation is required in the market –as the government demonstrated by its merger of gas distributor Perusahaan Gas Negara (PGN) with Pertamina’s gas subsidiary Pertagas last year.
The rationale for the merger also goes beyond pricing – as PGN has the potential to ramp up its distribution volume from tapping supplies owned by its shareholder Pertamina.
Other potential synergies include giving Pertamina access to midstream infrastructure, mainly PGN’s comprehensive pipeline in the Java and Sumatra regions.