Three years after President Joko Widodo dropped a bombshell by opting for the onshore processing of natural gas from eastern Indonesia’s giant Masela project, joint venture partners Inpex and Royal Dutch Shell are still working on an acceptable plan of development (PoD) to accomplish it.

The companies are saying little officially, but their initial reluctance to switch from a floating liquified natural gas (FLNG) platform and the slow progress made so far has raised questions from opposition politicians whether the foot-dragging has gone on too long.

“We have all agreed to settle on an onshore development, there’s no more argument about that,” says one senior government official, laying out a timeline under which construction of the expanded 9.4 million ton LNG facility is planned to begin in 2021-22.

Maritime Coordinating Minister Luhut Panjaitan, whose portfolio includes oil and gas, acknowledges the government still has to acquire 1,400 hectares for the project on the main Tanimbar island of Yamdena, 2,700 km east of Jakarta in the remotes reaches of the Arafura Sea.

But the land on Yamdena’s south coast is owned by the Department of Environment and Forestry and its acquisition won’t pose the same problem as for the long-delayed Jakarta-Bandung fast-rail project on its path through prime real estate on the eastern edge of Jakarta.

Basic services lacking

Virtually powerless with a small airport, few roads and poor internet and mobile phone services, Yamdena and the 65 smaller islands making up the Tanimbar group contain a population of about 118,000, 95% of them Christian and mostly engaged in fishing, coconut growing and timber milling.

Japan’s Inpex has a 65% operating interest in the Masela concession, where the Abadi gas field is located on the maritime boundary with Australia, while Shell holds the remaining 35%. The field is now not expected to come on stream until 2027.

Abadi has a proven 12.7 trillion cubic feet of gas, but possible and probable reserves could see that figure rise to 40 trillion cubic feet, three times larger than BP’s Tangguh operation in West Papua’s Bintuni Bay where a third $8 billion production train will begin operation next year.

Tangguh is now Indonesia’s biggest producing field, taking that mantle from East Kalimantan’s Mahakam field where output has dropped to an annual 700 million cubic feet a day, 300 million below target since state oil company Pertamina took over the field from French giant Total in 2017.

Upstream regulator SSK Migas approved the use of floating LNG technology as the basis for Inpex’s initial first development plan in 2010, but when appraisal wells in 2013-14 confirmed greater reserves, the company submitted a revised plan to expand the facility from 2.5 million to 7.5 million tons.

Widodo changed all that on the advice of new maritime coordinating minister Rizal Ramli, who argued that onshore development would help spur growth across the Maluku islands – a region which will also soon benefit from a Chinese-built, $10 billion nickel processor on the main island of Halmahera.

A New York-based consultancy, hired by then mines and energy minister Sudirman Said, had found the onshore option would negatively impact on the project’s rate of return, cost recovery for the joint venture and inevitably on government revenues.

Most crucially, would be the estimated $4 billion difference in cost – from $16 billion to $20 billion – because of the 180km pipeline to be laid from Abadi to Tanimbar which would cross a 2,000-3,000-metre-deep undersea trench, part of the quake-prone Indian Ocean fault line that skirts Sumatra, Java and the Nusa Tenggara island chain.

Two alternatives

But when Ramli took over the coordinating ministry post in mid-2015, he was not convinced, pulling together his own team of engineers, economists and other experts to compare the merits of the two alternatives.

Ramli may have known little about oil and gas, but as he explained later: “This was about national resource utilization as an economic prime mover and a territorial development factor and not about using a natural resource as simply a source of state revenue. It was all about the multiplier effect.”

Apart from the LNG plant itself, Ramli envisaged the development of ancillary industries, such as paints, glues, polymers, plastics, PVC pipes, Formica and fiberglass. What motivated him, he says now, were Malaysia’s two major petrochemical complexes, and the realization that Taiwan was importing LNG from Indonesia, then selling back the by-products at four times the value. “There were no backward or forward linkages,” he pointed out.

Observers note, however, that such commercial activity has never happened at Tangguh in the decade it has been in operation, or around Mitsubishi’s  East Java smelter, which has processed concentrate from the Freeport copper and gold mine since 1996.

Industry experts say attracting investors to such a remote area will depend on the price of the gas, which will be higher for a green field in a frontier zone – the reason why FLNG platforms came into vogue in the first place to avoid pipeline logistical and environmental costs.

Ramli also believed Masela was overpriced and worried that Indonesia was having to bear the cost of experimenting with a floating LNG facility similar to Shell’s 600,000-ton, South Korean-built Prelude platform that only began operations off West Australia in 2017.

Onshore development

There were also other concerns. The pioneering $10 billion Prelude only has a capacity of 3.6 million tons of LNG a year, while the Masela venture is now designed to produce 9.5 million tons, significantly more than was originally conceived.

Most importantly, Ramli calculated that the onshore development would provide employment for as many as 6,000 construction workers and eventually a 1,100-man operational staff. Offshore, only a limited workforce would be needed.

In the end, Widodo was eventually convinced by a comparison of the economic benefits Ramli’s team came up with – $2.5 billion a year for offshore and $6.5 billion onshore, taking into account the level of anticipated commercialization.

Inpex and Shell reluctantly went ahead with the onshore plan on the understanding their production sharing contract (PSC) was extended beyond the existing expiry date of 2028 to make up for delays that go back to when the field was discovered in the early 2000s.

But for the Inpex/Shell consortium, it also means the fiscal terms have to be adjusted to account for what it estimates is a $4 billion difference in cost – from $16 billion to $20 billion.

The good news is that overall LNG project costs have dropped from the highs of 2010-14. Consultants Wood McKenzie and the Oxford Institute of Energy Studies both estimate Masela at $2,000 a ton, slightly below that of BP’s new train.

Indonesia has a record of dragging its feet on large-scale resource projects, starting with ExxonMobil’s Cepu oil field in East Java, which took more than a decade to bring on stream because of land and other problem Jakarta seemed incapable of resolving.

Similarly, with the second stage of Chevron Pacific’s $12 billion Indonesia Deepwater Development (IDD) off East Kalimantan, which was postponed in 2014 over fiscal and incentive issues and only revived two years later when the first stage finally went into production.