A quiet dispute between Jakarta, Japan’s Inpex Corp and Royal Dutch Shell over the massive Masela gas project threatens to crimp new investment in the sector
Joint venture energy giants Inpex Corp and Royal Dutch Shell plc have remained quiet on whether they will continue to pursue the development of the massive Masela natural gas project in eastern Indonesia’s Arafura Sea after the government’s surprise decision to move its processing facility onshore.
Neither company has spoken publicly about the official decision handed down last year, but sources familiar with the venture say there is unlikely to be any movement until at least after the 2019 legislative and presidential elections, when President Joko Widodo is expected to seek a second term.
The decision, made ostensibly to spur economic multiplier effects and accelerate development in the eastern Maluku region, raises questions about whether the government can attract the foreign investment needed to continue developing its rich store of natural resources.
While media attention has focused recently on the government’s contractual dispute with US-based mining giant Freeport McMoran, a legal tussle that has raised regulatory risks for the wider mining sector, the quieter Masela dispute has cast a similar damper on the foreign investment reliant oil and gas industry.
Japan-owned Inpex currently holds a 65% operating interest in the Masela block, where its Abadi gas field is located hard up against the maritime boundary with Australia. Shell holds the remaining 35% in the project.
Abadi has a proven 12.7 trillion cubic feet of gas, but possible and probable reserves could boost that figure to as much as 40 trillion cubic feet, three times larger than BP’s Tangguh operation in West Papua’s Bintuni Bay, which currently has Indonesia’s largest reserves in a producing field.
Only the East Natuna field in the South China Sea is bigger, at 46 trillion cubic feet of recoverable reserves. But the huge amount of associated carbon dioxide has deterred its development since the early 1970s – and will continue to do so in the current environment of oversupply and low-cost oil.
Indonesian President Joko Widodo dropped a bombshell on Inpex and Shell last year when he rejected an initial proposal for a floating LNG facility to exploit the field, instructing them instead to submit a new plan based on an onshore plant to be situated either on the remote Tanimbar or Aru islands.
Asked several months ago whether Inpex and Royal Dutch Shell had fully accepted the government’s decision, then newly-appointed Mines and Energy Minister Ignatius Jonan told Asia Times: “I don’t know, but they can take it or leave it.”
The foreign investor partners appear to be nominally playing ball so far, on the understanding that their production sharing contract (PSC) will be extended by seven years from the current expiry date of 2028.
But if the government persists with the onshore plan, the fiscal terms will have to be adjusted to account for a US$5 billion difference in cost between the two designs– from $14 billion to $19 billion. As one source familiar with the project put it: “The ball is in the government’s court.”
Widodo has pushed for the onshore option because he has been persuaded it will help spur development of southern Maluku. But the concept is vague at best, with the government still undecided on which precise island group to locate the proposed processing facility.
The Tanimbars, 170 kilometers north of Masela, would appear to be the obvious choice. But the fact that the government is still looking at the Aru islands, 400 kilometers to the northeast, suggests to critics that lucrative pipeline contracts may be a key consideration.
Whether the Tanimbar or Aru islands, the pipeline will have to cross a 2,000-3,000-meter deep undersea trench, part of the quake-prone Indian Ocean fault line that skirts Sumatra and Java and curls around the southern coast of the eastern Nusa Tenggara island chain.
Industry experts say government talk of developing a related petrochemical industry defies all logic. “Masela gas is bone-dry methane, which means all you can produce are methanol, ammonia, and urea,” says one expert. “Indonesia is surplus in all three products already and internationally they are cut-throat businesses.”
Global leaders like Ferrostaal and Mitsubishi (ammonia), Methanex (methanol) and Yara (urea) are noticeably absent from the current discourse, which is dominated by state-owned companies apparently looking to be “allocated” gas or to prevent rivals from receiving it.
Experts say any further additional capacity for those three by-products will be conditional on very inexpensive gas and on a cheap plant in an already established location. They say Maluku fails on both counts.
BP’s Tanggu operation in Papua’s western Bird’s Head region does have cheap onshore gas, yet like Mitubishi’s East Java copper smelter it has not attracted any of the ancillary industrial investments officials may have hoped for since it opened in 2009.
After announcing in 2006 it would re-orient its natural gas production to domestic needs, Indonesia dropped from the world’s largest exporter of LNG in 2005 to the world’s fifth biggest in 2014, behind Qatar, Malaysia, Australia and Nigeria.
The Masela venture has been based on floating LNG technology since Indonesia’s upstream regulator, the Special Task Force for Upstream Oil and Gas, or SSK Migas, approved Inpex’s initial first-phase development plan in 2010 that called for an annual processing capacity of 2.5 million tons.
When three additional appraisal wells in 2013-2014 confirmed a much greater volume of reserves, the company dispensed with the phased approach and submitted a revised plan to expand the facility to 7.5 million tons.
Widodo changed all that, reportedly on the advice of newly-appointed maritime coordinating minister Rizal Ramli, who openly questioned why SKK Migas and then-mines and energy minister Sudirman Said had approved the new plan.
Ramli hired New York-based consultancy Poten & Partners to conduct an independent assessment which found that onshore development would impact adversely on the project’s rate of return, cost recovery and government revenues.
However, the report was never made public and was subsequently ignored, with Ramli, a former finance minister, talking vaguely about how the onshore option would help to develop a region whose economy lags far behind the rest of the country.
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 issues Jakarta seemed incapable of resolving.
It was only in mid-2016 that ExxonMobil began pumping 168,000 barrels a day from what is now the country’s second biggest oilfield, despite the fact that overall national oil output had slumped over that decade-long period from a million barrels to 780,000 barrels a day.
Chevron Pacific’s proposed US$12 billion Indonesia Deepwater Development (IDD) off East Kalimantan, which involves two projects with a combined capacity of 1.2 billion cubic feet of natural gas and 51,000 barrels of condensate a day, has been similarly hamstrung.
Chevron postponed the project in 2014 over fiscal and incentive issues and now finds itself in a deteriorating global LNG price environment, compounded by the need to seek a further contract extension to its Makassar Strait concession.
What was expected to be a two-year delay is now dragging on as the state-owned Pertamina oil company prepares to take over Total’s neighboring Mahakam gas-field in the first real test of its ability to manage a large but fast-maturing production block.
SSK Migas estimates the field will be down to 3.8 trillion cubic feet of gas by the time of the year-end hand-over, a far cry from the 1.68 billion barrels of oil and 21.2 trillion cubic feet of gas when it first came on stream in 1974.
Even then, the field once considered the crown jewel of Indonesia’s oil and gas sector will require careful maintenance – and at least US$1.5 billion a year in capital outlays – just to sustain its current level of production.