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SE Asia’s largest untapped gas field crisis

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More than a year after Royal Dutch Shell announced it was pulling out of the Masela natural gas project in eastern Indonesia, it has yet to find a buyer for its 35% stake in a US$19 billion venture already saddled by economic difficulties and the ongoing coronavirus pandemic.

China Petroleum & Chemical Corporation (Sinopec) had initially shown interest in joining forces with Japanese majority stakeholder Inpex Corporation but has now withdrawn, leaving the Japanese in a quandary over what to do with Southeast Asia’s largest untapped gas field.

Masela has proven reserves of 18.5 trillion cubic feet of gas and 225 million barrels of condensate, but stuck out in the remote Arafura Sea it presents a major challenge when the gas will have to be priced at $6 per Million British Thermal Units (MBTU) or more to make it economically viable.

A comparative breakdown of various LNG projects recently shared among industry executives shows Masela at the very top end of the cost curve. Indeed, some estimates put its break-even point as high as $7.50 to $8 per MBTU.

Cleaner than coal and currently making up about 18% of the energy mix, there will always be domestic demand for gas going forward. Although the Covid-19 pandemic was clearly a significant inhibitor, consumption last year was still about 2.8 million tonnes, down only slightly from 2019.

The government recently capped the price of natural gas sold to power plants managed by state-owned power utility Perusahaan Listrik Negara (PLN) at $6 per MBTU in an effort to reduce subsidies. PLN currently pays $8.4 per MBTU.

Indonesian oil and gas regulator SSK Migas has given Shell until the end of the year to find a buyer, but that looks unlikely in the middle of the pandemic given the profound impact it has had on the Indonesian economy and on new foreign investment.

A worker on the Masela gas project. Picture: Twitter

“If it goes on any longer than the end of this year, Inpex will have to review the whole project,” says one source familiar with the current situation. “It is very important it has a partner to share in the cost, otherwise it will have to absorb all of it itself.”

Despite optimistic statements, analysts believe the company may eventually be compelled to put Masela on hold once it has secured approval for its environmental impact assessment (Amdal) and met other commitments under its contract.

“What is the government going to do if it comes to that?” asks one Jakarta-based industry source. For now, he says, “Inpex has to be seen to be trying to preserve the field’s value. They can’t admit the situation is dire. The shareholders wouldn’t be happy.”

Masela would not be the first Indonesian gas bonanza to be frozen. Far to the north of Jakarta in the South China Sea lies the abandoned Natuna D Alpha gas field, discovered by Italian company Eni in 1973 and estimated to contain up to 46 million cubic feet of recoverable gas.

Despite US oil giant ExxonMobil and state oil company Pertamina forming a joint venture to develop the Natuna block in the mid-1990s, it has never got off the ground because of the high cost of separating out abnormally high quantities of Co2.

Shell had wanted out of Masela since the new Joko Widodo administration insisted on an onshore processing facility in 2015, ostensibly as a way to spur further development across economically depressed eastern Indonesia.

That unexpected decision removed the need for Shell’s floating liquified natural gas (FLNG) technology, first introduced off Australia’s gas-rich Northwest Shelf, that brought it into the deal in the first place.

The Anglo-Dutch company held on hoping the administration would change its mind given the technical issues involved in laying a 180-kilometer pipeline across a 3,000-meter-deep undersea trench to a planned 9.5 million ton processing facility on Tanimbar Island, 2,748 kilometers east of Jakarta.

Map: Facebook

But that never happened and Shell eventually pulled the plug last year, citing low crude oil prices and Covid-related development delays as the reasons for its exit. Estimates of the value of its stake have ranged from $2 billion to as low as $800 million.

Spending on Asia-Pacific upstream deals collapsed last year, due to the pandemic and an eight-year low in oil prices, with the sale of $400 million in assets representing less than 5% of global upstream transactions outside of North America. In 2018, Asia’s share was more than 35%.

This year, things are looking up as global prices rebound and countries focus on economic recovery, though not always to Indonesia’s advantage. Wood McKenzie notes about a third of the $14 billion worth of regional assets on the block are in production, including ExxonMobil’s Cepu onshore oil and gas block in East Java, which is now in gradual decline.

ConocoPhillips is also looking to exit its onshore Corridor production sharing contract in South Sumatra, while Eni is reportedly close to acquiring Chevron’s 62% participating interest in the Indonesia Deepwater Development (IDD) in East Kalimantan.

Elsewhere, Shell has recently sold its stake in the Malampaya gas field in the Philippines to local conglomerate Udenna Corp, as it continues to focus on the Appomattox and Vito deep-water developments in the Gulf of Mexico and the Penguins project in the North Sea.

Overall, however, Masela epitomizes the challenges facing oil and gas companies in more remote parts of the world when countries like Qatar continue to discover huge quantities of natural gas on their doorstep.

“The world is changing,” says one oil and gas consultant with long experience in Indonesia.

“This is a long-life project. No big company wants to push such a huge amount of money into a project that is high on the cost curve, particularly when decarbonization appears to be the way of the future.”






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