Urged on by President Joko Widodo, the nationalist tide that has decimated Indonesia’s oil and gas industry over the past decade has left the nation on the bottom rung for prospective foreign investment.
Without the financial and technical means – or even the inclination – to find and develop new fields itself, it needs foreign aid to improve and boost production.
Yet cash-strapped state oil company Pertamina is now on the verge of acquiring Royal Dutch Shell’s 35% stake in the giant Masela gas block in the Arafura Sea where operations have come to a virtual standstill since the Widodo government mandated a change from an offshore to an onshore development.
Pertamina is lukewarm on the US$1.4 billion deal, but Maritime Coordinating Minister Luhut Panjaitan and State Enterprise Minister Erick Thohir both want the company to proceed, despite it needing another US$6.5 billion in working capital over the next five years.
It will also have to pay its share of $1.2 billion to $1.4 billion in government-mandated carbon capture, utilization and storage (CCUS) facilities to reduce the project’s greenhouse gas emissions.
For Indonesia in its ambitious efforts to attain net-zero emissions by 2050, it also has to stop chopping down rain forests for palm oil for the food industry, destroying the Orangutan habitat.
In the latest sign that the window on fossil fuels is slowly closing, the Net Zero Asset Owner Alliance (NZAOA) announced last week that it had instructed its members to make no new direct investments in upstream oil and gas infrastructure projects for new fields.
Boasting $11 trillion in assets, the group’s requirements are the toughest yet and show that unless Indonesia makes significant improvements in its investment climate, the onrushing renewable era will leave untapped oil and gas deposits in the ground.
Analysts believe Pertamina is being compelled to buy into the venture to keep it alive, given the lack of foreign interest since the government’s surprise intervention, which added $4 billion to the original $16 billion price tag and precipitated Shell’s exit.
The previous Susilo Bambang Yudhoyono government had approved Shell’s plan to use a 7.5 million metric tonne floating liquified natural gas (FLNG) facility it has employed with mixed results on Australia’s gas-rich Northwest Shelf.
Widodo instead opted for laying a 180-kilometer pipeline to a larger onshore plant on Yamdena, the main island in the Tanimbar archipelago, seeing it as a way to spur development in eastern Indonesia, which has since become the center of a booming nickel industry.
The pipe will have to cross a 3,000-meter-deep trench, a section of the seismically active fault line that originates in the Indian Ocean and tracks along the west Sumatra coast and curls south around Java and the Nusa Tenggara island chain.
The switch to onshore also brings the additional complication of a greenfield LNG facility, along with any other potential gas offtake facilities on an island of 80,000 people that relies solely on diesel and solar power and is devoid of other infrastructure.
Similarly, nearby Timor Leste is holding out for either a floating platform, or a 150-kilometer pipeline from the 8 TCF Greater Sunrise field to an onshore LNG plant, which could be used for export and perhaps for power generation and industry.
Australian operating partner Woodside prefers a 450-kilometer pipeline to an existing LNG terminal in Darwin, like the one that has delivered gas from the shared Bayu-Undan field in the so-called Timor Gap for the past 17 years.
The result has been a prolonged deadlock, with founding president and now Planning and Strategic Investment Minister Xanana Gusmao dead-set against the Australian plan, largely because of his less-than-warm relations with Canberra in recent years.
Indonesia could reverse its decision on onshore development and scale back the scope of Masela, but the consortium would still need to export most of the gas to compensate for a loss-making $6 per Million British Thermal Unit (MBTU) cap on the price of domestic LNG.
Given the project’s break-even point is estimated to be as high as $7.50 to $8 per MBTU, the government may have to rescind the domestic market obligation under which production-sharing contractors effectively subsidize inefficient local industry.
Thohir must have something up his sleeve, says one Jakarta-based consultant. He would not expose Pertamina that much, so you would suspect there must be something lined up post-deal.
With most low-risk resources in Indonesia already being exploited, only deep-water exploration in areas like offshore northern Sumatra, northern Papua and the Makassar Strait looks likely to move the needle to any significant degree.
Since 1995, Indonesian oil production has fallen from 1.6 million barrels a day (BOPD) to an average of 647,000 BOPD, the contribution of oil and gas to GDP has plummeted from 9% to 3.3% and annual foreign investment has slumped to its lowest-ever point at $15-$16 billion.
Exploration has plunged by an average of 23% over the past decade.
Official data shows the number of exploratory wells dropped from 64 in 2014 to 26 in 2019, 18 in 2020, 28 in 2021 and 30 in 2022, partly because of the Covid-19 pandemic and partly because of better prospects elsewhere.
Officials like to boast that Indonesia still has 68 unexplored oil and gas basins, but many of them are in remote parts of eastern Indonesia and all require extensive seismic surveys followed by the drilling of expensive wells to determine their potential.
Pertamina’s actual exploration budget is not known, but upstream domestic capital expenditure is only $342 million, including production, development and exploration. That leaves precious little for high-risk, greenfield and remote exploration.
The costliest example of that was the $1 billion forked out by ExxonMobil, Marathon, ConocoPhillips, Statoil and Pertamina in an unsuccessful search for oil and gas on the once-promising eastern side of the Makassar Strait between 2006 and 2011.
Tangguh is the country’s biggest producing gas field with a long-delayed third production train coming on stream later in the year and proven and probable reserves climbing to an estimated 30 TCF from 13 TCF at the start of operations in 2010.
Timing is one factor Indonesian regulators have never recognized, despite its impact on returns and investment attractiveness.
It currently takes up to two years for an exploration firm, new to Indonesia, to open an office, secure financial and technical approvals, tender for goods and services, and acquire seismic data. It can take another two years to prepare for drilling an offshore well.
Over the years, the government’s take, at least in share of revenue, has shrunk because of the higher costs associated with maintaining aging fields.
That led to the introduction of an alternative gross split scheme under which firms bore the upstream costs, but the state received a smaller cut of up to 57% of revenue.
The mindset among officials that foreign investors overspent to take advantage of the cost recovery system was always illogical in the face of a micro-management policy that has also compelled firms to buy overpriced Indonesian goods and services and favors cost over quality.
Asia Times / ABC Flash Point News 2023.
