JAKARTA – 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 and without the financial and technical means – or even the inclination – to find and develop new fields itself.
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 reportedly 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, a first for Indonesia in its ambitious efforts to attain net-zero emissions by 2050.
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 doubt Pertamina’s ability to act as a full partner with Japan’s Inpex Corporation, the majority 65% stakeholder in Masela. But in recent weeks, Malaysia’s Petronas has emerged as a prospective partner in exploiting the 21 trillion cubic feet (TCF) discovery.
Although the two state companies have not always enjoyed the best of relations, Petronas has considerable experience in LNG and CCUS — and the technical and financial weight to add value to the $20 billion venture.
Budgeted capital expenditure for Pertamina’s upstream subsidiary, PT Pertamina Hulu Energy, this year is $5.7 billion, a 78% increase over 2022 because of $1.5 billion set aside for mergers and acquisitions. In other words, Masela.
During a parliamentary hearing in February, Pertamina president director Nicke Widyawati wouldn’t go into detail about the final price of the Masela stake, which corresponds to the money Shell spent on developing the field – but nothing more.
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.
Meanwhile, oil and gas output continues to fall as Pertamina struggles to stem the natural decline in production from East Kalimantan’s Mahakam gas field and the Rokan oil block in southern Sumatra, which it took over from Total and Chevron respectively when their contracts expired.
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.
Experts argue that Pertamina needs to lead exploration efforts to show it has what one calls “a skin in the game,” warning that Big Oil won’t be back unless a significant world-class discovery is made, with evidence of further upside and a clear commercialization route.
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.
In fact, risk is also something Pertamina has always been reluctant to take on, mindful that only one in nine wildcat wells yield results – and then not necessarily in commercial quantities.
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.
Pertamina executives were reportedly appalled so much had been spent on zero results, worried they would be accused of causing losses to the state – a charge used by the Anti-Corruption Commission (KPK) to punish official misdeeds.
One of Indonesia’s greatest hopes previously lay in the Andaman Sea, where Mubadala Petroleum, Repsol, Harbour Energy and Petronas have stakes in four adjacent blocks. However, despite seismic surveys hinting at several gas fields in the 3-4 TCF range, drilling results have so far been largely disappointing.
Analysts say a drastic paradigm shift is needed if Indonesia is to compete with the production-sharing regimes of other countries, especially in new frontier areas like West Africa and Latin America.
“The problem is the government has a major perception and reputation problem,” says one well-travelled consultant. “The international companies see Indonesia and its overzealous nationalism as too hard an environment to operate in.”
“Indonesia needs to remember how it got to become a prolific and attractive oil and gas destination in the 1970s and 80s when it didn’t have over-regulation or nationalism,” he argues. “Perhaps it should look to the past for its future before it’s too late.”
The Mines and Energy Ministry’s recent surprise early decision to extend BP’s Tangguh contract in West Papua from 2035 to 2051 suggests the government may now be realizing its nationalist policies have gone too far in the prevailing environment.
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.
Foreign oilmen want to see an end to upstream regulator SSK Migas’ micro-management of exploration budgets. Oversight, they say, should only be confined to ensuring a contractor’s work plan conforms with contract commitments and other laws.
Critics say apart from the government’s minute scrutiny of budgets, which often does not match the strict accounting procedures of most large foreign companies, it is also time to end the “archaic” tendering of exploration blocks.
In particular, they want to see significant changes to the cost recovery scheme, under which the government reimburses companies for upstream-related costs in exchange for a higher share – up to 85% – of each company’s earnings from oil and gas blocks.
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.
Once seen as a panacea to the deteriorating investment climate, the three-year experiment has now faltered, though it is unclear whether it has been entirely abandoned or replaced by something else.
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.