A worker scrapes sand affected by an oil spill as he cleans the beach at a shoreline in Karawang, West Java province, Indonesia, August 9, 2019. Image: Facebook/Agencies

JAKARTA – With Chevron and perhaps ExxonMobil heading for the exits, active exploration at a virtual standstill and production on an increasingly downward spiral, Indonesia’s government needs to conduct radical regulatory surgery before its oil and gas industry is doomed by the onrushing era of renewable energy.

Analysts say the nationalist tide that has swept over the industry in the past six years has left Indonesia on the bottom rung of prospective foreign investment and without the financial and technical means to explore for and develop new fields independently.

“The government needs to consider a major paradigm shift to spur investment if the country is to realize its geological potential before it becomes too late and its many remaining resources are left in the ground forever,” says one American oil expert with long experience in Indonesia.

That’s also because major oil companies, many with a previously long history in Indonesia, including BP, Royal Dutch Shell and Total, are signaling a shift to renewables as they start to scale back investment in traditional oil and gas projects.

“Globally, renewables are moving very fast, technology-wise, infrastructure-wise and cost-wise,” a former senior Indonesian energy official told Asia Times. “Renewables are now in head-on confrontation with oil and gas. As always, we (Indonesia) are behind the eight-ball.”

With most low-risk resources in Indonesia already being exploited, oil and gas output will continue to decline as state-owned Pertamina struggles to come up with the increased investment required to fund enhanced recovery technology in mature fields.

Exploration has fallen by an average of 23% over the past decade. According to government data, the number of exploratory wells plunged from 64 in 2014 to 26 in 2019 and only 18 last year, partly because of the impact of the Covid-19 pandemic and partly as a result of sagging global oil and gas prices.

Chevron is walking away after its failure to renew the contract to Sumatra’s long-producing Rokan oil block led to it relinquishing its 62% stake in the US$9 billion Indonesian Deepwater Development (IDD) project in Kalimantan’s Kutai Basin.

Italian oil company ENI, which operates one of the four fields to be merged under the IDD venture, is expected to replace Chevron, although officials said last week they were still in negotiations with ENI over commercial aspects of the five-year development.

ExxonMobil is also reportedly close to relinquishing its Cepu, East Java, oil block as it seeks to ditch projects with the lowest profit margins to focus on Papua New Guinea and the Gorgan liquified natural gas (LNG) project on Australia’s Northwest Shelf.

Workers at ExxonMobil’s Cepu oil block. Image: Facebook

The oil giant is laying off 14,000 employees, or about 15% of its global work force, after the impact of the pandemic saw it lose its position as America’s top energy company to NextEra Energy Inc, which specializes in solar and wind power. 

Cepu, an onshore block that went onstream in East Java in 2008, produced an average of 215,000 barrels of oil a day last year, edging ahead of Rokan’s 176,000 barrels, Indonesia’s largest producing field for more than five decades.

State oil company Pertamina estimates that Rokan’s Duri, Minas and Bekasap fields will need $70 billion in investment over the next 20 years to maintain production at acceptable levels and save an annual $4 billion in oil and product imports.

Since the 1980s, Chevron has employed the technologically challenging and capital intensive technique of steam-driven enhanced oil recovery (EOR), which has allowed it to achieve a 60% recovery rate to extend the life of the fast-maturing block.

But given the complexity of the operation, there are fears Rokan will follow the same pattern as East Kalimantan’s Mahakam gas block, where production has fallen away since Total was compelled to hand over control to Pertamina in early 2018.

Upstream regulator SSKMigas revealed last week that output fell by 20% in 2020 — from 605.5 million to 485 million standard cubic feet a day (MMSCFD) – because the number of wells drilled fell short of the target. It predicted a similar decline this year.

ExxonMobil’s departure would leave ENI, BP and ConocoPhillips as the only active petroleum majors in Indonesia. BP is adding a third production train to its Tanggu LNG complex in western Papua; delayed by Covid infections, it is now expected to be completed by early 2022.

Sources familiar with the project say promising results from exploratory drilling at BP’s new offshore Ubadari field, 70 kilometers southeast of Tanggu, will extend the facility’s life well beyond 2035 when the company’s current contract expires.

Japan’s Inpex will be hard-pressed to find a partner with the deep pockets and technical expertise to replace Royal Dutch Shell, which after a year of speculation has announced it is pulling out of the $19 billion Marsela gas venture in the remote Arafura Sea. 

Japan’s Inpex will be hard-pressed to replace Royal Dutch Shell in the Masela Gas project pictured here. Photo: Stock

Inpex turned down an overture from the China National Overseas Oil Corp (CNOOC) for political, technical and what one source describes as “bad business chemistry issues,” leaving the company to contemplate at least a decade-long delay in developing Marsela’s Abadi field.

Last month, Inpex signed an MoU with state-owned Perusahaan Gas Negara (PGN) for a long-term supply contract in an effort to entice interest from a new partner. It had previously signed MoUs with power utility Perusahaan Listrik Negara (PLN) and a state fertilizer company.

Some experts question whether the Abadi field, 2,800 kilometers east of Jakarta on Indonesia’s maritime border with Australia, will ever be developed given its position high on the LNG cost curve in a commoditizing market.

Still, it is one of four so-called National Strategic Projects, including Tanggu, IDD and Pertamina’s Cepu-associated Jambaran-Tiung gasfield, which the Mines and Energy Ministry hopes will deliver on its 2030 target of one million barrels of oil and 12 billion standard cubic feet of gas a day.

Industry sources insist that can only be accomplished with material EOR capital and extensive exploration – and that means providing a raft of unprecedented incentives and other measures that will help put Indonesia back on the map of desirable investment targets.

Indonesia has 128 geological basins, only half of which have been explored. Oil production has fallen from 1.6 million to 700,000 barrels a day since 1995, the contribution of oil and gas to GDP has plummeted from 9% to 3.3% and foreign investment is at its lowest-ever point.

Experts say only deep-water exploration in prospective areas like offshore northern Sumatra, northern Papua and the Makassar Strait, separating Kalimantan and Sulawesi, have the potential to move the needle to any significant degree.

As things stand now, Indonesia’s greatest hope lies in the Andaman Sea, northwest of Aceh, where Abu Dhabi-based Mubadala Petroleum, Spain’s Repsol, BP and Malaysian state oil company Petronas have stakes in four adjacent blocks all under active exploration at depths of 1,000-1,500 meters.

Industry sources say high-quality 3D seismic shows the existence of several natural gas fields in the 3-4 trillion cubic feet range, all located in close proximity to the mothballed Arun LNG plant and its pipeline infrastructure.

Elsewhere, Pertamina is exploring around Tarakan, an island off northeast Kalimantan close to the Malaysian border, and other companies are drilling wildcat wells in a handful of far-flung blocks, including near Seram, the main island in southern Maluku. 

“The opportunity is huge, but it cannot be met solely by risk-averse domestic and state-owned companies who also lack the balance sheets and necessary technology,” says the American expert. “The desire to nationalize the country’s resources, along with a woeful fiscal policy and bureaucracy, has dampened foreign investment.”

Ministry of Mines and Energy oil and gas director-general Tutuka Ariadji said in a year-end assessment that the government was considering a range of new incentives, among them investment credit, accelerated depreciation, value-added tax exemption and a streamlining of the licensing process.

Tutuka Ariadji is trying to lure in foreign investors through a raft of new incentives. Image: Facebook

“The government is very eager for a better oil and gas investment climate,” he said, adding that the government was open to “win-win” discussions with stakeholders on changes to regulations. But as in past years, officials may not be prepared to bite the bullet.

Foreign oil executives say they want to see an end to SSKMigas’ micro-management of exploration budgets. Oversight, they say, should only be confined to ensuring  a production sharing contractor’s (PSC) 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 international 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% — for 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 all 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 been abandoned by new Mines and Energy Minister Arifin Tasrif. Investors see the scheme as a victim of the Joko Widodo administration’s failure to consult with stakeholders.

“The mindset that foreign investors ‘overspend’ to take advantage of the cost recovery system is illogical,” says one consultant, echoing widespread complaints about a micro-management policy that also compels firms to buy overpriced Indonesian goods and services and favors cost over quality.

Apart from removing the limit on expatriate employees during the exploration phase, companies say SSKMigas oversight of a plan of development (POD) should be conceptual, instead of focusing on the money a PSC is spending from its own resources to develop a promising discovery.

“The main problem with POD evaluation is that the people doing the evaluation are incompetent,” says the consultant. “They may have the skill set to evaluate an onshore development, for example, but not a deep-water project.”

Other suggested changes include

  • Remove ring-fencing for producing PSCs and also allow cost recovery for those engaged in active exploration.
  • Allow failed exploration PSCs to sell any excess inventory to recover costs, instead of it automatically becoming the property of the Indonesian government.
  • Sweeping improvements to the budget/authorization for expenditure (AFE) process, particularly the requirement for time-consuming layers of bureaucratic approval. 
  • Why, the industry asks, does it take years to relinquish a PSC, or months to get a PSC transfer approved?

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 exploration companies to open an office, secure financial and technical approvals, tender for goods and services and finally drill a well.

If the well is dry or the block is relinquished, it still takes another two and a half years to close out AFE, a puzzling anomaly when cost recovery only applies to the production phase, not during exploration when all the risk falls on companies.

Risk is something cash-strapped Pertamina and domestic companies have never been ready to take, mindful of the fact that only one in nine wildcat, or exploratory wells, yield results – and then not necessarily in commercial quantities.

A PT Pertamina worker sits under pipes as he rests near crude oil tanks at Bunyu island, Indonesia's East Kalimantan province February 8, 2011. Pertamina has said it expects crude and condensate production of 132,000 barrels per day for this year, up just 1 percent from last year, though the former OPEC member country has often missed production targets because of declining output at ageing fields, Pertamina's director of investment and risk management Ferederick Siahaan said last month. REUTERS/Beawiharta (INDONESIA - Tags: ENERGY BUSINESS) - RTXXLW8
A PT Pertamina worker sits under pipes as he rests near crude oil tanks at Bunyu island, Indonesia’s East Kalimantan province. Photo: Agencies

The costliest example of that was the $1 billion spent by ExxonMobil, Marathon, ConocoPhillips, Norway’s Statoil and three smaller foreign companies in an unsuccessful search for oil and gas in 2,000-meter deep waters on the eastern side of the Makassar Strait between 2006 and 2011.

Most of the mature fields Pertamina has inherited as part of the same nationalist model Saudi Arabia adopted in the 1970s require the sort of enhanced recovery techniques and technology Indonesia does not possess.  

“So the dilemma is does Indonesia wait until matters get worse, or do they take bold and drastic steps now,” says one foreign executive. “It is akin to a patient waiting whether to undergo treatment now or wait until a doctor decides on a prescription.

“In other words, Indonesia can choose to implement incentives and measures which it believes will make it more attractive (as countries like Egypt and Columbia have done in recent years), or wait to negotiate with foreign investors from an increasingly weak bargaining position.”