Indonesia's Gas Shortage Set to Deepen Through 2028 as Export Cuts Bypass Java

A small export cut meets a much larger supply gap

Indonesia redirected 31 million standard cubic feet of gas a day from Singapore to domestic electricity generation on October 24, 2026. Yet industrial plants in Java, where government figures already show substantial shortages, will receive little immediate help because the diverted gas serves other islands and no pipeline connects Natuna directly to Java.

Yayan Satyakti, an energy economist at Universitas Padjadjaran, projects a national gas shortfall of about 200 million standard cubic feet a day in 2027 and 330 million in 2028 if liquefied natural gas exports stay at their 2026 level. The export reduction is equivalent to less than one tenth of his projected 2028 gap, even before considering where the gas can physically travel.

Central and East Java are already struggling. The Directorate General of Oil and Gas recorded supply of 649.73 million standard cubic feet a day against demand of 753.89 million in July 2026, leaving a deficit of 104.16 million. That meant roughly 14% of the region's recorded requirement was unmet.

Indonesia faces three connected problems: declining output from existing fields, growing domestic consumption, and pipelines that cannot always move gas from producing areas to industrial centres. Cutting exports can release some fuel, but getting enough gas to the right place requires new production and transport facilities.

Two measurements recur throughout the debate. MMSCFD means million standard cubic feet per day, a measure of gas volume under standard conditions. LNG is natural gas cooled into liquid so ships can carry it between places that pipelines do not connect. Receiving terminals must turn it back into gas before customers can use it.

Where the redirected gas actually goes

SKK Migas chief Djoko Siswanto detailed two parts of the reduction: 15 MMSCFD from Natuna for PLN Batam through the WNTS–Pulau Pemping–Batam pipeline, and 16 MMSCFD from Sumatra for electricity needs in Batam, Bintan and Sumatra through the TGI pipeline. The combined cut is roughly 8% of the previously stated export flow of 409.5 MMSCFD.

Djoko, who leads Indonesia's upstream oil and gas regulator, described the purpose of the change:

to maintain the reliability of domestic gas supply for electricity.

He said deliveries would be monitored daily. For Batam and the other receiving areas, the diversion provides fuel for electricity generation. Java's industrial customers remain dependent on their own supply connections.

Yayan explained the geographical limit:

The reduction is marginal and will not benefit industrial plants in Java,

Energy Minister Bahlil Lahadalia has said the diversion stays within the minimum delivery provisions of export contracts. Moshe Rizal, investment committee chair at the Indonesian oil and gas business association Aspermigas, warned more broadly that changing export commitments can expose contractors to penalties. Further reallocations therefore involve both physical delivery routes and commercial obligations.

Java's shortage is already affecting customers

Central and East Java's deficit reached 276.79 MMSCFD in February 2026, when supply was 473.64 MMSCFD and demand was 750.43 MMSCFD. About 37% of the recorded requirement was unmet that month, considerably more than July's 14% gap.

The Directorate General of Oil and Gas forecast another shortfall in December: supply of 634.02 MMSCFD against demand of 760.63 MMSCFD, leaving 126.61 MMSCFD uncovered. Its figures described average regional shortages of around 100–125 MMSCFD as of July.

PGN, the gas distributor, has introduced customer usage limits tied to contracted minimum consumption. The limits rise in stages, but remain below the contractual reference level through December:

• November 1–12, 2026: maximum use of 66% of the applicable daily contractual reference.
• November 13–30: maximum use of 72%.
• December 1–31: maximum use of 79%.

PGN corporate secretary Fajriyah Usman said the limits are intended to spread restricted supplies more evenly and maintain reliable distribution. For a factory, the practical issue is how to schedule production within its allocation. Gas used beyond the quota can attract a higher price under its gas sale and purchase agreement.

Factories face a dispute over LNG prices

PGN says the special price of US$13 per million British thermal units for regasified LNG remains applicable through December 31, 2026. A British thermal unit measures energy, rather than gas volume, allowing buyers to compare the fuel's usable heat content.

Yustinus Gunawan, chairman of the Gas Users Industry Forum, said customers experienced the US$13 price for only about 45 days, during July and part of August. He put the price of regasified LNG at around US$15.60 from September, a difference of US$2.60, or 20%.

Fajriyah said the special pricing had not ended after 45 days and that penalties apply only to volumes above the allocation. PGN and the industry forum therefore give different descriptions of how the pricing policy has worked for customers; the reasons for individual billing differences have not been explained.

Factories must manage both the amount available and the cost of exceeding their quota. More LNG can help supplement pipeline supplies, but its usefulness depends on shipping, receiving capacity, distribution and the price customers actually pay.

Official figures show output losing ground

The Energy and Mineral Resources Ministry's 2025 energy statistics handbook records natural gas production of 6,752.6 MMSCFD in 2025, down from 6,820.6 MMSCFD in 2024. Final energy consumption of natural gas rose from 272.37 million to 277.967 million barrels of oil equivalent, an increase of about 2.1%.

The handbook also notes an accounting change: natural gas liquids were reclassified from gas to oil beginning in 2025. Its gas series consequently excludes those liquids from that year, a relevant detail when comparing production across years.

National production through July 2026 averaged 6,544 MMSCFD, according to figures presented by the Directorate General of Oil and Gas. That was about 4.3% below the budget target of 6,837 MMSCFD. Deliveries averaged 5,208 MMSCFD against a target of 5,508 MMSCFD.

Joint Organisations Data Initiative figures for January through July show domestic demand rising 4% from a year earlier while production fell 3.7%. The initiative is coordinated by the International Energy Forum and supported by the International Energy Agency and OPEC.

Exports are absorbing part of the pressure. Statistics Indonesia recorded LNG exports of 6.2 million tonnes in January–September 2026, down 23% from the same period in 2025. The ministry's handbook shows that LNG exports had already fallen 7.7% in 2025, even as domestic LNG production rose 1.9%. Pipeline exports, however, increased that year from 142.6 to 152.4 trillion British thermal units.

Why the forecasts point to different danger dates

Yayan expects LNG export capacity to fall as domestic needs take priority. He set out the projected change and a major exclusion from his calculation:

Our calculations indicate that LNG export capacity will fall from approximately 1,490 million standard cubic ft per day (mmscfd) in 2025 to around 950 mmscfd by 2027, assuming domestic needs are met first. This projection does not yet account for the Eni project,

The decrease of 540 MMSCFD amounts to about 36%. His separate deficit projection assumes LNG exports remain at 2026 levels, showing the pressure that would arise if export volumes held steady while domestic supply and demand moved further apart.

Wood Mackenzie's May 2025 gas assessment gives a later date for a national deficit: 2033 without new supply development. It expects demand, including contracted exports, to remain around 6 billion cubic feet a day through 2035.

The forecasts use different demand paths, export assumptions and assessment dates. Yayan describes a nearer squeeze under specified export conditions, while Wood Mackenzie examines the longer balance between production and demand including contracted exports. Java's regional shortages are already present within that wider national picture.

Joshua Ngu, Wood Mackenzie's vice chairman for Asia Pacific, described the resource position:

"Indonesia has sufficient resources to meet existing gas demand, but it needs to plan for the future".

Investment is rising, but exploration remains limited

Indonesia's upstream investment rose from US$10.9 billion in 2021 to a stated US$15.4 billion in 2025. Yayan argues that too little goes into exploration, the work of finding and assessing new deposits. Exploration spending was US$1.3 billion in 2024, less than one tenth of the upstream total cited for that period.

The Indonesian Petroleum Association's sector outlook for 2026 gives an earlier snapshot: by October 2025, upstream investment was US$11.2 billion against a US$16.1 billion annual target. Exploration accounted for US$500 million against a US$1.5 billion target, or about one third of the planned exploration spending.

Drilling activity also points to a slow search for replacements. Exploration wells fell from 41 in 2023 to 35 in 2025. Only five of the 39 planned for 2026 had been completed by the end of May.

Wood Mackenzie data identify 499 undeveloped discoveries with a median size of just 3 million barrels of oil equivalent. About 78% are considered too small to develop economically under current prices and regulation. A discovery must generate enough revenue to cover wells, processing and transport before a company will build it.

The petroleum association advocates bringing idle fields into production, using drilling methods that can reach previously difficult rock formations, and simplifying licensing. Indonesia also plans to auction 75 new working areas by 2028. Exploration opens opportunities, while already discovered fields offer a potentially quicker route to additional output.

New fields offer relief on several different schedules

Eni's North and South Hub projects offshore East Kalimantan are expected to provide substantial relief in 2028–2029, with capacity reaching 2,000 MMSCFD by 2029. Their timing matters because Yayan's projected deficit widens before that capacity is expected to arrive.

Central and East Java have another development schedule. The government expects additional regional supplies to build gradually from 2027 to 2035, with the largest production increase in 2030–2031. Lengo is projected to contribute 84.49 MMSCFD from 2030, while Bukit Panjang could supply up to 50 MMSCFD in 2032–2033.

Other planned sources include ENC, TIS Blora Phase 2, Pertamina EP Asset 4, Paus Biru, West Sidayu, MBF and MDK. Officials are coordinating development and allocation to supply customers and make fuller use of the completed Cirebon–Semarang transmission pipeline stages.

The main milestones show why the next two years remain difficult:

• October 21, 2026: Bahlil said Indonesia was considering not renewing gas export arrangements with neighbouring countries.
• October 24, 2026: the 31 MMSCFD diversion from Singapore began.
• December 31, 2026: PGN's stated special LNG pricing period ends.
• 2027–2028: Yayan projects national deficits of 200 and 330 MMSCFD if LNG exports remain at 2026 levels.
• 2028–2029: substantial supply from Eni's hubs is expected.
• 2030–2033: Lengo and Bukit Panjang are projected to add supplies for Central and East Java.

Large resources still require pipelines and workable contracts

Wood Mackenzie identifies more than 35 trillion cubic feet of resources across Abadi, Geng North, Tangkulo and Layaran. It also cites the Indonesia Exploration Forum's estimate of more than 30 billion barrels of oil equivalent yet to be found in the North and South Sumatra and Northeast Java basins.

The consultancy estimates that US$50 billion would be needed to develop resources toward Indonesia's target of producing 12 billion cubic feet of gas a day by 2030. That target is twice the roughly 6 billion cubic feet of daily demand, including contracted exports, in its forecast.

Wood Mackenzie recommends protecting agreed contract terms, setting gas prices that reflect each project's costs and risks, and allowing developers to sell elsewhere when contracted buyers cannot accept deliveries. Its proposals also support agreements requiring buyers to pay for committed volumes even when they take less gas.

Gas transport remains central. Moshe's warning about weak connections between producing islands and Java matches the immediate limit of the Singapore diversion. New reserves, commercially viable projects and delivery infrastructure must arrive together for industrial customers to receive dependable supplies.

Without new development, Wood Mackenzie expects greater reliance on more expensive LNG imports or increased use of coal in power generation. It also identifies gas as an essential industrial raw material. Elsewhere in the region, eastern Australia faces a growing likelihood of shortages throughout the year in the early 2030s, while Singapore is seeking more flexible LNG supplies amid declining pipeline imports and recent global energy disruptions.

Singapore's energy relationship faces wider pressure

Indonesia supplied Singapore with 145.3 billion cubic feet of natural gas in 2024, according to figures attributed to the US Energy Information Administration. Reduced pipeline deliveries strengthen Singapore's need for alternative cargoes and contracts that allow it to adjust purchases.

Jakarta's domestic priority also extends to electricity. Bahlil's conditions for electricity exports have complicated plans to supply Singapore with 3.4 gigawatts by 2035. He said exports were unlikely soon unless buyers accepted Indonesia's price, while domestic customers still needed the power.

The gas decision came amid a damaging regional haze episode. Nusantara Atlas figures put the area burned through September at more than 1.9 million hectares. Singapore signalled legal action against companies linked to the fires, and ASEAN scheduled an emergency haze meeting.

Cooperation has continued alongside the tensions. On October 27, the two governments agreed on a joint haze investigation task force to connect company records, financial intelligence and evidence across borders. Indonesia's stated reason for the gas diversion remains domestic electricity reliability, while both governments are also managing the environmental dispute.

Deputy Energy Minister Yuliot Tanjung said on November 9 that gas availability had reached 513,000 billion British thermal units against a target of 548,000, about 94%. For Java's factories, the next practical tests are December allocations and prices, followed by whether new fields and transport connections meet their planned schedules.

Key Points

• Indonesia redirected 31 MMSCFD from Singapore to electricity needs in Batam, Bintan and Sumatra, with little immediate benefit for Java.
• Central and East Java recorded a July 2026 gas deficit of 104.16 MMSCFD, about 14% of demand.
• PGN's industrial usage limits rise from 66% in early November to 79% in December, with higher charges possible above allocations.
• Yayan Satyakti projects national shortages of 200 MMSCFD in 2027 and 330 MMSCFD in 2028 if LNG exports remain at 2026 levels.
• Eni's hubs are expected to provide substantial relief in 2028–2029; major additions for Java follow on later schedules.
• New production, investment terms and transport connections all determine whether Indonesia's gas resources can reach customers.