Indonesia Oil And Gas Market Size & Share Analysis - Growth Trends and Forecast (2027 - 2032)

Market Overview

Indonesia Oil And Gas Market Snapshot & Metrics Overview

Study Period	2021 - 2032
Forecast Data Period	2027 - 2032
Base Year Market Size (2026)	USD 14.6 Billion
Market Size (2027)	USD 15.36 Billion
Market Size (2032)	USD 19.56 Billion
Growth Rate (2027 - 2032)	4.95 %
Market Concentration	Medium
Major Players* Shell Chevron Pertamina ExxonMobil Medco Energi	*Disclaimer: Major Players sorted in no particular order

• Africa
• Africa
• Algeria
• Australia
• Brazil
• Canada
• Chad
• China
• Denmark
• Egypt
• Europe
• Gabon
• India
• Iran
• Iraq
• Italy
• Kazakhstan
• Kuwait
• Malaysia
• Mexico
• Nigeria
• Norway
• Oman
• Qatar
• Romania
• Russia
• South East Asia
• South Korea
• Sudan
• Sudan
• Thailand
• Turkmenistan
• United Arab Emirates
• United Kingdom
• United States
• Uzbekistan
• Venezuela
• Vietnam

Market Trends and Insights

Robust domestic demand from the middle class

Indonesia's domestic fuel sales reached a decade peak of 84.1 million kiloliters in 2025.^[1] Household use provides a second demand perspective, with 89.71% of Indonesian households using LPG, city gas, or biogas as their primary cooking fuel in March 2025. The Directorate General of Oil and Gas reported LPG sales of 9.24 million metric tons in 2025, up from 8.9 million in 2024. That increase raises the volume that LPG supply and distribution assets must handle, alongside an already broad household gas-fuel base. For terminal and bottling operators, capacity to handle additional LPG throughput is therefore a demand opportunity distinct from extending cooking-fuel access to new households.

Government push for 1 million bbl/d oil & 12 Bscf/d gas by 2030

National production targets create a coordinated reason to develop large fields and the infrastructure needed to deliver their output. In July 2026, SKK Migas said Indonesia targeted 1 million barrels of oil and 12 billion cubic feet of gas per day by 2030. The North Hub development, combining Geng North and Gehem offshore East Kalimantan, illustrates the scale of that undertaking. Its July 2026 plan targeted 1 billion standard cubic feet of daily gas production in the fourth quarter of 2028. This creates a commercial opening for integrated field development and the connections needed to move planned output. At 1 billion standard cubic feet a day, North Hub would supply about one twelfth of the 12 billion cubic feet daily gas target, so the national goal needs several further developments of similar scale.

LNG export arbitrage to North-East Asia

LNG exports connect Indonesian gas supply with a substantial North-East Asian buyer base, creating an additional route for monetizing production. Indonesia exported 3.8 million metric tons of LNG to Japan, 3.79 million metric tons to China, and 2.27 million metric tons to South Korea in 2025. Multiple destination economies provide a broader sales base than dependence on a single national buyer group. The same 2025 trade data valued shipments to Japan at USD 2.08 billion, China at USD 1.99 billion, and South Korea at USD 0.94 billion. South Korea's USD 0.94 billion for 2.27 million metric tons implies lower receipts per metric ton than Japan and China, making destination mix consequential for revenue from a given export volume.

PSC gross-split incentives attracting IOCs

Contract flexibility can make exploration acreage commercially attractive alongside the potential of its resources. In its 2025 performance report, the Directorate General of Oil and Gas said revised gross-split production-sharing terms had increased contractor participation interest in work-area auctions. The framework reduced additional contract components from 13 to 5 and provided conventional oil-and-gas contractors with a 75% to 95% share before tax. It also opened an option to change between gross-split and cost-recovery contracts. Together, these provisions allow prospective operators to weigh retained production against alternative ways of allocating development costs. Acreage competition can therefore turn on how contract form accommodates field economics, alongside the geology of the block itself.

Renewable-energy build-out & EV adoption

Electric-vehicle adoption creates a substitution challenge for suppliers whose revenue depends on petroleum-fueled road travel. The Association of Indonesian Automotive Industries (GAIKINDO) recorded 103,931 EV sales in Indonesia in 2025, up from 43,188 in 2024. The increase shows expanding adoption of an alternative propulsion technology, which changes the fuel-sales opportunity attached to new vehicle purchases. For refiners and fuel retailers, each added EV is a vehicle whose energy needs may be met through electricity rather than gasoline. With EV sales more than doubling in a year, the exposure is to capacity planned for future gasoline growth rather than to current sales.

Declining output from aging basins

Declining field productivity makes replacement spending necessary before operators can expand saleable output. In August 2026, ESDM described extreme natural decline at Cepu Block. That condition puts production protection in competition with new development for capital, since a spending increase need not translate into additional supply. In September 2026, PT Pertamina Hulu Kalimantan Timur, a PT Pertamina Hulu Indonesia subsidiary, reported reopening Sepinggan V-7 access, with workover and reperforation following. Well-access restoration therefore leaves the operator with further workover and reperforation costs before it can establish whether the reopened zone adds saleable output.

*Our forecasts treat driver/restraint impacts as directional, not additive. The impact forecasts reflect baseline growth, mix effects, and variable interactions.

Indonesia Oil And Gas Market Segment Analysis

Upstream accounted for a 72.3% share of the Indonesia oil and gas market size in 2026 and is the fastest-growing segment, forecast at a 5.25% CAGR over 2027-2032. Indonesia's Directorate General of Oil and Gas reported that upstream oil and gas investment rose slightly in 2025 from 2024, showing continued deployment at scale rather than a sharp annual spending acceleration. The commercial weight comes from sustaining large field programs, which can create substantial work for operators and contractors even when the change in annual investment is modest.

Midstream and downstream activity show different operating roles. Midstream's delivery function is illustrated by Pertamina Gas, part of Pertamina's Gas Subholding, which transported more than 1.5 billion standard cubic feet of gas daily in 2025. Downstream's processing role is illustrated by the Balikpapan expansion, inaugurated in January 2026 with reported refinery capacity rising from 260,000 to 360,000 barrels per day and Euro V-equivalent products. PT Kilang Pertamina Balikpapan reported commissioning and operational testing in August 2026. Midstream's transport volumes and downstream's refinery testing show that each stage carries its own execution timeline.

Onshore represented a 57.78% Indonesia oil and gas market share in 2026, making it the largest segment. PT Pertamina Hulu Sanga Sanga (PHSS), a PT Pertamina Hulu Indonesia subsidiary, averaged 13,200 barrels of oil daily across 7 onshore Sanga Sanga fields in East Kalimantan in 2025. The operator uses well reactivation, gas-lift, and compression methods to optimize existing surface facilities. Its Cement Packer approach accesses marginal zones above the production packer without recompleting the well. These methods create a service opportunity around recovery from existing well and surface infrastructure, complementing investment in new producing assets.

Offshore is the fastest-growing segment, forecast at a 5.75% CAGR over 2027-2032. On March 18, 2026, Eni took final investment decisions for Gendalo and Gandang (South Hub) and the Geng North and Gehem fields (North Hub), offshore East Kalimantan. That commitment shifts commercial requirements toward execution of deepwater production infrastructure, creating a contracting opportunity linked to bringing new offshore supply into service. The planned delivery route for the 2 hubs would connect to both domestic gas pipelines and Bontang LNG. Access to both outlets makes transport integration central to realizing value from the offshore investment.

Construction was the largest segment, accounting for a 51.2% share in 2026. On July 7, 2026, PT Saipem Indonesia, a Saipem subsidiary, and PT Tripatra Engineers and Constructors won Eni North Ganal's Kutei North Hub floating production, storage, and offloading contract. The award covered engineering, procurement, construction, and installation, with approximately USD 2 billion attributable to Saipem's share. The integrated scope connects fabrication with the work needed to bring an offshore production unit into service, creating substantial exposure to delivery coordination. Such packages concentrate the operator's delivery interfaces in the contractor consortium, linking construction value with engineering and installation execution.

Maintenance and turn-around is the fastest-growing segment, forecast at a 5.85% CAGR over 2027-2032. PT Nusantara Regas completed its turnaround from March 14 to 24, 2026, at LNG receiving, storage, and regasification facilities serving Greater Jakarta and West Java.^[2] The work combined inspections, maintenance, spare-part replacements, and technical checks for facilities supplying PLN power plants. Decommissioning covers a different service requirement, including well closure, platform dismantling, inspection and permitting costs, and site cleanup and restoration. A service supplier can consequently address operating reliability and asset retirement without depending exclusively on awards to build new capacity.

Geography Analysis

Domestic gas commitments and operating offshore assets give South Sumatra and East Kalimantan different commercial starting points. On February 6, 2025, PT Medco E&P Indonesia signed a gas-supply agreement with PT Perusahaan Gas Negara (PGN) for commercial, industrial, and electricity uses in South Sumatra and West Java. In East Kalimantan, PT Pertamina Hulu Mahakam's NB-701 well at Sisi Nubi began production on March 23, 2026, reaching up to 9.8 million standard cubic feet of gas daily on March 25.^[3] Buyer access and measured well delivery therefore anchor commercial activity in these provinces through different stages of the gas supply chain.

Natuna activity spans producing fields and acreage with committed work programs, while Java adds a transmission-readiness requirement. Medco E&P Natuna Ltd brought Forel and Terubuk in South Natuna Sea Block B into first production in 2025. ESDM named PT Nations Petroleum the Natuna D-Alpha tender winner in East Natuna on September 17, 2026, with initial 3-year commitments including geological and geophysical studies, seismic work, and appraisal and exploration wells. Central Java's Cisem II marked first gas-in at Batang on March 18, 2026, but BPH Migas reported on September 18 that supporting operational steps remained. Acreage awards create exploration obligations before field cash flow, while transmission readiness governs when gas resources can reach additional buyers.

Papua and the Arafura Sea present contrasting commercial stages, with an operating LNG base and a project developing its buyer arrangements. BP Berau Ltd operates Tangguh, a 3-train gas-production and LNG operation in Teluk Bintuni, Papua Barat. For Abadi in the Arafura Sea, INPEX Masela reached basic LNG offtake agreements with BP, PLN Energi Primer Indonesia, PGN, and Shell Eastern Trading in May 2026. A separate basic pipeline-gas agreement covered Pupuk Indonesia, and INPEX Masela continues negotiations toward final sales contracts. Securing final terms across LNG and pipeline gas would turn Abadi's diverse prospective buyer base into a clearer commercial foundation for project delivery.

Regulatory Framework and Outlook

The comparison of selected jurisdictions assesses national contracting and East Kalimantan's spatial rules from an upstream developer's perspective. National law assigns oil-and-gas management to the central government, while gross-split contracting places operational management with SKK Migas and capital and risk with contractors. East Kalimantan's spatial plan governs eligibility and conditions for oil-and-gas activities in the province's mining and energy areas. Contract structure and site compliance therefore create distinct parts of development exposure.

Indonesia's Medium rating reflects the investment risk borne by gross-split contractors under national operational oversight. Protection of gross-split contracts signed before August 12, 2024, through expiry preserves those existing terms, and the Oil and Gas Bill approved as a House of Representatives initiative on August 18, 2026, was still proposed on September 30, so No change rests on the in-force framework. East Kalimantan's Medium rating reflects permitted oil-and-gas use with spatial conditions on offshore structures and a prohibition on unlicensed activity. Its in-force 2023-2042 planning framework supports No change, with site access continuing to depend on compliant location and use.

Value Chain Stages

The value chain comparison follows production, transportation, and refining to show where operators and specialist suppliers earn income. Pipeline development separates asset ownership, contracting, and equipment supply, creating distinct commercial roles within one delivery system. An August 2025 pipe shipment for the 96-kilometer Cikampek to Plumpang fuel pipeline illustrates the connection between construction and manufacturing. The commercial task is to coordinate these interfaces so that equipment and operating assets contribute to a usable supply route.

Kilang Pertamina Internasional sources domestic crude and condensate and uses international markets to meet domestic supply shortages. It uses a Crude Acceptance Matrix to assess whether feedstock meets its refineries' technical and operational requirements. Refinery-product sales therefore depend on compatible feedstock as well as processing capacity, tying downstream earnings to producers and import suppliers whose crude and condensate meet those requirements.

Key Opportunities for Market Participants

The opportunities comparison assesses 3 upstream entry routes with different bidding deadlines and exploration obligations. On September 17, 2026, the Directorate General of Oil and Gas opened direct and regular tenders and invited proposals for additional available acreage. Participation in the announced tenders requires interested business entities and permanent establishments to register and access the official bid documents. The commercial choice turns on whether an operator has an evaluation ready, needs time to define exploration work, or seeks to propose terms for available acreage.

The September 17, 2026, Sapukala award to Eni Indonesia Limited demonstrates a completed direct-tender selection, separate from the Stage II offering. The Stage II direct tenders for 7 blocks provide the nearest-dated entry route, with participation documents due November 2, 2026. Because bid-document access for the 7 blocks ends October 31, 2026, operators without completed evaluations by then are better placed in the Leti Selatan tender, which runs to January 14, 2027, or in the 6-month proposal route.