Indonesia Oil And Gas Upstream Market Size & Share Analysis - Growth Trends And Forecast (2025 - 2030)

Indonesia Oil And Gas Upstream Market Trends and Insights

Fiscal & Licensing Reform Accelerates Investment Flows

Revisions to Government Regulation 35/2004 introduce a selectable gross-split regime that awards contractors up to a 95% revenue share for unconventional projects, thereby improving the net present value and shortening the payback period. Operators now switch between cost-recovery and gross-split frameworks to match project risk, an option that has already attracted joint studies from Eni, Harbour Energy, ExxonMobil, and BP. The regulatory update directly addresses earlier investor concerns about fiscal rigidity and stimulates license uptake in frontier acreage, particularly in deep-water tracts where risk-weighted economics favor higher contractor shares. Concurrently, streamlined permitting under MEMR Regulation 13/2024 reduces license approval time from 24 months to 12 months, enabling faster exploration cycles.

Deep-Water Gas Discoveries Reshape Resource Portfolio

The Layaran-1 find in South Andaman validated a 6 TCF resource base and 30 MMSCFD test flow, while the Timpan-1 well holds 5-6 TCF and 27 MMSCFD output potential.^{[1]Reporting Team, “South Andaman Discovery Adds 6 TCF Gas,” Business-Indonesia, business-indonesia.id} Alongside Eni's 5 TCF North Ganal discovery, Indonesia's proven reserves increased by roughly 30%, contingent upon appraisal.^{[2]Source: Research Unit, “Indonesia Deep-Water Round-Up 2025,” GBR, gbreports.com} SKK Migas schedules the first gas between 2028 and 2030, necessitating subsea pipelines and floating LNG storage that anchor a new export corridor. INPEX's Abadi LNG, which completed FEED in 2024, targets 9.5 MTPA and USD 20 billion capex, reinforcing Indonesia's oil & gas upstream market leadership in regional LNG supply.

AI-Led Subsurface Imaging Transforms Operational Efficiency

Pertamina Hulu Rokan reduced candidate well identification time to one day by utilizing machine-learning-driven seismic analytics—an 86% efficiency increase that accelerates rig scheduling and reserve replacement. The SOPPRED model reduced non-productive rig hours from 82 to 12 and saved 30,000 liters of diesel per well by anticipating gumai shale hazards. Cloud-based AI services from Indosat Ooredoo Hutchinson deliver high-resolution wave measurements that can increase production by 10% and reduce potential fatal injuries by 95%. Such gains lower lifting costs, extend economic field life, and strengthen the Indonesian oil & gas upstream market against price volatility.

CCS-EOR Hubs Enable Tertiary Recovery Potential

Indonesia holds 572 gigatons of CO₂ storage capacity in saline aquifers and 4.85 gigatons in depleted reservoirs, positioning CCS as both an emissions solution and a recovery enabler. Pertamina identified 950 million STB of EOR potential across 12 projects, utilizing its proprietary surfactant, PHR-24, which proved commercially viable in mature Sumatran fields. The Tangguh CCS facility—Southeast Asia’s largest—anchors a network approach that enables high-CO₂ gas fields to move forward, while China-Indonesia technology cooperation accelerates the deployment of tertiary recovery.

Aging Onshore Mature Fields Constrain Production Growth

Roughly 70% of Indonesia’s 44,985 oil wells are mature, declining at a rate of 21% annually, and leaving 16,990 idle sites that require workovers or permanent abandonment (P&A) decisions. The heavy oil dominance in Central Sumatra’s Duri and Rantau Bais fields, with API gravities below 25°, increases thermal and chemical EOR costs. Reactivation programs target 4,500 wells but face economic hurdles without further fiscal sweeteners. Consequently, sustaining base output diverts capital expenditures from exploration, moderating the growth curve of the Indonesian oil & gas upstream market.

ESG-Driven Capital Scarcity Pressures Project Financing

Domestic banks allocate only 1-3% of green portfolios to renewables, yet impose stricter ESG lending filters on hydrocarbons, requiring ISO 14001 compliance and SKUP certification.^{[3]Analysis Team, “Banks Tighten ESG Lending for Hydrocarbons,” Indonesia Business Post, indonesiabusinesspost.com} Pertamina’s 2024 Sustainable Finance Framework secured ISS validation, opening up hybrid green-transition funding; however, the firm still drew USD 2.5 billion in short-term conventional loans during market uncertainty. Stricter ESG scrutiny raises the cost of capital and can delay frontier developments, particularly those with higher carbon dioxide (CO₂) content.

Segment Analysis

By Location of Deployment: Offshore Momentum Sustains Growth

Offshore assets accounted for 56.5% of 2024 revenue and are expected to advance at a 6.2% CAGR, increasing the Indonesian oil & gas upstream market size for offshore assets to USD 7.57 billion by 2030. Massive gas clusters in Andaman and Masela underpin long-cycle cash flows, while brownfield subsea tie-backs around Mahakam preserve volume stability. Operators cite shorter sanction-to-first-gas timelines for jack-up re-entries, and flexible fiscal terms improve project IRR to double-digits under USD 65/bbl scenarios.

Onshore output trails, constrained by mature reservoirs but buffered by lower development costs and proximity to infrastructure. AI-aided workovers at Rokan achieved 152,161 bpd in June 2025, demonstrating that digital optimization can help narrow productivity gaps. Still, heavy crude viscosity and water-cut issues inflate lifting cost to USD 22/bbl versus offshore’s USD 16/bbl. The government’s aim to revive 4,500 idle wells should slow the decline; yet, offshore remains the main growth engine for the Indonesian oil & gas upstream market.

Note: Segment shares of all individual segments available upon report purchase

By Resource Type: Gas Ascendance Challenges Oil Supremacy

Crude oil held a 52.8% share in 2024, translating to USD 5.07 billion of the Indonesian oil & gas upstream market size, but expands modestly at a 4.1% CAGR as mature fields dominate the slate. Gas, in contrast, is expected to reach a 46% share by 2030, driven by a 6.3% CAGR, backed by startup schedules from Layaran, Timpan, and Abadi. Price-indexed LNG contracts enhance project netbacks when Asian spot prices trend above USD 16/MMBtu, attracting capital expenditure even amid debates about the energy transition.

Elevated CO₂ in Natuna D-Alpha kept bids away, underscoring the need for CCS to unlock mega-gas. Meanwhile, domestic gasification programs accelerate demand from fertilizers and power plants, ensuring offtake security. Collectively, the growth of natural gas materially reshapes the revenue mix within the Indonesian oil & gas upstream market.

By Well Type: Conventional Base Dominates, Unconventional Outlook Brightens

Conventional wells account for a 93.1% share, equivalent to USD 8.95 billion in 2024 revenue, and sustain a 5.4% CAGR through drilling campaigns that have doubled to 40 wells in 2024. This segment anchors near-term cash flow and underpins the Indonesia oil & gas upstream market share advantage for established operators.

Unconventional opportunities post the Gulamo DET-1 find are projected to achieve an 8.8% CAGR, targeting 233 TCF of shale potential across Sumatra. MEMR’s 95% gross-split for shale projects cuts break-even to USD 55/bbl oil equivalent, but hydraulic fracturing supply chains are nascent. Success hinges on technology alliances with North American specialists and water-management best practices, stages that could unlock a multi-billion-dollar upside for the Indonesian oil & gas upstream market.

Note: Segment shares of all individual segments available upon report purchase

By Service: Development & Production Lead, Decommissioning Accelerates

Development and production services captured 64.4% of 2024 spend, mirroring operators’ priority on short-cycle output and lifting cost reductions. Robotic process automation at PT Patra Drilling cut invoicing lag by 30 days and improved crew safety, proving digital ROI. The Indonesian oil & gas upstream market size for this service line is forecast to cross USD 8.5 billion by 2030.

Decommissioning services, although with a 4.6% share in 2024, are expected to surge at an 8.1% CAGR as 630 offshore platforms reach the end of their 40-year life. Government guidelines now require abandonment cost provisions in PSCs, spurring early engagement of specialized contractors. Exploration services maintain a stable 5.5% CAGR, driven by annual block auctions and 3D seismic commitments in the Andaman region.

Geography Analysis

East Kalimantan supplied 37.7% of national LNG in 2024 via the Bontang facility, validating the region’s infrastructure depth and export connectivity to Japan, South Korea, and China. Mahakam’s brownfield compression projects sustain plateau, while subsea tie-backs from North Ganal add incremental throughput. Planned CCS in the region further extends asset life and addresses shifts in carbon policy.

Central Sumatra remained Indonesia’s second-largest oil hub at 152,161 bpd in June 2025, driven by Rokan steam-flood optimization.^{[4]Energy Desk, “Mahakam Compression Keeps Output Stable,” Katadata, katadata.co.id} Heavy-oil viscosity and high water-cut demand chemical EOR, which elevates unit costs but also yields upside through enhanced recovery factors. South Sumatra complements established pipeline networks feeding domestic refineries and power plants, anchoring demand certainty that underpins continuing infill drilling.

North Sumatra–Andaman and offshore Maluku mark Indonesia’s frontier axis. Layaran-1’s 6 TCF discovery and Abadi’s 9.5 MTPA LNG plan attract global capital, yet deep-water skills gaps and subsea infrastructure requirements prolong timelines. Still, the cumulative resource base positions these provinces as the future growth pole for the Indonesian oil & gas upstream market, shifting the production center of gravity eastward by the next decade.