Why did Indonesia’s monthly energy import bill jump by nearly half when its physical import volume grew by just 15%? Statistics Indonesia (BPS) reported that the country’s oil and natural gas imports reached US$3.77 billion in July 2026, marking a steep 49.91% year-on-year surge compared to the US$2.51 billion recorded in July 2025.  The US$1.25 billion year-on-year increase in July’s oil and gas bill contributed significantly to Indonesia’s overall monthly imports, which climbed 27.02% annually to US$26.09 billion, while non-oil and gas imports rose 23.83% to US$22.33 billion. Market analysts and government data point to a combination of elevated global crude prices, a persistently weak Indonesian Rupiah, and a domestic upstream production deficit as the core drivers behind the swelling import bill. Speaking at a press conference in Jakarta, BPS Deputy for Distribution and Service Statistics Ateng Hartono highlighted a sharp divergence between the value and the volume of the country's energy purchases. While the monetary value of oil and gas imports soared by nearly 50%, the physical import volume rose by only 15.44% in July 2026. "The price increase certainly contributed to the rise in oil and gas imports; just compare the values, which are much higher compared to the volumes. Hence, automatically there is a price increase that contributes to the surge," Ateng explained, confirming that global market pricing rather than a sudden spike in domestic consumption was the primary trigger. According to BPS data, the annual jump in July’s energy purchases was fueled by a 51.68% spike in crude oil imports which rose by US$406.3 million alongside a 49.11% increase or US$48.3 million in oil-derived products. Cumulatively, throughout the January - July 2026 period, Indonesia’s oil and gas imports expanded by US$7.39 billion, or 40.24% year-on-year. This seven-month surge was driven by oil-derived product imports totaling US$5.319 billion (up 39.6%) and crude oil imports reaching US$2.075 billion (up 41.81%). Beyond international crude benchmarks which have hovered between US$94 and over US$100 per barrel amid ongoing Middle East geopolitical tensions, Indonesia’s energy bill has been compounded by currency depreciation. With the Rupiah trading under pressure between Rp17,750 and Rp17,926 per US dollar in recent months, state energy company PT Pertamina (Persero) and private importers must spend significantly more in local currency to procure US dollar-denominated oil cargoes. Economists warn that this macroeconomic "triple shock" of high global crude prices, a weak Rupiah, and rising logistics costs is feeding directly into imported inflation. Because energy accounts for roughly 15% of input costs across Indonesia’s manufacturing sector, downstream industries particularly petrochemicals, plastics, and packaging that rely on crude derivatives like naphtha are facing narrower profit margins and rising production expenses. At the same time, heavy corporate demand for US dollars to finance oil and gas imports places recurring pressure on Bank Indonesia’s foreign exchange reserves. At the root of Indonesia’s vulnerability to global oil price swings is a long-standing structural gap between domestic upstream output and national fuel consumption. Since becoming a net oil importer in 2003, Indonesia has struggled to reverse the natural decline of its aging oil fields, while domestic fuel demand has grown to approximately 1.6 million barrels per day (bpd). Data from the Ministry of Energy and Mineral Resources (ESDM) showed that as of September 8, 2026, national crude oil lifting stood at 571,731 bpd, remaining below the 2026 State Budget (APBN) target of 610,000 bpd. To ease the financial strain of expensive crude imports while keeping domestic refineries running at optimal capacity, the government has moved to diversify its import sources, including preparing a second phase of crude oil imports from Russia. Energy and Mineral Resources Minister Bahlil Lahadalia confirmed that the procurement is being executed through a Government-to-Government (G2G) and Government-to-Business (G2B) framework involving the Testing Center for Oil and Gas (Lemigas) and Pertamina under Presidential Regulation No. 26/2026 and Ministerial Decree No. 224.K/MG.03/MEM.M/2026, following an initial shipment of 770,000 barrels processed at the Balikpapan Refinery in late June. "We are looking for priority scales that can secure our crude oil supplies first, as long as they do not violate regulations and are economically viable," Minister Bahlil said in Jakarta, emphasizing that alternative crude sourcing is aimed at safeguarding national energy resilience. While discounted crude cargoes and state fiscal buffers have so far shielded Indonesian citizens from immediate subsidized fuel price hikes, energy analysts caution that tactical import deals are only a temporary relief. Without accelerated upstream investment, widespread deployment of Enhanced Oil Recovery (EOR) technology, and regulatory certainty through the long-awaited Oil and Gas Bill, Indonesia’s trade balance will remain exposed to every global price rally. As global energy volatility persists, can Indonesia reform its upstream oil sector fast enough before the next import bill shock hits? 

PT Pertamina Hulu Energi (PHE), Indonesia's state-owned upstream oil and gas subsidiary, recorded total oil production of 475,000 barrels per day (bopd) through April 2026, a significant drop from the 556,000 bopd achieved across 2025. The company's CEO, Awang Lazuardi, attributed the decline to a combination of domestic operational setbacks and geopolitical turbulence abroad, revealing the breadth of pressures bearing down on Indonesia's largest upstream operator.At home, the most disruptive incident occurred at Blok Rokan in Riau, PHE's single largest producing asset. Early in the year, a gas supply disruption arose after a pipeline integrity failure, specifically a leak in a transmission line operated by Transportasi Gas Indonesia (TGI). The outage lasted more than 20 days, severely curtailing the gas-powered energy supply to production facilities across the block. "Average oil production at Rokan dropped quite sharply," Awang said during a hearing with the House of Representatives' Commission XII in late May. Domestic output for the period stood at 367,000 bopd, down from 396,000 bopd in 2025.Further domestic pressure came from Lapangan Banyu Urip, a joint-operated asset with ExxonMobil. PHE encountered facility constraints that limited efforts to ramp up gas production at the field, compounding the output shortfall at a time when the company was already struggling to recover losses at Rokan.On the international front, PHE holds a participating interest in West Qurna-1, an oil field in southern Iraq. Due to force majeure caused by the conflict between the United States, Israel, and Iran, the Iraqi government ordered a temporary shutdown of the field. The move cost PHE approximately 100,000 bopd of production. Though operations have since been permitted to resume, output remains at less than ten percent of capacity, allocated solely to meet Iraq's domestic needs, and a full recovery timeline remains uncertain.Together, these disruptions have pushed PHE's total production well below the government's 2026 lifting target of 610,000 bopd set in the state budget. Awang acknowledged the scale of the challenge but pointed to the temporary nature of several setbacks. Industry observers, however, note that structural vulnerabilities including aging infrastructure, geopolitical exposure, and dependence on a small number of high-output blocks continue to pose long-term risks to Indonesia's energy security goals.Written by: Akhirian Taka

Indonesia has taken a significant step in reshaping its upstream oil and gas landscape, with the government formally announcing 118 potential new oil and gas working areas as part of a broader push to accelerate exploration and grow the country's reserve base. The announcement was made by Director General of Oil and Gas Laode Sulaeman on May 28, referencing a presentation delivered by Energy and Mineral Resources Minister Bahlil Lahadalia at the 50th Indonesian Petroleum Association Convention and Exhibition (IPA Convex) on May 20.The initiative comes as Indonesia seeks to reverse a long-term decline in oil production while strengthening domestic energy security. The 118 potential working areas were developed through contributions from the Geological Agency of the Ministry of Energy and Mineral Resources, Lemigas, and existing contractors, with costs funded through the state budget.As of May 20, 2026, 25 of the 118 areas had already attracted formal interest or progressed to contract signing, with an additional 43 in the joint study phase. The remainder are being positioned for joint studies or direct designation as new working areas, suggesting meaningful industry appetite across the board.On the optimization side, the government has expressed strong support for PT Pertamina Hulu Energi's (PHE) push to bring idle structures back into productive use through Operational and Technology Cooperation arrangements (KSOT), under Ministerial Regulation No. 14 of 2025. PHE has prepared around 41 idle structures for KSOT, of which 22 were publicly announced at IPA Convex 2026, spanning all four operational regions: 8 in Regional 1 (Sumatra), 4 in Regional 2 (Java), 7 in Regional 3 (Kalimantan), and 3 in Regional 4 (East Java and Eastern Indonesia). The remaining structures are expected to be opened for cooperation in the near term.The scale of the initiative, covering new working areas, idle structures, idle wells, and community production schemes simultaneously, signals a coordinated government posture aimed at closing the gap between Indonesia's hydrocarbon resource potential and its current production levels. With drilling activity and partnership processes already in motion across multiple fronts, if executed as planned, the initiative could unlock new reserves and accelerate production growth from both frontier exploration areas and previously idle assets over the coming years.  Writer: Timothy Evan

In 2026, the oil and gas industry’s AI revolution is no longer a forecast, it is an operational reality. The world’s largest energy companies have moved past experimentation, embedding AI into drill floors, control rooms, and thousands of kilometers of pipeline. The results are tangible: fewer equipment failures, lower costs, faster drilling cycles, and tighter emissions control.ExxonMobil was the first in the industry to deploy AI-driven closed-loop drilling automation in a deepwater setting, operating in Guyana where AI systems adjust drilling parameters in real time without human input. In the Permian Basin, machine learning has lifted shale well output by more than 5% and cut data preparation time by roughly 40%.BP has wired over two million sensors across assets in the Gulf of Mexico, the North Sea, and Oman, feeding data into digital twins and its in-house AURA system that simultaneously tracks operational inefficiencies and monitors carbon and methane emissions. The company reports drilling more wells annually as a direct result. Chevron, meanwhile, deploys AI-enabled drones over its Permian operations to detect methane leaks and equipment failures without putting personnel in hazardous zones. Shell applies machine learning to forecast equipment failures before they occur, while Saudi Aramco uses computer vision to monitor thousands of kilometers of pipelines for anomalies.The financial case is well-documented. Boston Consulting Group reports AI has cut operating costs by 15–20% and reduced key cycle times from months to weeks. McKinsey estimates predictive analytics alone lowers maintenance costs by up to 25%. At the field level, AI systems have prevented over 140 hours of unplanned downtime, protecting 1.6% of production uptime figures that translate directly into revenue.The global AI in oil and gas market was valued at USD 7.6 billion in 2025 and is projected to surpass USD 25 billion by 2034, growing at 14.2% annually. Upstream operations account for over half of all AI deployment, driven by the data-intensive nature of exploration and production. North America leads adoption, while Asia-Pacific is forecast as the fastest-growing region through 2031.The companies advancing fastest are not doing so simply to cut costs. They are responding to growing complexity: volatile markets, tightening emissions rules, aging infrastructure, and the sheer volume of real-time data across global assets. Managing all of that with human judgment alone has become impractical. In 2026, AI is not the future of oil and gas. It is the present. Writer: Akhirian Taka

Indonesia recorded a significant upstream milestone after Eni announced a giant gas discovery at the Geliga-1 exploration well in the Ganal Block, offshore East Kalimantan. The find holds an estimated 5 trillion cubic feet (Tcf) of gas and around 300 million barrels of condensate, making it one of the more consequential discoveries in the region in recent years.The well was drilled to roughly 5,100 meters in water depths of about 2,000 meters, approximately 70 kilometers from shore. Drilling encountered a substantial gas column within Miocene formations with strong petrophysical properties, a result that speaks to the quality of the reservoir even under technically demanding conditions.Geliga-1 is the latest in a string of exploration successes Eni has logged in the Kutei Basin, following Geng North in 2023 and Konta-1 in 2025. Taken together, these findings steadily reinforce the basin's standing as one of Indonesia's most promising gas provinces, with resource potential that scales across multiple structures.On the development side, Eni has already taken Final Investment Decisions (FID) for the South Hub and North Hub projects, both expected to come online around 2028. At full capacity, the two hubs are projected to produce up to 2 billion cubic feet per day (Bcfd) of gas alongside 90,000 barrels of condensate per day. The development will rely on subsea systems and FPSO infrastructure, tied into existing facilities at the Bontang LNG plant.The location of Geliga-1 also draws attention to the nearby Gula discovery, estimated at around 2 Tcf. Early assessments suggest that combining resources from both fields could add roughly 1 Bcfd of gas output and support the formation of a third production hub in the basin, sharing infrastructure and cutting time to market.To close the loop on the downstream side, Eni is looking at options to expand liquefaction capacity at Bontang. The rationale is straightforward: leverage what is already there, keep capital spending in check, and extend the working life of one of Indonesia's principal LNG export facilities.The Ganal Block is operated by Eni with an 82% interest, with Sinopec holding the remaining 18%. The block will eventually fold into a broader joint venture with Petronas, anchoring Eni's position in Southeast Asia's gas market over the longer term.Drilling is expected to continue through 2026 and 2027. If results hold, Geliga looks set to become a meaningful contributor to Indonesia's gas reserve base while reaffirming the Kutei Basin's role in both domestic supply and international LNG trade.Writer: Timothy Evan

Indonesia's energy landscape received a significant lift as Pertamina Hulu Mahakam (PHM) launched Platform WPN-7, boosting gas production by 20 million standard cubic feet per day (MMSCFD) in the Mahakam Block. This achievement underscores ongoing efforts to secure national gas supplies amid rising demands.Located offshore in East Kalimantan's mature Sisi Nubi field, WPN-7 went operational on March 23, 2026. It features two key wells: NB-701, which began flowing at 9.8 MMSCFD on March 25, and NB-702, achieving 12.5 MMSCFD by March 26. Together, they target a combined initial output of 20 MMSCFD, with PHM actively monitoring to stabilize and optimize performance in line with Q1 2026 objectives.This platform represents the third in the Sisi Nubi Area of Interest (SNB AOI) 1-3-5 project. Predecessors include WPS-4, activated December 4, 2025, and WPS-5 on February 23, 2026. These phased developments build on rigorous technical groundwork, revitalizing output from the longstanding Mahakam Block, a cornerstone of Indonesia's upstream sector.The boost aligns with broader national strategies, enhancing energy resilience. PHM's initiatives complement prior Mahakam projects that added substantial capacities, like up to 36 MMSCFD, supporting SKK Migas targets for oil and gas stability."These new wells play a vital role in ensuring steady gas availability and strengthening our upstream self-sufficiency goals," said PHM General Manager Setyo. As Indonesia navigates energy transitions, such milestones from mature fields like Mahakam remain crucial for economic and supply security into 2026 and beyond. Written by: Christya

Indonesia is stepping up its renewable energy efforts through a strategic partnership between global energy technology company SLB and Star Energy Geothermal. The two companies have signed an agreement to support the development of the Sekincau geothermal project in Lampung, marking a deeper phase of collaboration in the country’s geothermal sector.The agreement, signed on Thursday (February 19), expands beyond earlier technology cooperation into a more comprehensive scope that includes field development planning, subsurface evaluation, and integrated drilling services. SLB will play a key role in providing technical expertise, particularly in subsurface mapping, well planning, and drilling operations, all of which are critical in reducing risk during geothermal development.“Advanced technology, deep technical expertise and disciplined operational performance, through integration across the project lifecycle, are essential to scaling geothermal projects,” said Nurzhan Ongaltayev, managing director, Indonesia, SLB. “These agreements and new collaboration opportunities apply SLB’s subsurface consulting expertise and global execution experience to support geothermal development alongside an experienced operator, from project execution in Indonesia to evaluating opportunities overseas.”The Sekincau geothermal project represents more than just another energy development initiative. It reflects a shift in how geothermal projects are approached, with a stronger emphasis on collaboration, technology integration, and risk reduction.If successful, the partnership between SLB and Star Energy could serve as a model for future geothermal developments in Indonesia. By combining technical expertise with operational experience, the project has the potential to accelerate the country’s transition toward a more sustainable and resilient energy system.As demand for clean energy continues to rise, initiatives like Sekincau highlight the importance of turning Indonesia’s vast geothermal resources into tangible and lasting impact.

Surabaya, SPE ITS SC – PT Elnusa Tbk (IDX: ELSA), an integrated energy services company under Pertamina’s Upstream Subholding, is strengthening its wireline services capabilities through a new technology access program developed in collaboration with SLB.Wireline services are specialized upstream oil and gas operations that use cable-deployed tools to collect subsurface data and perform various well interventions. These services are essential for evaluating reservoir conditions and supporting exploration and production activities.The initiative, called Technology Access Enablement and Delivery to Elnusa, forms part of the company’s 2026 transformation agenda themed “Rediscover Technology & Innovation Edge,” which emphasizes technology-driven service development and operational competitiveness.Through the collaboration, Elnusa will gain access to advanced open hole and cased hole wireline logging tools, enabling the company to expand its service portfolio and address increasingly complex subsurface challenges in upstream operations.Elnusa Director of Operations Andri Haribowo said the program is designed to broaden the scope of the company’s wireline services while strengthening internal capabilities through a structured capacity-building approach.“This collaboration not only opens access to advanced open hole tools, but also enhances Elnusa’s internal competencies and operational capacity. Previously, our services were primarily focused on cased hole logging. With this initiative, we are expanding into advanced open hole logging, creating a more comprehensive service portfolio for our customers,” he said.The cooperation framework will be implemented in phases to ensure effective technology transfer and sustainable capability development. In addition to gaining access to advanced tools, Elnusa aims to strengthen operational procedures and develop internal talent capable of independently operating the technology in the future.The program also marks a new phase of collaboration between Elnusa and PT Schlumberger Geophysics Nusantara, an affiliate of SLB. According to Armando Ballesteros, Director of PT Schlumberger Geophysics Nusantara, the partnership reflects a shared commitment to supporting technology transfer and competency development in Indonesia’s upstream services sector.Industry experts note that the adoption of advanced wireline technology is becoming increasingly important as oil and gas reservoirs grow more complex. Advanced subsurface evaluation tools allow operators to better understand reservoir characteristics, improving decision-making while reducing exploration and development risks.Strategic partnerships between local service providers and global technology companies are also seen as a key driver of innovation in the energy sector. Such collaborations can accelerate the adoption of advanced technologies while strengthening domestic technical capabilities.With the launch of the program’s initial phase, Elnusa is positioning itself as a technology-driven upstream service provider, aiming to enhance operational efficiency while supporting the development of Indonesia’s oil and gas industry.Writer: Aura Hammada