Drilling in East Kalimantan – Photo by Rick Patenaude
Indonesia has announced the latest winners of its oil and gas exploration bid rounds, awarding nine new work areas (WAs) under the 2025 IPBR II and III.
Out of 110 oil and gas work areas identified as having exploration potential across the country, 21 have been awarded since late 2024. The nine newly awarded work areas were officially announced on March 17, 2026.
The total committed investment for these nine work areas amounts to US$84.75 million, with a signing bonus of US$3.65 million. The awards were granted through a direct offer tender process conducted by the Ministry of Energy and Mineral Resources (ESDM).
The Newly Awarded Oil and Gas Work Areas
In Sumatra * Karunia WA – PT Sele Raya * Jalu WA – Armada Talu Holdings B.V. * Southwest Andaman WA – Mubadala Petroleum (Andaman II JSA) Limited * Delapan Muaro WA – PT Tenang Wijaya Sejahtera * Tapah WA – PT Goldenheaven Prima Investama
In Java * Nawasena WA – Medco Energi * Barong WA – Consortium of Inpex Corporation and BP Exploration Indonesia Limited
In Papua * Bintuni and Drawa WA – Consortium of BP Exploration Indonesia Limited, MI Berau B.V., CNOOC Southeast Asia Limited, and Indonesia Natural Gas Resources Muturi Inc.
These awards mark a continued effort by the Indonesian government to accelerate upstream oil and gas development and attract investment into prospective exploration areas nationwide.
Here is a summary of Indonesia’s upstream oil and gas production activities and results throughout 2025.
Daily oil and NGL production in December 2025 – 595,000 BOPD Daily gas production in December 2025 – 6837 MMSCFD Daily oil and gas production in December 2025 – 1798 MBOEPD Total Investment in 2025 – 15.4 billion USD Exploration wells drilled in 2025 – 35 Development wells drilled in 2025 – 980 2D seismic completed in 2025 – 420 KM 3D seismic completed in 2025 – 2574 KM2 Number of work areas – 164
Looking ahead to 2026, the government has set an oil production target of 610,000 BOPD.
Through the South Hub project, the country expects to add 2 BSCF of gas and 19 billion barrels of condensate from the five deepwater gas fields located in the southern part of the Makassar Strait by optimizing the utilization of the deepwater Jangkrik FPU.
The South Hub Project
The five gas fields are Jangkrik, Merakes, Gendalo, Gandang, and Maha. The gas gathered at the Jangkrik FPU will be piped to the Badak LNG plant in Bontang. Oil and gas operators involved in the project include Eni Indonesia, Pertamina Hulu Energi East Sepinggan, and Tiptop Indonesia.
The image above shows the first deepwater platform in Indonesia – The West Seno Field TLP. It is a tension leg platform commissioned by Unocal in 2003 in the Makassar Strait.
The first oil discovery well in Venezuela, the Zumaque -1 (MG-1)
This is the story and enduring legacy of Venezuela’s first oil discoveries and early petroleum development, which began in the early 20th century and went on to reshape global energy history.
The birth of Venezuela’s oil industry is traced to Well Zumaque I, also known as MG-1, which was drilled on July 31, 1914, by the Caribbean Petroleum Company, a subsidiary of Royal Dutch Shell, at Mene Grande in the state of Zulia. The well reached a depth of just 135 meters, yet produced 264 barrels of oil per day, officially marking the beginning of Venezuela’s petroleum era.
Venezuela quickly captured worldwide attention:
Royal Dutch Shell, Standard Oil (later ExxonMobil), and other international majors launched large-scale exploration programs.
The legendary Barroso II gusher in 1922, which erupted uncontrollably for nine days, confirmed the country’s extraordinary oil potential.
By the 1930s, oil towns, refineries, pipelines, and export infrastructure were being developed at unprecedented speed.
During the 1940s and 1950s, Venezuela became the world’s largest oil exporter, earning the nickname “the gasoline station of the world.” Giant fields in Lake Maracaibo and later the Orinoco Belt profoundly shaped the nation’s economy, politics, and global influence.
Venezuela was also the site of Schlumberger’s first major electric logging project in 1929, a technological breakthrough that transformed reservoir evaluation worldwide.
Today, Venezuela holds the largest proven oil reserves on Earth — more than 300 billion barrels. Yet decades of mismanagement, nationalization, sanctions, and political instability have led to a steep decline in production.
International companies such as Shell (1913), ExxonMobil via Standard Oil (1920s), Chevron as Standard Oil of California (1920s), TotalEnergies (1990s), and Eni (1998) once played central roles in Venezuela’s oil development. Many later exited or saw assets expropriated following the nationalization wave under Hugo Chávez in the 2000s.
Today, PDVSA (Petróleos de Venezuela S.A.), the national oil company, is in control. However, much of the country’s immense oil potential remains untapped due to aging infrastructure, limited investment, and ongoing geopolitical constraints.
Legacy of Oil Development in Venezuela
In its formative years, Venezuela was not only a production leader but also a pioneer in oilfield technology and governance. SLB’s first commercial electric logging run in 1929 at Campo La Rosa marked a global milestone in subsurface evaluation. Many of the oil industry’s early technological and institutional “firsts” were rooted in Venezuelan fields.
Venezuela’s contributions are often underappreciated. The 1943 Hydrocarbons Law fundamentally reshaped upstream economics by introducing the 50/50 profit-sharing model, later adopted by producing nations worldwide. Long before the creation of OPEC or the rise of deepwater exploration, Venezuelan professionals helped establish international standards for petroleum operations.
From early offshore drilling in Lake Maracaibo to training generations of geoscientists and engineers, Venezuela did more than produce oil — it produced knowledge.
As energy historian Gamal Mouallem observed:
“An extraordinary reminder of how Venezuela’s oil story began, and how deeply it shaped global energy history.
Beyond Zumaque I and Barroso II, Venezuela was also a pioneer in oil governance and technical excellence. The 1943 Hydrocarbons Law established the famous 50/50 profit-sharing model, redefining relations between host countries and international operators.
By mid-century, Venezuela was exporting not only massive volumes of oil, but also world-class expertise — geologists, reservoir engineers, drilling practices, and institutional frameworks that influenced operations across the Middle East and beyond. Lake Maracaibo became one of the most advanced producing regions of its time, featuring offshore drilling, early waterflooding, and integrated refining-export systems.
Venezuela’s oil history is therefore not just about reserves or production peaks, but about institutional innovation, technical leadership, and global impact. Zumaque I stands as a symbol of that legacy, and a reminder that the question has never been whether Venezuela has oil, but how vision, stability, and strategy determine what that oil can mean for the nation and the world.”
This article is adapted from a post by Radmir Ganiev, Ph.D., originally published on LinkedIn.
Geothermal operators in Indonesia are experiencing a busy year in 2025. The second half of the year is marked by a range of activities, including the arrival of two new players in the country’s geothermal sector: EDC from the Philippines and PT DSSR Daya Mas Sakti from Indonesia.
Pertamina Geothermal Energy (PGE)
Pertamina Geothermal Energy began operating its newest facility, the 55-MW Lumut Balai Unit 2 power plant, on June 29, 2025. This addition raises PGE’s total installed geothermal capacity to 727.5 MW.
The company has set a goal to reach 1 GW within the next three years, which will be achieved through the completion of several projects: the Hululais power plant Units 1 and 2, contributing a combined 110 MW, and multiple cogeneration projects totaling 230 MW. Additionally, PGE plans to start exploration activities in the Gunung Tiga area in Lampung, which has an estimated potential of 55 MW.
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Pertamina Geothermal Energy (PGE) plans to invest USD 24 million in PGE Kotamobagu to advance the development of the Kotamobagu geothermal site in Sulawesi.
PGE Kotamobagu is a joint venture between Pertamina Geothermal Energi, Chevron New Energies, and Mubadala Energy, overseeing a work area with an estimated potential capacity of 280 MW.
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PGE’s Ulubelu Geothermal Complex has been selected as a national case study for the Water-Energy-Food (WEF) Nexus initiative. This program aims to assess the effects of geothermal development on water and food resources, as well as its broader impact on local communities.
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Additionally, PGE has broken ground on the Green Hydrogen Pilot Plant in Ulubelu, Lampung. Scheduled to begin operations in 2026, the facility will produce green hydrogen using electricity supplied from the Ulubelu geothermal power plant.
Star Energy Geothermal
Star Energy Geothermal has completed a retrofit project for Units 4, 5, and 6 of the Salak geothermal power plant in West Java.
The upgrade increased the field’s installed capacity by 7.7 MW, exceeding the expected 7.2 MW, bringing the total installed capacity to 910.3 MW.
The company invested USD 22.5 million in the retrofit and plans to add over 100 MW of new geothermal generation capacity in the coming years, with a total investment target of USD 365 million.
Outside Java, Star Energy has commenced drilling its first exploration well at the Hamiding geothermal work area in North Maluku. The Hamiding project is initially targeting a capacity of 50 MW, with the potential to reach a total capacity of 300 MW.
Geo Dipa Energi
Geo Dipa Energi is expanding installed capacities at both the Dieng and Patuha geothermal fields with financial support from the Asian Development Bank.
Earlier this year, the company completed the well testing phase for 18 wells across the two projects. Commercial operations for Dieng Unit 2 and Patuha Unit 2 are expected to begin in 2027.
Geo Dipa recently signed an agreement with the Dutch consultancy Witteveen+Bos to conduct a lithium extraction pilot project from geothermal brine at the Dieng site. Funded by the Dutch government, the project aims to assess the feasibility of lithium recovery, with estimates suggesting the Dieng field could produce up to 2,200 tons of lithium per year, equivalent to approximately 3.5 GWh of battery capacity.
Supreme Energy
Supreme Energy Muara Laboh (SEML)—a joint venture between Supreme Energy, Sumitomo Corporation, and Inpex—is investing USD 490 million to expand its Muara Laboh geothermal facility in West Sumatra. The expansion includes the construction of the 80 MW Muara Laboh Unit 2 plant, scheduled for completion in 2027. When completed, the Muara Laboh geothermal power plant will have a total capacity of 165 MW.
To support the new unit, SEML has launched a drilling campaign involving six to eight production and injection wells.
EDC and PT DSSR Daya Mas Sakti
First Gen Corporation, through its renewable energy arm Energy Development Corporation (EDC), has announced plans to invest USD 80 million to establish a presence in Indonesia’s geothermal sector in partnership with PT DSSR Daya Mas Sakti, a subsidiary of the Sinar Mas Group.
The collaboration covers multiple geothermal prospects across West Java, West Sumatra, Jambi, Central Sulawesi, and Flores, with a combined target capacity of around 440 MW.
This marks EDC’s first overseas geothermal venture and Sinar Mas Group’s first geothermal project.
Medco Power Indonesia
Medco Power Indonesia, through its subsidiary Medco Geothermal Sumatera, has commenced exploration drilling at the Bonjol geothermal site in West Sumatra.
The company plans to drill two wells, Bonjol-1 and Bonjol-3, with completion expected by the end of 2025.
The Bonjol resource, classified as medium-enthalpy, has an estimated capacity of 60 MW and a fluid temperature of approximately 150°C.
PLN (Perusahaan Listrik Negara)
Indonesia’s state electricity company PLN has begun infrastructure development for geothermal drilling at the Mataloko work area site in East Nusa Tenggara.
Current activities include constructing well pads, access roads, and drilling support infrastructure, which is now approximately 80% complete.
Drilling is expected to begin in 2026, with a development target of 2×10 MW for the site.
PT Sarana Multi Infrastruktur (SMI) and Ormat Geothermal
Sarana Multi Infrastruktur (SMI) and Ormat Geothermal Indonesia have signed a cooperation agreement to explore financing options for geothermal exploration in Wapsalit in Maluku and Toka Tindung in North Sulawesi.
SMI, as a Special Mission Vehicle under Indonesia’s Ministry of Finance, supports energy and infrastructure financing and has previously been involved in the 10-MW small-scale geothermal project at Dieng operated by Geo Dipa Energi.
Ministry of Energy and Mineral Resources of Indonesia
The Government of Indonesia, through the Ministry of Energy and Mineral Resources (ESDM), continues to enhance the policy framework to accelerate geothermal development.
Starting this year, Geothermal Work Area (WKP) auctions will be conducted through the Geothermal Energy Information System (GENESIS)—a digital platform designed to streamline geothermal management.
This initiative aims to simplify permitting processes, reducing the average permit processing time from 18 months to just 5 days.
This article is adapted from ThinkGeoEnergy articles.
Turbidite fields play a vital role in modern oil and gas exploration, particularly in offshore and deepwater settings where they often host large hydrocarbon reserves. As exploration increasingly shifts toward frontier basins, turbidites offer high-quality reservoirs with favorable porosity and permeability, supporting efficient hydrocarbon production.
Historically, these reservoirs have made a major contribution to global petroleum supplies. Between 1894 and 1969, 11 giant turbidite fields (each exceeding 500 million BOE recoverable) added around 14 billion BOE. Since the 1970s, a further 30 giants have been discovered, contributing an additional 34 billion BOE and highlighting their growing importance.
This expansion has been enabled by advances in deepwater technology, which opened access to previously unreachable basins. Notable examples include the Campos Basin (Brazil) and the Gulf of Mexico, where petroleum systems combine rich source rocks, salt-related migration pathways, and effective seals, resulting in reservoirs with porosities of 19–29% and permeabilities up to 2,560 mD.
Key features of turbidite reservoirs include:
Trap styles dominated by combined structural–stratigraphic traps, accounting for ~65% of reserves in giant fields.
Net pay thicknesses range from 20 to 230 meters.
High well productivity, with top rates of 11,000–18,000 BOPD.
Predominance in Tertiary-age formations.
Turbidite systems are shaped by tectonics, sea-level fluctuations, and sediment supply, producing geomorphological features such as submarine canyons, channels, lobes, and levees. These features guide reservoir development and enhance production potential.
Today, oil and gas exploration remains heavily focused on turbidites in underexplored Atlantic passive margins—including the Gulf of Mexico, Suriname-Guyana, Niger Delta, Lower Congo, Brazil, and the Orange Basin. Remarkably, 15 of the last 18 global giant discoveries occurred in these settings, leveraging proven source rocks and charge systems.
Topside sail away – Sisi Nubi AOI project of Pertamina Hulu Mahakam
Pertamina Hulu Mahakam is flying high.
It is taking huge steps to further develop its gas fields to increase its oil and gas production.
One project is the development of the Sisi-Nubi area of interest.
Sisi and Nubi are offshore gas fields located 25 km from the Mahakam Delta in 60-80m of water depth. Sisi was discovered in 1986, followed by Nubi in 1992. The fields started production in November 2007 from 5 wellhead platforms.
In the Sisi-Nubi AOI project with a budget of 215 million USD, PHM is in the process of installing six new platforms, modifying three existing platforms, and installation of 22 Km of subsea pipeline. Each platform can handle 30 MMSCF of gas per day when they are completed at the end of 2025.
Here is the status of the Sisi-Nubi AOI project.
Topsides completed:
– Topside WPS4–WPS5 Sail away 28 April 2025
– Topside WPN7–WPN8 Sail away 6 Mei 2025
– Topside WPN5–WPN6 Sail away 16 Mei 2025
Installation completed:
– 6 platform jackets.
– 6 offshore Pipelines.
– 2 topside (WPS4 & WPS5).
In addition to undertaking the Sisi-Nubi AOI project, Pertamina Hulu Mahakam has started a drilling campaign to continue developing and exploring the potential of the Mahakam block.
The Amazing PHM
Pertamina Hulu Mahakam is formerly Total Indonesia. In 2018, when its lease expired, Total handed over the operatorship of the Mahakam Block to Pertamina.
Total signed on to operate the Mahakam Block in 1968 along with Inpex as a 50-50 partner.
Since then, it has gone on to discover many major oil and gas fields such as:
• Handil
• Bekapai
• Tunu
• Tambora
• Peciko
• Sisi
• Nubi
At its peak in 2006, Total Indonesia produced 2600 MMSCF of gas and 90,000 barrels of oil and condensate daily.
PHM’s manpower is world-class due to the intensive and extensive training provided by Total Indonesia to its people.
Today, PHM continues to operate the Mahakam block with the spirit of dedication, operational excellence, and innovation.
This article is adapted from various sources of information by Jamin Djuang, Chief Learning Officer of LDI Training.
The oil and gas industry has long been characterized by significant mergers and acquisitions (M&A), reflecting the sector’s dynamic and complex nature. These strategic consolidations have shaped the global energy landscape, influencing market dynamics, competitive standing, and technological advancements.
The history of M&A in the oil industry dates back to the late 19th and early 20th centuries when major oil companies began to consolidate their operations to gain control over production, distribution, and marketing. One of the earliest and most notable mergers was the formation of Standard Oil in 1870, which eventually led to the company controlling nearly 90% of the oil business in the United States.
Over 60% of independent oil and gas exploration companies in the U.S. were acquired or merged between 2010 and 2020, per IHS Markit.
Majors like ExxonMobil and Chevron have grown reserves through acquisitions. For example, Exxon and Mobil merged to become ExxonMobil in 1999, Chevron acquired Texaco in 2000 and Unocal in 2005, and Conoco and Phillips merged to become ConocoPhillips in 2002.
Why some oil companies get sold or acquired
Most oil exploration companies get sold or acquired due to a mix of economic, operational, and strategic factors:
Financial Distress or Underperformance: Struggling with high debt, low cash flow, or unprofitable operations, making it difficult to sustain independently. Exploration is expensive, risky, and requires massive upfront investment. Successful companies often need more capital than they can come up with to develop discoveries, making them attractive acquisition targets for larger firms with deeper pockets.
Economies of Scale and Access to Resources: Big oil companies (majors) have integrated operations—exploration, production, refining, and distribution—which reduce costs. Smaller exploration firms, even if successful, often lack this scale and expertise and are acquired to plug into larger value chains.
Risk Diversification: Exploration is a high-risk, high-reward game. Smaller companies may hit big finds but face volatility in oil prices or dry wells. Selling to or merging with a larger entity spreads risk and ensures financial stability.
Strategic Asset Acquisition: A successful exploration company with proven marketable reserves becomes a prime target. The target company may own desirable assets (e.g., prime drilling locations, refineries, or pipelines) that align with the buyer’s growth strategy. Larger firms acquire them to boost their reserve base, especially when buying is cheaper or faster than exploring themselves and if the assets are in geographically complementary or desirable areas.
Management and Expertise: Smaller firms often have lean teams focused on exploration but may lack the expertise or resources for full-scale production. In some cases, there may be mismanagement. Acquirers with established infrastructure can maximize the value of discoveries.
Market Consolidation: Low oil prices or unpredictable markets can push smaller companies to sell to avoid bankruptcy or sustain operations. Industry trends toward consolidation to strengthen market position, reduce competition, or gain control over valuable assets like oil fields or infrastructure. Oil markets are cyclical. During booms, successful explorers are acquired at premium valuations. During busts, struggling firms are bought at a discount by cash-rich majors looking to consolidate and maintain competitive lead.
Shareholder Pressure: Investors in exploration companies often seek quick returns. A lucrative acquisition offer can be hard to resist, especially if it delivers immediate payouts compared to long-term development risks. Investors may push for a sale to maximize returns, especially if the company’s stock is underperforming or a lucrative offer is on the table.
Regulatory and Geopolitical Factors: Sometimes there may be undue exposure to regulatory and political risk if assets are not diversified. Operating in multiple regions involves navigating complex regulations and political risks. Larger firms with global reach and legal expertise are better equipped, making sales a strategic move for smaller players. Instability in operating regions or changes in government policies (e.g., nationalization risks) may drive a sale to a larger firm with better risk management capabilities. Smaller firms may struggle to comply with tightening regulations or transition to cleaner energy, prompting a sale to a larger firm better equipped to handle these challenges.
Energy Transition: As the industry shifts toward renewables, smaller oil companies may sell to larger competitors diversifying their portfolios or exiting fossil fuels strategically.
Exploration success: Success in exploration makes companies valuable but resource-constrained, pushing them toward acquisition by larger players who can fully exploit their assets.
Why do some OG Companies go bankrupt
Some smaller oil companies were acquired due to their exploration success, but some did not last because they went bankrupt.
The main drivers for an oil company going bankrupt include:
Low Oil Prices: Sustained low crude oil prices reduce revenue, making it hard to cover operating costs, debt payments, or capital expenditures.
High Debt Levels: Overleveraging, often from borrowing to fund exploration or acquisitions, can lead to insolvency if cash flows dry up or interest payments become unmanageable.
Operational Inefficiencies: High production costs, aging infrastructure, or poor management can erode profitability, especially in competitive markets.
Declining Reserves: Depleting oil reserves without successful exploration or acquisition of new assets limits future revenue potential.
Market Volatility: Fluctuations in global oil demand (e.g., due to economic downturns or geopolitical events) can strain finances, particularly for companies with limited cash reserves.
Regulatory and Environmental Costs: Stricter environmental regulations, carbon taxes, or cleanup liabilities increase expenses, especially for smaller firms with limited resources.
Energy Transition Pressures: The shift to renewables and reduced demand for fossil fuels can devalue assets and erode investor confidence, impacting long-term viability.
Geopolitical Risks: Operating in unstable regions or facing sanctions, nationalization, or policy changes can disrupt operations and revenue streams.
Poor Strategic Decisions: Failed investments, overpaying for assets, or misjudging market trends (e.g., betting heavily on shale during a downturn) can lead to financial distress.
Competition and Consolidation: Smaller or less efficient companies may be outcompeted by larger firms with better economies of scale, technology, or market access.
Access to Capital: The inability to secure financing or attract investors during tough market conditions can push a company toward bankruptcy, especially if it relies on external funding.
These factors often interact, amplifying financial strain. For example, low oil prices combined with high debt and regulatory costs can create a perfect storm.
Some Companies that have been acquired
Mobil by Exxon (1999)
Amoco by BP (1999)
EOG Resources’ Spinoff
Sale of Enron Oil & Gas (1999)
Petrofina by Total (1999)
Elf Aquitaine by Total (1999-2000)
Arco by BP (2000)
Texaco by Chevron (2000)
Phillips by Conoco (2002)
Unocal by Chevron (2005)
Burlington Resources by ConocoPhillips (2006)
XTO Energy by ExxonMobil (2010)
TNK-BP by Rosneft (2013)
BG Group by Shell (2016)
Andeavor by Marathon (2018)
Anadarko Petroleum by Occidental Petroleum (2019)
Noble Energy Acquisition by Chevron (2020)
Concho Resources by ConocoPhillips (2020)
WPX Energy’s merger with Devon Energy (2021)
Whiting Petroleum’s Merger with Oasis Petroleum (2022)
Lundin Energy by Aker BP (2022)
PDC Energy by Chevron (2023)
Endeavour Energy by Diamondback (2024)
CrownRock LP by OXY (2024)
Callon Energy by Apache (2024)
Pioneer Natural Resources by ExxonMobil (2024)
Marathon by ConocoPhillips (2024)
Hess Acquisition by Chevron (2025 ongoing)
Conclusion
Mergers and acquisitions have been a cornerstone of the oil industry’s evolution, shaping its structure and competitive dynamics. As the sector faces new challenges and opportunities, strategic consolidations will remain a key tool for companies seeking to navigate the complexities of the global energy landscape.
Eddy Ong wrote this article. He is a retired technical advisor living in the Dallas-Fort Worth Metroplex. He enjoys technical problem-solving, mentoring, professional networking, and idea exchange. He has an exciting international exploration career with notable E&P companies and a significant hydrocarbon discovery track record in SE Asia and W Africa. His work experience includes Passive Margin Deep Water Plays, Rift Basins, Sub Andean and M East Foldbelt and Foreland basins, SE Asian Back Arc basins, Salt basins, and Cratic Paleozoic basins.
Indonesia is aiming to become the world’s largest geothermal energy producer, according to Eniya Listani Dewi, Director of New and Renewable Energy and Energy Conservation of Indonesia, in her meet-the-press presentation during the 11th Indonesia International Geothermal Convention and Exhibition on April 14, 2025, in Jakarta.
Indonesia is the world’s second-largest geothermal energy producer, with a total installed capacity of 2680 MW, while the US is the largest, with 3937 MW.
Indonesia, which has 40% of the world’s geothermal potential, hopes to add 1.1 GW of geothermal capacity in the next five years.
Here are geothermal companies that are actively expanding their geothermal assets in Indonesia.
KS Orka Renewables
KS Orka Renewables added a new geothermal power station in December 2024—the 33-MW Sorik Marapi Unit 5. This power station is operated by Sorik Marapi Geothermal Power, a subsidiary of KS Orka Renewables. With this new station, the total installed capacity of the five Sorik Marapi power stations in North Sumatra increased to more than 200 MW.
Medco Cahaya Geothermal
PT MCG started commercial operations of the 35-MW Ijen geothermal power plant in February 2025, the first geothermal power plant in East Java. Medco Cahaya Geothermal is a joint venture between Medco Power Indonesia and Ormat Technologies.
Star Energy Geothermal
Star Energy Geothermal added 15.5 MW of installed power generation capacity from its new Salak binary plant in West Java. With this expansion, the company boasts a total installed capacity of 901.5 MW, making it Indonesia’s largest geothermal power plant operator.
Star Energy Geothermal is also working on increasing power generation capacity in its Darajat and Wayang Windu plants.
The company has secured financing to retrofit its Wayang Windu Units 1 and 2 to enhance their capacity by 18.4 MW and to build a 30-MW Wayang Windu Unit 3 power plant.
Pertamina Geothermal Energy
Pertamina Geothermal Energy is expected to complete its new 55 MW Lumut Balai Unit 2 power plant in May 2025. The company also has plans to start exploration drilling this year in the Seulawah Agam Geothermal Working Area at Aceh, a joint project with PT Pembangunan Aceh (PEMA).
Geo Dipa Energi
Geo Dipa Energi looks forward to adding a new geothermal power plant, the 55-MW Patuha Unit 2, in 2027. Toshiba ESS will supply the steam turbine, generator, and auxiliary equipment. The expansion will double the Patuha power generation capacity to 110MW.
Geodipa is also working on adding a second power station in the Dieng area. The company aims to increase its installed capacity to 1100 MW in 5 years.
Supreme Energy
Supreme Energy Muara Laboh, a joint venture company of Supreme Energy, Sumitomo, and Inpex, plans to complete the 80 MW Muara Laboh Unit 2 in 2027. Supreme Energy also operates the 91.2 MW Rantau Dedap geothermal power plant.
PLN
Perusahaan Listrik Negara, Indonesia’s national power company, has started the Atadei Project to develop a 10-MW geothermal power plant in the Atadei work area, and is acquiring land to drill two wells.
The Atadei geothermal work area is on Lembata Island in East Nusa Tenggara (NTT).
This article is written by Jamin Djuang based on information provided by various sources including ThinkGeoEnergy and Geoenergis.
By Robert Chambers – Actionable insights and advisory | Upstream and LNG
Indonesia announced the results of the 2024 oil and gas second bid round on April 16, 2025. Five of the six blocks have been awarded, and the sixth is yet to be announced.
The five blocks awarded were all offered through the direct offer path, with the results being:
KOJO – The Kojo block was awarded to Bumi Armada through its 100% subsidiary, Armada Etan Limited. It is located offshore Makassar Strait and was awarded under cost recovery terms.
BINAIYA – The Binaiya block was awarded to a consortium of Pertamina Hulu Energi, PETRONAS Carigali, and SK Earthon. The block is located Offshore Maluku and was awarded under cost recovery terms.
SERPANG – The Serpang block was awarded to a consortium of PETRONAS Carigali, INPEX, and SK Earthon. The block is located Offshore East Java and was awarded under cost recovery terms.
GAEA I and GAEA II – The Gaea I and Gaea II blocks, offered separately, were awarded to the same consortium that is essentially the current Tangguh LNG partners (BP, Mitsubishi, INPEX, CNOOC, ENEOS Xplora, Sojitz, Sumitomo, JOGMEC and Mitsui) plus EnQuest and PT Agra Energi. The two contiguous blocks are located Onshore & Offshore West Papua, with the blocks awarded under cost recovery terms.
The remaining unawarded block is Air Komering, which was offered under the regular tender method, and therefore can still be considered active.
Trends in recent awards
The chart below summarizes the blocks offered and awarded over the last 4 years’ rounds.
As can be seen, this latest round has been very successful in attracting bidders and is considered a success.
Companies involved
This latest bidding round sees both a strengthening of positions by some of the awardees as well as new entrants.
EnQuest
EnQuest continues its recent growth story in the region, which has seen new awards in Malaysia and entry into Vietnam.
Agra Energi Indonesia
Agra Energi Indonesia is currently running a farm-out process for its 16.67% stake in the North Ganal PSC (Geng North discovery).
SK Earthon
SK Earthon has been active in Vietnam and Malaysia and is looking for expansion opportunities. It has partnered with PETRONAS Carigali in both the Binaiya and Serpang blocks, which brings excellent operating experience, especially in Offshore East Java.
Bumi Armada
This is Bumi Armada’s second award in Indonesia, following the award of a 51% operated stake in the Akia PSC, which was offered in the 2023 bid round with partners Pexco and Tately N.V. Bumi Armada is making an interesting move into the upstream space for a company that has traditionally been an FPSO contractor.
Final comment
This was a very successful bid round, with new companies entering and a majority of the blocks awarded.
About Robert Chambers
I have spent 20 years working within the upstream oil and gas industry. I have a technical engineering background and have worked across a broad spectrum of technical, commercial, and advisory roles as well as driving and managing commercial product offerings.
I have worked across the world, including over 11 years in Asia-Pacific, where I continue to be active.
Geothermal drilling in Sokoria geothermal area by KS Orka.
Positioned along the Ring of Fire, Indonesia possesses vast geothermal resources estimated at 24 GW. Spanning from Sumatra in the west to Papua in the east, each major island in the country is home to several active volcanoes.
As the world’s second-largest producer of geothermal energy, Indonesia boasts a total installed power-generating capacity of 2,653 MW. The country plans to add an additional 3,300 MW of capacity between 2021 and 2030, aiming to increase geothermal energy to 8% of its total energy mix. With the expansion costs estimated at 14 billion USD, Indonesia is actively seeking participation from companies to support this initiative.
Businesses interested in contributing to Indonesia’s geothermal sector can do so in three key ways:
Securing rights to conduct preliminary surveys and exploration in designated areas for early-stage geothermal assessments, known as WPSPE.
Bidding to acquire a geothermal work area, officially recognized as WKP (Wilayah Kerja Panas Bumi).
Forming partnerships with existing license holders of geothermal work areas. Indonesia has several geothermal energy producers, and many of them are actively expanding their production capacity while exploring new work areas for future energy generation.
The Ministry of Mining and Natural Resources has identified various geothermal work areas (WKP) and areas for preliminary survey and exploration (WPSPE). Some of them are already licensed and developed. Here is the list.
WKP in Aceh, Sumatra
Jaboi
Seulawah Agam.
WPSPE in Aceh, Sumatra
Gn. Geureudong
WKP in North Sumatra
Sibayak – Sinabung.
Sibual-Buali
Sipaholon Ria-ria
Sorik Marapi
WPSPE in North Sumatra
Simbolon Samosir
WKP in West Sumatra
Gunung Talang – Bukit Kili
Liki Pinangawan Muara Laboh
Sumani
WPSPE in West Sumatra
Bonjol
Cubadak
Tandikat Singgalang
WKP in Jambi, Sumtra
Sungai Penuh
WPSPE in Jambi, Sumatra
Graho Nyabu
WKP in Bengkulu, Sumatra
Hululais
Kepahiang
WPSPE in Bengkulu, Sumatra
Tanjung Sakti
Lawang Malintang
WKP in South Sumatra
Lumut Balai.
Rantau Dedap
WKP in Lampung, Sumatra
Gunung Rajabasa
Gunung Way Panas.
Way Ratai
Andau Ranau
WPSPE in Lampung, Sumatra
Sekincau
WKP in Banten, Java
Kaldera Andau Banten
Gunung Endut
WKP in West Java
Cibeureum – Parabakti
Cibuni
Cisolok Cisukarame
Gunung Tamponas
Gunung Tangkuban Perahu
Kamojang.
Darajat
Karaha Cakrabuana.
Pangalengan
Gunung Ciremai
Gunung Galunggung
WPSPE in West Java
Cipanas
WKP in Central Java
Batu Raden
Dataran Tinggi Dieng.
Guci
Gunung Ungaran
Candi Umbul Telomoyo
Gunung Lawu
WKP in East Java
Blawan – Ijen.
Gunung Iyang Argopuro
Telaga Ngebel
Arjuno Wilerang
Gunung Pandan
Gunung Wilis
Songgoriti
WKP in Bali
Tabanan
WKP in NTB, West Nusa Tenggara
Sembalun
WPSPE in NTB, West Nusa Tenggara
Hu’u Daha
WKP in NTT, East Nusa Tenggara
Atadei
Sokoria
Ulumbu
Mataloko
Oka Ile Ange
Gunung Sirung
Waesano
Nage
WKP in Central Sulawesi
Marana
Bora Pulu
WKP in Central Sulawesi
Lainea
WKP in North Sulawesi
Kotamobagu
Lahendong-Tompaso.
WPSPE in North Sulawesi
Klabat Wineru
WKP in North Maluku
Jailolo
Songa Wayaua
Telaga Ranu
WPSPE in North Maluku
Gunung Hamiding
WKP in Maluku
Tulehu
WPSPE in Maluku
Wapsalit
Here are geothermal companies that are actively expanding their geothermal assets in Indonesia.
KS Orka Renewables
KS Orka Renewables added a new geothermal power station in December 2024—the 33-MW Sorik Marapi Unit 5. This power station is operated by Sorik Marapi Geothermal Power, a subsidiary of KS Orka Renewables. With this new station, the total installed capacity of the five Sorik Marapi power stations in North Sumatra increased to more than 200 MW.
Medco Cahaya Geothermal
PT MCG started commercial operations of the 35-MW Ijen geothermal power plant in February 2025, the first geothermal power plant in East Java. Medco Cahaya Geothermal is a joint venture between Medco Power Indonesia and Ormat Technologies.
Star Energy Geothermal
Star Energy Geothermal added 15.5 MW of installed power generation capacity from its new Salak binary plant in West Java. With this expansion, the company boasts a total installed capacity of 901.5 MW, making it Indonesia’s largest geothermal power plant operator.
Star Energy Geothermal is also working on increasing power generation capacity in its Darajat and Wayang Windu plants.
Pertamina Geothermal Energy
Pertamina Geothermal Energy is expected to complete its new 55 MW Lumut Balai Unit 2 power plant in May 2025. The company also has plans to start exploration drilling this year in the Seulawah Agam Geothermal Working Area at Aceh, a joint project with PT Pembangunan Aceh (PEMA).
Geo Dipa Energi
Geo Dipa Energi looks forward to adding a new geothermal power plant, the 55-MW Patuha Unit 2, in 2027. Toshiba ESS will supply the steam turbine, generator, and auxiliary equipment. The expansion will double the Patuha power generation capacity to 110MW.
Geodipa is also working on adding a second power station in the Dieng area. The company aims to increase its installed capacity to 1100 MW in 5 years.
Supreme Energy
Supreme Energy Muara Laboh, a joint venture company of Supreme Energy, Sumitomo, and Inpex, plans to complete the 80 MW Muara Laboh Unit 2 in 2027. Supreme Energy also operates the 91.2 MW Rantau Dedap geothermal power plant.
PLN
PLN, Indonesia’s national power company, has started the Atadei Project, aiming to develop a 10 MW geothermal power plant in the Atadei work area, and is acquiring land to drill two wells.
The Atadei geothermal work area is on Lembata Island in East Nusa Tenggara (NTT).
Sources: Various sources, including Geoenergis and ThinkGeoEnergy.
Drilling a re-entry well in East Kalimantan – Photo by Rick Patenaude
Indonesia has been facing a decline in its oil and gas production over the years. To reverse this trend, the country’s Special Task Force for Upstream Oil and Gas Business Activities (SKK Migas) has outlined several strategies during a meeting with the heads of all oil and gas operators.
The key strategies include: • Optimizing existing production, including Enhanced Oil Recovery (EOR). • Reactivating idle wells and fields. • Increasing exploration activities.
Here are the exploration and production targets set for 2025: • Oil production: 605,000 barrels of oil per day (BOPD). • Oil and gas production: 1,610,000 barrels of oil equivalent per day (BOEPD). • Drilling 993 new development wells, an 11% increase over the previous year. • Drilling 46 exploration wells, an 18% increase over the previous year. • Completing 15 approved projects in 2025.
In addition to these projects, Indonesia has identified four large projects as Strategic National Projects:
Abadi Masela gas development.
The Tangguh UCC project.
Developing deepwater resources, including the Indonesia Deepwater Development (IDD) and Geng North projects.
Genting Oil’s Asap, Kido, and Merah (AKM) fields in the Kasuri Block in West Papua.
Here are the monthly oil and gas exploration and production data for February 2025:
Number of work areas: 163.
Oil production: 577,000 BOPD.
Gas production: 6,786 million standard cubic feet per day (MMSCFD).
Following the announcement of the final investment decision (FID) of BP’s Tangguh CCUS project, the company has signed onshore and offshore Engineering, Procurement, Construction, and Installation (EPCI) contracts with two contractors worth US$3.6 billion. They are Saipem in a consortium with partner PT Meindo Elang Indah and JGC Holdings Corporation through its local subsidiary PT JGC Indonesia.
The contract was signed on November 26, 2024, by BP’s VP of Procurement James Tehubijuluw, Paolo Evangelista from Saipem, Vincent Chan from Meindo, and Suryadi from JGC Indonesia. Witnessing the signing of the contract were Djoko Siswanto, the new Head of SKK MIGAS, and Kathy Wu, BP regional president of Asia Pacific, Gas & Low Carbon Energy.
Djoko Siswanto said that as a National Strategic Project, the Tangguh project has an important role in supporting the Government of Indonesia in meeting the ever-increasing energy needs, achieving national gas production targets, and advancing decarbonization efforts to achieve national emission reduction goals.
Kathy Wu, BP’s regional president of Asia Pacific, Gas & Low Carbon Energy, said that the Tangguh Project has the potential to generate an additional 3 trillion cubic feet of gas resources to meet the increasing energy needs of Indonesia and Asia while supporting Indonesia’s decarbonization efforts through the reinjection of around 15 million tons of CO2 in the initial phase.
About the Tangguh CCUS Project
The Tangguh CCUS project consists of developing the Ubadari gas field, enhancing gas recovery through carbon capture, utilization, and storage (CCUS), and onshore compression.
Production at the Ubadari field is expected to start in 2028. This will mark the start of the next phase of Tangguh LNG development, which will add 3 trillion cubic feet of natural gas.
The project supports Indonesia’s decarbonization agenda by re-injecting around 15 million tons of CO₂ into reservoirs as Indonesia’s first large-scale CCUS application.
2023 has been a year of significant gas discoveries in Malaysia, with numerous new fields identified by key players such as Petronas, PTTEP, Hess EP Malaysia, and Hibiscus. These discoveries are paving the way for a booming offshore gas industry in the country in the coming years.
Below are the discovery wells made by Petronas Carigali in Malaysia throughout 2023.
Gedombak-1 well – Block SK306, Balingian Province, Malaysia.
Nafiri-1 well – Block SK306, Balingian Province, Malaysia.
Bendai-1 well – Block SK306, Balingian Province, Malaysia.
Mirdanga-1 well – Block SK411, Balingian Province, Malaysia.
Sinsing-1 well – Block SK313 Balingian Province, Malaysia.
Tadom-1 well – Block SK313, Balingian Province, Malaysia.
Machinchang-1 well – Block SK301B, West Luconia, Malaysia.
Pangkin-1 well – Block SK301B, West Luconia, Malaysia.
Kalung Emas-1 well – Block SK315, West Luconia, Malaysia.
Sirih-1 well – Block SK306, Balingian Province, Malaysia.
Layang Layang-1 well – Block 2V, Sabah Trough, Malaysia.
Kulintang-1 well – Block SK438, Offshore Malaysia.
Mak Yong-1 well – Block SK438, Offshore Malaysia.
Nujong-1 well – Block SK306, Balingian Province, Malaysia.
Timi-1 well – Block 318, Offshore Sarawak, Malaysia.
Bekok Deep-1 well – A new play in the Malay basin, Malaysia.
Here are the discovery wells made by PTTEP in Malaysia in 2023.
Chenda-1 well in Block SK405E, Balingian Province, Malaysia.
Sirung-2 well in Block SK405E, Balingian Province, Malaysia.
Bangsawan-1 well in Block SK438, Baram Province, Malaysia.
Babadon-1 well in Block SK438, Baram Province, Malaysia.
Mong Merah-1 well in Block SK413A, Balingian Province, Malaysia.
Hikmat-1 well in Block H, Sabah Outboard, Malaysia.
Dermawan-1 well in Block H, Sabah Outboard, Malaysia.
Simpoh Beludu-1 well in Block PM407, Malay Basin, Malaysia.
Discovery wells in Malaysia made by Shell.
Ruku Ruku-1 well in MLNG Block, Central Luconia, Malaysia.
Memari-1 well in MLNG Block, Central Luconia, Malaysia.
The discovery well made by Hess EP Malaysia.
Bergading Deep-4 in Block PM302, North Malay Basin, Malaysia.
The discovery well made by Hibiscus in Malaysia
Bunga Lavatera-1 in Block PM3CAA, Malay Basin, Malaysia.
This article is adapted from a LinkedIn post by Alexander Kolupaev by Jamin Djuang, Chief Learning Officer of LDI Training.
LNG is crucial as a transition fuel, increasingly replacing more carbon-intensive options like coal and heavy oil. Consequently, LNG consumption is projected to rise. Over the next five years, 237 LNG projects are expected to commence globally, including 154 regasification and 83 liquefaction projects.
Building LNG liquefaction plants involves significant costs, and their operational lifespan typically ranges from 20 to 40 years. So, how do project owners mitigate risks and ensure profitability throughout this period?
Let’s explore three common commercial structures for LNG liquefaction.
𝟭. 𝗜𝗻𝘁𝗲𝗴𝗿𝗮𝘁𝗲𝗱 𝗦𝘁𝗿𝘂𝗰𝘁𝘂𝗿𝗲
In this model, the natural gas producer owns both the upstream gas fields and the liquefaction plant. This vertical integration allows for better operational efficiency and consolidated revenues under long-term LNG sales agreements.
𝗘𝘅𝗮𝗺𝗽𝗹𝗲𝘀:
Projects like Qatar’s QatarGas and Indonesia’s Tangguh LNG follow the integrated structure.
𝟮. 𝗧𝗼𝗹𝗹𝗶𝗻𝗴 𝗦𝘁𝗿𝘂𝗰𝘁𝘂𝗿𝗲
Using the tolling structure, a liquefaction plant acts like a service provider here. It processes the gas but doesn’t own it. The upstream producer retains ownership and pays a processing fee.
𝗘𝘅𝗮𝗺𝗽𝗹𝗲𝘀:
The Freeport LNG in the U.S. and Badak LNG plant in Bontang, Indonesia.
𝟯. 𝗠𝗲𝗿𝗰𝗵𝗮𝗻𝘁 𝗦𝘁𝗿𝘂𝗰𝘁𝘂𝗿𝗲
In contrast to the tolling model, merchant liquefaction plants buy gas from producers and sell LNG directly. This structure allows for more flexibility and potential profit.
𝗘𝘅𝗮𝗺𝗽𝗹𝗲𝘀:
Projects like Angola LNG and Malaysia LNG use this structure.
Each model has unique advantages and risks, and the choice often depends on market conditions and investment strategies.
Acknowledgment
This article is adapted from an article posted by Faishal Rachman and is based on the study by Jin Zhang, Xiuling Yin, Zhanxiang Lei, Jianjun Wang, Zifei Fan, and Shenaoyi Liu, titled Economic Feasibility of LNG Business: An Integrated Model and Case Study Analysis (2024).
Jamin Djuang – Chief Learning Officer of LDI Training
Oil companies had immense roles in the geothermal development in Indonesia. They were the ones who kickstarted the geothermal industry in the country from 1970-2010.
The early rise of geothermal energy production in Indonesia is due to the contribution of the oil companies that were operating in Indonesia.
Without their efforts and perseverance, Indonesia would probably not be the second-largest geothermal energy producer in the world after the USA today.
Here are the oil companies that played key roles in the early development of geothermal projects in Indonesia.
1. Pertamina with the cooperation of New Zealand completed the first Kamojang power station in 1982.
2. Amoseas, a joint venture of Chevron and Texaco, completed the first Darajat power station in 1994.
3. Unocal completed the first Salak power station in 1997.
4. Unocal started drilling deep geothermal wells in Sarulla in North Sumatra in 1993 and discovered the huge geothermal potential in the area. Unocal did not complete the project, however, due to the Asian financial crisis in 1997. The project was later taken over by Sarulla Operation Limited which finally completed the huge 330 MW Sarulla power plant in 2016.
5. Chevron took over operations and expansion of the Darajat and Salak power plants from Amoseas and Unocal years later. Chevron eventually sold the two projects to Star Energy.
The photo above shows the 377 MW Salak geothermal plant built by Unocal – The biggest geothermal plant in Indonesia and one of the largest in the world. It is now operated by Star Energy.
The monument of the Mathilda B-1 well, the first oil well in Balikpapan. Photo courtesy of Rudiansyah JA.
Balikpapan, a small town located in East Kalimantan, became an oil town due to the huge and relentless efforts of the Dutchman Sir Jacobus Hubertus Menten.
Balikpapan was just a small outpost of Kutai sultanate in 1800s. It eventually became the greatest oil town in Indonesia and a well-known oil town in the world.
Here is the story of how the small dot along the shore of East Kalimantan became the most famous oil town in Indonesia today.
The story began in August 1860 when Jacobus Hubertus Menten, a mining engineer from The Netherlands was dispatched by the mining department of the Netherlands to East Kalimantan to explore for coals.
The mission was successful as Jacobus Menten discovered high-quality coals in the Mahakam delta area.
Due to the coal discovery and his good relationship with the Sultan of Kutai, Jacobus Menten was subsequently appointed by the government of the Netherlands as the manager of the coal mining company in 1862.
After several job assignments in Bangka and Bogor, Jacobus resigned from the mining department in 1882.
In December 1882, Menten received a coal mining concession from the Sultan of Kutai. In 1888, he handed over the concession to SMOB – Steenkolen Maatschappij Oost Borneo.
While searching for coals, Jacobus noticed oil seepages and realized the prospect of finding oil in East Kalimantan. After sharing this information with Sultan Aji Sulaiman, the sultan gave Jacobus an oil concession on 29 August 1888.
This concession to explore and produce oil covered the entire area of Kutai. Menten named the concession Louise after the name of his daughter. The Netherlands later recognized the Louise concession on 30 June 1891.
Menten could not do much with the oil concession as he could not get funding from investors in the Netherlands and Europe. Fortunately, the Sultan of Kutai extended the concession till 1897.
His luck came in September 1895 when Jacobus Menten met with Sir Marcus Samuel of Shell Transport and Trading Ltd, a company based in London. Sir Marcus Samuel agreed to finance the oil exploration in East Kalimantan.
On his return to Borneo, Menten met with Adrian Stoop of Steenkolen Maatschappij Oost Borneo, who also had applied to explore for oil in Louise concession. This meant SMOB would be a competitor of Jacobus in the quest to find oil in the Kutai area.
In 1896, Sir Marcus Samuel of Shell Transport and Trading Ltd and Jacobus Menten formed and registered a new company, NIIHM – Nederlandsch Indische Industrie en Handel Maatchappij – with the government of Dutch Indie. This joint venture sow the seed of the formation of Royal Dutch Shell.
Menten was ready to explore oil in the Louise concession with the new company and capital. Menten began the drilling for oil in the swamps of Delta Mahakam at the Sanga Sanga River. The drilling was extremely challenging as the area was swampy and they had to deal with wild animals such as boars, orangutans, and leeches. Many workers from Europe and Java suffered from illness and lost their lives.
Despite the difficulties, Menten eventually succeeded in striking oil 150 feet deep in Sanga Sanga on 5 February 1897. This marked the first oil discovery in East Kalimantan.
To refine the newly found crude oil, Menten identified Tandjung Toekoeng located at the bay of Balikpapan for building a refinery and a seaport for exporting the refined products. This is the location of the oil refinery and seaport in Balikpapan today.
Although the well in Sanga Sanga was more productive than the one in Balikpapan, Jacobus chose to build the refinery in Balikpapan as the location was ideal for constructing the refinery and the seaport. Also, the company found a water reservoir beneath Balikpapan.
At the same time, Menten spotted an oil seepage at Tandjung Toekoeng in Balikpapan and he managed to get a second oil concession which he called Mathilde, named after his wife, Mathilde van de Wal.
Jacobus Menten drilled the first exploration well in the Mathilde concession at Gunung Komendur. The drilling was successful. The Mathilda B-1 well had a decent flow from a depth of 180 meters on 15 April 1898.
With this discovery, Menten, after a long quest for oil, now had found a second source of oil and the location to build a refinery and a seaport for oil export.
1898 was a busy year for Balikpapan as Menten brought in oil workers, materials, and drilling equipment.
On 20 August 1898, A Shell oil tanker carried the first load of crude oil from East Kalimantan to Singapore. Subsequently, the oil tanker Broadmain shipped the crude oil directly to London.
This also marked the first oil trading in Asia. This was all due to the tremendous efforts of Menten and Samuel of Shell.
Although the oil production from the Mathilde concession around Balikpapan was not as significant as the Louise concession in Sanga Sanga, Balikpapan with its refinery was recognized as the oil town and the gateway to all the oil districts in East Kalimantan.
And this was how Balikpapan became an oil town in Indonesia.
However, Balikpapan boomed and became a truly significant oil town when several international oil companies, such as Total, Unocal, and Roy Huffington, came to town in the late 1960s. They discovered many giant oil and gas fields in East Kalimantan.
Although these huge oil and gas fields are quite depleted by now, Balikpapan continues to grow as it is the gateway to the new capital city of Indonesia, Ibu Kota Nusantara (IKN).
Drilling in Darajat geothermal work area of Star Energy. Photo courtesy of Ridha Budi Nugraha.
Chevron is back in Indonesia. This time Chevron is back not to develop oil fields, but Indonesia’s geothermal resources with joint venture partner Pertamina Geothermal Energy.
Chevron is a familiar face in Indonesia’s geothermal landscape. Chevron operated two huge geothermal plants – the 370 MW Salak and 240 MW Darajat – but sold them to Star Energy in March 2017.
The Chevron and Pertamina Geothermal Energy consortium was awarded the Way Ratai geothermal work area in Lampung, Sumatra on June 12, 2023.
Then on October 3, 2023, the two companies signed agreements to set up a joint venture company, PT Cahaya Anagata Energy (CAE), and placed funds in a joint account as a commitment to carry out various activities such as surveys and exploration works.
On 24 September 2024, the Indonesian government issued the geothermal permit – IPB or Izin Panas Bumi – to Cahaya Anagata Energy as the Way Ratai geothermal work area operator.
The geothermal permit allows CAE to start geoscience surveys and other activities to develop the geothermal resources of Way Ratai.
This IPB issuance also marked the first time that an application for IPB was made seamlessly by online submissions in Indonesia.
So, Chevron and Pertamina Geothermal Energy are ready to go. We look forward to seeing a potentially 55 MW Way Ratai geothermal plant operate commercially by 2032.
Here are the 10 largest gas discoveries in Southeast Asia in the past 30 years.
The Abadi gas field in Indonesia. The deepwater field has 18 TCF of gas in place and was discovered by Inpex in 2000. Inpex, along with new partners Petronas and Pertamina, plans to complete the Abadi project that will include the construction of an onshore LNG plant and carbon capture and storage.
The Layaran-1 well in Indonesia. The discovery well was drilled by Mubadala in 2023. Test data show 6 TCF of gas in place.
The Geng-North 1 well in Indonesia. Eni drilled this discovery well in 2023. The gas in place is said to be 5 TCF.
The Kawasari Field in Sarawak, Malaysia, was discovered by Petronas in 2011 in Block SK 316 offshore Sarawak. The field holds an estimated 2 trillion cubic feet (TCF) of gas in place. Initial production reached about 200 million standard cubic feet per day (MMSCFD). Under its gas sales arrangements, Kawasari is contracted to supply up to 545 MMSCFD to the Petronas LNG Complex in Bintulu as well as the domestic market.
The Marjoram/Rosmari development project in Sarawak, Malaysia. Shell discovered the deepwater Marjoram and Rosmari sour gas fields in 2014. The two fields contain 2 TCF of combined gas in place.
The Jerun Field in Sarawak, Malaysia. The Jerun gas field was discovered by SapuraOMV Upstream with its partners, Sarawak Shell and Petronas Carigali in 2016. Located in Block SK 408 in offshore Sarawak, the field contains 1.5 TCF of gas.
Block B Gas development in Vietnam. This huge integrated gas and power project involves Vietnam Oil and Gas Group, PetroVietnam Exploration Production Corporation Limited, PetroVietnam Gas Joint Stock Corporation, PTTEP of Thailand, and Mitsui of Japan. The field is scheduled to start delivering 490 MMSCFD of gas to four power plants in southern Vietnam by a subsea pipeline in 2026.
Ca Voi Xanh field in Vietnam. The Cai Voi Xanh field was discovered by ExxonMobil and PetroVietnam in 2011. This is one of Vietnam’s two largest gas discoveries, with a gross gas volume estimated at 7 TCF (including CO2 and other inert gas). First gas production is not expected earlier than 2030. The gas will be delivered to power onshore power plants via an 88 Km subsea pipeline.
B14 gas field in Sarawak, Malaysia. Located in block SK310 offshore of Sarawak, the gas field was discovered in 2013 by SapuraOMV along with its partners Petronas and Mitsubishi. With 1.3 TCF of gas in place, production is scheduled to begin in 2028.
BIGST Cluster in Malaysia. The cluster, comprised of five undeveloped high-CO2 gas fields – the Bujang, Inas, Guling, Sepat, and Tujoh fields – was awarded to Petronas Carigali and JX Nippon Oil and Gas Corporation. The BIGST development will include carbon capture and storage, making it the first high-CO2 gas development in peninsular Malaysia that incorporates CCS. Production will start in 2026.
In the early years of the petroleum industry, the American Petroleum Institute (API) adopted the API gravity (°API) as a measure of the crude oil density or specific gravity (SG). The API gravity is calculated from the following equation:
°API= (141.5/SG) – 131.5
The API scale for gravity was adapted from the Baumé scale, developed in the late 18th century to be used in hydrometers for measuring even small differences in the specific gravity of liquids, using water as a reference material in these devices.
The equation above shows that lighter with lower specific gravity has higher API gravity.
Crude oil is generally lighter than water. Water with SG of 1 has an API gravity of 10. Therefore, liquid hydrocarbons with lower SGs have higher API gravities.
The API of crude oils varies typically between 10 and 50, with most crude oils falling in the range of 20-45. Using API gravity, the conventional crude oils can be generally considered as light (°API>30), medium (30>°API>22), and heavy (°API<22).
For example, Brent crude oil has an API gravity of 38.3 and WTI has an API of 39.6. This means that WTI is slightly lighter than Brent. However, both Brent and WTI fall into the light oil category.
Classification of Crude Oil Based on API Gravity
1. Light Crude Oil: API gravity above 31.1°.
– Light crude is highly valued because it contains a higher proportion of hydrocarbons that can be easily refined into gasoline, diesel, and other high-demand products. It is less dense and viscous, making it easier to transport and refine.
2. Medium Crude Oil: API gravity between 22.3° and 31.1°.
– Medium crude oil is a versatile type of oil that can be processed into a wide range of products. It strikes a balance between the lighter and heavier crudes in terms of ease of handling and refining.
3. Heavy Crude Oil: API gravity between 10.0° and 22.3°.
– Heavy crude oil is denser and more viscous, making it more challenging to produce, transport, and refine.
4. Extra Heavy Crude Oil: API gravity less than 10.0°.
– Extra heavy crude, also known as bitumen or tar sands, is extremely dense and viscous. It is often blended with lighter hydrocarbons or processed using special techniques like thermal recovery or upgrading to make it suitable for refining.
Importance of API Gravity in the Oil Industry
1. Market Value: Crude oil with a higher API gravity is generally more valuable because it produces a greater yield of high-demand products like gasoline and diesel.
2. Refining Process: The API gravity of crude oil determines the complexity of the refining process. Light crudes require simpler and less energy-intensive processes, while heavy crudes need more sophisticated refining techniques, such as cracking and coking, to convert them into usable products.
3. Transportation: Lighter crudes are easier and cheaper to transport because of their lower viscosity. Heavier crudes often need to be heated, blended with lighter oils, or diluted with other substances to facilitate transportation through pipelines.
4. Production Challenges: Extracting and producing heavy and extra heavy crudes pose significant technical challenges. These oils often require enhanced recovery techniques, such as steam injection or solvent extraction, to flow to the surface.
API Gravity in Global Oil Markets
– West Texas Intermediate (WTI): A light crude oil with an API gravity of approximately 39.6°. WTI is a benchmark for oil prices in North America and is known for its high quality and ease of refining.
– Brent Crude: With an API gravity of around 38.3°, Brent crude is slightly heavier than WTI but is still considered a light crude. It serves as a global benchmark for oil prices.
– Arab Light: A medium-light crude with an API gravity of about 33.4°, Arab Light is one of the primary export grades from Saudi Arabia.
– Maya Crude: A heavy crude oil from Mexico with an API gravity of about 22°. Maya crude is more challenging to refine and is typically sold at a discount compared to lighter crude.
This article is adapted from a post by Reservoir Solutions and other sources.
