Guyana’s Record-Breaking Oil Boom
- Guyana’s offshore Stabroek Block has unlocked around 11 billion barrels of recoverable oil, turning the small nation into one of South America’s top producers in under a decade.
- Exxon and its partners rapidly brought multiple FPSOs online, pushing output to 900,000 bpd in 2025 and aiming for 1.7 million bpd by 2030.
- Initial PSA terms were unusually favorable to Exxon, prompting Guyana to revise future contracts to secure higher royalties, taxes, and profit shares.
The tiny South American nation of Guyana, once one of the continent’s poorest countries, recently emerged as a top oil producer. After a swathe of high-quality discoveries in the offshore Stabroek Block, the government in Georgetown finds itself managing one of the world's largest oil booms. In roughly a decade, Guyana went from its first oil discovery to South America’s third-largest oil producer with signs of further growth ahead. This delivered a massive economic dividend for the country of less than one million, which sees it now ranked among the wealthiest in South America.
Key to Guyana’s booming hydrocarbon sector is the 6.6 million offshore Stabroek Block. It is here that ExxonMobil, which is the operator holding a 45% interest along with partners Chevron and CNOOC, controlling 30% and 25% respectively, made the first oil discovery in Guyana’s territorial waters during 2015. This was followed by a swathe of major commercially viable discoveries, which were eventually estimated to collectively contain recoverable oil resources of around 11 billion barrels. The oil discovered is light and sweet with an API gravity of 31.9 degrees and 0.59% sulfur, making it desirable in a low-emission world.
Impressively in a mere four years, Guyana went from first discovery with the Liza-1 wildcat well to first oil. This is a startling development for an industry where major offshore oilfields can take a decade or more to develop and bring to production. Indeed, the consensus is it takes, on average, seven to 10 years to develop an offshore oil discovery so that commercial production can begin. This is something being witnessed in neighboring Suriname, which shares the Guyana-Suriname Basin. More complex geology delayed the development of TotalEnergies' GranMorgu project in offshore Block 58, which lies adjacent to the Stabroek Block, where, despite the discovery being made in 2020, the operation won’t be commissioned until 2028.
The development of the Stabroek Block is continuing at a stunning rate. By August 2025, Exxon had brought its fourth project, Yellowtail, online. This saw the 250,000 barrel per day ONE GUYANA Floating Production, Storage and Offloading (FPSO) vessel come online and start pumping crude oil. During November 2025, production at Yellowtail had ramped up to full capacity. This saw Exxon announce that Guyana was now pumping 900,000 barrels per day, all from the prolific Stabroek Block. This is a significant development for the former British colony because it is now South America’s third-largest oil producer behind Brazil and Venezuela.
In fact, in a decade, Guyana has gone from not being an oil-producing nation to lifting close to one million barrels per day. This saw the country overtake Ecuador, Colombia, and Argentina to become South America’s third largest oil producer behind Brazil and Venezuela. Production volumes will continue to expand with considerable production growth ahead for the Stabroek Block. Exxon is currently developing four additional projects, which, with a combined production capacity of 940,000 barrels per day, will lift Guyana’s total output to 1.7 million barrels per day by 2030. That will make the former British colony South America’s second-largest oil producer.
Meanwhile, Chevron, a 30% partner in the Stabroek Block, which acquired the interest by purchasing independent oil company Hess, recently stated the prolific oil acreage contains more oil than the 11 billion barrels currently estimated. Exxon, aside from developing already sanctioned projects in the Stabroek Block, continues to conduct exploration and appraisal drilling in the prolific oil-bearing acreage. During June 2025, the supermajor started drilling the Hamlet-1 prospect in the southeast portion of the Stabroek Block. Exxon also commenced the Lukanani-2 appraisal well for evaluating the 2022 Lukanani-1 discovery situated southeast of the Liza facility.
The Exxon-led consortium obtained highly favorable terms from Georgetown for exploiting the Stabroek Block. These were encapsulated in a production sharing agreement (PSA), which is considered one of the most lopsided to ever be introduced in the global petroleum industry. Aside from an incredibly low royalty rate of two percent being applied only to what is called cost oil, 75% of all oil lifted is classified as cost oil, with all revenue generated returned to the consortium members. In fact, only 25% of the revenue of all petroleum produced is classified as profit oil and shared 50/50 with Georgetown.
It is easy to understand why Guyana’s government initially offered such an extremely favorable agreement to the Exxon led consortium. Prior to the Liza-1 discovery, over six decades of exploration drilling had failed to find any commercially viable petroleum reservoirs in offshore Guyana. This was despite considerable conjecture that the Guyana-Suriname Basin contained as much as 32.6 billion barrels of crude oil. Such a beneficial PSA made it attractive for global energy companies to drill in Guyana’s underexplored territorial waters, despite the risks posed by earlier poor results.
As a result of the global outcry surrounding this PSA, Georgetown revised the contracts to ensure Guyana received a far greater cut of the profits generated by the country’s vast offshore petroleum reserves. The main changes were reducing cost oil to 65% of all petroleum sold and bumping up royalties to 10%, while also introducing a corporate tax of 10%. This means no other companies can secure the beneficial terms associated with the Stabroek Block, which make it extremely profitable for Exxon and its partners. Indeed, the prolific oil acreage is estimated to possess a low average breakeven price of $30 per barrel, which is among the lowest in South America.
By Matthew Smith for Oilprice.com
Eni Bets on Uruguay’s Offshore Potential with New Exploration Deal
Italy’s Eni has signed an agreement to acquire a 50% stake and operatorship of Uruguay’s offshore exploration block OFF-5 from Argentine state energy firm YPF, marking a new phase in the companies’ strategic partnership across the Southern Cone.
The deepwater block, which spans roughly 17,000 square kilometers about 200 kilometers off the Uruguayan coast, is regarded as one of the country’s most promising offshore prospects. Eni said the acquisition, pending approval from Uruguayan authorities, will “further strengthen its exploration portfolio” by adding high-impact acreage where its proprietary technologies can be applied to accelerate resource assessment.
The move deepens Eni’s growing cooperation with YPF, which began in Argentina and now extends to neighboring Uruguay. The two companies are already partners in Argentina’s $10 billion liquefied natural gas (LNG) export initiative—known as Argentina LNG—where they are working to deploy two floating LNG units with a combined capacity of about 12 million tons per year. Abu Dhabi’s ADNOC joined that project earlier this year as a strategic investor.
YPF first signed the Uruguayan exploration contract in 2023, committing to geological evaluations and advanced 3D modeling to better map the area’s resource potential. Although Uruguay has yet to make a commercial offshore oil discovery, recent geological studies suggest that formations along its Atlantic margin share characteristics with Namibia’s Orange Basin, where several billion-barrel discoveries have been made
Eni joins a growing roster of global firms exploring Uruguay’s offshore sector, including Shell, APA Corporation, and Challenger Energy. All seven of the country’s offshore blocks are currently under contract, reflecting renewed international interest in the region’s deepwater potential.
With this latest deal, Eni positions itself at the center of a new frontier in South American energy exploration—one that could reshape Uruguay’s role in the Atlantic oil map while deepening the Italy–Argentina energy axis.
Uganda Discovers 600 Million-Barrel Oil Find as Pipeline Nears Finish Line
Uganda’s state-owned oil company has announced a major breakthrough that could reshape the country’s energy future. The Uganda National Oil Company (UNOC) confirmed it has identified nine potential oil wells in the Kasuruban block containing “significant new crude oil deposits,” estimated at about 600 million barrels of recoverable crude.
The discovery, located within the 1,285-square-kilometer Kasuruban exploration block acquired under a 2023 production sharing agreement, could boost Uganda’s proven recoverable reserves beyond the current 1.65 billion barrels. It also strengthens prospects in the Albertine Rift Basin, where French energy giant TotalEnergies and China’s CNOOC are developing the Tilenga and Kingfisher oilfields—projects expected to begin commercial output in the second half of next year.
The announcement comes as Uganda edges closer to becoming a regional oil exporter. The $5 billion East African Crude Oil Pipeline (EACOP), which will transport crude from Uganda’s Albertine Graben to Tanzania’s Tanga port, is now 75% complete. The 1,443-kilometer pipeline will enable Uganda to export its oil for the first time, with production from Tilenga and Kingfisher expected to peak at around 200,000 barrels per day.
However, EACOP has drawn environmental scrutiny for its potential impact on ecosystems and communities along the route. Supporters argue that the project could be transformative for East Africa, creating jobs, boosting infrastructure investment, and strengthening regional energy security.
With new discoveries adding momentum, Uganda is positioning itself as one of sub-Saharan Africa’s emerging oil players—balancing the promise of energy-driven growth with the challenge of ensuring sustainability and global investor confidence.
Shell Finalizes Increased Stake in Nigeria’s Deepwater Bonga Field
Shell plc (SHEL) has completed the acquisition of an additional 10% interest in Nigeria’s OML 118 Production Sharing Contract, raising its stake in the deep-water Bonga field from 55% to 65% and reinforcing its commitment to growing upstream output.
The deal, executed through Shell Nigeria Exploration and Production Company (SNEPCo), follows last year’s final investment decision on the Bonga North project and aligns with Shell’s strategy to prioritise high-return, existing assets. Bonga, Nigeria’s first deep-water oil development, has been a core pillar of Shell’s regional portfolio for two decades and remains one of the country's most strategic offshore producers.
The acquisition had initially been expected to total 12.5%, but Nigerian Agip Exploration—an Eni subsidiary—exercised pre-emption rights to acquire 2.5%, revising Shell’s incremental gain to 10%. The updated ownership structure now places SNEPCo at 65% (operator), Esso Exploration and Production Nigeria at 20%, and Agip at 15%, with all partners operating on behalf of the Nigerian National Petroleum Company (NNPC).
The move supports Shell’s target to grow combined Integrated Gas and Upstream production by around 1% annually to 2030 and helps secure the company’s stated 1.4 million barrels per day of liquids output. As Nigeria seeks to revitalize its offshore sector and stabilize crude supply, increased operator investment in mature deep-water assets is seen as a critical pathway to sustaining national production levels.
Industry observers have noted that the Bonga North expansion—expected to tap several hundred million barrels of oil equivalent—could help reverse Nigeria’s offshore decline curve, provided fiscal and regulatory stability continues to improve.
Shell’s announcement also reiterated standard cautionary statements regarding forward-looking expectations, reflecting ongoing geopolitical, market, and policy risks faced by global operators.
Overall, the higher stake signals confidence in Nigeria’s upstream potential, continued capital allocation to advantaged conventional oil, and the long-term role of deep-water assets in Shell’s portfolio strategy.
Shell plc (SHEL) has completed the acquisition of an additional 10% interest in Nigeria’s OML 118 Production Sharing Contract, raising its stake in the deep-water Bonga field from 55% to 65% and reinforcing its commitment to growing upstream output.
The deal, executed through Shell Nigeria Exploration and Production Company (SNEPCo), follows last year’s final investment decision on the Bonga North project and aligns with Shell’s strategy to prioritise high-return, existing assets. Bonga, Nigeria’s first deep-water oil development, has been a core pillar of Shell’s regional portfolio for two decades and remains one of the country's most strategic offshore producers.
The acquisition had initially been expected to total 12.5%, but Nigerian Agip Exploration—an Eni subsidiary—exercised pre-emption rights to acquire 2.5%, revising Shell’s incremental gain to 10%. The updated ownership structure now places SNEPCo at 65% (operator), Esso Exploration and Production Nigeria at 20%, and Agip at 15%, with all partners operating on behalf of the Nigerian National Petroleum Company (NNPC).
The move supports Shell’s target to grow combined Integrated Gas and Upstream production by around 1% annually to 2030 and helps secure the company’s stated 1.4 million barrels per day of liquids output. As Nigeria seeks to revitalize its offshore sector and stabilize crude supply, increased operator investment in mature deep-water assets is seen as a critical pathway to sustaining national production levels.
Industry observers have noted that the Bonga North expansion—expected to tap several hundred million barrels of oil equivalent—could help reverse Nigeria’s offshore decline curve, provided fiscal and regulatory stability continues to improve.
Shell’s announcement also reiterated standard cautionary statements regarding forward-looking expectations, reflecting ongoing geopolitical, market, and policy risks faced by global operators.
Overall, the higher stake signals confidence in Nigeria’s upstream potential, continued capital allocation to advantaged conventional oil, and the long-term role of deep-water assets in Shell’s portfolio strategy.
Indonesia Invites Firms to Explore 108 Untapped Oil and Gas Basins
Indonesia looks to unlock its upstream potential by offering more than 100 previously untapped oil and gas basins to global investors for exploration.
Southeast Asia’s biggest economy, which is also a major oil and gas producer, aims to reverse its decade-long production decline and bolster national energy security.
Indonesia targets to nearly double its oil production to 1 million barrels per day (bpd) of crude oil. Currently, Indonesia pumps about 600,000 bpd of crude.
Indonesia has developed only 20 out of 128 identified oil and gas basins across its archipelago, Deputy Minister of Energy and Mineral Resource, Yuliot Tanjung, said at the launch event to attract investments in Indonesia’s energy future.
The government is allocating resources to its Geological Agency to conduct advanced 2D and 3D surveys, paving the way for exploration to unlock the potential of these resources, the official said.
“Our shared vision is clear: by 2029, Indonesia will achieve its production target of 1 million barrels of oil per day, boost energy security, and advance sustainable development,” Yuliot said at the event.
Indonesia has also prepared 75 oil and gas blocks across Sumatra, Kalimantan, Sulawesi, Papua, and offshore areas for auctions and concessions. Nine of these oil and gas blocks have been awarded to business entities, with several more blocks to follow, the deputy energy minister added.
Earlier this year, Indonesia awarded five strategic oil and gas blocks to international and domestic players. The awards are part of Indonesia’s broader upstream revival strategy, with nearly 60 additional blocks expected to be offered over the coming years.
Once a key OPEC member and oil exporter, Indonesia has increasingly relied on imports to meet domestic energy demand in recent years. Indonesia quit OPEC in 2016 when the cartel struck a deal with non-OPEC producers led by Russia to withhold supply to the market via producers in the OPEC+ pact, reducing their production.
By Charles Kennedy for Oilprice.com
Indonesia looks to unlock its upstream potential by offering more than 100 previously untapped oil and gas basins to global investors for exploration.
Southeast Asia’s biggest economy, which is also a major oil and gas producer, aims to reverse its decade-long production decline and bolster national energy security.
Indonesia targets to nearly double its oil production to 1 million barrels per day (bpd) of crude oil. Currently, Indonesia pumps about 600,000 bpd of crude.
Indonesia has developed only 20 out of 128 identified oil and gas basins across its archipelago, Deputy Minister of Energy and Mineral Resource, Yuliot Tanjung, said at the launch event to attract investments in Indonesia’s energy future.
The government is allocating resources to its Geological Agency to conduct advanced 2D and 3D surveys, paving the way for exploration to unlock the potential of these resources, the official said.
“Our shared vision is clear: by 2029, Indonesia will achieve its production target of 1 million barrels of oil per day, boost energy security, and advance sustainable development,” Yuliot said at the event.
Indonesia has also prepared 75 oil and gas blocks across Sumatra, Kalimantan, Sulawesi, Papua, and offshore areas for auctions and concessions. Nine of these oil and gas blocks have been awarded to business entities, with several more blocks to follow, the deputy energy minister added.
Earlier this year, Indonesia awarded five strategic oil and gas blocks to international and domestic players. The awards are part of Indonesia’s broader upstream revival strategy, with nearly 60 additional blocks expected to be offered over the coming years.
Once a key OPEC member and oil exporter, Indonesia has increasingly relied on imports to meet domestic energy demand in recent years. Indonesia quit OPEC in 2016 when the cartel struck a deal with non-OPEC producers led by Russia to withhold supply to the market via producers in the OPEC+ pact, reducing their production.
By Charles Kennedy for Oilprice.com
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