The Next Petro State? Suriname’s Path to Oil Prosperity

As Guyana consolidates its position as a global offshore heavyweight, attention is shifting across the maritime border to Suriname. The geology is familiar, the operators are credible, and the development timelines are beginning to crystallize. What remains unclear is how far and how fast Suriname can go, and whether it intends to follow Guyana’s high-volume path or chart a more calibrated trajectory.

Guyana’s offshore story began in earnest with ExxonMobil’s Liza-1 discovery in 2015, followed by first oil in 2019. Today, production from the Stabroek Block exceeds 660,000 barrels per day (b/d), with output forecast to surpass 1.3 million b/d by 2027. Reserves are estimated at 11 to 13 billion barrels. ExxonMobil, alongside partners Hess and CNOOC, has rapidly deployed a fleet of floating production, storage, and offloading (FPSO) units, transforming Guyana into a top-tier producer in just a few years.

The economic impact has been profound. Oil revenues have funded infrastructure, raised public sector wages, and launched diversification efforts. Nonetheless, regulatory institutions are still maturing, and the development of domestic technical capacity remains a work in progress.

Then, we have Suriname.

Geologically, Suriname shares the same hydrocarbon-rich basin as Guyana. Offshore exploration began later, but since 2020, attention has concentrated on Block 58, operated by TotalEnergies and APA Corporation. Their Gran Morgu project is now Suriname’s most advanced development, with a final investment decision confirmed in late 2024 and production expected in 2028.

Gran Morgu is projected to produce between 200,000 and 220,000 b/d at peak, with reserves around 700 million barrels. Staatsolie, the state oil company, holds a 20% stake. Other prospects have proven more challenging. In July 2025, Hess exited Block 59 following earlier withdrawals by ExxonMobil and Equinor, citing exploration risks and technical uncertainty.

Block 59 has consistently tested the risk appetite of major operators. With water depths ranging from 2,700 to over 3,500 meters, this is among the deepest frontier zones explored anywhere in the Atlantic Margin. Despite early enthusiasm and large-scale seismic surveys, partners like ExxonMobil, Equinor, and finally Hess all withdrew, citing both technical uncertainty and the disproportionate cost of drilling relative to commercial expectations. The block has since been returned to Staatsolie, underscoring how far below the confidence threshold this acreage currently sits.

While Suriname shares the broader Guyana-Suriname Basin, not all acreage benefits equally from the basin’s underlying petroleum system. Gran Morgu, in Block 58, lies within the central corridor where trap structures, source rock maturity, and charge timing align favorably. In contrast, areas like Block 59 appear to straddle a geologic margin, where the risk of incomplete charge, failed migration, or leaky traps increases. This edge-of-sweet-spot position makes the petroleum system less predictable, despite surface similarities to Stabroek.

Shell’s re-entry into the Araku Deep?1 prospect in Block 65, for instance, delivered a useful, if sobering, outcome for Suriname’s deepwater ambitions. Drilled in water depths of approximately 960 meters, the well failed to encounter commercial reservoir-quality rocks and was ultimately plugged and abandoned. While the result was a setback, analysts noted its strategic value as a calibration point for future drilling. Rystad Energy characterized Araku as a “data-gathering opportunity” that would help refine subsurface models across the deeper, less-defined portions of the basin. Rather than a clear endorsement or rejection of deeper plays, the well has reinforced the need for tighter seismic interpretation and more cautious step-outs beyond the proven corridor of Block 58.

Despite the risk and uncertainty, industry analysts maintain a cautiously optimistic view. Rystad Energy forecasts up to 10 wells drilled in Suriname’s offshore sector by the end of 2026, and basin-wide potential remains significant.

Suriname is attracting substantial capital. TotalEnergies and APA expect to invest approximately $9-10 billion in the Gran Morgu development. For a country with modest historical oil production, the implications are considerable.

Staatsolie has taken early steps to expand local capacity through training programs and academic partnerships. TotalEnergies has also committed to supporting domestic supplier development. However, the scale-up required in engineering, logistics, and regulatory capability isn’t exactly trivial.

And there is plenty of politics to wade through.

During his presidency, Chan Santokhi introduced the “Royalties for Everyone” initiative, proposing to distribute $750 savings bonds to citizens from future oil revenue. While the move signaled a populist intent to share benefits broadly, Suriname has yet to establish a formal sovereign wealth fund or long-term fiscal framework.

In contrast, Guyana has implemented the Natural Resource Fund Act and Local Content Act, providing more structured mechanisms to manage its oil windfall. Suriname will need to follow suit if it hopes to avoid the pitfalls of boom-and-bust resource cycles.

Suriname’s May 2025 elections resulted in a narrow victory for the National Democratic Party (NDP), leading to the appointment of Jennifer Geerlings-Simons as Suriname’s first female president. Her administration has signaled continuity in energy policy and emphasized social investment priorities. Thus far, the operating environment remains stable.

Suriname’s exploration outlook is still evolving. The relinquishment of Block 59 underscores the challenges of deepwater drilling in frontier conditions. While Block 58 has produced commercial results, not every lead has translated into viable reserves. The geological risk profile remains a factor in capital allocation decisions.

Nevertheless, the underlying resource potential is drawing continued attention. With a focused drilling program over the next two years, additional discoveries could shift the trajectory of Suriname’s upstream sector.

While Suriname is unlikely to match Guyana in production scale or reserve size in the near term, it is on track to position itself as a competitive regional producer. The years leading up to first oil in 2028 will be decisive. Institutional readiness, infrastructure planning, and public engagement will all play critical roles in determining whether Suriname’s oil ambitions are realized in full. The geology is only one part of the equation; the rest will depend on choices made in Paramaribo.

By Alex Kimani for Oilprice.com