LatAm Insights: Gran Morgu FID holds promise for Suriname’s deepwater ambitions

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Gran Morgu FID holds promise for Suriname’s deepwater ambitions

Suriname’s hopes of replicating the offshore success of neighboring Guyana got a considerable lift with the 1 October announcement of TotalEnergies’ final investment decision for the $10.5 billion Gran Morgu project, earlier known as Sapakara South and Krabdagu, in offshore Block 58. The news marks an important milestone in Suriname’s journey to its first offshore production and could herald significant changes for Suriname and state oil company Staatsolie. Time from discovery to FID has been rather short — Sapakara South was discovered in 2021 and Krabdagu in 2022 by TotalEnergies and APA Corporation, each holding equal participating interest — and in line with trends currently seen in other Latin American countries. Together, the two fields are expected to hold recoverable resources of nearly 700 million barrels of crude.

Production from the offshore project, located 150 kilometers off the coast of Suriname, is expected to come online in 2028. The fields will be developed using a system of subsea wells connected to a floating production storage and offloading (FPSO) unit with a capacity of 220,000 barrels per day (bpd) of oil.

The drilling program, expected to commence during 4Q 2026, will include 32 wells, half of which will be used to re-inject associated gas and water to maintain reservoir pressure. TotalEnergies aims to deploy two drilling rigs and three offshore support vessels, along with helicopters, to aid the campaign.

Although the Gran-Morgu project holds about half the reserves of the Liza project in Guyana, we expect greater overall development expenditure, with a per-barrel development cost of $14, around 2.6 times that of Liza. Suriname is expected to follow a buy-operate-transfer (BOT) model similar to that employed in Guyana, where the FPSO initially is leased, deferring capitalization costs.

Rystad Energy expects the Gran Morgu project’s Sapakara South and Krabdagu fields will be able to recover their costs and start making profits within the next seven to eight years. However, one of the upsides of buying the FPSO rather than leasing is that the operators can avoid lease costs and make the barrels more competitive, with a lower opex per barrel once production is online.

Staatsolie keen to participate in field development
Staatsolie plans to enter the development project with up to 20% interest and will participate in the costs, sharing the burden of FPSO capitalization. Block 58’s fiscal regime has been a topic of much discussion, with comparisons being drawn to the Stabroek block in Guyana. The Block 58 production sharing contract (PSC) allows the government to take a royalty of 6.25% along with a corporate income tax of 36%. The profit oil share can vary between 20% to 70%, depending on the R factor, but a cost ceiling of 80% and no additional taxes are good incentives for the companies.

Staatsolie has agreed to participate in Gran Morgu in hopes of fostering economic growth in Suriname and building a technically skilled workforce. However, the company must come up with $1.8 billion for its share of the $10.5 billion project and is considering various financing options, such as using its own cash reserves, bonds, bank loans and forming strategic and non-strategic partnerships, or some combination of options. Issuing new bonds to secure the necessary investment capital seems to be the go-to strategy, with bond issuance likely to be launched in January 2025 and closed in March. Staatsolie aims for maximum local participation and has vowed to “structure the issuance in such a way that participation is simple and accessible.”

Rystad Energy has looked at the impact that Staatsolie becoming a 20% partner in the project would have on government take and free cash flow to the companies.

The royalty rate and profit oil share will remain the same for Staatsolie after the farm-in since the bases on which they are calculated are unchanged. But the company will also receive a portion of the contractor share of profit oil after the government’s profit oil share is deducted. After the farm-in, the government take will include royalties plus government profit oil, along with 20% of contractor profit oil and income tax from the companies. This farm-in would lead to Staatsolie’s cumulative share increasing by nearly $3 billion, or 18%, up to the end of the next decade, assuming the farm-in materializes from 1 January 2025. However, Staatsolie’s contribution to development costs leads to a negative government take until 2028.

Production outlook
Suriname, in the last five years, has made quite a few discoveries, the latest being Fusaea in May 2024. Fusaea holds recoverable resources of nearly 50 million barrels and once developed along with the remaining resource potential, could help turn the nation into one of the world’s leading offshore deepwater producers.
Assuming the remaining discoveries are approved for development within this decade, Rystad Energy expects Suriname’s hydrocarbon production to exceed 650,000 bpd by 2035, with crude production peaking at around 350,000 bpd and gas production at about 250,000 barrels of oil equivalent (boe) per day. Most of the remaining production will be condensates. Although Gran Morgu is Suriname’s largest discovery to date, others like Maka Central and Kwaskwasi, which have gross recoverable resources of about 700 million boe, will be essential in increasing the country’s gas-condensate production.

Recent awards and farm-in/farm-out activities
The deepwater successes in Guyana and Suriname have led to a surge of interest in shallow-water areas as well, evidenced by Suriname’s shallow-water licensing round and recent farm-in activities.

PetroChina, a subsidiary of China National Petroleum Corporation (CNPC), signed production-sharing contracts for offshore Blocks 14 and 15 late last month. The Chinese national will hold 70% operating interest along with Staatsolie at 30%. The blocks are located east of the Petronas-operated Block 52, which holds a trio of discoveries: Sloanea-1, discovered in 2020; Roystonea-1, in 2023; and 2024’s Fusaea-1. These discoveries together are estimated to hold around 500 million boe of recoverable resources. Offshore blocks 14 and 15 have existing 2D seismic and well data that could help augment potential new seismic shots in advance of exploration drilling. Exploratory wells have been drilled in these blocks: Maroni-1 in Block 14, drilled in 1966; and Galibi-1 (GLO-1) in Block 15, drilled in 1971. Both wells failed to find commercial hydrocarbons.

ExxonMobil and Equinor exited deepwater Block 59 in August 2024, handing 100% interest to the remaining block partner, US independent Hess. Block 59 was awarded in 2018 with ExxonMobil as operator and Hess and Equinor, each holding one-third interest. Equinor left to focus on its core Norwegian assets, while ExxonMobil’s exit could be purely based on risk minimization. It remains active in the country via its 50% interest in Block 52 and in Guyana, which forms a major component of its exploration and production strategy. Hess is now seeking partners to enter the next Block 59 exploration phase and has until July 2025 to do so.

Earlier this year, QatarEnergy acquired a 20% interest in shallow-water Block 5 from Chevron, which operates the block with 40% interest alongside partner Paradise Oil Company, a Staatsolie subsidiary, on 40%. QatarEnergy also holds a 20% interest in shallow-water Blocks 6 and 8, where operators TotalEnergies and Staatsolie each hold 40% interest. These blocks were awarded in June 2021 in Suriname’s shallow-water licensing round.

Few but high-impact exploration wells planned

The rate of exploration drilling in Suriname will remain slow in comparison to the flurry of activity seen in neighboring Guyana — particularly in the ExxonMobil-operated Stabroek Block — with around four exploration wells expected in the next three years: one well each in Chevron-operated Block 5 in 2025, TotalEnergies-operated Blocks 64 and 8 in 2026, and Petronas-operated Block 63 in 2027. Successful completion of these wells will help increase the country’s resource base and provide an opportunity to develop additional production hubs. Crucially, it would pave the way towards the nation's dream of replicating Guyana’s success, uplifting the economy and making possible a sovereign wealth and stabilization fund (SWSF) similar to the Norwegian and Guyanese model.

Some of the blocks have been drilled before and have seismic and well data, which could be incorporated with new technologies to determine new drill locations. Previous operator Tullow Oil conducted 3D seismic surveys in Block 64 (formerly Block 47) and drilled the Voltzberg North prospect (GVN-1) in 2021. The well was drilled to a total depth of 5,060 meters in 1,856 meters of water before being plugged and abandoned, as it resulted in minor oil shows despite encountering high-quality reservoir rock. The well tested dual targets in the Cretaceous turbidite play. Similarly, Teikoku Oil (INPEX) in 2011 drilled the Akanti-1 well on Block 8 and encountered 52 meters of net intervals with hydrocarbon shows. Nonetheless, the well proved the presence of an Upper Cretaceous reservoir equivalent to the present-day deepwater discoveries. The recovered samples were saturated with light oil with 370API to 530API. Also, Kosmos Energy drilled Anapai-1A (ANA-1A) in Block 63 (formerly Block 45) to a total depth of 4,556 meters to test the potential of the Lower Cretaceous reservoirs in a structural trap on the flank of the basin. Despite encountering high-quality reservoir rocks, the well was not saturated with hydrocarbon and was declared a dry hole.

Moving ahead, Malaysian state giant Petronas is readying a 3D seismic survey covering the entire 6,042 square kilometers of Block 63. The purpose is to delineate the Ironman prospect and prepare for its exploration drilling, a part of its committed work program in the second exploration phase set to commence in January 2027. Petronas has also suggested the Ironman prospect could extend into adjacent Block 52, which it also operates. The probability of an extension and announcement of a substantial find enable fast-tracking of the development and unitization with Block 52. ExxonMobil holds a 50% stake in Block 52 after acquiring half of Petronas’ interest in 2020 and could be looking to acquire a stake in Block 63.