Costs expected to rise as BP and partners switch concepts for Greater Tortue Phase 2

In the first quarter of 2023, BP and partners (PETROSEN, Societe Mauritanienne des Hydrocarbons {SMH} and Kosmos Energy) announced a distinct change to their development concept for the second phase of the Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project. The GTA project is a phased, ultra-deepwater (2,850 m) LNG development situated 120 km offshore Senegal/Mauritania, representing the development of the Ahmeyim/Guembeul field. Three phases are expected over the course of the full field development with phase 1 moving towards first gas in the first quarter of 2024. The development is key especially for the countries and its importance globally was recognised when Senegal was asked to join the 11-member Gas Exporting Countries Forum (GECF) as an observer member in October 2022 before being fully admitted into the alliance, which includes Algeria, Egypt, Nigeria and Qatar and controls about 70% of the world's gas production when GTA phase 1 comes onstream.

The concept that is being evaluated with contractors and progressed towards the pre-FEED stage will be a gravity based structure (GBS). GBS have a static connection to the seabed, which in this case is expected to provide a base for LNG storage and a foundation for liquefaction facilities. New wells and subsea equipment will also be required which will integrate and expand upon some existing phase 1 infrastructure. This is quite a change from the past concept design in which an upgrade to the existing phase 1 floating, production, storage and offloading vessel (FPSO) had been discussed as well as being able to utilise existing subsea infrastructure and a likely new module on the phase 1 floating liquified natural gas vessel (FLNG). It is not known why BP and partners changed their development concept, but the deepwater, offshore location prone to strong seas may have played a part. This is very likely the reason why in the first phase of the development the construction of the breakwater to protect the FLNG was so important and maybe why the decision to have a GBS for the second phase, which has a static connection to the seabed, hence protected from the sea swells is being evaluated.

Based on S&P Global modelling and our assumptions related to the concept change, key costs and performance metrics demonstrated changes. An increase in total CAPEX of 93% was recorded due to the increased costs of a GBS concept and further subsea equipment needs. OPEX illustrated a 13% increase with both of these culminating in a point forward NPV decrease of 33%.

Challenges remain ever present in these African deepwater developments. It wasn't long ago that Aker Energy altered its development plan for the Pecan field in the Deepwater Tano Cape Three Points block offshore Ghana. Instead of one centralized FPSO supporting the development of the entire Pecan field, as well as tie-ins of other satellite fields, a phased approach with one FPSO for the main Pecan field in the south would commence and be expanded to a second FPSO in the north after a few years, with tie-ins of additional discovered resources. This would allow Aker Energy and partners time to concentrate on one area of the large development before proceeding with an additional phase spreading costs, risks and bringing lessons learned forward through the process. BP, Aker Energy and partners' concept change won't be the last as other projects progress forward and technical as well as financial challenges become apparent and worked through.

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This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.