Sub-Saharan majors face a $70 billion sanctioning test

By Daniel Okafor

How large is the prize?

More than $70 billion is needed to deliver the oil majors' next Sub-Saharan production wave. Welligence sees the region as central to the peer group's next growth phase.

Gordon Hardie, Welligence's head of Sub-Saharan Africa research, estimates in Offshore Engineer Magazine that pre-FID projects could add 1.2 million barrels of oil equivalent per day at peak. The estimate assumes the next wave reaches final investment decision within 12 to 18 months.

At that rate, the pipeline yields about 438 million barrels of oil equivalent over 365 days. It remains conditional, not committed. Capital discipline has constrained investment in recent years, and base production across the peer group's portfolios will decline before the decade ends.

Shell and ExxonMobil account for more than half of the potential peak output. Hardie expects the group to remain "laser-focused on costs, delivering project synergies and compressing project cycle times." The arithmetic looks attractive. The sanction calendar remains less forgiving.

The next wave depends on investment decisions that have not yet happened.

Which projects already have firm footing?

TotalEnergies has the strongest outlook. Uganda's Tilenga and Kingfisher projects are due to start in the 2026/27 period, giving the company near-term operating visibility.

Eni will add about 100,000 boe/d by 2029 from the recently sanctioned Coral Norte, Baleine Phase 3, and Azule-operated Greater PAJ developments across Sub-Saharan Africa. That contribution equals less than one-tenth of the conditional 1.2 million boe/d pipeline.

Chevron sanctioned its Aseng gas monetization project in April. Even so, Chevron faces the steepest production decline in the peer group. These schemes provide the base case. The larger pre-FID pipeline remains conditional.

Sanctioned projects support the base case; the larger wave still awaits approval.

Where does gas carry the most risk?

ExxonMobil is expected to sanction Rovuma LNG in Mozambique later this year, a decision that would establish its first operated LNG project in the region. For now, expected sanctioning keeps it in the pre-FID bucket.

Large gas developments in Tanzania add meaningful volumes for Shell and Equinor. The analysis says Mozambique has struggled with regulatory commitment, creating a key risk for first gas.

Equinor carries the most regional exposure because Block 2 is its only pre-FID development in the region. bp has the group's weakest project pipeline and lowest pre-FID growth.

Gas offers volume, but sanctioning and first-gas timing set the pace.

What will delivery cost?

Deepwater developments absorb around 70% of the more-than-US$70-billion delivery bill, reflecting the concentration of major discoveries offshore and their higher regional cost premium across the region.

In Namibia, TotalEnergies' Venus and Mopane projects will consume the bulk of its regional spend. A tight global supply chain strengthens the case for cost control.

Only a select few majors developed and brought deepwater projects onstream in Sub-Saharan Africa during the last decade. The record offers little comfort for schedule slippage.

The next production wave is capital-heavy before it becomes operational.

Can the majors compress schedules?

Eni stands out for compressing development cycle times. The trade-off arrives at peak production: its field output lags other larger projects.

Discovery to FID remains far from automatic in every case. A fast-track approach could unlock Calao offshore Côte d'Ivoire, Algaita in Angola, and Capricornus in Namibia. The source presents these discoveries as development candidates, not sanctioned production.

Over the next 12 to 18 months, the peer group is expected to drill 22 exploration and appraisal wells, with the bulk on the Atlantic Margin. That pace averages one well every two to four weeks.

TotalEnergies holds the highest well count. More than half target the Orange Basin.

More wells can refill the project funnel, but sanctions decide whether they become production.

What has the new acreage added?

The majors picked up 395,000 square kilometers of net acreage during the past 18 months. More than 80% came through reconnaissance permits, pre-license awards, and other early-stage instruments with low capital requirements.

These moves widen future exploration options without committing full development capital. Hardie concludes: "Taken together, the Majors are ideally positioned to deliver sustained, long-term value across Sub-Saharan Africa."

Watch the next 12 to 18 months of FIDs, ExxonMobil's expected Rovuma decision, Mozambique's path to first gas, and Uganda's 2026/27 startups.