Can East Africa’s Ruvuma-Rufiji gas basin help quench growing global LNG demand?
MICHELA FRANCISCO, Westwood Global Energy Group
According to BP’s Energy Outlook, published in July 2024, global liquefied natural gas (LNG) traded volumes are forecast to grow 43% to 778 Bcm by 2030 from the 543 Bcm recorded in 2022. In recent years, LNG exports have been dominated by the U.S., Australia and Qatar, which—according to the U.S. Energy Information Administration (EIA)—held a combined LNG export capacity of approximately 257 MMtpa in 2023 (60% of total global LNG capacity).
By 2030, Qatar and the U.S. are projected to add approximately 150 MMtpa in LNG feedstock, securing the top two positions in global LNG export capacity. New additions are anticipated to stem from LNG facilities currently under construction in the U.S. (84.1 MMtpa) and expansion phases of QatarEnergy’s North Field project (65 MMtpa).
Making the case for EARR development. Despite these additions, there is still an appetite for additional LNG supply, given current demand expectations, making the business case for developing long-stalled gas projects in frontier areas stronger. Mozambique and Tanzania, which house the East African Ruvuma-Rufiji (EARR) gas basin, could potentially be major beneficiaries of this projected demand, given abundant gas reserves (165.7 Tcf1) and the basin’s proximity to South-Asian import markets. However, the burning question remains: how soon can the world expect the EARR gas basin to roar amid an increasingly thirsty LNG demand environment?
A track record of bottlenecks and delays. It is pertinent to state that the EARR gas basin has failed to live up to its full potential, due to a series of endemic bottlenecks faced in the host countries. In Tanzania, the $40 billion Tanzania LNG project—which aims to receive gas feedstock from six fields across Blocks 1 and 4 (Shell) and Block 2 (Equinor)—has been subject to extensive delays, due to protracted negotiations rooted in unattractive fiscal terms, thanks to high domestic supply obligations.
The story behind undeveloped gas reserves is quite different for those offshore Mozambique, with the main culprit being the Islamist insurgency in Cabo Delgado province. The conflict has led to delays in final investment decisions (FIDs) and project start-ups, given declarations of force majeure for key existing projects. One example is TotalEnergies enforcing force majeure on the 13-MMtpa Mozambique LNG project, delaying production start-up from its Golfinho-Atum field into 2028—nine years post-FID.
On a similar note, ExxonMobil’s Rovuma LNG project also felt the knock-on effect following the declaration of force majeure by TotalEnergies, given that it plans to share some facilities belonging to the Mozambique LNG project. ExxonMobil, however, seized this as an opportunity to cut costs by heavily reconfiguring the design plan from its initial two-train 15.2-MMtpa stick-build facility to an 18-MMtpa facility, which will be constructed using a modular approach while putting emphasis on mitigating greenhouse gas emissions from the project.
Other complications. Another factor contributing to the untimely development of resources in Mozambique is complicated project economics. TotalEnergies highlighted this in 2023 when it reported that supply chain inflationary pressures further complicated the resumption of the $20 billion Mozambique LNG project. However, there have been signs of positive progress, given that the operator communicated in its April 2024 earnings call that contractors have agreed to reverse contract inflation plans; thus, this is no longer an obstacle to the project’s sanctioning decision, Fig. 1.
Some successes in Mozambique. Despite these challenges, Eni’s 75,000-boed Coral Sul floating liquified natural gas (FLNG) project came onstream in 2022, signalling that complex, multi-billion-dollar developments could work offshore Mozambique. Confidence in an improved security situation in Mozambique’s Cabo Delgado province saw ExxonMobil launch two parallel front-end engineering design (FEED) contracts for work on the Mozambique LNG plant in the second half of 2024. In August 2024, Technip Energies and a JGC consortium were awarded a 16-month FEED contract for the liquification plant that will receive gas from Eni’s Mamba field.
This was followed by another FEED contract award to McDermott, Saipem and China Petroleum Engineering and Construction Corporation (CPECC), in September 2024, for the same LNG facility, of which one of the FEED contractor groupings will be awarded the engineering, procurement and construction (EPC) contract; thus, project FID is now anticipated in 2026. Progress was also made towards a fourth-quarter 2024 FID for Eni’s 3.6- MMtpa Coral Norte FLNG project, as reports indicated that Technip Energies had started preparatory engineering work for the project, which will support production growth in the latter years of the forecast.
Despite a decade of security challenges, Mozambique’s production outlook up to 2027 is forecast to remain stable at around 75,000 boed before growing to 295,000 boed by 2030, up 293%, driven by TotalEnergies’ Golfinho-Atum field and Eni’s Coral Norte project.
On the Tanzanian side of the EARR Basin, ARA Petroleum and its development partner Aminex were formally awarded a 25-year development license for the Ntorya onshore gas field in September 2024, which Westwood anticipates will commence production at 7,000 boed in 2026. A gas sales agreement, signed in January 2024 between ARA Petroelum, Aminex and the Tanzanian Petroleum Development Corporation (TPDC), indicated the operators’ intent to ramp up production to 23,000 boed in a few years. However, no timeline for this production ramp-up was disclosed, and neither have the operating partners provided further drilling plans to support this ramp-up. Hence, this is not included in Westwood’s production outlook over the 2030 forecast.
Another project update in Tanzania comes from Maurel & Prom’s (M&P) Mnazi Bay project, which came online in 2006 and accounts for approximately 50% of Tanzania’s total production. In February 2024, TPDC increased its stake in the development to 40%, with the operator stating that the two companies planned to invest $100 million to extend gas compression infrastructure and boost drilling.
Increased output estimate. With this, the EARR basin's total gas output could be boosted to approximately 327,000 boed by 2030, up 184% on 2023’s level. However, the specter of delays that have been haunting projects across both countries remains strong, potentially diluting the positive picture prior to 2030, especially since only one of the three projects (TotalEnergies' Golfinho-Atum) expected onstream by 2030 has passed sanctioning, Fig. 2.
Drilling outlook. Historic drilling activity across the EARR gas basin has been negligible. However, activity is anticipated to liven up over the forecast, driven by approximately 50 wells to support upcoming LNG projects in Mozambique. Of these, 20 subsea tree units were awarded in 2019 for TotalEnergies’ Golfinho-Atum fields, and 26 additional subsea trees are forecasted to be awarded, of which six units are anticipated for Eni’s Coral Norte project. Onshore drilling activity will remain negligible, with only ARA Petroleum’s Chikumbi-1 exploration well set to be spudded in 2024—the only onshore E&A well spudded in the basin since 2016.
Tanzania could see three well spuds in M&P's Mzani Bay field during 2025, namely the MB5 and MS2 development wells, which are intended to maintain the field production levels (12,400 boed), and an additional exploration well, the Kasa well. To date, M&P has completed an environmental impact assessment and is reported to have held a meeting in October 2024 with the Tanzanian Petroleum Upstream Regulatory Authority (PURA) to discuss drilling prospects for the aforementioned wells, as well as disbursement of an $80.2 million drilling budget from PURA to M&P, Fig. 3.
Long-term outlook. Post 2030, the outlook for the EARR basin could be more promising, given continued interest from international energy companies (IECs), as well as licensing rounds and concession award announcements made across both countries since 2023. Although projects are few and far between in Tanzania, Shell and Equinor proposed a $42-billion LNG project from three deepwater blocks in March 2023. This was later followed by CNOOC’s expression of interest in developing a FLNG deepwater project in Blocks 4/1B and 4/1C in June 2023. From a regulatory standpoint, the current administration has increased optimism, given ongoing negotiations on fiscal terms with joint venture companies; however, nothing has materialized thus far.
It is noteworthy to highlight the potential for an uptick in E&A drilling activity beyond Westwood’s current forecasts. This is due to the semi-autonomous Government of Zanzibar, off the shore of Tanzania, launching its inaugural five-year licensing round in March 2024, inviting IECs to explore eight offshore blocks. Furthermore, in September 2024, the Government of Zanzibar launched a separate two-block bidding round to international and local companies—Block 1 (Z1) and Block 2 (Z2). In Mozambique, E&A drilling could also occur, given that the National Hydrocarbon Company approved a concession contract for oil exploration and production in the Angoche A6-C Area in July 2024. However, across both countries, Westwood is bearish on these projects progressing into any substantial E&A drilling activity before the second half of the forecast.
When dissecting current developments in the EARR basin, it is evident that by the onset of the next decade, the basin could contribute about 300,000 boed of gas to meet global LNG demand. Westwood anticipates that Mozambique will continue to lead production and drilling in the EARR basin through 2030. However, it remains crucial for the Mozambican government to continue to take strides towards eradicating the insurgency to guarantee rapid progression of projects off Cabo Delegado province, which are currently mainly in the FEED stage.
In contrast, on the Tanzanian side of the EARR basin, the outlook is more promising than in the hindcast, though there is still a need to focus on improving fiscal terms to attract more near-term investment and ensure that current interest from IECs is maintained. Overall, Westwood believes that by 2030, the EARR gas basin might start to live up to its potential, as projects finally move from potential to reality.
Note: Data are derived from Westwood’s Wells & Production Outlook 2024-2031, which is a series of four regional reports covering onshore and offshore drilling and production outlooks for Africa and Europe, the Americas, Asia Pacific and the Middle East. Published bi-annually, they are available to purchase individually or as a bundle.
About the Author
MICHELA FRANCISCO is a research analyst within Westwood's Energy Services team and one of the authors of the Wells and Production Market Outlook. She holds a BA degree in economics from the American University of Sharjah and a Master’s degree in Petroleum Energy Economics and Finance from the University of Aberdeen. Ms. Francisco can be contacted at: mfrancisco@westwoodenergy.com
REFERENCES
- Estimates are from the Tanzanian Investment Centre, which reports the Tanzanian side of the EARR Basin holds reserves of 41.7 Tcf and from Westwood, which estimates that the Mozambican side of the basin currently holds reserves 124 Tcf.
