Vaalco Energy has found a new source of production in the Etame 14H development well within the Etame Marine Block offshore Gabon following drilling and placement in an attic position, promising a lateral of 325 meters of net pay in high-quality Gamba sands with unmatched porosity and permeability.
The company has reported excellent initial flow rate of approximately 4,850 gross barrels of oil per day, 2,850 bopd net to Vaalco.
Encouraged by the initial well results from the 14H well, the rig has been mobilised to the Ebouri platform for the drilling of the EEBOM-5H development well. For this well too, the team is targeting an updip/attic position by sidetracking from the previously abandoned EEBOM-5P well.
“We continue to see positive results from our Gabon drilling campaign. The Etame 14H development well encountered 325 meters of net pay in high-quality Gamba sands in an attic position within the Main Fault Block at Etame. We are very pleased with the initial well rates of around 4,850 gross BOPD, or 2,850 net BOPD and are excited to add this new production. We have mobilised the rig to the Ebouri platform where we are drilling a development well and plan to workover two other wells. Our goal is to continue to successfully add production and reserves with the remainder of our Gabon drilling campaign," said George Maxwell, Vaalco’s chief executive officer.
Offshore Ivory Coast, the Baobab field in CI-40 block has been brought back online for production to begin in Q2 2026. Output from the field will be generated via risers and umbilicals that are currently being reconnected to the Baobab Ivorien Floating Production Storage and Offloading Vessel (FPSO), which is moored on location. It is ready to support production flow after a 47-day tow for refurbishment at the Dry Dock World shipyard in Dubai. Q2 2026.
George Maxwell, Vaalco’s chief executive officer, said, “We are at a critical junction, with successes in the Gabon drilling campaign and the Baobab field returning to production, and we believe that the remainder of 2026 will be very profitable. We remain focused on execution and driving meaningful growth through our organic capital programmes that we believe will translate into value for our shareholders in 2026 and beyond,” said Maxwell.
Tullow Oil has stepped into 2026 with a strong financial optimisation strategy in place, building on the previous year's results.
In 2025 itself, the company recorded commendable value from limited capital expenditure, with 8 kbopd count from one of the new Jubilee wells brought onstream, and the FPSO at Jubilee and TEN reaching 97% uptime in average. Also it has got on the books US$347mn proceeds from the sales of its Gabonese and Kenyan assets.
For a financially sound delivery of its investment programme and optimum asset value realisation, the company recently completed a comprehensive refinancing transaction, including an extension to its Senior Secured Notes and Glencore facility to November 2028 and May 2030 respectively, and a new US$100mn cargo pre-payment facility with Glencore to provide additional liquidity.
“Throughout 2025 and into early 2026, we have delivered against a clear set of strategic priorities to position Tullow for long-term success. This began with the consolidation of our business to focus on our high-value assets in Ghana, with the sale of our non-core assets in Gabon and Kenya, alongside significant cost reductions. These efforts positioned the company strongly for the successful refinancing, which completed earlier this month with overwhelming support from our creditors. This transaction provides Tullow with the strong financial foundation and flexibility required to deliver value for stakeholders," said Ian Perks, chief executive officer, Tullow Oil plc.
The company is aiming for stronger production generation than usual, encouraged by an overall 43.4 kboepd during the first quarter of 2026. Further material oil and gas reserves have opened up for the company as the Ghanaian parliament ratified long-term extensions for the Jubilee and TEN fields till 2040.
With the acquisition of the TEN FPSO, the company is securing maximum cost efficiency in unlocking future reserves and the long-term development of the TEN and Jubilee fields. This year, an additional four Jubilee wells, including three producers and one water injector, are expected onstream. As part of the current drill programme, Tullow is focussing on well designing and placement backed by data interpretation from 4D and OBN seismic survey.
"We are particularly encouraged by the positive early results from our Ghana drilling campaign...A key milestone has been the agreement to purchase the TEN FPSO, a value-accretive acquisition that significantly improves the field’s economics by eliminating lease costs and providing an opportunity to capture operating cost savings. Additionally extending the Jubilee and TEN petroleum agreements to 2040, and higher oil prices have further strengthened our platform for sustainable growth,” Perks said.
With 20,006 barrels of oil per day generated from offshore Angola during Q1 2026, Afentra plc reported a stable asset performance, driven by the consistency of asset revamping and integrity workstreams.
Key workstreams as part of multi-year redevelopment plan in Angola for increased reserves recovery and production growth included water injection work, which reached up to 70,000 bwpd. The company now targets attaining 100,000 bwpd in H2 2026.
The Pambi platform has already undergone infrastructure upgrades for improved reliability and operational performance, and similar work is ongoing on the Cobo and Palanca platforms. The Palanca FSO is ready for safe operations over the next five years as it has received formal recertification.
As part of the company's 2026 light well interventions (LWI) programme that aims to complete 40 interventions work, six has been completed on the first quarter of the year.
Alongside the drilling of the Pacassa SW well as part of 2026 infill drilling and workover programme in Block 3/05, the company will also be tackling the Impala-2 development well. It aims from this well a potential gross production uplift of ~9,000 bopd and gross recoverable resources of over 100mmbo.
Hydraulic workover programme preparations are ongoing with execution planned for late 2026/27.
In Block 3/24, operational activities continued for the GPQ development, including the planning of a survey vessel programme to execute wellhead inspection, survey and measurement scope.
Reconnaissance Energy Africa Ltd. has released its operational update and 2025 financial and operational results, alongside the renewal of its shelf prospectus.
Brian Reinsborough, President and CEO, said, "2025 was another transformational year for ReconAfrica as we progressed all aspects of our strategic goals. We completed our farm down transaction with BW Energy Ltd. which was a significant milestone for the Company. We made the strategic move to broaden our portfolio by entering the shallow waters of Gabon by signing the Ngulu PSC, which adds another discovery to our inventory and high potential exploration acreage. We entered Angola by signing the MOU to ensure we captured significant running room in the Damara Fold Belt in advance of drilling the Kavango discovery. And finally, we made a significant play opening discovery at the Kavango West 1X well. I congratulate the ReconAfrica team, and our partners, for making this an exceptional year of advancement for the Company."
Namibia
In Namibia, activities at the Kavango West 1X discovery well are progressing as planned, with optimised zone production testing expected to begin in early to mid-May. A five-inch production liner has been installed in the wellbore, enabling isolation and sequential testing of zones. Perforation and testing will cover six hydrocarbon-bearing intervals ranging from 45–75 metres in thickness across the Elandshoek and Huttenburg formations, assessing around 420 metres of hydrocarbon-saturated section. Testing will proceed from the deepest to the shallowest zone, with each phase potentially lasting up to 10 days, extending the programme to the end of June.
The company is also advancing preparations for a follow-up appraisal well located approximately 3 – 4 km southeast of the KW1X discovery. A successful appraisal well would support reserve booking and help progress toward a final investment decision (FID).
Gabon
The company has received all raw seismic data to begin a 3D reprocessing programme over the Loba oil discovery, along with an additional 400 sq km covering high-priority prospect areas. Final seismic reinterpretation is expected in Q4 2026 and will incorporate advanced Pre-Stack Depth Migration and Full Waveform Inversion technology to better image salt-related exploration plays across the concession. The dataset will support a resource report and appraisal well location selection for the Loba oil field.
Further details on the 2025 highlights and subsequent period are available on the ReconAfrica website
Namibia draws in oil major bp's interests in three offshore exploration blocks as it seeks the acquisition of 60% stakes from Eco Atlantic Oil & Gas.
The move aligns with the major's upstream portfolio expansion strategy, and follows the exploration success of its Azule Energy venture in the region.
Once the formal approvals from the Namibian government are in, bp will assume operatorship of three blocks – PEL97, PEL99 and PEL100 – in the Walvis Basin while Eco Atlantic continues as a partner, alongside Namibia’s national oil company NAMCOR, following transaction closing conditions being met.
Gordon Birrell, bp’s executive vice president, production and operations, said, “Namibia is a region attracting growing industry interest and has a number of exciting frontier basins. This agreement marks bp’s entry into the country as an operator, strengthens bp’s exploration portfolio and provides long-term growth potential. We look forward to supporting the country in developing its resources.”
bp announced two exploration discoveries since the beginning of the year, following 12 discoveries in 2025, further strengthening its exploration portfolio in support of long-term organic growth. Since the beginning of 2025, Azule Energy – a 50:50 joint venture between bp and Eni – has announced four hydrocarbon discoveries: the Algaita-01 well and Gajajeira-01 gas find in Angola and the Volans-1X and Capricornus-1X discoveries in Namibia’s Orange Basin.
Other majors such as TotalEnergies and Galp are already deeply invested in significant projects in the Namibian deep waters. They pledged long-term commitment to the country during a recent meeting with the President Netumbo Nandi-Ndaitwah.
With TotalEnergies acquiring operatorship of Petroleum Exploration License (PEL) 83 while Galp stepping into PEL 56 and PEL 91, the partners have expressed high hopes from Namibia's production generation capacity. This confidence builds on past results from the licenses, namely the Mopane and Venus discoveries, which brought the Orange Basin international-scale success.
The Aseng Gas Monetisation Project offshore Equatorial Guinea will undergo subsea installation by Subsea7, which has received a significant contract by Noble Energy EG Ltd (a Chevron Company)
Subsea7 will be establishing a single-well tieback for the project, connecting Aseng field to the existing Alen platform. It will transport and install approximately 19 kilometres of rigid production flowline and 20 kilometres of umbilicals, along with associated subsea structures and tie-ins in water depths of 800 metres.
Project management and engineering will commence immediately and will be managed from Subsea7’s Paris office, with additional support from teams in Lisbon and Equatorial Guinea. Offshore activities are expected to begin in 2026.
David Bertin, Senior Vice President for Subsea7’s Global Projects Centre East, said, “This award represents an important milestone in our ongoing global relationship with Chevron. Subsea7 has operated in Equatorial Guinea for nearly two decades, supporting offshore construction and inspection, maintenance and repair activities. We look forward to continuing our collaboration with Chevron on the Aseng Gas Monetisation Project, continuing to deliver safe, high-quality offshore installation services in West Africa.”
Global technology company SLB has announced a three-year agreement with Azule Energy to extend and enhance the use of its enterprise digital platform across Azule’s operations in Angola
The platform aims to drive more consistent execution, speed up decision-making, and support reliable energy delivery throughout Azule’s portfolio.
Azule Energy, a joint venture between bp and Eni and the largest independent energy producer in Angola, manages some of the country’s most complex assets. This new agreement builds on two years of Delfi use within Azule’s reservoir organization, where the platform supports reservoir studies, modelling, simulation, and well planning workflows, while enabling enterprise-wide digital integration by connecting reservoir workflows with wider operational data environments over time.
“Azule operates large, complex energy assets where execution reliability and consistency matter,” said ND Maduemezia, president, Europe and Africa, SLB.
“This agreement expands the use of an enterprise digital platform that connects workflows and data, strengthening and accelerating decision-making and improving execution predictability in support of reliable energy delivery in Angola.”
The agreement highlights Azule’s shift toward enterprise-scale digital operations, leveraging SLB’s platform and cloud-based capabilities. Implementation is supported through the SLB Luanda Performance Center, which allows digital solutions to be deployed and maintained locally.
The platform supports critical workflows across Azule’s reservoir and planning functions, with gradual integration into broader operational data systems. It also positions Azule to quickly adopt emerging digital and AI-driven technologies, enabling continuous performance enhancements.
Early results demonstrate tangible benefits: integrated workflows, including DrillPlan coherent well planning and engineering solutions, have shortened planning cycles from days to hours while boosting automation and reducing manual coordination.
The enterprise platform strengthens execution consistency across Azule’s large, mature operations, where operational discipline is key to sustaining performance.
Key Points:
With an aim to achieve a potential gross production uplift of around 9,000 barrels of oil per day, Afentra has secured contracts to advance its accelerated two-well drilling programme on Block 3/05 offshore Angola.
The primary objective will help define the material upside potential in the Pacassa SW area (up to 70 mmbo recoverable) and the Impala field (up to 50 mmbo recoverable).
The Block 3/05 Joint Venture partners have signed a commercial agreement with Sonangol to use the Borr Grid jackup rig for the well programme. It will begin with the drilling of Pacassa SW, which will determine the next well eligible for drilling, be it the Pacassa SW injection well or the Impala-2 development well.
The Pacassa field which is anticipated to hold up to 210 mmbbls of oil will be drilled from the Pacassa F4 platform. If the drilling is a success, the well will be put to completion before connecting it to the existing production infrastructure.
The Impala field, on the other hand, can potentially play a significant role in defining the upside potential of the field that can contain up to 200mmbo of oil in place. Impala-2 will be drilled from the Impala wellhead platform into the Impala field around 1000m from the existing Impala-1 production well. Upon completion the well will be connected to the existing production infrastructure. The outcome will also assist in defining the optimum Impala field development which has up to 50mmbo of incremental recoverable resources.
"The ability to accelerate our drilling programme is a pivotal moment for Afentra, marking a clear transition to the execution phase of our organic growth strategy. This opportunity is a direct result of the strong, collaborative partnership we have with Sonangol and the Joint Venture. The funding structure agreed with Sonangol allows us to fast-track the unlocking of significant potential value from both the Pacassa SW area and the Impala field without impacting our 2026 cash capex. This programme is designed to efficiently convert resources into production, growing volumes through our existing infrastructure and delivering tangible value for our shareholders. Crucially, it will also provide invaluable data to de-risk and define future prospectivity across the wider Block 3/05 area, optimising our long-term development plan," said Paul McDade, Chief Executive Officer of Afentra.
bp and Eni venture, Azule Energy, has announced start-up of gas production from the Quiluma field, part of the New Gas Consortium (NGC) in Angola, which is initially expected to reach 150 mn standard cu/ft per day and ramp up to 330 mn standard cu/ft per day by the year end.
A first for Angola's non-associated gas development, the NGC project is driven by gas produced from the shallow water offshore Quiluma field. This gas is directed for export from the Angola LNG plant following treatment at an onshore processing facility.
Azule Energy is operator of the NGC, with a 37.4% participation, in partnership with Cabinda Gulf Oil Company (CABGOC) with 31%, Sonangol E&P with 19.8% and TotalEnergies with 11.8% and ANPG as the National Concessionaire.
Gordon Birrell, bp’s executive vice president for production and operations, and Azule board member, said, "The safe delivery of the NGC project is another example of bp’s strategic progress and demonstrates what strong partnerships and collaboration can deliver. This project marks an important step for Angola’s energy system and strengthens the country’s energy mix as it looks to enhance its position as a global player in the natural gas market.”
This development comes following the inauguration the project’s gas treatment plant in November 2025. The NGC start-up is the latest in a series of upstream advancements such as the Agogo field at the Agogo Integrated West Hub (Agogo IWH) project, in block 15/06, offshore Angola, and the Ndungu start-up in February 2026.
Eni has announced two new gas discoveries offshore Libya following an exploration campaign carried out in recent months.
The finds are located within two nearby geological structures, Bahr Essalam South 2 (BESS 2) and Bahr Essalam South 3 (BESS 3). These were confirmed through drilling activities at the B2-16/4 and C1-16/4 wells, positioned around 85 km offshore in water depths of approximately 650 feet and about 16 km south of the Bahr Essalam gas field.
Both wells intersected gas bearing zones within the Metlaoui Formation, which is recognised as the primary producing reservoir in the region. Analysis of the data suggests a high quality reservoir, with strong productivity already verified through testing conducted on the first well.
Initial estimates indicate that the combined gas resources of the BESS 2 and BESS 3 structures exceed 1 trillion cubic feet (Tcf). Their close location to the Bahr Essalam field, Libya’s largest offshore gas field, operational since 2005, means development can be fast tracked by linking the discoveries to existing offshore infrastructure. The extracted gas is expected to serve both domestic demand in Libya and exports to Italy.
Eni has maintained a long standing presence in Libya since 1959 and remains the country’s leading international energy operator. In 2025, the company reported equity production of approximately 162,000 barrels of oil equivalent per day and is currently advancing three development projects, with two scheduled to come online in 2026.
As part of phase three drilling programme offshore Gabon, Vaalco Energy has completed drilling the Etame West ET-14P exploration well.
The target zone was water bearing even though 10 meters of high-quality Gamba sands were encountered in line with pre-drill predictions. Awaiting partner approval, this finding can be further pursued by utilising the well bore part to sidetrack it in the upper portion of the well. This move is expected to support the drilling of the ET-14H development well in the Main Fault Block of Etame.
The lower portion of the well will be plugged and abandoned. Operations are expected to be completed in April.
George Maxwell, Vaalco’s chief Executive Officer, said, “When we committed to drilling the Etame West exploration well, we knew there was the geologic risk of not encountering commercial sands but the size of the potential reservoir made it a risk worth taking. Furthermore, we purposely designed the well so we could still utilise the well bore to drill a development well into a known productive area if the sands were non-commercial. This side-tracked well should be completed in April.”
Vaalco has also been spudding the ET-15 infill well on the Etame platform as part of Phase Three Drilling Programme offshore Gabon.
This infill well is anticipated to significantly add to the production generation capacity of the floating storage and offloading vessel (FSO) that is operational on the Etame Block since 2022 following an extensive transition and field reconfiguration process. While a low cost solution, the FSO boasts of a high storage capacity and improved operational performance. It has helped Vaalco reach operational excellence, and production uptime and enhancement.
Following a period of challenging drilling work, including horizontal wells, Lime Petroleum has confirmed that the hook-up of its Mobile Offshore Production Unit (MOPU) and Floating Storage and Offloading unit (FSO) has been completed on the Sèmè field in Benin.
After the FSO Kristina was anchored in place, a flow-line was laid from the Stella Energy 1 MOPU to the FSO.
“Commissioning of the production system is well underway, with oil now flowing into the FSO,” a Lime Petroleum statement noted on 5 March, 2026.
Over the coming days, further testing and commissioning will take place, with the aim to optimise production rates and start regular production, it added.
However, drilling operations proved a challenge, the company reported earlier in February.
While the latest operational milestones marked an important step forward, it noted that drilling operations “encountered significant technical complications” — this resulted in a “material increase in drilling costs and a production delay of more than three months.”
The delays and complications brought with them knock-on financial implications, it added.
At the field, it follows the drilling of the AK-2H production well by Lime Petroleum’s wholly-owned indirect subsidiary Akrake Petroleum Benin.
A total of 1,405 metres was drilled horizontally through the reservoir section at the site.
The well was geo-steered using advanced Logging While Drilling (LWD) tools to ensure the well only encountered oil-bearing reservoir sandstone.
The Sèmè Field, discovered by Union Oil in 1969, is located in Benin’s Block 1in shallow water depth of 20 to 30 metres.
It was first developed by Norwegian oil company, Saga Petroleum, and had produced approximately 22 MMbbl1 between 1982 and 1998, before production was stopped prematurely due to low oil prices of around US$14 per barrel in 1998.
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