TotalEnergies has announced the regulatory approval, by Namibian authorities, of its acquisition a 40% operated interest in the PEL83 license, holding the Mopane discovery, from Galp Energia.
“We would like to thank the Namibian authorities for their swift approval of this strategic transaction with Galp, our new partner”, the French major says in a press release.
TotalEnergies agreed to the transaction with Galp to acquire an interest in the Mopane field (PEL 83 license) in December 2025, and the deal was submitted for regulatory review. Namibia’s Ministry of Industries, Mines and Energy granted official approval for the transaction during the week ending July 17, 2026. A month and half later, on September 3, 2026: TotalEnergies officially announced the final completion of the acquisition and took over operatorship.
Galp, in turn, succeeded in having the government approve its own acquisition of 10% participating interest in the PEL56 license, holding the Venus discovery and a 9.39% participating interest in the PEL91 license, both from TotalEnergies.
Further to the completion of this transaction, TotalEnergies holds a 40% operated interest in the PEL83 license alongside Galp (40%), Namcor (10%) and Custos (10%), a 35.25% operated interest in the PEL56 license, alongside QatarEnergy (35.25%), Galp (10%), Namcor (10%) and Impact (9.5%), as well as a 33.09% operated interest in PEL91 alongside QatarEnergy (33.03%), Namcor (15%), Impact (9.5%) and Galp (9.39%).
“This transaction positions TotalEnergies as the operator of Namibia’s two largest oil discoveries and strengthens its position in the Orange Basin, supporting the long-term value creation from prolific licenses”, declares Patrick Pouyanné, Chairman and CEO of TotalEnergies.
Exploration opportunities are already lining up beyond the Mopane development, which we will start appraising as early as the second half of 2026 aiming at taking the FID of the project in 2028, after a 3 appraisal well campaign”.
TotalEnergies’ entry as operator of the giant Mopane discovery marks a key milestone in our journey to establish a major production hub in Namibia”, said.
Panoro Energy has entered into a definitive agreement with DNO ASA to acquire the entire share capital of DNO’s wholly owned subsidiary DNO CI LLC, which holds an indirect 9.09% interest in the gas producing Block CI-27 offshore Côte d’Ivoire.
The purchase is being made for a consideration of $80Million on a cash free / debt free basis, with effective date at January 1, 2025.
“No regulatory approvals are pending or required and there are no pre-emptive rights for the acquisition that is expected to complete between September and December 2026”, the company declared in a statement.
The 9.09% interest amounted to 3,287Barrels of Oil Equivalent Per Day (BOEPD) during FY 2025 and 3,334BOEPD during H1 2026.
Block CI-27 is operated by Foxtrot International LDC. The fields include Foxtrot, Mahi, Marlin, and Manta.
Success of the transaction will accelerate Panoro’s pathway to achieving group (net) production of >20,000BOEPD, the company said.
This means that the deal will “increase pro forma group production by ~23% and group 2P reserves by ~11%”, Panoro explained in the statement.
Net 2P (Proved plus Probable) reserves at effective date of acquisition is 9.4Million barrels of oil equivalent (MMboe) with net 2C (Best Estimate of Contingent) resources being 5MMboe (14.4 MMboe 2P+2C). Resource volumes in Block CI-27 are ~95% gas weighted.
Panoro Energy was incorporated and began operations in 2009 in Oslo, Norway. It holds a diverse portfolio of oil and gas production, development, and exploration assets in Equatorial Guinea (Offshore), Gabon (Offshore), South Africa (Offshore) and Tunisia (Onshore and Offshore).
The value of Block CI-27 is largely tied to the country’s robust, domestic gas market .
“Produced gas is sold into strong and growing local market for power generation with liquids sold to a local refinery.
“Gross production for FY 2025 was 195Milions tandard cubic feet per day ( MMscfd) of gas and 1,380BOPD liquids (~36,000BOEPD)
“Gas pricing is de-linked from oil price and sold under long term contracts with majority of gas used for power generation in Abidjan
“Low unit production cost at just $ 6/boe and accretive to Panoro on all standard metrics applied by industry”.
The transaction is to be financed through a combination of (i) equity, comprising the issuance of seven million new Panoro shares to DNO, and (ii) debt, comprising a fully placed $50Million senior unsecured bond issuance.
It was a convivial atmosphere in the marquee on the premises of the Abuja Hilton, where the Bid Conference was held to decide the winners of the eight month long, Nigerian 2025 oil and gas licencing sale, on July 21, 2026.
“If you don’t win this round, there is a next time”, chorused the country’s two Ministers of state for Petroleum (gas and oil).
Heineken Lokpobiri, Minister of state for Petroleum (oil), elicited a roar of laughter in the packed hall, when he jokingly lamented that the country’s five year old Petroleum Industry Act PIA had discarded the notion of Ministerial discretion in awarding licences. “I wish I was in another Ministry”, he said.
“Transparency was integral to the design and execution of this Licensing Round”, Oritsemeyiwa Eyesan, Chief Executive of the NUPRC, the upstream petroleum regulator, told the participants. “The Nigeria 2025 Licensing Round Guidelines provided clear information regarding participation rules, technical and commercial requirements, and evaluation criteria. These provisions were further clarified through the Licensing Round Portal, the Pre-Bid Conference, subsequent webinars, as well as dedicated channels established to address applicants’ enquiries”.
She said that NEITI was present to observe the relevant evaluation and bid-opening procedures, in order to enhance the integrity of the process.
“It is evident that allocating petroleum rights is a matter of public trust, requiring a process that can withstand independent scrutiny. NEITI’s involvement demonstrates Nigeria’s commitment to internationally recognised standards of transparency and accountability in natural resource management”.
There were murmurs in the hall when Dutchford E&P was announced as receiving a score of 100% in the evaluation of the technical and commercial submissions for the bid for the Yorla field – Petroleum Prospecting Licence (PPL) 2A 32, beating NNPC E&P Ltd and 10 other contestants to win the asset.
That result was the third of the 37 that were announced and the rest of the contest appeared to continue, in the same celebratory air with which it started.
At the close of the proceedings, Africa Oil+Gas Report asked a retired manager at one of the major oil companies, who acclaimed the round as being “most transparent and impressively executed”. His own entry failed for a reason he couldn’t fault: “We missed consideration of our Commercial package because our Bid Guarantee wasn’t uploaded on the NUPRC portal. We brought a hardcopy to Abuja but it wasn’t tenable by the process”, he explained. “We say: “Never give up” though this is expensive”, he clarified.
Africa Oil+Gas Report left the premises sharing that same perspective.
Two winners we spoke to, in the immediate aftermath, didn’t think there were deliberate fudging of the process but they thought things could be better run. “The removal of technical pass/fail gate, making all bidders to proceed to commercial evaluation, made the process vulnerable”, one winner argued. “A bidder with a weak technical submission can now win a block on the strength of commercial bid precisely reversing the Commission’s stated objective”. That’s one. “There were no scored rubric or minimum threshold for Technical Evaluation (Schedule H)”, the winner continued. “Without anchored scoring bands, evaluator discretion is unconstrained”. The argument is that “polished documentation could potentially substitute for genuine technical capability. Potential for inconsistent scoring across bids.”
A former director of one of the country’s hydroarbon regulatory agencies told Africa Oil+Gas Report that “the overall evaluation of submissions needs to be improved. A score of 100% will always look suspicious”. He observed that “there were side talks during the announcement and on the floor changes and they should not be condoned”. He then emphasised that: “the commission must find a way to improve the due diligence on bidders by way of engaging them to presentations, questions and answers as part of the overall process”.
These submissions turned out to be extremely generous compared with the responses we got from other bidders and observers as the week progressed. Our respondents have largely chosen to be anonymous.
“The president (Ahmed Bola Tinubu) decided everything 100%”, one bidder remarked. “For each PPL, he chose the winner and passed it to NUPRC to permutate the criteria from the backend of the IT application”.
The bidder offered no evidence for this claim and when we pressed, he offered: “I don’t know your gauge for transparency, but do we expect there would be no human interference with the process? We haven’t attained that standard as a people”.
Some came across far more embittered. “The commercial is an embarrassment” one bidder declared. “There is no way on earth that their criteria for 100% (40/40); which implies 100% work programme guarantee will generate a profitable economics…Most “winners” scored 40/40 commercial. One genius even scored 100% overall. It is unbelievable”. He paused. “I worked all the prolific asset.. from a shortlist of 10 through the final two picks… all were barely marginal by any shade of robust economics”, he offered. “Considering that work programme guarantee is sunk cost through the plan cycle, it is a heavy strain on the project economics. Then, the signature bonus cap at $7Milion is stretch enough. But you had people calling $15Million to $21Milion”.
When Africa Oil+Gas Report countered that those figures should not be construed as meaning that the process was fudged, he responded: “Either they would never pay, when a more obejective assessment by the financiers finally points them to the realities. Or, they have a plan to go back to NUPRC to rig back those signature bonuses and work programme commitments”.
One invited observer to the process dismissed the bid as non transparent. “Everyone who won has some form of political affiliation. I also saw some elements of influence from NUPRC staff especially those that worked on the technical scoring. Technical was weighted 60% that means companies won bids by just scoring very high >50% in the technical e.g Dutchford, who scored 60% in an asset that does not have a (Three dimensional) 3D Seismic data”
Does anyone have ideas to make things better?
“This is what I expect”, one responder said: 1) That NUPRC evaluators will pull our each party’s technical output- the profiles.2) input their costs 3) generate base case economics 4) score flawed (dubious and criminal) economics zero (technical and commercial)5) then proceed with the serious bidders.
One bidder recommends the reinstatement of a minimum technical qualification threshold. “Only bidders exceeding the threshold should have commercial bids opened and aggregated. This preserves competition among qualified bidders while excluding unqualified ones”.
The bidder also calls for introduction of a 1–5 scoring rubric with defined descriptors per score band for each evaluation parameter.
“Establish a minimum aggregate technical score (e.g., 60%) below which commercial bids are not opened.
“Publish weightings for Technical Bids and Commercial Bids. We recommend equal weights for technical score and commercial score to ensure both technical and commercial quality equally influence the winning bid determination”.
The Namibian government has approved TOTALEnergies’ deal to secure a 40% and operatorship of Galp Energia’s sprawling Mopane accumulation in the Orange basin.
The transaction is tied to Galp Energia accessing a 10% stake in TOTAL’s large Venus development.
Finalising these two -deals -in-one provides a clearer line of sight for TOTAL to take a Final Investment Decision (FID) on Venus, but the latter is still a work in progress.
Jean Pierre Sbraire, TOTAL’s Chief Financial Officer, said at the earnings call on July 2023, 2026 that the company had received the official approval of the Ministry of Energy of Namibia at the end of the week of July 13, 2026 for the farm ins. “And so we are just, in fact, finalizing the last paper to close the deal potentially tonight (July 23, 2026) or tomorrow (July 24, 2026).
“So, that’s important, of course,” Sbraire said, “because this fact that we are going to be on both developments as operator has a strong value for us in order to engage with the FID of Venus, and I would say there are intense discussions as well, we have a joint target between the government of Namibia and the consortium to sanction it by end of July.
“There are discussions progressing, we’ll see if we can conclude in July or if we need to have a little more time.
“Technically, I think we have selected all contractors, so we are ready to take the FID subject to finalizing discussions with the government of Namibia”.
July 2026 timeline for Venus is not cast in stone.
“There have been some progress, but there’s still some progress to be done”, Sbraire noted.
“So again, generally it’s when the last minute you can conclude, but we’ll see if we can do it.
“I would say I’m reasonably optimistic that all the parties, there is a joint interest clearly, and in particular the Namibian authorities are fundamentally supportive to have a strong operator, being able to capitalize on synergies between the projects.
“I remind you that now that the Mopane has been approved and will be closed, the next step is to engage ….. to appraise Mopane.
“We have three wells in 2027, and the FID will be taken in 2028.
“So all that, as we engage in a strong momentum, and clearly for us, Namibia will begin, is becoming a very important hub for future growth, not only to 2030, but beyond 2030”.
African countries are increasingly choosing to hand over parcels of overlooked assets to majors and top-tier international independents to evaluate and decide if they want to proceed with negotiations for valid permits to operate the blocks.
In early May, 2026, Angola signed a Memorandum of Understanding with Woodside Energy, Australia’s largest independent, establishing an initial study period to identify potential investment in blocks 25, 26 and 43, and setting the basis for collaboration on geological and geophysical data evaluation, including 2D and 3D seismic, well reports and other technical information.
In that same week, US major Chevron agreed with Libya’s National Oil Corporation (NOC) to evaluate unconventional shale oil and gas potential in the Sirte, Murzuq, and Ghadames basins. The partnership aims to assess potential resources of up to 123Trillion cubic feet of gas and 18Billion barrels of oil.
A week after Woodside’s Angolan MoU and Chevron’s Libyan signatures were inked, French major TOTAL announced it had signed an MoU with Egypt’s state hydrocarbon firm Egyptian Natural Gas Holding Company (EGAS) company, covering exploration activities on a large area located in the north-western offshore of Egypt. “The MoU establishes a framework for technical cooperation including preliminary exploration and subsurface evaluation activities”, EGAS declared.
Ghana is exploring similar possibilities with Shell, the UK major. Equatorial Guinea has inked Reconnaissance Licences with ENI on six acreages in 2026 and signed Heads of Terms with ConocoPhillips in four tracts between 2025 and 2026.
Algeria had made similar moves much earlier. In May 2024, the state hydrocarbon firm, Sonatrach inked an MoU with ExxonMobil to explore and develop the Ahnet and Gourara basins, two key areas in southern Algeria rich in unconventional gas. In January 2025, the country’s regulator, Algerian National Agency for the Development of Hydrocarbons (ALNAFT) formalized a cooperation agreement with Chevron for several offshore projects.
In all these agreements, there are no mandates or obligations, tied to the usual exploration licence. The expectations from these MoUs are documents to point the way to open up areas that would otherwise have been ignored in the bid round process, and left undeveloped. Nigeria is not yet in the party. The country’s Petroleum Industry Act does not leave room for this kind of special relationships. To take charge of any part of even the least explored sedimentary basin in the country, a company has to join in the annual contest to secure a Petroleum Prospecting Licence.
The Angolan government has authorized the state hydrocarbon company to cede a large fraction of its equity in one of the country’s optimal producing assets to a privately owned, local independent.
Sonangol – Exploração e Produção, SA will transfer 17% of its own 30%, amounting to 5% of the entire shares of all participating interests in block 17/06, to the Falcon Oil holding company, part of the António Mosquito group.
Block 17/06, operated by TOTALEnergies, produced 38,000Barrels of Oil Per Day in May 2026.
Falcon’s 5% share in the block now grows to 10%.
The updated composition of equities in the block then becomes: TOTALEnergies EP Angola Block 17/06 (-30%); Sonangol – Exploração e Produção, SA (25%); SSI Seventeen Limited (27.5%); Falcon Oil Holding Angola, SA (10%); Etu Energias Bloco 17/06 (SU) (7.5%).
Falcon Oil was founded by the Angola businessman António Mosquito in Panama in 1998. It currently holds a 20% stake in Etu Energias operated Block 2/05, a shallow water producing block. It also holds a 10% stake in ExxonMobil -operated undeveloped, non-producing Block 33.
Falcon Oil was not always a top-notch participant in Angola’s E&P environment. The company was removed from three blocks: 18/06, 6/06 and 15/06 by the Ministry of Petroleum between 2014 and 2015, on account of lack of proven suitability and financial capacity, after the group had accumulated debts worth over $200Million with the State. “It was one of the most cited episodes on the financial fragility of Angola owned E&P companies in the face of the cost commitments of the contracting groups”, according to the Angolan economic and financial media outlet O Ponteiro. “Falcon Oil regained ground in the following years: in 2015, it was the (homegrown) oil company with the highest production growth in Angola, a jump of 3.207% from the previous year”.
According to the order signed by the Minister of Mineral Resources, Petroleum and Gas, Sonangol – Exploration and Production, SA notified its intention to transfer to Falcon Oil Holding Angola 5% (five percent) of the participating interest it holds in this concession to the national concessionaire, which did not wish to exercise its right of first refusal.
The Namibian government has begun to clear the backlogs of farm –in/farm- out deals awaiting approval.
Just four days after -June 25, 2026-the London listed Tower Resources announced that it had received a formal letter of approval from the Namibian Ministry of Industries, Mines and Energy for its farm-out of the Petroleum Exploration Licence (PEL) 96 license to Prime Global Energies Limited, Canada based Eco (Atlantic) released a statement indicating Ministerial approval of the farm-out of its 85% participating interest in PEL 98 to Lamda Energy (Pty) Ltd . Eco (Atlantic)’s announcement was dated June 29, 2026.
Canada headquartered Stamper Oil &Gas had earlier announced, on June 22, 2026, that the farm-out process between TotalEnergies and Galp Energia on PEL 83 in the Orange Basin “has been completed”, meaning that the government has given formal approval to the transaction, which was set in motion by an agreement between the two parties in early December 2025.
It is instructive that Eco (Atlantic)’s transaction had taken around 10 months from agreement between the two parties (announced September 16, 2026) to approval by the state (announced June 29, 2026).
On the contrary, Tower Resources and Prime Global Energies initially announced their farm-out deal for the PEL 96 license as far back as January 10, 2025. The approval came in 17 months after.
TotalEnergies and Galp Energia disclosed their own transaction to the public in December 2025.
PEL 96 covers 23,297 square kilometres “of the highly prospective northern Walvis Basin and Dolphin Graben”, Tower Resources said.
PEL 98 (Block 2213, or the ‘Sharon Block’) in the Walvis Basin, is approximately 5,700 square kilometres in size, situated in shallow waters, ranging from 100 to 500 metres.
THERE HAD BEEN ANXIETIES ABOUT delays of approval of these transactions by the administration of President Netumbo Nandi-Ndaitwah, who was inaugurated in March 2025.
When TotalEnergies and Galp Energia announced their farm-in/farm-out agreement involving two large discoveries (Galp operated Mopane field and Total operated Venus accumulation), the government immediately responded that the two companies had not consulted it before agreeing to a farm out. It was an unusual statement and it came off as a little aggressive. As a rule, oil companies often agree with themselves on farm outs, and then request for approvals after. It is up to governments to reject or approve.
The anxieties about Mrs. Nandi-Ndaitwah’s methods found expression in a recent update by Tower Resources (2025 Annual Report, June 1, 2026). “Every government has its own processes, but at the risk of stating the obvious, it is common for many individuals in different departments to review a file, to ensure a matter has been properly considered, that the decision-making process complies with different laws and regulations, and that the correct documents have been obtained and the resulting approvals are in the correct form. Delays can therefore occur as a result of any individuals raising questions, waiting for answers from another department, or simply being unavailable. In both Cameroon and Namibia the processes have been complicated by the Presidential elections in 2025. The new President of Namibia, HE Dr Nandi-Ndaitwah, has instigated an overhaul of the Ministry of Mines, Industries and Energy. We believe this reorganisation and expansion of staff will allow MIME and the Upstream Petroleum Unit in the office of the Presidency, which oversees MIME, to handle more effectively the greatly increased workload associated with the growth of the sector in the last couple of years, and the path to production. But it has also come at a cost in the short term, as the new organisation is formed and finds its feet.”
Eco Atlantic has one more approval to go. It says that the government’s approval process for BP’s farm in into its PELs 97, 99, and 100, initialled by the two companies in April, 2026, “is progressing and, subject to the satisfaction of the remaining conditions, is expected to close by September 2026.
Eco Atlantic’s deal with BP involves cash consideration of $2.7Million payable by BP to Eco on completion of the transaction. BP will carry 100% of Eco’s 25% retained interest, as well as Eco’s proportionate share of the (state hydrocarbon company) NAMCOR (10%) and Local Partners (5%) interest in PEL97, PEL99 and PEL100 for the current exploration phase, with a maximum aggregate carry consideration payable by BP in respect of Eco’s interests of $63Million (based on a maximum of $21Million per asset for each license).
Panoro Energy’s recently completed acquisition of an additional 40.375% interest in Block G in Equatorial Guinea will increase the company’s overall share to 54.625% working interest production in the deepwater acreage located in the Rio Muni Basin.
The asset was acquired from Kosmos Energy, the US junior who is now left with only non-producing properties in the country.
“The event is transformational and highly accretive acquisition “, Panoro said of the completion, which followed approvals from the Communauté Économique et Monétaire de l’Afrique Centrale (CEMAC) “and their mandatory anti-competition review which took approximately three months, and has been obtained in a record time well in advance of the six-month deadline”.
The acquisition positions Panoro as the largest independent E&P oil producer in Equatorial Guinea, where it sees scope for significant further organic and external growth.
But with the country’s overall crude oil output having been stuck at less than 55,000 Barrels of Oil Per Day (BOPD) in the last six months and Block G gross production contributing all of 20,500BOPD, the Norwegian player is merely becoming a larger fish in a small pond.
Panoro is counting the pennies and talking up the positive.
It says:
After interim adjustments in Panoro’s favour of $53Million, the closing consideration paid by Panoro is $127Million versus $180Million announced.
Panoro is due to lift a Block G cargo of ~546,000Barrels shortly in July 2026, of which ~404,000Barrels is attributed to the interest being acquired.
At flat pricing of $90/bbl & $80/bbl Panoro expects to achieve payback on the acquisition within 18 months (@$80/bbl = 24 months) from completion date.
At EG-23 Panoro is progressing work on the Estrella (gas) and Rodo (oil) discoveries for a coordinated initial appraisal and development project utilising existing nearby infrastructure. As per the 2025 AQSR Panoro has net 2C resource recognition of 26.3 MMboe.
Panoro is on track to produce over 20,000BOPD (on a net basis) in 2027.
Equinor has signed an agreement with TOTALEnergies under which the Norwegian company acquires a 30% stake in Block 16/21, offshore Angola, where the French multinational holds 100% participation and the status of Operator.
The transaction will be completed after approval from the competent authorities.
The asset is non-producing, but it is located south of ExxonMobil operated Block 15 and north of TOTAL operated Block 17, the largest producing block in the country.
The signatories were Martin Deffontaines, CEO of TOTALEnergies in Angola and Ane Aubert, Equinor’s country manager in Angola.
The ceremony was witnessed by Hélder Iombo, Director of Negotiations; Raúl Madaleno, the Block Manager and Neusa Cardoso, Director of Communications, all of the Angolan National Oil, Gas and Biofuels Agency (ANPG).
The signed Agreement reflects the shared ambition to explore and develop new oil and gas resources, in line with the production targets established for the sector in Angola.
Italian major ENI is taking a look at what could have been overlooked in the serial exploration campaigns offshore the Northwest African margin in the last 15 years.
On June 2, 2026, the company secured reconnaissance permits for 15 blocks off the coast of Guinea, a largely unexplored part of the Northwest African margin, also known as MSGBC (Mauritania-Senegal-Gambia-Guinea-Bissau-Guinea-Conakry) Basin. The terms cover Blocks A4, A5, B4, B5, C3, C4, C5, D2, D3, D4, E2, E3, E4, F2 and F3, a total area of about 49,089 square kilometres in water depths ranging from 60 metres to 4,500 metres. The deal, signed with Guinea’s Ministry of Water and Hydrocarbons in Conakry, is valid for one year and can be extended to two.
Earlier today (June 5, 2026), ENI inked a Petroleum Exploration Development and Production License Agreement for the Block A1, offshore the Republic of The Gambia, also in the MSGBC.
Block A1 covers an area of 1,300 square kilometres in water depths ranging from 1,250 to 3,300 metres. ENI says that A1 “is located in a region of the Atlantic margin with proven hydrocarbon discoveries”.
The Gambia has always hoped to be as lucky as neighbouring Senegal, the major beneficiary of the series of discoveries in the MSGBC basin between 2010 and 2017. A number of companies had looked at Block A1 and were either forced out or walked away. African Petroleum Corporation was asked to leave in 2017. UK major BP came in after and officially exited the country, in 2021.
ENI has a track record of hitting the mother lode where others see nothing. Recent examples are Tullow in Côte d’Ivoire and Shell in Egypt.
