Liberia will feature its 2026 Offshore Direct Negotiation Licensing Round at Africa Energy Week (AEW) 2026 in Cape Town.
The process, led by Liberia Petroleum Regulatory Authority (LPRA), will present 29 offshore blocks with substantial subsurface data package comprising more than 50,000 line-kilometres of two dimensional (2D) seismic and over 31,000 square kilometres of 3D seismic data to international investors during Africa’s largest energy event to run from October 12-16, 2026.
The offering highlights the Liberia and Harper basins, with available acreage targeting a range of Cretaceous structures, deepwater basin-floor fans and structural closures, with the wider petroleum system sharing geological characteristics with prolific plays across the Atlantic margin.
TGS (for geophysical data) and Core Laboratories (for stratigraphic data) have supported the technical programme, while additional gravity, magnetic, well-log and multi-client datasets provide further information for companies evaluating the acreage
The LPRA’s formal presentation follows months of preparation led by Director General Marilyn T. Logan, including an August 19, 2026 investor day in Houston and the August 28, 2026 opening of prequalification. Companies are now able to establish their technical and financial eligibility ahead of expressions of interest and block-specific negotiations.
Liberia’s last formal competitive oil and gas bid round was conducted in August to December 2014 by the National Oil Company of Liberia (NOCAL), which ultimately concluded unsuccessfully due to political disagreements.
In the last five years, the country has replaced the traditional competitive bidding round with an alternative hybrid process called the Direct Negotiation Licencing Round. It was in this context that the 2024 Liberia Direct Negotiation Round was run through the LPRA.
The direct negotiation model allows qualified companies to advance individual technical and commercial prospects. The process operates under Liberia’s 2014 Petroleum Exploration and Production Act and its 2019 amendments, while resulting PSCs require signatures from both the LPRA and Ministry of Finance and Development Planning. Companies are assessed on technical capability, financial strength and offshore experience before progressing into negotiations over proposed exploration programmes.
TGS has reprocessed 12,000 kilometres of 2D seismic using Pre-Stack Depth Migration, alongside 5,100 square kilometres of reprocessed 3D data from a 26,000-square kilometre volume. The wider TGS library includes more than 24,000 kilometres of legacy 2D data, strengthening imaging across an offshore frontier where subsurface definition remains central to exploration decisions.
The available Liberia Basin acreage includes LB-1, LB-2, LB-3, LB-7, LB-12, LB-13 and LB-14, while Harper Basin opportunities include LB-18, LB-19, LB-20, LB-21, LB-23, LB-25 and LB-28. Other blocks within the wider 29-block grid are already covered by existing commitments and agreements.
TotalEnergies holds LB-6, LB-11, LB-17 and LB-29, covering approximately 12,700 km2, while Atlas Oranto Petroleum holds LB-15, LB-16, LB-22 and LB-24. PetroQuest holds interests connected to LB-32, while RL-003 covers LB-26, LB-30 and LB-31 and involves TotalEnergies and BluEnergies in a separate study and application arrangement.
Activity around LB-32 has provides a fresh indication of corporate interest ahead of the AEW launch. Australian independent Bounty Oil & Gas agreed on September 22 to acquire 100% of PetroQuest Liberia Deep Water, which holds an exclusive letter of engagement with the National Oil Company of Liberia to negotiate a PSC for the Harper Basin block.
The Harper Basin’s geological setting is also attracting attention because of its relationship to neighboring Ivory Coast’s offshore petroleum system. Eni’s Baleine and Calao discoveries have demonstrated the wider prospectivity of the regional margin, while companies including Petrobras and Murphy Oil are pursuing comparable Upper Cretaceous deepwater plays elsewhere in the region.
Liberia’s licensing process uses a direct negotiation model, allowing qualified companies to advance individual technical and commercial prospects. The process operates under Liberia’s 2014 Petroleum Exploration and Production Act and its 2019 amendments, while resulting PSCs require signatures from both the LPRA and Ministry of Finance and Development Planning. Companies are assessed on technical capability, financial strength and offshore experience before progressing into negotiations over proposed exploration programs.
With prequalification now open and valid for five years, companies can establish their eligibility ahead of the licensing round and be prepared to move quickly when new opportunities are launched.
Namibian homegrown E&P firm Trago Energy Pty Ltd, a wholly-owned subsidiary of Custos Energy (Pty) Ltd., has entered into an agreement with Chevron Corporation, in respect of its 10% participating interest in Petroleum Exploration License 90 (PEL 90).
PEL 90 is located offshore Namibia in the Orange Basin and covers an area of approximately 5,433 km². The licence is operated by Chevron.
The agreement provides for the transfer of all of Trago’s participating interest in PEL 90 to Chevron, in exchange for $11Million in cash at completion and further contingent consideration payable on the achievement of appraisal and production milestones, including the revenues associated with commercial production currently estimated to be between 1.5 and 2.5Million barrels of oil (dependent upon commodity price assumptions.)
“Chevron has been buying and selling equity in PEL 90 in the last four years. The American major returned to Namibia for the Orange Basin Rush in late 2022, several months after Shell’s basin opening discovery. It acquired 80% of the acreage from Trago.In December 2024, Chevron reached an agreement to transfer a 27.5% working interest to Qatar Energy, reducing its stake to 52.5%.”
The transaction provides Trago, through the contingent consideration with ongoing exposure to the significant prospectivity and upcoming activities on PEL 90, including the Nabba-1X exploration well, while eliminating Trago’s funding and capital risk.
Completion of the transaction remains subject to governmental, regulatory and third-party approvals. Following completion, Trago will no longer hold a participating interest in PEL 90 and will have no further obligation to fund its share of costs on the licence, including the Nabba-1X exploration well.
Chevron has been buying and selling equity in PEL 90 in the last four years. The American major returned to Namibia for the Orange Basin Rush in late 2022, several months after Shell’s basin opening discovery. It acquired 80% of the acreage from Trago. In December 2024, Chevron reached an agreement to transfer a 27.5% working interest to Qatar Energy, reducing its stake to 52.5%.
Chevron drilled the disappointing Kapana-1X exploration well on the asset, reaching its target depth in January 2025 and plugging the probe as a dry hole after failing to encounter commercial quantities of hydrocarbons.
In August 2026, Chevron sold a 17.4% participating interest in PEL 90 to Equinor.
Equinor acquired the stake through an agreement signed in August 2026. This has not been approved by regulators. It would have reduced Chevron’s stake from 52.5% to 35.1%. Chevron has now acquired-again pending regulatory approval- the entire 10% that Trago holds.
“Adjusted for recently announced, but as yet uncompleted, farm-out to Equinor and prior to adjustment for Trago’s interest exchange, the PEL 90 participants include Chevron (35.1% interest) Qatar Energy (27.5%), Equinor (17.4%), the National Petroleum Corporation of Namibia (10%) and Trago (10%). No reserves or resources have been attributed to PEL 90”.
Chevron will then be holding 45.1% operated interest in PEL 90 after regulators have approved its 17.4% sale to Equinor and 10% acquisition from Trago.
Oil majors are responding to Ghana’s encouraging invitation to invest in the upstream”, Shell Ghana’s chief executive, Brian Mariuki, told Africa Oil+Gas Report.
“But the time that Ghana has is short”.
On September 1, 2026, the UK major, along with its American counterpart, Chevron, signed a non-binding preliminary agreement to acquire production rights for the South Deepwater Tano Cape Three Points (SDTCTP) block, a large tract covering approximately 3,482 square in 2,000 to 3,500 metre water depth. The SDTCTP houses an existing discovery, Nyankom, and was relinquished by AGM Petroleum in 2023.
The two companies are currently negotiating final license terms with the government, after which the operator will be decided.
Mr Mariuki is hoping that the timeline for reaching Petroleum Agreement can be fast tracked to below six months.
Mariuki acknowledged Africa Oil+Gas Report’searlierstory that Shell had shown some interest in Tullow Oil’s assets (Jubilee and TEN fields in the Deepwater Tano and West Cape Three Points), but he indicated that “the materiality” of the property was not worth the UK major’s time.
Shell cannot yet get on board the development of the Pecan field in Deepwater Tano Cape Three Points (DWT/CTP) block, operated by Pecan Energies (50%), as long as (the Russian player) Lukoil was involved, because of US sanctions. But Mariuki indicated that the government was looking for a way to handle the issue. The impression is that Final Investment Decision may be on hold for a little while more.
The Kenyan national, who has been with Shell for about 20 years, credits the current Ghanaian government for the renewed interest being shown by investors. “This didn’t happen for a long time”.
The Ghanaian government has proposed reducing state hydrocarbon company GNPC’s free carried state stake from 15% to 10% for new upstream projects. This policy shift requires a parliamentary amendment to Act 919.
Ghana’s upstream industry is back in the spotlight. So far in September 2026, the country has signed three upstream Memoranda of Understanding (MoUs) with international oil companies (IOCs): Shell and Chevron, and ENI. This is particularly important because, in Ghana’s upstream landscape, an MoU mostly precedes a Petroleum Agreement (PA), subsequent work programmes and, ultimately, barrels.
For a country whose oil production has been declining for some time, the appeal of the MoUs is obvious. Total oil production in 2025 stood at 37.3Million barrels (MMbbls), a 22.67% plunge from 48.24MMbbls in 2024, while gas production slipped 2.4% to 273.78Bcf from 280.51Bcf over the same period, according to data from Ghana Upstream Petroleum Chamber.
Against this backdrop, there is no doubt about the belief that this new wave of MOUs holds the key for production revival, if the signed understandings translate into PAs, work programmes encompassing data acquisition and drilling, commercial discoveries, and eventually first oil. The optimism is understandable, given the deep pockets and technical credentials of the majors involved. Then again, this would not be Ghana’s first rodeo with MoUs.
Since Ghana upstream sector emerged with the start of production from the Jubilee field in 2010, MoUs have featured in the entry of oil and gas companies into the country’s upstream industry. The record of these understandings since then provides a basis to assess how previous MoUs have translated into Petroleum Agreements (PAs), exploration activity, discoveries and barrels, and whether the enthusiasm surrounding the current wave can go beyond expectations and materialise into production.
Ghana’s Petroleum (Exploration and Production) Act, 2016 (Act 919), provides the legal basis for the award of a PA. Under the Act, a PA can be awarded through “an open, transparent and competitive public tender process” or by “direct negotiations”. Regardless of the mechanism, it is mandatory that a PA is ratified by Ghana’s parliament to become effective.
This distinction is important because an MoU is not a PA, and does confer the same rights under the law. Unlike a PA which grants the holder the right to “engage in the exploration, development and production of petroleum”, an MOU is only a step in a much longer journey that may lead to petroleum agreement, exploration activity, and eventual first oil.
September 2026’s MoU signings covers three blocks across Ghana offshore basins. Shell and Chevron signed an MoU with Ghana National Petroleum Corporation (GNPC) in the South Deepwater Tano block. ENI, in partnership with Vitol Upstream Tano Ltd, also inked two MoUs for GH WB_3 and GH_W8 blocks, offshore Tano basin. The Shell-Chevron MoU relates to an acreage previously held by AGM Petroleum and is distinguished by an existing discovery, Nyankom, rather than being a pure frontier block. The block was relinquished in 2023.
While the three MoUs signed in September 2026 leave room for confidence, particularly given the credentials of the companies involved, recent experience suggests caution. One of the two blocks in the ENI – Vitol signed MoU, GH-WB3, was previously awarded to the same partners in 2019 following Ghana’s 2018 licensing round. An MoU for block GH_WB_3 was signed in 2019, but it never progressed into a PA and eventually lapsed in 2023. The expiration of ENI’s 2019 MOU is particularly noteworthy given that ENI is already an established producer in Ghana, with net equity production of 40,000Barrels of Oil Equivalent per day (BOEPD). Yet the operational record and in-country presence did not prevent the 2019 MoU from expiring without progressing into a PA. Perhaps ENI could not reach an amicable understanding with authorities in Ghana then?
Even more telling is the case of ExxonMobil. In 2015, Ghana signed an MOU with the American major for the Deepwater Cape Three Points block. Unlike companies seeking to accumulate paper barrels or warehouse acreage, ExxonMobil’s operational record and global portfolio gave credibility that the MoU could lead to significant upstream activity. The Exxon MOU morphed to a PA in 2018, and secured parliamentary ratification in 2019. It is important to note that the ExxonMobil MoU was signed before the Petroleum (Exploration and Production) Act 2016 came into force. According to the Petroleum Agreement, this complicated the negotiations before all parties eventually reached a compromise.
Under the terms of agreement, ExxonMobil committed to undertake a minimum work programme which include to “acquire, process and interpret 2,222 square kilometres of three dimensional (3D) seismic data; drill one (1) exploration well (optional)” in the initial exploration period (two and half years from the date of the agreement). Alongside a minimum capital expense of $20Million. Yet the PA did not live to see the subsequent commitments beyond the initial phase as the block was relinquished in 2021. No exploration well was drilled nor subsequent programmes attained. Exxon held 80% interest in the block, with GNPC holding 15%, and Ghana Oil Company Limited the remaining 5%. In other words, despite progressing from MoU to PA, the acreage did not translate to barrels or production.
The above cases have shown that neither financially and technically heeled companies such as ExxonMobil and ENI, nor an independent player like Norway AGM Petroleum, were able to beat the odds. AGM Petroleum’s case is particularly interesting given that it had made a discovery. The question, perhaps best answered by industry insiders or parties to the agreement, is what could have led to AGM Petroleum and ExxonMobil to walk away? Because in ENI’s case, the issue was different, as the MoU it signed in 2019 simply expired without progressing into PA.
If there is anything to learn from the past, it is that these MoUs represent opportunities rather than guaranteed barrels or production. Their real significance would be determined on what follows, that is: the signing of Petroleum Agreements, execution of work programmes, exploration activity, appraisal, and ultimately first oil.
Expectedly, the current wave of MoUs offers room for hope. However, recent records suggests that eventual barrels would come from work commitments and execution that follows the MOU, and not from the announcement itself.
Upstream asset divestment by International Oil Companies (IOCs) in Nigeria is now a norm.
But what about the time between the familiar phrase “the transaction is subject to obtaining all required regulatory approvals” in divestment announcements and when the approval is actually granted?
“The transaction is subject to obtaining all required regulatory approvals” is more than a routine caveat – it is a substantive regulatory condition for the transfer of interests. Approval requires the transaction to be assessed against the buyer’s technical and financial capacity, the asset’s end of life obligations, the agreement of the parties, and other relevant considerations. Yet recent IOC divestments show that the process behind this condition can be uncertain, with timelines extending well beyond those anticipated at the point of the announcement.
“The real litmus test of the implementation of the regulatory divestment framework would be the ongoing NNPC Ltd Project Delta divestment, where the legal frameworks can be tested against its own promises of predictability vis-à-vis established timelines, procedural steps, the due diligence elements, and even the deemed approval clause. Expectedly, the complexity of individual transactions will differ, and the time it takes parties to furnish NUPRC with updated or additional information will vary, as such, some reviews might extend beyond the established timelines. But this is precisely where NUPRC may rethink its current communication approach around transaction approvals. “
As upstream divestment by the IOCs intensified in the first five years of the 2020s, the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) has had to build on the legal foundation established by the Petroleum Industry Act 2021 (PIA) for the transfer of interests in upstream assets. This foundation is been operationalised through the Nigeria Upstream Petroleum (Assignment of Interest) Regulations, 2024, and NUPRC’s seven pillar regulatory divestment framework.
Section 95 of the PIA establishes the statutory basis for upstream asset transfer. The section prohibits the transfer of interest by a party to another without approval. The section establishes that the first step after submission of an application for approval by a party is for NUPRC to evaluate and recommend the application to the minister of petroleum for ministerial consent. The expectation of section 95 is for NUPRC to make the recommendation within 60 days and another 60 days for ministerial approval consideration. Notwithstanding these timelines, approval is not a given. Section 95 of the PIA also establish deemed consent as section 95(7b) states that where “no response on the application has been received within 60 working days from the receipt of the recommendation of the Commission, the consent of the Minister … shall be deemed to have been granted”.
The Nigeria Upstream Petroleum (Assignment of Interest) Regulations 2024 further provides procedural guidance for implementing section 95 of the PIA. It highlights details for asset transfer, including mandatory eligibility stage before commercial negotiation. The regulation requires the holder of the asset to inform NUPRC of the transaction and the candidates it has penciled down for the ownership transfer after technical evaluation. Under this regulation, NUPRC is obligated to, within 15 working days of receiving the shortlisted candidates to inform the asset owner of the candidates deemed acceptable to the federal government. Bypassing this stage and going ahead to commercial negotiation is considered by NUPRC that the transaction has “failed the eligibility criteria for the grant of consent by the Minister”.
The regulation establish that NUPRC will undertake “due diligence on application for transaction at any stage of such transaction before making any recommendation to the Minister in respect of the application”. The due diligence include “technical capacity, financial capacity, legal requirements, decommissioning and abandonment, host community trust and environmental remediation fund arrangements, industrial relations and labour related issues; and data repatriation”. The regulation also sets out what happens when the due diligence checks are not met or met, and maintains the same timeline as section 95 of the PIA.
The NUPRC regulatory divestment framework outlines the substantive elements that regulatory approval assessment is based on. It covers technical capacity, financial capacity, legal requirements, decommissioning and abandonment, host community trust and environmental remediation, industrial relations and labour issues, and data repatriation. This framework offers clarity on what is assessed during a divestment regulatory approval.
Benchmarking recent divestment approval timelines against the statutory timeframes in the PIA and the Assignment of Interest regulation reveals approval cycles contrary from what the framework envisages. Seplat announced its acquisition of Mobil Producing Nigeria Unlimited assets in February 2022. Despite an initial presidential assent in August of the same year, followed by a regulatory veto from NUPRC, the transaction did not reach completion until December 2024. Almost three years from announcement to close. The acquisition of Shell Petroleum Development Company by the Renaissance consortium (ND Western, Aradel Energy, First E&P, Waltersmith Petroman, and Petrolin Group), followed a different trajectory. Announced in January 2024, and completed in March 2025, about 14 months to regulatory clearance. Italian ENI and Oando transaction stands out as the fastest of the three deals. First announced in September 2023, it received regulatory approval and closed by August 2024. Taking less than a year from announcement to completion. Notably, both the Seplat and Oando deal faced pre-emption right claims from NNPC Ltd, which added an extra layer to the approval process.
These transactions provide a useful context for assessing the regulatory approval journey of divestment transactions, but they cannot be treated as a direct test of the established regulatory framework. The Seplat and Oando transactions were already underway before the Assignment of Interest regulation was issued, while the NUPRC regulatory divestment framework emerged much later in the life of the three transactions. Instead, it can be inferred that the complexity and lessons learned from these transactions must have informed the development of the regulation and divestment framework.
The real litmus test would be the ongoing NNPC Ltd Project Delta divestment, where the legal frameworks can be tested against its own promises of predictability vis-à-vis established timelines, procedural steps, the due diligence elements, and even the deemed approval clause. Expectedly, the complexity of individual transactions will differ, and the time it takes parties to furnish NUPRC with updated or additional information will vary, as such, some reviews might extend beyond the established timelines. But this is precisely where NUPRC may rethink its current communication approach around transaction approvals.
While communications between NUPRC and transaction parties are generally private correspondence, formalizing periodic updates on the status and progress of a transaction could provide greater clarity to the parties involved. Such updates could indicate the stage reached in the regulatory approval process, outstanding matters, and the likely next steps. This in turn would give stakeholders and even the wider public a better sense of how a transaction is progressing and help reduce perceptions of regulatory inaction.
It is equally important for NUPRC to clarify whether the 60 days regulatory clock pauses or restarts upon request of additional information from the parties to the transaction. The language in section 8(4) of the Assignment of Interest Regulation – “The regularisation of an existing application or an amendment thereto or submission of a new application, shall be deemed to be an application for consent under Regulations” is consequential. The implication of this is that every amendment or regularisation is considered as a fresh application, effectively restarting the 60 days timeline. While it is understandable that this approach ensures that NUPRC evaluates a complete application, it also means that the statutory window can extend well beyond what the framework envisages. A clearer distinction between minor updates or substantial amendments required to establish application completeness, or to undertake due diligence, and how each affects the regulatory clock would be reasonable. This would prevent unnecessary timeline resets and help keep approval periods well within the established window.
Publication of aggregated data on divestment transactions that have undergone regulatory approval, including: review durations relative to established legal timelines, instances where applications were deemed incomplete, the frequency of additional information requests, and the number of regulatory clock restarts would enhance predictability by giving transacting companies clearer data to benchmark their expectations. Because this sort of disclosure is process focused, it would not compromise proprietary or commercially sensitive information.
“The regulation requires the holder of the asset to inform NUPRC of the transaction and the candidates it has penciled down for the ownership transfer after technical evaluation. Under this regulation, NUPRC is obligated to, within 15 working days of receiving the shortlisted candidates to inform the asset owner of the candidates deemed acceptable to the federal government. Bypassing this stage and going ahead to commercial negotiation is considered by NUPRC that the transaction has “failed the eligibility criteria for the grant of consent by the Minister”.
Divestment approval is a consequential element of Nigeria’s petroleum governance framework, with real implications for indigenous capacity building, oil and gas production outcomes, employment, taxes and other revenues accruable to the government. As such, NUPRC must close the gap in its framework to reduce uncertainty around approval timelines for future divestment transactions. This aligns with the position of Mrs. Eyesan Oritsemeyiwa, NUPRC’s Chief Executive, who noted in her inaugural address to the industry that “execution and implementation – predictable regulation, faster decisions, stronger governance, and measurable outcomes that restore confidence, unlock investment, and maximize value for Nigerians and investors” is what the industry should expect following the legal foundation provided by the PIA.
Adeniyi Adeoloye, a petroleum geoscientist based in Calgary, is in a postgraduate course on Energy Management at the University of Calgary. An editorial associate at Africa Oil+Gas Report, Adeoloye writes from time to time for this platform and can be reached at adeniyi@africaoilgasreport.com.
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.
In the last five years, the country has replaced the traditional competitive bidding round with an alternative hybrid process called the Direct Negotiation Licencing Round. It was in this context that the 2024 Liberia Direct Negotiation Round was run through the LPRA.
