Angola’s Licensing Programme: Strategic Context
Angola’s ongoing licensing programme, managed by ANPG (Agencia Nacional de Petroleo, Gas e Biocombustiveis), represents one of the most ambitious efforts by any African oil-producing nation to reverse production decline through systematic acreage allocation. Since ANPG assumed the concessionaire role from Sonangol in 2019, more than 50 exploration blocks have been offered across six onshore and offshore sedimentary basins, with awards made to a mix of international majors, mid-cap explorers, and domestic companies.
The 2025-2026 licensing cycle continues this momentum, offering blocks across the Lower Congo, Kwanza, and Namibe basins. For investors evaluating entry or expansion in Angola’s upstream sector, understanding the available acreage, the bidding process, the fiscal terms on offer, and the competitive dynamics is essential. This article provides a comprehensive guide to the current and upcoming licensing rounds.
Historical Licensing Programme (2019-2024)
Six-Year Programme Overview
ANPG’s six-year licensing programme, launched in 2019, was structured to systematically offer blocks across Angola’s sedimentary basins:
- 2019 (Onshore Kwanza Basin): 10 blocks offered in the onshore Kwanza Basin, primarily targeting conventional and unconventional oil and gas plays. Awards included Oando (Block KON-17) and several domestic companies.
- 2020 (Onshore Lower Congo): 9 blocks in the onshore portion of the Lower Congo Basin, including the Cabinda sub-basin. Limited international interest due to COVID-19 and oil price collapse.
- 2021 (Offshore Kwanza Basin): 7 deepwater blocks in the Kwanza Basin, a frontier area with limited exploration history. Awards included a partnership between Petronas and TotalEnergies.
- 2022 (Offshore Lower Congo): 12 deepwater and ultra-deepwater blocks in the Lower Congo Basin, the most prospective area. Strong international interest with awards to Azule Energy, Equinor, and others.
- 2023 (Namibe Basin): 5 blocks in the frontier Namibe Basin, offshore southern Angola. Limited data availability constrained bidding.
- 2024 (Remaining blocks and relinquishments): Reoffering of blocks not awarded in previous rounds, plus acreage from licence relinquishments by operators.
Key Outcomes
The six-year programme resulted in the award of approximately 35 to 40 blocks, with committed work programmes including over 50 exploration wells and seismic acquisition across more than 100,000 square kilometres. However, several blocks remained unawarded, particularly in frontier basins with limited geological data, and some awarded blocks have seen delays in work programme execution.
The return of Shell to Angola in October 2025, through a 17-block memorandum of understanding valued at approximately USD 1 billion in committed exploration expenditure, was the single most significant licensing outcome of the programme.
2025-2026 Licensing Round Details
Available Blocks
The 2025-2026 licensing round is expected to include the following acreage categories:
Deepwater Lower Congo Basin: 5 to 8 blocks in water depths of 1,000 to 2,500 metres, adjacent to proven production areas in Blocks 15, 17, 18, and 31. These blocks benefit from proximity to existing FPSO infrastructure and well-characterised source rocks. They are the most likely to attract competitive bids from international majors.
Ultra-Deepwater Lower Congo: 3 to 5 blocks in water depths exceeding 2,500 metres, at the frontier of current drilling technology. While geological prospectivity is supported by regional seismic interpretation, the extreme water depths increase technical and cost risk.
Kwanza Basin (offshore): 4 to 6 blocks in the deepwater Kwanza Basin, where TotalEnergies’ Kaminho discovery (Block 20/21) proved the basin’s petroleum system. The Kaminho FID in May 2024, with a total investment of approximately USD 6 billion, has significantly de-risked the Kwanza Basin and is expected to increase investor interest in adjacent acreage.
Onshore Kwanza and Lower Congo: Reoffering of onshore blocks not awarded or relinquished from earlier rounds. Onshore blocks have attracted primarily domestic companies and smaller independents, given the lower capital requirements but also lower expected volumes.
Namibe Basin: Potential reoffering of frontier blocks in the Namibe Basin, where limited exploration data remains the primary barrier to investment.
Fiscal Terms
Blocks offered in the 2025-2026 round are expected to be governed by fiscal terms aligned with Decree 8/24 for incremental production and a modified PSA framework for new exploration:
- Royalties: 15 percent for deepwater, with potential reductions for ultra-deepwater or frontier areas
- Cost recovery ceiling: 65 to 70 percent, depending on water depth and geological risk
- ANPG profit oil: 25 to 40 percent, with lower percentages for higher-risk blocks
- Petroleum income tax: 50 percent
- Signature bonuses: Competitively bid, with minimum thresholds set by ANPG
- Work programme commitments: Minimum seismic acquisition and well commitments as bid variables
The petroleum fiscal regime article provides a detailed analysis of each component.
Bidding Process
ANPG conducts licensing through a competitive bidding process governed by Presidential Decree 52/19. The process includes:
Pre-qualification: Companies must demonstrate technical and financial capacity. Minimum requirements include proven upstream experience (typically 5+ years), audited financial statements showing adequate capitalisation, and acceptable HSE track records.
Data room access: Pre-qualified companies gain access to ANPG’s virtual data room containing available seismic data, well logs, geological reports, and environmental baseline studies. Data room fees typically range from USD 50,000 to USD 200,000 per block.
Bid submission: Bids are evaluated on a weighted scoring system considering: work programme commitment (50-60 percent weighting), signature bonus (20-30 percent), and local content commitments (10-20 percent). The specific weighting varies by round.
Award and negotiation: Preferred bidders enter into PSA negotiations with ANPG. Final terms may vary from the model PSA based on block-specific conditions negotiated during this phase.
Government approval: Negotiated PSAs require approval by the Council of Ministers before signature and gazette publication.
The entire process, from announcement to contract signature, typically takes 12 to 18 months.
Local Content Requirements
All bids must include local content plans demonstrating compliance with Presidential Decree 271/20 and its three-tier framework for Angolan participation in goods, services, and employment. ANPG evaluates local content plans as part of the bid scoring process, and strong local content commitments can differentiate otherwise comparable bids.
Competitive Dynamics
Likely Bidders
Based on existing presence and stated exploration strategies, the following companies are likely participants in the 2025-2026 round:
International majors:
- TotalEnergies: Seeking to consolidate its Kwanza Basin position following Kaminho FID
- Shell: Implementing its 17-block MoU, likely to bid on additional Lower Congo deepwater blocks
- Equinor: Active in Blocks 17, 46, and 47, may seek additional acreage in adjacent areas
- Chevron: May seek new exploration acreage to offset mature Block 0 and Block 14 decline
Joint ventures and mid-caps:
- Azule Energy: With 16 existing licences, likely to be selective but may bid on strategic blocks adjacent to existing assets
- Petronas: Already partnered with TotalEnergies in Kwanza Basin, may seek additional deepwater exposure
Domestic companies:
- ACREP: Emerging independent seeking to build a meaningful Angolan portfolio
- Sonangol E&P: May take direct interests in selected blocks, particularly in areas with Sonangol infrastructure
Potential new entrants:
- Woodside Energy (Australia): Active in Senegal and has expressed interest in West African deepwater
- Kosmos Energy (US): West African deepwater specialist, previously evaluated Angolan opportunities
- Africa Oil Corp (Canada/UK): Has indicated interest in Angolan acreage acquisition
Namibia Spillover Effect
The Namibia Orange Basin discoveries—Shell’s Graff and Jonker finds, TotalEnergies’ Venus discovery—have revitalised interest in West African deepwater exploration. The geological continuity between the Namibia and Angola offshore basins, particularly in the Namibe Basin, could drive increased bidding interest in Angola’s southern offshore blocks. Companies that missed out on Namibia acreage may view Angola’s 2025-2026 round as an alternative entry point.
Block Assessment: Key Geological Factors
Lower Congo Basin Prospectivity
The Lower Congo Basin is Angola’s most prolific petroleum province, with cumulative production exceeding 10 billion barrels of oil equivalent from Blocks 0, 14, 15, 17, 18, and 31. Key geological factors include:
- Pre-salt play: Proven in adjacent basins (Brazil’s Santos Basin, Congo-Brazzaville), the pre-salt carbonate play remains underexplored in Angola’s deeper waters. Blocks offering pre-salt prospectivity command premium interest.
- Post-salt turbidite play: The dominant play in existing deepwater fields (Girassol, Dalia, Pazflor, CLOV, Kizomba), with well-understood reservoir characteristics and proven FPSO development concepts.
- Syn-rift and sag plays: Emerging exploration targets in the Lower Congo Basin, requiring new geological concepts and potentially different development approaches.
Kwanza Basin De-Risking
The Kaminho discovery and FID have confirmed the Kwanza Basin’s petroleum system, but the basin remains less explored than the Lower Congo. Blocks adjacent to the Kaminho area (Block 20/21) are expected to attract the strongest interest, while more distal blocks in the basin will require aggressive work programme commitments.
Investment Considerations
Entry Strategy
For companies considering entry into Angola through the 2025-2026 licensing round, key strategic considerations include:
Partnering strategy: Given the capital requirements of deepwater exploration (USD 100-300 million per well), most companies bid as consortia. Identifying compatible partners with complementary technical capabilities and financial capacity is essential.
Data acquisition: Early access to ANPG’s data room and, where available, multi-client seismic data from providers such as TGS, PGS, and CGG, is critical for bid preparation.
Local content partnerships: Identifying and pre-agreeing local content partnerships with Angolan companies strengthens bid competitiveness and facilitates post-award implementation.
Fiscal modelling: Detailed fiscal modelling using block-specific geological assumptions and the applicable fiscal regime is essential for determining bid economics. Professional consulting firms provide fiscal modelling services for Angolan PSAs.
Legal preparation: Engaging oil and gas law firms with Angola experience early in the process ensures smooth navigation of the bidding, negotiation, and contract execution phases.
Risk Factors
- Geological risk: Exploration success rates in Angola’s deepwater have been approximately 20-30 percent historically, with significant dry hole costs of USD 100-200 million per well.
- Schedule risk: The time from licence award to first oil in Angola deepwater is typically 8 to 12 years, requiring patient capital.
- Fiscal risk: While current terms are competitive, the absence of formal fiscal stability clauses in most PSAs creates residual risk of future fiscal changes.
- FATF grey-listing: Angola’s placement on the FATF grey list affects banking relationships and increases regulatory compliance costs.
Conclusion
Angola’s 2025-2026 licensing round represents a significant opportunity for upstream investors seeking exposure to one of Africa’s most prolific petroleum provinces. The combination of proven geological prospectivity in the Lower Congo Basin, emerging potential in the Kwanza and Namibe basins, and increasingly competitive fiscal terms under Decree 8/24 creates an attractive investment proposition. Success in the round requires thorough geological assessment, competitive bid preparation, strong local content partnerships, and experienced legal and fiscal advisory. For companies with the technical capability and financial capacity for deepwater exploration, Angola remains one of Africa’s most compelling upstream destinations.