Production averaged approximately 1.03 million barrels per day through 2025, a figure that obscures significant intra-year volatility — output dipped below the psychologically important 1 million bpd threshold in July 2025 before recovering on the back of new deepwater volumes from CLOV Phase 3 and the Begonia field. Angola now operates entirely outside OPEC constraints, having formally exited the cartel in January 2024, but the freedom to pump at will has done little to reverse a structural decline that has seen output nearly halve from the 2008-2010 peak of 1.9 million bpd.

Production Profile and Trajectory

Angola’s production history is a textbook illustration of deepwater field lifecycle dynamics:

The July 2025 dip below 1 million bpd was triggered by simultaneous maintenance shutdowns on Block 17 (TotalEnergies) and Block 15 (ExxonMobil), compounded by natural decline in the Dalia and Girassol fields. Production recovered to approximately 1.05-1.08 million bpd by Q4 2025 as CLOV Phase 3 and Begonia ramped up, collectively adding roughly 60,000 bpd of new capacity from mid-year.

The structural decline rate — the pace at which existing fields lose output absent new investment — is estimated at 8-12% annually for Angola’s deepwater portfolio. This means the country must bring approximately 100,000-120,000 bpd of new capacity online each year merely to maintain flat production. In practice, new project approvals have failed to keep pace with decline, a consequence of the post-2014 investment drought and the 5-7 year lead time between final investment decision and first oil in deepwater developments.

OPEC Exit and Its Consequences

Angola joined OPEC in 2007 at the height of the oil boom and remained a member for seventeen years. The January 2024 exit was precipitated by a quota dispute: OPEC+ had assigned Angola a production ceiling of approximately 1.28 million bpd for 2024, which Luanda viewed as both unattainable (given actual production well below this level) and an unacceptable constraint on sovereign resource management.

The practical impact of the OPEC exit has been minimal. Angola was already producing below its allocated quota, so removal of the ceiling changed nothing operationally. The strategic significance is longer-term: Angola is now free to negotiate directly with international oil companies on investment frameworks without the perception that OPEC membership constrains production flexibility. The move also reflected a broader geopolitical pivot — Luanda has deepened relationships with non-OPEC producers and consuming nations, diversifying its diplomatic energy portfolio.

For fiscal planning purposes, the Ministry of Finance budgets oil revenue based on a reference price (currently $65/bbl for the 2025 budget) and a production assumption of approximately 1.0 million bpd. The OPEC exit does not affect these assumptions, but it removes a potential source of policy friction if production ever recovers above OPEC-assigned levels.

Operator Landscape

Angola’s upstream sector is structured around Production Sharing Agreements (Contratos de Partilha de Producao) between the state concessionaire Sonangol and international oil companies (IOCs). The major operators:

TotalEnergies (35-40% of gross production). The dominant IOC, operating deepwater Blocks 17 (Dalia, CLOV, Pazflor, Girassol) and 32 (Kaombo). Block 17 alone produces approximately 350,000-400,000 bpd and represents the single largest production cluster in Angola. TotalEnergies has committed to CLOV Phase 3 and additional infill programs to slow decline on its mature assets.

ExxonMobil. Operates Block 15 (Kizomba complex), historically one of Angola’s most prolific deepwater developments. Production has declined from a peak above 300,000 bpd to approximately 150,000-180,000 bpd. ExxonMobil has been investing in enhanced oil recovery techniques to extend field life.

Chevron. Operates the Cabinda concession (Block 0, onshore/shallow water) and holds interests in the Angola LNG plant at Soyo. Cabinda production has declined steadily from over 200,000 bpd to approximately 80,000-100,000 bpd, with the asset approaching end-of-life within the current decade.

BP. Operates deepwater Blocks 18 and 31, with combined production of approximately 150,000-200,000 bpd. Block 31 hosts the Plutao-Saturno-Venus-Marte (PSVM) development, which has underperformed original production forecasts.

ENI. Operates Block 15/06 (West Hub and East Hub), producing approximately 130,000-150,000 bpd. ENI has been among the more active explorers in Angola, with recent appraisal success on the Agogo discovery.

Sonangol. The national oil company holds a minimum 20% participating interest across all blocks and operates certain marginal fields directly. Sonangol’s role is transitioning from an operational concessionaire to a more commercially oriented entity under the ongoing corporate restructuring. The planned partial IPO would represent a landmark event for Angola’s capital markets.

Fiscal Significance

Oil’s weight in the Angolan economy, while declining in GDP terms, remains overwhelming in fiscal and external account terms:

The receitas petroliferas (oil revenues) flow through multiple channels: production sharing oil (the government’s share of physical crude under PSAs), corporate income tax on IOC profits (Imposto sobre o Rendimento do Petroleo), surface fees (taxa de superficie), and dividends from Sonangol. The Ministry of Finance publishes quarterly oil revenue data, though with a significant lag.

For every $10/bbl change in Brent crude prices, Angola’s fiscal balance shifts by approximately 2-3% of GDP. At $80/bbl, the budget is roughly balanced; below $65/bbl, the government faces a financing gap that must be covered by debt issuance or reserve drawdown.

New Developments and Exploration

Despite the structural decline, Angola’s upstream sector retains significant geological potential:

CLOV Phase 3. TotalEnergies’ infill development on Block 17, which reached first oil in mid-2025. The project adds approximately 40,000 bpd at peak through new subsea tiebacks to the existing CLOV FPSO. Investment cost estimated at $2-3 billion.

Begonia. A satellite development also on Block 17, adding approximately 20,000 bpd from July 2025. The project demonstrates the continued viability of tieback developments that leverage existing infrastructure.

Agogo (ENI, Block 15/06). A potentially significant light oil discovery in the pre-salt Aptian play, analogous to Brazil’s Santos Basin pre-salt. ENI reported estimated recoverable resources of 1-2 billion barrels across the Agogo complex. If confirmed and developed, this could represent Angola’s most important new upstream project in a decade, with first oil potentially in 2028-2030.

Angola LNG expansion. The 5.2 mtpa Soyo LNG plant, operated by Chevron, has scope for expansion to 7-8 mtpa through additional liquefaction trains. Global LNG demand growth and the availability of associated gas from deepwater fields make this a commercially attractive proposition, though final investment decisions have been deferred.

Pre-salt exploration. Angola’s Kwanza Basin shares geological characteristics with Brazil’s prolific pre-salt play. TotalEnergies and other operators have conducted seismic campaigns, but no commercially viable pre-salt discovery has been confirmed. The basin remains a high-risk, high-reward frontier.

Long-Term Outlook

The consensus among industry analysts is that Angola’s production will continue a managed decline through the remainder of the decade, averaging 900,000-1,000,000 bpd through 2028 and potentially falling below 800,000 bpd by 2030 absent a major new development cycle. The Agogo discovery represents the most significant upside risk to this baseline.

For Angola’s economy, the oil outlook reinforces the urgency of the diversification agenda under the PND 2023-2027. Each barrel of lost production reduces fiscal revenue and FX earnings, narrowing the government’s fiscal space and increasing reliance on debt markets to fund the investment program. The relationship between oil decline and macroeconomic performance is not linear — it depends critically on the oil price — but the trend is unambiguously negative for a country that still derives 90% of its export earnings from hydrocarbons.

The global energy transition adds a longer-term structural risk. While Angola’s crude is predominantly light and sweet (low sulfur), commanding a premium to heavier grades, declining global oil demand in a net-zero scenario would compress both production volumes and prices. Angola’s window to monetize its remaining reserves and reinvest proceeds into productive diversification is measured in decades, not generations.