Angola’s Production Trajectory: Quantifying the Challenge
Angola’s oil production trajectory is the central variable shaping the country’s fiscal position, upstream investment climate, and geopolitical relevance. From a peak of nearly 2 million barrels per day in 2008, output has declined to approximately 1.13 million bpd in 2024, a reduction of more than 40 percent over 16 years. Understanding the dynamics driving this decline, and the potential for new developments to offset it, is critical for investors, operators, policymakers, and analysts.
This article presents a data-driven production forecast through 2030, incorporating decline curve analysis of existing producing fields, scheduled new development contributions, and scenario modelling that captures the range of plausible outcomes.
The Physics of Decline: Why Angola’s Output Is Falling
Oil field decline is a natural physical phenomenon driven by reservoir pressure depletion as fluids are extracted. In the absence of intervention (pressure maintenance through water or gas injection, infill drilling, artificial lift), a field’s production rate declines exponentially from its plateau peak.
Angola’s production decline reflects the maturation of its major deepwater developments. The country’s largest producing blocks, including Block 17 (TotalEnergies), Block 15 (ExxonMobil), Block 15/06 (Azule Energy), and the Cabinda concession area (Chevron), entered production between 2001 and 2014. Most of these developments reached plateau production within 2 to 5 years of first oil and have been in decline since.
Observed Decline Rates by Block
Analysis of publicly reported production data and operator disclosures reveals the following approximate decline profiles for Angola’s principal producing blocks:
| Block | Operator | Peak Production | Current (~2024) | Annual Decline Rate |
|---|---|---|---|---|
| Block 17 | TotalEnergies | ~650,000 bpd | ~280,000 bpd | 6-8% |
| Block 15 | ExxonMobil | ~350,000 bpd | ~200,000 bpd | 5-7% |
| Block 15/06 | Azule Energy | ~190,000 bpd | ~155,000 bpd | 4-6% |
| Block 32 | TotalEnergies | ~230,000 bpd | ~160,000 bpd | 8-10% |
| Block 18 | Azule Energy | ~120,000 bpd | ~50,000 bpd | 10-12% |
| Cabinda area | Chevron | ~300,000 bpd | ~210,000 bpd | 3-5% |
| Block 31 | Azule Energy | ~150,000 bpd | ~60,000 bpd | 10-12% |
| Others | Various | ~100,000 bpd | ~35,000 bpd | Various |
The weighted average decline rate across Angola’s producing portfolio is approximately 7 to 9 percent per year on an un-arrested basis. With active intervention (infill drilling, water/gas injection optimisation, well workovers), operators have moderated effective decline rates to approximately 5 to 7 percent annually at the national level.
At a 6 percent effective annual decline rate applied to a 1.13 million bpd base, Angola would lose approximately 68,000 bpd per year from existing production, implying a decline to below 900,000 bpd by 2028 and below 800,000 bpd by 2030 in the absence of new production additions.
New Development Contributions: What Is in the Pipeline
The critical question for Angola’s production forecast is whether new developments entering production can offset, or ideally exceed, the natural decline from existing fields. The following new developments are expected to contribute material volumes through 2030:
Kaminho (Block 20/11, TotalEnergies)
- FID: May 2024
- Expected first oil: ~2028
- Plateau production: ~70,000 bpd
- Ramp-up period: 12-18 months from first oil to plateau
Kaminho is the single most important new development for Angola’s production trajectory. As the first major pre-salt development in the Kwanza Basin, it carries both volumetric significance and a signalling effect for future Kwanza Basin investment. However, first oil is unlikely before 2028, meaning Kaminho’s contribution falls into the later years of the forecast period. For full project details, see our deepwater field development pipeline analysis.
Begonia (Block 17, TotalEnergies)
- First oil: Late 2024
- Production contribution: ~25,000-30,000 bpd
- Type: Satellite tieback to Pazflor FPSO
Begonia is already contributing production and represents a near-term offset to Block 17’s natural decline. The development demonstrates the viability of satellite tiebacks to extend FPSO utilisation and capture remaining resource in the Lower Congo Basin.
Ndungu (Block 15/06, Azule Energy)
- Expected first oil: 2025-2026
- Production contribution: ~20,000-30,000 bpd
- Type: Infill development tied to Agogo FPSO
Ndungu is an infill development designed to boost Block 15/06 production through additional subsea wells connected to the existing Agogo FPSO. While not a standalone new development, Ndungu’s incremental barrels are important for moderating Azule Energy’s portfolio decline.
Sanha Lean Gas Connection (Cabinda, Chevron)
- First gas: December 2024
- Gas production: 80 mmscf/d ramping to 300 mmscf/d
- Liquids contribution: Modest (condensate associated with gas production)
While primarily a gas project, the Sanha Lean Gas Connection may yield modest associated liquids production and will improve the economics of the Cabinda concession area. For gas implications, see our coverage of natural gas monetisation.
Shell Exploration Programme (Various Blocks)
- First drilling: Expected 2027-2028
- Potential first oil: 2032+ (if commercial discovery made)
- Impact on 2030 forecast: Minimal (exploration phase through 2030)
Shell’s 17-block exploration programme will not contribute production volumes within the 2026-2030 forecast window. However, exploration results could materially influence the post-2030 production outlook.
Other Infill and Satellite Developments
Multiple smaller infill and satellite development projects are ongoing or planned across Angola’s producing blocks. These include additional subsea well tiebacks in Blocks 17, 32, 15, and 15/06, as well as mature-field workover and recompletion campaigns. Collectively, these programmes are estimated to contribute 20,000 to 40,000 bpd of incremental production through the forecast period.
For details on workover programmes, see our article on well intervention and workover activity.
Production Forecast Scenarios: 2026-2030
Based on the decline and new development analyses above, three forecast scenarios illustrate the range of plausible production outcomes:
Base Case: Managed Decline
Assumptions:
- Effective national decline rate of 6% per year on existing production
- Kaminho first oil in 2028, reaching ~50,000 bpd by end of 2029
- Begonia and Ndungu contributing ~50,000 bpd combined
- Infill and satellite developments contributing ~30,000 bpd incrementally
- No significant exploration success prior to 2030
| Year | Existing Production | New Additions | Total Production |
|---|---|---|---|
| 2024 | 1,130,000 | - | 1,130,000 |
| 2025 | 1,062,000 | 30,000 | 1,092,000 |
| 2026 | 998,000 | 45,000 | 1,043,000 |
| 2027 | 938,000 | 55,000 | 993,000 |
| 2028 | 882,000 | 85,000 | 967,000 |
| 2029 | 829,000 | 120,000 | 949,000 |
| 2030 | 779,000 | 140,000 | 919,000 |
Under the base case, Angola’s production declines from 1.13 million bpd to approximately 919,000 bpd by 2030, a reduction of approximately 19 percent over six years. New developments slow but do not halt the decline trajectory.
Upside Case: Accelerated Development
Assumptions:
- Effective decline rate moderated to 5% through enhanced recovery and intervention
- Kaminho first oil in late 2027, reaching plateau 70,000 bpd by end of 2029
- Additional FID on at least one Kwanza Basin development by 2028
- EOR programmes contribute ~20,000 bpd by 2030
- Successful appraisal of recent gas-condensate discoveries yields liquids
| Year | Total Production (Upside) |
|---|---|
| 2025 | 1,107,000 |
| 2026 | 1,067,000 |
| 2027 | 1,032,000 |
| 2028 | 1,010,000 |
| 2029 | 995,000 |
| 2030 | 985,000 |
The upside case stabilises production near 1 million bpd through 2030, avoiding a breach of the psychologically and fiscally significant million-barrel threshold.
Downside Case: Accelerated Decline
Assumptions:
- Decline rate of 8% (operational disruptions, reduced investment)
- Kaminho delays to 2029 first oil
- Limited infill investment due to commodity price weakness or fiscal uncertainty
- No material exploration success
| Year | Total Production (Downside) |
|---|---|
| 2025 | 1,060,000 |
| 2026 | 985,000 |
| 2027 | 910,000 |
| 2028 | 840,000 |
| 2029 | 785,000 |
| 2030 | 745,000 |
The downside case sees production fall below 750,000 bpd by 2030, a level that would have severe fiscal implications for the Angolan government and could trigger further reform measures.
Fiscal Implications of Production Decline
Angola’s government revenue is heavily dependent on petroleum sector receipts, which typically account for approximately 50 to 60 percent of total government revenue and more than 90 percent of export earnings. Production decline directly erodes the fiscal base, creating budget pressures that compound during periods of low oil prices.
At $75 per barrel (a representative mid-cycle price assumption for 2026-2030), the difference between the base case and downside case production forecasts translates to a revenue differential of approximately $4 to $5 billion per year by 2030. Our analysis of oil price impact on Angola’s economy explores these fiscal dynamics in depth. This underscores the fiscal urgency driving Angola’s efforts to attract upstream investment and accelerate new development.
The fiscal reform embedded in Presidential Decree 8/24, which reduced royalties to 15 percent and capped ANPG profit oil at 25 percent, reflects the government’s pragmatic calculation that lower per-barrel revenue is preferable to higher per-barrel revenue on a rapidly shrinking production base. For a detailed examination of the fiscal framework, see our production sharing agreement guide.
Can EOR Change the Trajectory?
Enhanced oil recovery technologies represent a potential but uncertain source of additional production that is not fully captured in the scenario analysis above. With average recovery factors in Angola’s offshore fields estimated at 30 to 40 percent, the theoretical potential for EOR to unlock incremental volumes is substantial. However, offshore EOR implementation is technically complex and capital-intensive.
The most promising EOR opportunities in Angola include water-alternating-gas (WAG) injection in depleted reservoirs, low-salinity waterflooding in suitable geological formations, and polymer flooding in viscous oil reservoirs. TotalEnergies and Azule Energy are both piloting EOR techniques in their mature Block 17 and Block 15/06 operations, respectively.
If EOR programmes deliver an additional 2 to 3 percentage points of recovery across Angola’s major producing fields, the incremental volume could amount to 50,000 to 100,000 bpd, a material contribution to the production forecast. However, realising this potential requires sustained investment in pilot programmes, technical demonstration, and full-field implementation. For more on this topic, see our dedicated analysis of enhanced oil recovery in Angola.
The Post-2030 Horizon: What Comes Next
Looking beyond 2030, Angola’s production trajectory will be determined by factors that are currently uncertain:
Kwanza Basin pre-salt development: If Kaminho proves the commercial viability of pre-salt production in the Kwanza Basin, follow-on developments in adjacent blocks (CON 1-6) could deliver 100,000 to 200,000+ bpd of new production in the 2030-2035 timeframe. This is Angola’s single largest production upside.
Shell exploration results: Shell’s multi-block exploration programme could yield discoveries that support new developments in the 2030s. The scale of Shell’s commitment suggests the company sees material exploration upside.
Namibe Basin frontier exploration: If geological analogies with Namibia’s Orange Basin are confirmed by drilling, the Namibe Basin could emerge as a significant new petroleum province.
Gas-to-liquids and gas-condensate: The Gajajeira-01 gas discovery in July 2025, with estimated resources of over 1 trillion cubic feet of gas and 100 million barrels of condensate, illustrates the condensate liquids potential associated with gas development. Understanding the full natural gas value chain is essential for evaluating these prospects.
For investors and operators, the key takeaway is that Angola’s production outlook is not predetermined. Active investment in new exploration, development, and mature-field optimisation can meaningfully alter the trajectory. The fiscal, regulatory, and geological environment has improved materially over the past two years, and the window for capital deployment is open.
For a comprehensive view of the investment landscape, see our analysis of upstream investment opportunities and our oil block concessions directory.
External resources: ANPG Official Website | IEA Angola Country Profile | OPEC Angola Data