The production sharing agreement (PSA) is the foundational legal and fiscal instrument governing oil and gas exploration and production in Angola. Every barrel of crude oil and every cubic foot of natural gas produced in the country is subject to the terms of a PSA between the national concessionaire—ANPG (Agencia Nacional de Petroleo, Gas e Biocombustiveis)—and the contractor group (the international and domestic companies that fund and execute exploration and production activities). Understanding how a PSA works, step by step, is essential for operators, investors, lenders, and advisors active in Angola’s energy sector.
What Is a Production Sharing Agreement?
A production sharing agreement is a contract in which the state retains ownership of the petroleum resources in the ground and grants a contractor group the right to explore for and produce those resources at the contractor’s risk and expense. In return, the contractor receives a share of the production (measured in barrels or equivalent) as compensation for its investment and risk-taking. The production is divided between “cost oil” (used to recover the contractor’s costs) and “profit oil” (split between the contractor and the state according to agreed percentages).
The PSA model was pioneered by Indonesia in the 1960s and has since been adopted by more than 40 countries globally. Angola adopted the PSA framework as its primary petroleum fiscal instrument, replacing earlier concession-based arrangements.
The Parties to an Angolan PSA
The Concessionaire: ANPG
ANPG acts as the concessionaire—the entity that holds the sovereign right to explore for and exploit petroleum resources on behalf of the Angolan state. ANPG enters into PSAs with contractor groups, monitors compliance with work program obligations, receives the state’s share of production (royalty oil and profit oil), and exercises regulatory authority over upstream activities.
The Contractor Group
The contractor group typically comprises one or more international oil companies (IOCs) and may include Sonangol (the national oil company) as a participating partner. One member of the contractor group is designated as the operator, responsible for day-to-day management of exploration and production activities. The contractor group bears the financial risk of exploration and development.
The Operator
The operator is the company within the contractor group that manages operations on behalf of all partners. The operator is typically the largest or most technically capable partner. In Angola, major operators include TotalEnergies, Chevron (through CABGOC), ENI/Azule Energy, and ExxonMobil (through Esso Exploration Angola).
Step-by-Step: How Production Sharing Works
Step 1: Block Award and Signature
The PSA life cycle begins with the award of a block to a contractor group, typically through a competitive licensing round administered by ANPG. The award process involves an ANPG announcement of available blocks and licensing terms, submission of bids by qualifying companies (evaluated on technical capability, financial strength, work program commitment, and signature bonus offers), ANPG evaluation and selection of the winning bidder, and execution of the PSA between ANPG and the contractor group. For details on the licensing process, see our guide on how oil block licensing works in Angola.
At signature, the contractor may be required to pay a signature bonus—an upfront cash payment to the government. Signature bonuses for Angolan deepwater blocks can range from $5 million to over $100 million depending on the perceived prospectivity of the acreage.
Step 2: Exploration Phase
The exploration phase typically spans 4–8 years, during which the contractor must fulfill minimum work program obligations specified in the PSA. These obligations typically include the acquisition and processing of 2D and/or 3D seismic data, environmental baseline surveys, the drilling of one or more exploration wells, and geological and geophysical studies.
All exploration costs are borne by the contractor. If no commercial discovery is made, the contractor bears the loss and the block reverts to ANPG at the end of the exploration period. This “risk/reward” structure is fundamental to the PSA model—the state bears no exploration risk.
Step 3: Discovery and Appraisal
If an exploration well encounters hydrocarbons, the contractor must notify ANPG and conduct appraisal activities to determine the size and commercial viability of the discovery. Appraisal typically involves drilling one or more additional wells, conducting well tests (to measure flow rates and reservoir properties), preparing resource estimates and preliminary development plans, and submitting a declaration of commerciality to ANPG.
Step 4: Development Approval
If the contractor determines that a discovery is commercially viable, it submits a development plan to ANPG for approval. The development plan includes field development concept and design (including FPSO specifications, subsea architecture, and well count), capital cost estimates, production forecasts, environmental impact assessment, local content plan, and decommissioning plan. ANPG reviews and approves the development plan, potentially requesting modifications. Approval triggers the development phase and the final investment decision (FID) by the contractor group.
Step 5: Production and Revenue Sharing
Once a field begins producing, the PSA’s revenue-sharing provisions come into effect. This is the core of the PSA economic model, and it operates through a defined sequence.
Gross Production: The total volume of petroleum produced from the block in a given period (typically measured monthly or quarterly).
Royalty Deduction: A royalty is deducted from gross production and paid to the government. Under Decree 8/24, the royalty rate is 15 percent. This is the government’s first take from production, assessed before cost recovery. Royalty can be paid in cash or in kind (physical crude oil).
Cost Oil (Cost Recovery): After royalty deduction, a defined portion of the remaining production is allocated to the contractor to recover accumulated exploration, development, and operating costs. Under Decree 8/24, cost recovery is capped at 70 percent of production after royalties. The cost recovery ceiling is a critical parameter: it determines the maximum rate at which the contractor can recoup its investment. A higher ceiling allows faster cost recovery, improving the contractor’s internal rate of return and accelerating the payback period.
Costs eligible for recovery typically include exploration costs (seismic, drilling, studies), development costs (FPSO, subsea infrastructure, development wells), operating costs (production operations, maintenance, logistics), and overheads (management, administration).
Profit Oil: The production remaining after royalty and cost recovery deductions constitutes “profit oil.” This is split between the contractor group and ANPG according to percentages defined in the PSA. Under Decree 8/24, ANPG’s profit-oil share is capped at 25 percent, meaning the contractor retains at least 75 percent of profit oil.
Profit-oil splits may be tiered, with the government’s share increasing as cumulative production or production rates exceed defined thresholds. This mechanism allows the government to capture a larger share of the upside from highly productive fields.
Petroleum Income Tax: The contractor’s share of profit oil is subject to petroleum income tax. The effective tax rate depends on the specific provisions of the PSA and Angolan tax law.
Step 6: Decommissioning and Abandonment
At the end of a field’s economic life, the contractor is responsible for decommissioning production facilities, plugging and abandoning wells, and restoring the environment to an acceptable condition. Decommissioning costs are typically recoverable through the cost recovery mechanism, and contractors are required to establish decommissioning provisions during the production phase.
Illustrative Fiscal Model
To illustrate how the PSA mechanics work in practice, consider a simplified example based on Decree 8/24 terms.
Assumptions: Daily production of 50,000 barrels of oil per day, Brent price of $80 per barrel, annual production of approximately 18.25 million barrels, cumulative development cost of $3 billion requiring recovery.
Annual Revenue Calculation:
Gross revenue: 18.25 million barrels x $80 = $1.46 billion
Royalty (15 percent): $219 million (paid to government)
Revenue available for cost recovery and profit split: $1.241 billion
Cost recovery (70 percent cap): Up to $869 million (of the $1.241 billion) can be allocated to cost recovery. If actual annual costs and amortized capital total $600 million, the contractor recovers $600 million.
Profit oil: $1.241 billion minus $600 million = $641 million
ANPG profit oil (25 percent of profit oil): $160 million
Contractor profit oil (75 percent): $481 million
Petroleum income tax is then assessed on the contractor’s profit oil.
Government total take (simplified): Royalty ($219M) plus ANPG profit oil ($160M) plus petroleum income tax on contractor profit oil = substantial government revenue share.
This simplified model illustrates the layered fiscal take that characterizes Angola’s PSA regime. The actual economics of any specific block depend on the particular PSA terms, production profile, cost structure, and oil price. For detailed coverage of the Angolan fiscal framework, see our petroleum fiscal regime article.
How Angolan PSAs Compare Internationally
Angola’s PSA terms under Decree 8/24 are competitive relative to other deepwater basins:
Guyana: 2 percent royalty, 75 percent cost recovery, 50/50 profit-oil split. Lower government take but less established infrastructure.
Brazil (pre-salt): Production sharing regime with a higher government take, especially for the most productive fields. Petrobras holds mandatory operatorship.
Nigeria (deepwater): PSA and joint venture structures with production-tiered royalties and tax rates that result in a moderate government take.
Mozambique: PSA terms similar in structure to Angola but with different specific parameters and a less mature regulatory framework.
Angola’s balance of 15 percent royalty, 70 percent cost recovery, and 25 percent maximum ANPG profit-oil share provides sufficient fiscal incentive for operators while ensuring meaningful government revenue.
Key Negotiation Points
When negotiating or evaluating an Angolan PSA, the following parameters are critical:
Cost recovery ceiling: Higher ceilings favor the contractor; lower ceilings favor the government. The 70 percent ceiling under Decree 8/24 is moderate by international standards.
Profit-oil split tiers: The rate at which the government’s profit-oil share increases with production is a key determinant of the economics of large discoveries.
Signature and discovery bonuses: These upfront payments are non-recoverable and represent pure government revenue.
Domestic market obligation: The PSA may require the contractor to supply a percentage of production to the domestic market at a discount to international prices.
Stabilization clause: Provisions that protect the contractor from adverse changes in fiscal terms for the duration of the PSA.
For investment evaluation using PSA parameters, see our 2026 oil and gas investment opportunities outlook and our guide to due diligence for oil and gas acquisitions. For the broader fiscal context, see our analysis of foreign direct investment in Angola’s energy sector.