Angola: Economic and Fiscal Incentives for Mature Oil Blocks and Undeveloped Fields

Presidential Legislative Decree 8/24, of 20 November 2024, created a Legal and Fiscal Regime applicable to Incremental Production in Mature Oil Blocks and projects in Undeveloped Development Areas. Below is a summary of PLD 8/24:

1. Scope: PLD 8/24 is applicable to the Incremental Production arising:

(i) In a Mature Block;
(ii) From projects in Undeveloped Development Areas.
The above must occur in a block located offshore Angola.

2. Definitions:

“Mature Block” – a block which contains 50% or more of Mature Development Areas. A Mature Development Area is defined as containing 50% or more of Mature Fields. A Mature Field is defined as an oil field where the accumulated production has reached 70% or more of the Total Estimated Volume of 1P Reserves. 1P Reserves must be certified by an independent auditor and approved by the Angolan authority.

“Incremental Production” – positive difference between the crude oil volume produced in a field in a given month and the forecasted volume in the same month corresponding to the Field Reference Curve. The Field Reference Curve or Reference Production is defined as the forecasted production agreed between the National Concessionaire (ANPG) and the Operator taking into account the field’s historical production decline, the approved work program and investment commitments and the certified reserves report.

“Project in Undeveloped Development Area” – project to develop a discovered field in a producing block which warrants the creation of a new development area.

“Large Production Field“ – field located in a Mature Block in water depth up to 750 meters which produces 50.000 or more barrels per day, or in water depth exceeding 750 meters which produces 70.000 or more barrels per day.

3. Production Incentives: The Operator may submit to the National Concessionaire a request for incentives for the Incremental Production in the following cases:

(i) Project in a Mature Blocks with an estimated maximum 25% Internal Rate of Return (IRR) under the existing contractual and fiscal terms;
(ii) Project in an Undeveloped Development Areas in a field without prior commercial production with an estimated minimum 25% IRR (on a standalone basis separate from the adjacent DAs) under the existing contractual and fiscal terms.

The National Concessionaire will set annually (by February) the oil barrel price to be considered to calculate the IRR. The first price set in PD 8/24 is USD 60/barrel.

A number of technical and financial/economic documents must be supplied by the Operator to support the request.

The National Concessionaire will review the request and submit it to the Ministry of Mineral Resources and Petroleum (MIREMPET) for final approval.

The respective petroleum contract covering the block (typically, a Production Sharing Contract (PSC)) will be amended as necessary to reflect the production incentives granted. The incentives are effective from the month following the initial work undertaken under the Development and Production General Plan.

4. Tax Incentives: The following tax incentives may be given to the Incremental Production projects:

(i) Petroleum Production Tax (Royalty) – reduced to 15%;
(ii) Petroleum Income Tax – reduced to 25% in Production Sharing Contracts and 55.75% in Association Contracts.

The tax incentives are only applicable to the Incremental Production (the baseline production remains subject to standard tax). The taxable income assessment and tax compliance obligations of Incremental Production projects are done completely separate from the other Block activities.

As an exception, the Large Production Fields are not eligible for any tax incentives.

5. Cost Oil and Production Sharing: For fields other than Large Production Fields, the Incremental Production share of the National Concessionaire is decreased (and the share of the Contractor Group/Operator is increased accordingly), from the baseline share split set out in the respective PSC, in accordance with a set formula. In addition, the cost oil cap is increased by 15%, up to a maximum of 70%, in the case of:

(i) Projects in Undeveloped Development Areas;
(ii) Mature Blocks where the potential cost recovery exceeds USD 10 per barrel.

For Large Production Fields, when the accumulated production reaches the Reference Production, the cost oil cap is increased as follows:

Provided that the cost oil cap shall not be higher than 75% in any event.

Provided that the National Concessionaire share cannot dip below 20%.

6. Recovery of Exploration Well Costs: The costs incurred with Exploration Wells will be recovered in accordance with the following rules:

(i) All Exploration Well costs, whether they lead to petroleum discovery or not, can be recovered against any existing or future production from any Development Area in the respective block, in the case of a PSC, or de ducted for tax purposes, in case of an Association Contract;
(ii) In the event an Exploration Well is completed as a production or injection well, only the costs related to such completion will be included in the development costs bucket;
(iii) The National Concessionaire must approve any Exploration Well drilling under PD 8/24.

7. Management Committee: The National Concessionaire will set up a dedicated Management Committee to implement the Incremental Production objectives within 30 days of PD 8/24 coming into force.

8. Pending requests: Any requests for Incremental Production incentives in relation to Large Production Fields submitted prior to PD 8/24 shall be considered by the National Concessionaire provided the IRR is less than 25%.

9. Existing Contracts: The existing petroleum contracts shall remain fully valid and effective; however, these contracts may be amended to adjust to the terms of PD 8/24 as necessary.

10. Entry into force: PD 8/24 is applicable from its publication date: 20 November 2024.

For more information about PD 8/24, please contact Rui Amendoeira at rui.amendoeira@onelegal.pt.