On 23 August 2026, the National Assembly of Vietnam adopted the Law on Petroleum (the “New Law”), which will take effect on 1 March 2027 and replace Law No. 12/2022/QH15 on Petroleum (the “2022 Petroleum Law”).

The New Law represents a targeted recalibration of Vietnam’s petroleum regulatory framework rather than a significant restructuring. It is built around five policy pillars approved under Resolution No. 81/NQ-CP of the Government dated 3 April 2026:

• simplifying administrative procedures and decentralising approval authority;
• improving the regulatory framework for petroleum contracts and petroleum operations;
• strengthening investment incentive policies;
• developing the petroleum value chain, high-tech technical services and offshore energy; and
• establishing a legal framework for greenhouse gas emission reduction and carbon capture and storage (“CCS”) in petroleum operations.

For investors, the significance of the New Law lies less in any single amendment than in the overall shift towards greater regulatory flexibility and delegated decision-making. The reforms should be particularly relevant to projects involving mature, marginal or technically complex fields, although their practical impact will depend substantially on the implementing regulations and the manner in which the newly delegated powers are exercised.

1. Simplifying Investment Procedures and Strengthening Decentralisation

One of the most significant structural reforms is the transfer of a substantial number of approval powers from the Prime Minister and the Ministry of Industry and Trade (“MoIT”) to the competent State authority for petroleum management and, in particular, the Vietnam National Industry – Energy Group (“Petrovietnam”).

Key changes include:

• Petrovietnam will prepare and approve contractor-selection plans, conduct bidding processes and approve contractor-selection results, replacing the Prime Minister in these functions;
• petroleum contract terms will be approved by the State petroleum authority rather than the Prime Minister;
• transfers of participating interests will be reviewed by Petrovietnam, followed by amendment of the petroleum contract and investment registration certificate after reporting to the State petroleum authority, replacing the previous MoIT review and Prime Ministerial approval process;
• Petrovietnam will determine whether to exercise its participation and pre-emption rights under petroleum contracts, replacing the previous MoIT review and Prime Ministerial approval process; and
• Petrovietnam will assume a greater role in dealing with fields upon expiry of petroleum contracts, which previously required MoIT review and Prime Ministerial approval.

Decentralisation is particularly significant at the field-development stage. Petrovietnam may approve resource and reserve reports where total oil in place is below 30 million m³ and total natural gas in place is below 30 billion m³. It will also generally appraise and approve outline development plans, early production plans, field development plans and decommissioning plans that were previously subject to MoIT approval.

Contractor selection will also be streamlined. The New Law retains open bidding, limited bidding and direct appointment, while the competitive-offer method under the 2022 Petroleum Law is no longer maintained as a separate statutory method.

The expanded powers granted to Petrovietnam are accompanied by express accountability mechanisms. Petrovietnam is responsible for approvals and consents falling within its delegated authority and must periodically report delegated approvals to the State petroleum authority for supervision.

The principal benefit of these reforms is likely to be a shorter and more commercially responsive approval process, particularly for decisions that need to be made during the exploration and development phases. This could reduce transaction and delay costs for investors and contractors. At the same time, the expanded role of Petrovietnam means that investors are likely to engage more extensively with Petrovietnam throughout the project lifecycle. The effectiveness of the new regime will therefore depend on the clarity of the delegation framework, internal decision-making procedures and post-approval supervision.

2. Improving Petroleum Contracts and Petroleum Operations

The New Law retains the basic contractual term of up to 30 years for ordinary blocks and 35 years for incentivised blocks, with exploration periods of five and ten years, respectively.

The principal changes concern greater flexibility in extending and adjusting petroleum contracts, including:

• the ordinary extension period is increased from five years to up to ten years and will be subject to Petrovietnam’s approval rather than MoIT approval;
• an extension may exceed ten years where necessary to support efficient gas production;
• petroleum contracts may be extended by up to 15 years for enhanced petroleum recovery;
• extensions of exploration periods of less than five years will be subject to Petrovietnam’s approval rather than MoIT approval;
• exploration periods may, in prescribed circumstances, be extended up to ten years for ordinary blocks and up to 15 years for incentivised blocks; and
• only suspension periods resulting from force majeure or reasons relating to foreign affairs, national defence or security are excluded from the running of the petroleum contract term.

The New Law also introduces a specific mechanism for adjusting work commitments. Where geological conditions make an agreed work programme inappropriate, the contractor may propose changes to its commitments. In cases involving national defence, security or force majeure, the contractor may be entitled to an exemption, reduction or amendment of contractual commitments, subject to approval by the State petroleum authority.

Operational procedures are also simplified. The prior notice period for early termination is reduced from six months to three months. Where a field can be developed by connecting to existing petroleum infrastructure without constructing a new production platform or floating storage facility, an outline development plan is not required. Adjustments to early production plans and field development plans may also incorporate corresponding adjustments to the outline development plan, reducing duplicative approval requirements.

These amendments improve the flexibility of petroleum contracts over their potentially long project lifecycles. This is particularly important for projects where geological conditions, commercial circumstances or production profiles evolve materially after contract award. The extended terms for gas production and enhanced recovery may also improve bankability and support additional investment in mature assets. Investors should nevertheless pay close attention to the conditions and approval procedures for extensions and changes to work commitments, as greater flexibility does not necessarily mean automatic entitlement to an extension or adjustment.

3. Strengthening Investment Incentive Policies

The New Law broadly maintains the existing incentive framework. Incentivised projects retain a 70% cost-recovery ceiling, while specially incentivised projects retain an 80% ceiling, together with the corresponding preferential corporate income tax and crude-oil export tax treatment.

The principal development is the introduction of more targeted incentives for marginal, mature and late-life assets.

Marginal fields

The New Law establishes a dedicated regime for marginal petroleum fields. Where a field does not satisfy the applicable economic threshold under ordinary contractual terms, it may progressively access:

• the ordinary incentive regime;
• the special incentive regime; and
• a bespoke fiscal mechanism where those incentives remain insufficient.

At the highest level of support:

• after payment of natural resources tax and export tax, if applicable, the contractor may apply the entire remaining petroleum production towards recovery of petroleum costs of that field from the date on which the field development plan is approved; and
• after payment of applicable taxes and recovery of petroleum costs, the contractor is entitled to the remaining petroleum.

Where a marginal field forms part of a block containing other fields, the contractor may alternatively seek an increase of up to 10% in the applicable cost-recovery rate for costs attributable to that marginal field.

Changes to the incentive policy for a marginal field already included in an approved list and covered by an existing petroleum contract do not require amendment of that list.

Enhanced petroleum recovery

The New Law introduces a separate incentive for enhanced petroleum recovery, allowing an increase of up to 10% in the cost-recovery rate for qualifying expenditure. Combined with the potential 15-year contract extension, this provides both contractual and fiscal support for continued investment in mature fields.

Tail-end production

The tail-end production regime is also strengthened. Crude oil produced under a qualifying tail-end production project may be exempt from export tax. If the decommissioning security fund is insufficient, the shortfall may be addressed through proceeds from the State’s share of profit petroleum.

The targeted incentive regime is potentially one of the most commercially significant aspects of the New Law. It recognises that applying a uniform fiscal framework to all petroleum assets may leave marginal or late-life resources commercially stranded. The combination of enhanced cost recovery and extended contractual terms could improve project economics sufficiently to justify further investment in fields that would otherwise be uneconomic. For investors, the key issue will be how the economic thresholds and qualification criteria are ultimately defined and administered in practice.

4. Developing the Petroleum Value Chain, High-Tech Services and Offshore Energy

The New Law broadens the petroleum sector beyond conventional upstream production by recognising adjacent infrastructure, services and offshore-energy activities.

The definition of petroleum services is expanded to include services supporting CCS and offshore-energy facilities associated with petroleum operations. The definition of petroleum facilities is also expanded to capture additional reception, distribution, processing and treatment infrastructure. Natural hydrogen is expressly included within the definition of unconventional petroleum.

Offshore energy

Article 52 permits petroleum contractors to study and develop offshore-energy facilities within existing field development areas, including through the use of existing petroleum infrastructure, to serve the relevant field and neighbouring fields.

Qualifying expenditure for the development of offshore-energy facilities serving petroleum activities may be treated as recoverable petroleum costs.

The regime is deliberately limited. Offshore-energy projects that are independent from petroleum operations remain subject to the relevant sector-specific legislation.

High-tech petroleum services

Article 53 establishes a dedicated framework for high-tech petroleum technical services.

Qualifying services may benefit from incentives under investment, tax and land legislation. Specialised machinery, equipment, materials and spare parts that are not domestically available may also qualify for import-duty exemption.

These provisions create potential opportunities for international engineering, technology, offshore-services and specialist equipment providers. In particular, the ability to leverage existing petroleum infrastructure may improve the economics of certain offshore-energy projects. However, the scope of the petroleum-law framework remains deliberately limited to activities sufficiently connected with petroleum operations. Investors considering standalone offshore-energy projects should therefore assess the interaction with the separate regulatory regimes governing electricity, investment, maritime activities, environmental protection and offshore planning.

5. Establishing a Legal Framework for Greenhouse Gas Reduction and CCS

The New Law establishes Vietnam’s first dedicated petroleum-law framework for CCS. The framework encourages the use of existing petroleum infrastructure and suitable geological formations for CO₂ storage, including CO₂ generated outside the petroleum sector.

Key features include:

• CCS activities may be incorporated into an existing petroleum contract upon a proposal by the contractor;
• where a storage formation or injection area extends into an adjacent open petroleum block, the contract area may be expanded for CCS purposes;
• where the relevant formation extends into another existing petroleum contract area, the affected contractors must agree on an implementation arrangement and report it to the State petroleum authority;
• CCS planning may be integrated with petroleum outline development, field-development and decommissioning plans;
• contractors may own, trade and sell carbon credits generated from CCS activities;
• qualifying CCS expenditure is recoverable as petroleum costs; and
• revenue from carbon-credit sales reduces recoverable petroleum costs.

Following decommissioning of CCS facilities, the contractor remains responsible for monitoring and ensuring the safety of the CO₂ storage area and remedying leakage at its own cost before transfer to Petrovietnam.

The New Law nevertheless provides only an initial, sector-specific framework. Longer-term liability following transfer, the interaction with Vietnam’s carbon market and CCS projects independent from petroleum operations remain matters for further regulatory development.

The CCS provisions are potentially significant for petroleum contractors because they create a statutory basis for integrating CCS with existing petroleum assets and cost-recovery mechanisms. They may also create new commercial opportunities around storage, infrastructure and carbon credits. However, long-term liability is likely to remain a key consideration for investors. Until the implementing framework clarifies post-transfer liability, monitoring obligations, carbon-credit treatment and the interface with Vietnam’s broader carbon market, CCS projects may continue to carry material regulatory and allocation-of-risk uncertainties.

6. Comparative Snapshot

Topic	2022 Petroleum Law	New Law	Key change
Decision-making	Multiple approvals required at Prime Ministerial / ministerial level	Substantial authority transferred to the State petroleum authority and Petrovietnam	Shorter approval chain
Contractor selection	Four statutory methods, including competitive offer	Competitive offer removed; open bidding, limited bidding and direct appointment retained	Procedural rationalisation
Contract extension	Generally up to five years	Generally up to ten years; longer for gas and up to 15 years for enhanced recovery	Greater lifecycle flexibility
Gas discovery retention	Generally up to five years	Extension may be up to ten years for ordinary blocks or 15 years for incentivised blocks	Better alignment with gas commercialisation timelines
Marginal fields	Recognised mainly as an incentive-eligibility criterion	Dedicated, escalating incentive mechanism	Improved prospects for commercialisation
Enhanced recovery	No dedicated incentive regime	Additional cost recovery plus extended contract term	Supports investment in mature fields
CCS	No statutory framework	Dedicated framework	New carbon-management investment pathway
Offshore energy	No petroleum-law regime	Permitted where linked to existing field infrastructure	Enables infrastructure and capability sharing
High-tech services	General petroleum-services framework	Dedicated incentives for high-tech technical services	Supports domestic and specialist service capability
Petrovietnam’s role	State-assigned functions and a limited contractor role	Wider delegated approvals, paired with defined accountability measures	Greater autonomy subject to oversight

7. Overall Assessment

Overall, the New Law should be viewed positively from an investor perspective. It addresses several longstanding structural constraints by reducing approval layers, increasing contractual flexibility and introducing more targeted fiscal mechanisms for difficult assets. Its effectiveness, however, will ultimately be measured not by the number of powers or incentives introduced, but by whether investors can obtain approvals more efficiently, achieve greater certainty over project economics and manage long-term regulatory and contractual risks more effectively. The transition to the new regime should therefore be monitored closely, particularly as the implementing regulations are developed ahead of the 1 March 2027 effective date.

For existing contractors and investors, the period before the New Law takes effect would be an appropriate time to review pending approvals, field-development plans, work commitments, participating-interest arrangements and decommissioning obligations to determine whether the new framework creates opportunities for restructuring, extension or improved project economics.

Download a copy of this legal update here.