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We thank our colleagues Arnoldo Troconis and Carlos Omaña at D’Empaire Reyna Abogados—�鶹ֱ��’s Latin American Network member firm in Venezuela since 1998—for their invaluable assistance in analyzing these reforms.

Key Takeaways

1. Venezuela’s amended Hydrocarbons Law marks a major policy shift by reopening the upstream oil and gas sector to private participation through new contractual models like CPPs, while preserving state ownership of resources.

2. The reforms improve fiscal terms and contractual certainty—including tax caps, economic stabilization mechanisms, and access to international arbitration—but the State retains substantial control over approvals and operations.

3. Despite these legal changes, U.S. sanctions remain the primary constraint, with upstream participation still dependent on OFAC licensing and likely to proceed cautiously and incrementally.

On January 3, 2026, no one was more surprised by the capture and arrest of Nicolás Maduro and his wife than this author, who was born and raised in Caracas. With the installation of Delcy Rodríguez as the new President of the Bolivarian Republic of Venezuela, however, nothing seemed to change as the Chavista party that has governed the country for more than two decades remained firmly in power.

That expectation changed on January 29, 2026, when Venezuela’s National Assembly approved sweeping amendments to the Hydrocarbons Law. The amendments mark an opening of the Venezuelan oil and gas sector and fundamentally reshape the legal framework governing private participation in upstream activities. While any significant return of U.S. oil companies will depend on the scope and durability of U.S. sanctions relief, the amended law itself represents a break from prior policy and establishes a statutory foundation for private capital participation.

I. Overview of the Amended Hydrocarbons Law

The amended Hydrocarbons Law adopts a more pragmatic approach to upstream development while preserving core constitutional principles, including state ownership of hydrocarbon reservoirs and continued governmental oversight. The law expressly authorizes alternative business models alongside traditional joint ventures, codifying structures that previously operated through special authorizations or informal arrangements.

The reforms are aimed at attracting investment by improving contractual certainty, recalibrating fiscal terms, and introducing mechanisms designed to preserve project economics over time. At the same time, the State retains a central role through state‑owned entities, and the executive branch maintains substantial discretion over project approvals, business plans, and marketing arrangements. 

II. Key Structural and Economic Features

The centerpiece of the reform is the formal recognition of production‑based participation contracts (Contratos de Participación Productiva or “CPPs”). Under this model, private companies may assume full technical, operational, and financial responsibility for upstream activities, bearing operating costs and risks in exchange for compensation tied to production and/or profits. Contractors do not acquire ownership of reservoirs or permanent infrastructure, which remains with—or reverts to—the State.

Joint ventures continue to play a significant role, with the State retaining majority ownership. However, the CPP model allows private companies to manage operations directly without holding an equity interest in a state‑controlled entity. Nevertheless, state‑owned companies remain contractual counterparties and act as collection agents for royalties and certain taxes.

The amended law introduces greater flexibility by permitting, in certain cases, minority shareholders to exercise technical and operational control, manage funds through foreign accounts, and directly market a portion of production, subject to governmental approval. These provisions are designed to address long‑standing operational and cash‑flow constraints that have limited the effectiveness of joint ventures in practice.

The fiscal regime has also been updated. Although the overall amount of taxes are still high, royalties are capped at 30% and an integrated hydrocarbons tax is capped at 15% of annual gross revenues. The Ministry of Hydrocarbons may grant income tax reductions where necessary to preserve project viability. Certain special contributions and non‑core taxes have been expressly repealed.

Importantly, the amended law introduces a statutory economic and financial equilibrium mechanism. If changes in law or regulation materially and adversely affect a project’s economics, the Ministry of Hydrocarbons may agree to adjustments intended to restore the project to the economic position contemplated at the time of contracting. While the effectiveness of this mechanism will depend on implementation, its inclusion marks a meaningful shift toward contractual stabilization.

The law also permits alternative dispute resolution options, including international arbitration, without requiring additional governmental approvals—an important development for international companies’ risk mitigation.

III. Sanctions and U.S. Licensing Considerations

Despite the breadth of these legal reforms, sanctions remain a gating issue for many investors. Currently, U.S. companies need to obtain a license from the Office of Foreign Asset Control (“OFAC”) in order to do business with PDVSA, the state-owned oil company in Venezuela. Nevertheless, Washington and Caracas are aligning, and arguably trading, sanctions relief with a domestic legal overhaul.

On January 29, 2026—the same day the hydrocarbons reforms were approved—the U.S. Treasury Department issued a general license expanding the scope of permitted activities for U.S. oil companies in Venezuela.[1] The license authorizes a range of downstream and midstream activities, including exporting, selling, storing, transporting, and refining Venezuelan crude, as well as certain commercial oil swaps, provided the activities are conducted by U.S. entities.

The license does not broadly authorize new upstream production beyond activities already permitted under company‑specific licenses, e.g. Chevron’s OFAC license, and it includes significant restrictions. Transactions involving Chinese‑controlled entities remain prohibited, payments related to PDVSA generally must flow through U.S.‑controlled accounts, covered contracts are governed by U.S. law, and disputes must be resolved in the United States. In addition, detailed reporting obligations apply to oil transactions, particularly where crude is sold onward to third countries.

Taken together, the amended Hydrocarbons Law and the expanded U.S. general license suggest a coordinated—but still cautious—shift toward re‑engagement with Venezuela’s energy sector. For now, upstream participation by U.S. companies remains license‑dependent and likely to proceed incrementally through targeted authorizations rather than broad sanctions relief.

Conclusion

Venezuela’s amended Hydrocarbons Law creates new pathways for private participation and introduces tools aimed at improving contractual certainty and project economics. Companies considering opportunities in Venezuela should evaluate potential structures holistically, with careful attention to regulatory risk, sanctions exposure, and enforcement considerations.

�鶹ֱ��’s Energy, International Trade & Sanctions, and Latin America teams regularly advise clients on cross‑border energy investments, sanctions compliance, and complex regulatory frameworks. For questions regarding these developments or their potential impact on proposed projects in Venezuela, please contact the authors or your �鶹ֱ�� relationship partner.