Cuba has had a new law in place since Monday establishing the rules governing oil and gas exploration and production. Issue No. 85 of the Official Gazette published Decree-Law 135, “On Oil and Gas,” signed on September 3, along with its implementing regulations, Decree 184, approved by the Council of Ministers on September 29. Both measures will enter into force in just one week, on October 19.
The new legislation repeals the 1938 Fuel Minerals Law and Law 635 of 1959, which had provided the main legal framework for the sector. In its recitals, Decree-Law 135 itself acknowledges that those laws were incompatible with the constitutional framework and had become “inapplicable” under current conditions.
For decades, one of the country’s most strategic industries operated under a legal framework dating from before the Revolution, supplemented by resolutions and contracts negotiated on a case-by-case basis.
Pedro Abigantus León, director of Oil and Gas Investment and Business at the Ministry of Energy and Mines (MINEM), presented the legislation at a press conference, according to Cubadebate.
The official explained that the aim is to establish the legal conditions needed to gradually increase crude oil and gas production, boost reserves and meet as much domestic fuel demand as possible.
In drafting the law, authorities examined regulations in 18 countries and consulted 31 institutions, which submitted 389 comments. Of those, 347 were incorporated.
Four Contractual Arrangements
Article 21 of the decree-law establishes four forms of participation in exploration and production:
- Production-sharing agreements, a model used with foreign companies since the 1990s. These agreements can run for up to 40 years, with a possible 10-year extension.
- Oil concessions, the most significant innovation introduced by the new legislation. They can last up to 30 years, with a possible 10-year extension.
- Oil services contracts.
- Other forms of association provided for under Cuban law.
Under production-sharing agreements, investors recover their costs through an allocated share of the crude produced and divide the remainder with the state-owned partner.
Under the concession model—the most significant new feature of the decree—the concessionaire explores for and produces oil at its own expense and risk. The state transfers ownership of the hydrocarbons extracted to the concessionaire at the designated measurement point in exchange for concession fees, royalties and taxes.
Irenaldo Pérez Cardoso, deputy director of the Cuba-Petroleum Union (Cupet), said at the presentation that this arrangement could prove more attractive to certain investors. In his view, the new law is “much more comprehensive, much more precise” than the previous legislation.
The decree states that “oil and gas deposits, together with associated substances, located beneath the national territory, regardless of their physical state, are the socialist property of all the people and are governed by the principles of inalienability, imprescriptibility and immunity from seizure.”
Bidding Procedures
Concessions will be awarded through open tenders and, only in exceptional circumstances, through restricted tenders. The implementing regulations also allow interested parties to request a specific area. If no other bidder responds to the call for tenders, the area will be awarded to the applicant, provided all requirements are met.
Production-sharing agreements, by contrast, may be awarded either through competitive bidding or by direct negotiation.
Before entering into negotiations, all prospective bidders, whether Cuban or foreign, must obtain accreditation from the National Office of Mineral Resources (ONRM). Accreditation is divided into three categories based on water depth, measured vertically from the seabed to the surface: more than 300 meters, up to 300 meters, or onshore.
The ONRM has 45 days to issue the certificate, which is valid for three years. However, state-owned entities are not required to negotiate contracts, as doing so remains a matter of “discretionary authority.” Nor is the award of a concession guaranteed.
Any exploration or production license requires prior approval from the Council of State and formal authorization by the Council of Ministers. It may be denied on national security grounds, although the legislation does not specify the criteria to be applied.
The Financial Terms
For the first time, the implementing regulations publicly establish the sector’s tax and royalty framework.
For oil concessions, royalties are calculated on gross production:
| Area | Oil | Gas |
| Onshore and shallow waters (up to 300 m) | 12%–15% | 8% |
| Deepwater | 5%–8% | 4% |
Crude oil is valued against the West Texas Intermediate (WTI) benchmark, with adjustments for API gravity and sulfur content. An annual surface-area fee also applies. Onshore and in shallow waters, the fee is $50 per square kilometer during exploration and $500 during production. In deepwater areas, it falls to $10 and $100, respectively.
The fee is cut in half east of longitude 77°55′ west, roughly around the latitude of the city of Camagüey. The measure is intended to encourage investment in the eastern half of the country, which has been less extensively explored.
Royalties are also subject to adjustment mechanisms:
- High prices. If international prices exceed the average for the previous five years by more than 30%, the royalty rate may be increased by up to 10%.
- Low prices. If prices fall by the same proportion, a reduction of up to three percentage points may be granted.
- Production above targets. If output exceeds the contractual target by more than 20%, royalties may increase by up to five percentage points.
- Declining fields. If a field enters accelerated decline, royalties may be reduced by up to three percentage points to encourage secondary recovery.
- Domestic refining. Crude processed at Cuban refineries qualifies for a two-percentage-point royalty reduction.
Under production-sharing agreements, the share of gross production allocated to cost recovery may not exceed 65% for onshore and shallow-water projects or 75% for deepwater operations.
Existing contracts will retain their current terms until expiration. If extended, they must comply with the new limits.
The state retains the right of first refusal to purchase, at market prices, the volumes it needs to safeguard national energy security.
Domestic Private Businesses Enter the Sector, Subject to Conditions
Article 13 of the implementing regulations provides that Cuban MSMEs, private companies employing more than 100 workers and non-agricultural cooperatives may participate directly in exploration and production through concessions. They must also obtain MINEM’s endorsement and approval from the Council of Ministers.
According to Cubadebate, the opening extends across the entire value chain, including services, supplies and marketing. The regulations also explicitly mention self-employed workers in this area.
Pérez Cardoso clarified that private-sector participation may extend to refining, storage and fuel sales, but strategic assets will remain under state control. These include oil wells, major critical infrastructure, refineries and key storage facilities, such as the supertanker terminal in Matanzas.
Other facilities could be made available for negotiations with Cuban or foreign investors, under terms that will depend on the capital contributed.
The Cupet executive highlighted the possibility of several domestic private companies joining forces to undertake larger-scale projects. He acknowledged, however, that these arrangements still require supplementary regulations, particularly regarding contracts and partnerships between private businesses. He described the process as gradual, with potential pilot projects.
According to Pérez Cardoso, the industry is no longer the sector that Cupet once controlled almost entirely. Private operators now import fuel, transport it by truck and operate their own storage facilities. Certification procedures are being developed for these businesses but have yet to be finalized.
Transparency, Gas Flaring and Insurance
The legislation introduces commitments that are relatively unusual in a sector that has historically lacked transparency:
- Publication of concessions. The full text of each concession agreement will be published in the Official Gazette and on the ONRM website.
- Public tenders. The ONRM will maintain a public register of parties interested in each tender and publish questions and answers from clarification meetings.
- End to routine gas flaring. Venting and flaring gas during normal operations are prohibited, despite being common practices in Cuban oil fields. Existing operators have one year to submit a plan and three years to eliminate the practice or reduce it. In the event of a breakdown, they have 72 hours to resolve the problem before operations must be halted.
- Strict liability. In high-risk activities, operators are liable for damage without the need to prove fault; establishing a causal link is sufficient.
- Preference for domestic suppliers. Cuban goods and services companies will receive priority in procurement, as will domestic insurers in insurance policies and permanent residents in hiring for foreign-investment projects.
Oil Production Falls Short of Demand
Cuba has been searching for oil since the 19th century, but its modern oil industry emerged in response to an emergency. In 1989, the island consumed approximately 13 million metric tons of oil a year, almost all of it supplied by the Soviet Union. The collapse of the USSR cut off those supplies, forcing Cuba to turn to its own underground resources.
In the 1990s, Cuba opened exploration to foreign capital through risk-service and production-sharing agreements and eventually signed 16 contracts with European and Canadian companies. Between 1991 and 1999, the sector received approximately $600 million in foreign investment, according to figures cited by EFE.
The key player was Canada’s Sherritt International, which began oil operations in 1992. Its initial work focused on rehabilitating around 100 wells in the Varadero, Boca de Jaruco, Periféricos and Pina fields.
A decisive technological shift followed: horizontal and highly deviated wells drilled from onshore locations to reach offshore deposits beneath the so-called Northern Oil Belt, stretching between Havana and Varadero. Other companies, including Canada’s Pebercan, joined operations in neighboring fields.
The result was a decade of sustained growth, with production eventually reaching its peak in 2003. Output rose for ten consecutive years before hitting 3.68 million metric tons of crude that year, according to Cuba’s National Office of Statistics and Information (ONEI).
Since then, production has trended downward. In 2023, ONEI reported output of 2.31 million metric tons, a decline of 37%, according to an analysis by Jorge Piñón, a researcher at the University of Texas Energy Institute.
Sherritt itself, which was producing approximately 20,000 barrels per day across its three fields in 2013, saw output plunge from 2017 onward, when its Varadero Oeste contract expired.
Cuba currently produces around 40,000 barrels per day, covering approximately one-third of its consumption.
The Gulf’s False Promise
For years, Cuba’s greatest hope lay in the deep waters of its Exclusive Economic Zone in the Gulf of Mexico: an area of 112,000 square kilometers divided into 59 blocks.
The U.S. Geological Survey estimated that these waters could contain between five billion and nine billion barrels of crude oil. Cupet once put the figure as high as 20 billion barrels.
The test came in 2012—and failed. That year, the Scarabeo 9 drilling rig, built with less than 10% U.S. components to circumvent the embargo, drilled three wells:
- Repsol, in May, northwest of Havana.
- Petronas and Gazprom Neft, in July, off the coast of Pinar del Río.
- PDVSA, in October, at the Cabo de San Antonio 1X well.
None discovered oil in commercially viable quantities. Repsol relinquished its blocks, and the rig left Cuba that November. A subsequent attempt by Russia’s Zarubezhneft in shallow waters off Cayo Coco also proved unsuccessful.
Piñón later qualified the findings, explaining that the wells were not necessarily dry: oil was present, but extracting it was not commercially viable given the technology and prices at the time. Since then, Cuba’s portion of the Gulf has remained on hold.
Melbana: The Promise That Never Materialized
Onshore, the most prominent bet of the past decade was Australia’s Melbana Energy, formerly MEO Australia. In 2015, it signed a production-sharing agreement with Cupet for Block 9, covering approximately 2,344 square kilometers along the northern coast between Havana and Varadero.
- 2021. The Alameda-1 exploratory well, near Martí in Matanzas province, encountered oil-saturated zones.
- 2023. The Alameda-2 well reached a peak flow rate of 1,903 barrels per day. Its crude, with an API gravity of around 18 degrees, was lighter and contained less sulfur than the oil typically found in the belt. Piñón argued that crude of this quality would be more valuable when refined into gasoline and diesel than when burned in a thermoelectric power plant.
- 2024. Melbana announced a prospect estimated to contain 90 million barrels. By then, Angola’s Sonangol had joined the project with a 70% stake in exchange for financing most of the drilling.
In early 2025, expectations were optimistic. By the end of that year, however, the Amistad-2 well had been described as “disappointing,” and Alameda-2 had been shut down. In April 2026, Sonangol lost its stake after failing to meet $23.5 million in funding commitments.
The final blow came on June 18, 2026, from Washington, a week after the U.S. State Department added Cupet to its list of sanctioned entities. Melbana suspended all financial, technical and administrative involvement in Block 9.
What Is Cuba Doing With Its Crude Today?
Oil from the Northern Belt is predominantly heavy or extra-heavy, with high sulfur and metal content. A Cupet executive has explained that this crude is suitable only for generating electricity and producing cement, lubricants and asphalt.
In practice, much of it ends up in the boilers of thermoelectric power plants. Around 85% of the electricity generated by these plants depends on domestic crude, at considerable cost: its sulfur content corrodes boilers and economizers, forcing frequent shutdowns and cleaning operations.
In 2026, with crude imports cut off by the oil blockade and distributed generation almost paralyzed by shortages of diesel and fuel oil, aging plants such as the Antonio Guiteras thermoelectric power station—which burns domestic crude—have become the electricity system’s mainstay.
Associated gas is used at Energas facilities in Boca de Jaruco and Puerto Escondido. Energas is a joint venture from which Sherritt also withdrew this year.
The Obstacles
During the presentation of the decree-law, Pérez Cardoso himself warned that the new legislation would not eliminate every obstacle to attracting capital. He cited the geopolitical environment and restrictions associated with the U.S. embargo, which continue to limit investment opportunities.
Since January, Washington’s oil blockade has cut off crude imports. Both companies that shaped the history of Cuba’s oil industry over the past 30 years—Sherritt and Melbana—have scaled back their involvement in the same year.
The decree-law does not mention Cupet by name. Instead, it refers to a “national oil entity,” to be designated by the Council of Ministers, which will operate across the entire value chain.
