Shell Plans Venezuela Return With $15B Dragon Gas Bet Over 30 Years

A 10-mile undersea pipeline between Venezuela and Trinidad and Tobago has become a focal point in a fast-changing struggle over who will profit from one of the world’s largest untapped gas troves. The Dragon gas field, long frozen by sanctions and political risk, is now being recast as a test case for how U.S. power, Venezuelan resources and global energy markets intersect.

Massive gas reserves and a narrow route to market

The Dragon field holds an estimated 120 billion cubic meters of natural gas in Venezuelan waters close to Trinidad, roughly three times the United Kingdom’s annual consumption. Proven reserves of about 4.2 trillion cubic feet make it one of Venezuela’s largest known gas deposits.

In October 2025, Shell obtained authorization from the U.S. Treasury to develop Dragon under a phased licensing scheme. For the company, the appeal is clear: a relatively short, 10-mile pipeline could move gas directly to its existing facilities at Trinidad’s Atlantic LNG terminal and nearby petrochemical plants. Unlike many oil projects in Venezuela that would require extensive repairs to decaying infrastructure, the Dragon-to-Trinidad route offers a defined scope, a known destination and an established export platform.

Yet that commercial logic is overshadowed by volatile politics. Washington’s sanctions architecture and license conditions effectively determine what can be developed, when and by whom.

Political upheaval reshapes control of Venezuelan energy

The energy outlook shifted dramatically in early January 2026, when U.S. forces removed Venezuelan President Nicolás Maduro. Soon after, President Donald Trump said Washington would manage the country’s oil sales “indefinitely,” signaling a move from punitive sanctions to direct oversight of the sector.

U.S. officials describe a strategy centered on controlling production, exports and income flows as leverage over Venezuela’s political and economic future. Energy Secretary Chris Wright has characterized the approach as managing “the flow of oil, the sales of oil, and the flow of the cash.” Under new rules, Caracas is required to spend oil earnings on “ONLY American Made Products,” tying any recovery to U.S. supply chains.

The change has turned Venezuela from an isolated producer into what analysts call a system of “permissioned petroleum,” where licenses issued in Washington matter more than the quality of the resource base or the technical capabilities of operators on the ground.

American firms move first, Europeans wait in line

Chevron is the dominant foreign operator in Venezuela today, producing an estimated 100,000 to 150,000 barrels per day, or roughly 20 to 30 percent of total output. Backed by U.S. policy, the company is expected to expand quickly. Wright has said Chevron’s production will grow “quickly,” underscoring the administration’s preference for American-led development.

Industry analysts forecast that U.S. majors will secure the prime opportunities. Ashley Kelty of investment bank Panmure Liberum has argued that the main beneficiaries will be large U.S. firms, “especially Chevron,” with European companies such as Shell and BP likely to be brought in later as partners to share risk. That implies a secondary role for European operators, who may have to accept minority positions in joint ventures rather than lead complex projects.

Shell, for its part, has kept a low profile. The company has declined to discuss its Venezuelan strategy publicly, reflecting wider uncertainty across the industry. With licenses subject to executive decisions in Washington and political direction in Caracas still in flux, companies face a setting where diplomatic relationships and regulatory shifts can outweigh engineering plans.

Fragile sector, huge capital needs and deep investor caution

Venezuela holds the world’s largest proven oil reserves, at about 303 billion barrels, but ranks around 20th in actual production. Current output, roughly 800,000 to 950,000 barrels per day, is far below historical peaks. Years of underinvestment, corruption, mismanagement and sanctions have left state oil company PDVSA and associated infrastructure in severe decline.

Independent estimates highlight the scale of investment needed for a real turnaround. Rystad Energy calculates that restoring production to levels last seen in the 1990s would require around $183 billion over more than a decade. Another assessment suggests about $110 billion is needed just to raise production from 1 million to 2 million barrels per day by 2030. These figures explain why many firms remain cautious despite the potential rewards.

Investor concerns are not limited to current politics. Venezuela’s history of expropriations continues to weigh heavily. ExxonMobil and ConocoPhillips both exited in 2007 after their assets were seized in nationalization campaigns. That legacy has left lingering doubts about contract stability and property rights, even with a new political order.

Sanctions relief could deliver short-term gains. Analysts at Kpler estimate Venezuela might lift output by 100,000 to 150,000 barrels per day within three months, bringing production close to 1 million barrels per day. By late 2026, capacity could reach 1.1 to 1.2 million barrels per day, assuming modest new investment. But achieving more than 2 million barrels per day would require sweeping reform at PDVSA and new upstream agreements with foreign operators, alongside large capital inflows and governance changes.

Licenses, price risks and the Dragon field’s uncertain future

For projects like Dragon, regulatory risk is as important as geology. The U.S. Treasury framed Shell’s authorization in three stages, each with increasing requirements. The first phase, running through April 2026, allows Trinidad and Shell to negotiate with Venezuela and state firm PDVSA. Later phases will demand further clearances, leaving timelines and eventual project scope uncertain.

Policy reversals have already demonstrated how fragile such approvals can be. In April 2025, the Trump administration revoked licenses tied to Dragon and a similar BP-linked project, only to grant new authorizations later. BP, which holds interests via the Manakin-Cocuina exploration license issued in 2024, has been pressing for its permits to be restored, underscoring how competitive and unpredictable access to Venezuela’s gas and oil assets has become.

Any large expansion of Venezuelan production would also reverberate in global markets. Greg Newman, chief executive of oil trading firm Onyx Capital, has warned that OPEC’s ability to balance supply and demand is already under strain. Additional Venezuelan barrels—potentially one to two million per day over time—could add to an existing surplus and further weaken the producer group’s influence.

Oil prices fell by about 18 percent in 2025, the sharpest annual decline since 2020. In response, OPEC+ members agreed to pause output increases in early 2026 to support prices. A renewed Venezuelan surge backed by U.S. policy could complicate those efforts, pushing prices lower and altering trade flows.

For Shell, Dragon offers a manageable gas project tied to existing infrastructure, but its fate will depend on forces beyond engineering or geology. The company must navigate shifting U.S. regulations, an evolving political environment in Caracas, competition from American majors and uncertain market conditions. As Venezuela reopens under tight external control, the country is emerging as a place where access rights, not just resource size, determine who benefits from its vast oil and gas endowment.