BP returns to Venezuela with Loran Phase 2 gas project
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BP is returning to Venezuela’s upstream gas sector through a partnership with two Gulf investors, adding momentum to the country’s efforts to bring foreign capital back into its energy industry.
The UK major has agreed to operate Loran Phase 2 alongside Abu Dhabi-based XRG and Qatar-based UCC Oil and Gas. Each company will hold an equal interest in the project, which contains more than 4 trillion cubic feet of gas resources.
The deal gives BP a position in one of the Caribbean’s largest undeveloped offshore gas areas. It also gives XRG and UCC an entry into Venezuela as both companies expand their international energy portfolios.
For Venezuela, the importance of the agreement extends beyond the size of the resource. The country has held some of the world’s largest hydrocarbon reserves for decades, but political uncertainty, sanctions and years of underinvestment have limited production and discouraged foreign companies.
Loran could offer a different route because of its location.
The field forms part of the wider Loran-Manatee gas accumulation, which crosses the maritime border between Venezuela and Trinidad and Tobago. Estimates put recoverable gas across the wider structure at about 10 trillion cubic feet.
That makes the resource significant, but the nearby infrastructure could be just as important to its commercial prospects.
Loran’s value comes from the infrastructure around it
Large offshore gas discoveries can take years to develop, especially when they require new processing plants, pipelines and export terminals.
Loran sits close to a gas market where much of that infrastructure already exists.
Trinidad and Tobago has spent decades building a gas-based economy around LNG exports, petrochemicals and industrial demand. Its Atlantic LNG complex provides an established route to international buyers, while nearby industrial plants consume large volumes of natural gas.
That could give Venezuelan gas a commercial advantage.
Instead of developing a separate export system, producers may be able to connect future production with infrastructure in Trinidad and Tobago. Any such plan would still depend on commercial agreements, government approvals and sanctions rules.
The regional link is already becoming more important.
Shell is developing the Manatee field on the Trinidad and Tobago side of the same geological structure. First gas is expected in 2027, with government estimates putting peak production at about 604 million standard cubic feet per day.
That supply matters because Trinidad and Tobago has faced domestic gas shortages that have affected industrial output, government revenue and foreign exchange earnings.
Additional regional gas could support Trinidad’s existing energy industry while giving Venezuelan resources a shorter route to international markets.
For BP, the infrastructure link is especially relevant. The company owns a major stake in Atlantic LNG and has a long operating history in Trinidad and Tobago.
The commercial case for Loran may therefore depend less on finding new demand and more on connecting new supply with an energy system that already operates nearby.
Gulf investors are changing Venezuela’s investor base
The ownership structure also points to a wider change in energy investment.
XRG and UCC are both entering Venezuela through Loran Phase 2. Their involvement suggests the country’s energy reopening could attract a broader group of investors than the Western oil majors that historically led large international projects.
XRG, backed by Abu Dhabi energy group ADNOC, has been expanding its international gas and LNG interests. Loran gives the company exposure to another large gas resource as it builds its international portfolio.
UCC’s participation adds another source of Gulf capital.
For BP, the partnership combines its operating experience with investors seeking a larger position in international gas.
This type of consortium could become more common in countries where resource quality is high but political and financial risks remain difficult to manage.
Shared ownership reduces the exposure carried by one company. It can also combine operating knowledge, financing capacity and established government relationships.
Venezuela has strong reasons to encourage that approach.
Years of falling investment have left the country needing outside capital, technology and project management experience. Companies considering large developments, however, need confidence that contracts, licenses and operating conditions will remain stable.
The Loran partnership does not remove those concerns. It does show that investors are again willing to consider Venezuelan projects when the resource, location and ownership structure support the business case.
Political risk will decide whether Loran reaches production
The main question is whether renewed investor interest can survive future changes in policy.
Venezuela’s energy industry has repeatedly been affected by sanctions, political disputes and changes in relations with the US. Those factors can affect projects even when the geology and economics remain attractive.
BP has already faced this issue elsewhere in the region.
The company and Trinidad and Tobago’s National Gas Company previously received US authorization to pursue the Manakin-Cocuina cross-border gas development, which is estimated to contain about 1 trillion cubic feet of gas. Changes in US sanctions policy later affected the project’s regulatory path.
That history shows the gap between identifying a commercial resource and turning it into sustained production.
Loran Phase 2 will still require regulatory approvals, sanctions compliance, detailed development planning and major capital commitments before gas begins to flow.
Those steps can take years.
For investors, the issue is whether policy conditions will remain stable for long enough to support projects that may require billions of dollars and operate for decades.
That makes Loran an important test of Venezuela’s wider energy reopening.
The resource base is large. Nearby infrastructure could reduce some development costs. BP brings regional operating experience, while XRG and UCC provide additional capital and international investment capacity.
Together, those factors support the project’s commercial case.
Yet Venezuela’s offshore gas sector will attract sustained investment only if companies believe the rules governing their investments will remain predictable.
If Loran moves from agreement to development and production, it could offer a model for connecting Venezuelan gas with Caribbean infrastructure and global LNG markets.
If political or regulatory conditions change again, the project will underline a problem that has held back Venezuelan energy investment for years: large resources cannot create lasting value without enough certainty to develop them.
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