Who ends up with the gas?

Atlantic LNG, the company in Trinidad, has a nominal installed capacity of 15 million tonnes per year. Their problem hasn't been a lack of LNG infrastructure, but a lack of gas to run it fully. That shortage even forced the shutdown of one of their four trains.

And now new production is organizing itself around all of that infrastructure. Shell took FID control over Manatee, the Trinidad portion of the Loran-Manatee field, with production starting in 2027 and an estimated peak of around 604 MMscf/d. The design includes eight wells and a 110-kilometer pipeline to the Beachfield processing plant, from where gas can flow to Atlantic LNG or into Trinidad's domestic market.

On Trinidad's side, we're not talking about a future need. We're talking about a pipeline that already exists. The processing already exists. The LNG already exists. Even the petrochemical industry already exists. They have buyers and companies with positions at multiple points along that chain.

Then add Cocuina-Manakin. BP and Trinidad's state company NGC agreed to commercialize 70% of future production toward Atlantic LNG, and the remaining 30% toward petrochemicals. That project still needs to reach a final investment decision, which according to Reuters could happen before the end of 2026.

In other words: the field isn't producing commercially yet, and a large part of where that molecule is going is already being decided. To me, that's the key point. The competition for the gas doesn't start when the gas comes out of the ground. It starts years earlier.

It starts when someone decides who holds the equity. When the pipeline gets designed. When the offtake gets signed. When the buyer gets defined. When the financing comes together. And finally, when the FID arrives.

By the time the molecule physically exists, much of its future is already locked in contractually.

Physical need is not the same as commercial demand

That has real implications for Venezuela. Because Venezuela also genuinely needs that gas. Not just for residential use or to fix the power grid. It needs it to restore thermal capacity, sustain oil production, feed compression, processing, refining, water systems, petrochemicals, and the ports that could eventually anchor new industrial activity.

An oil and gas recovery will probably increase electricity demand before it relieves it. But physical need is not the same as commercial demand. Venezuela may have a far greater need for that molecule than Trinidad, and still be a less attractive buyer.

Because Trinidad can say: here's the pipeline, here's the plant, here's the buyer, here's Atlantic LNG, here's even the contract. And here's how we get paid.

Venezuela still has to solve most of that sequence.

This doesn't mean exporting the gas is wrong.

The point is that monetizing offshore resources through infrastructure that already exists a few kilometers away can be one of the fastest ways to make certain Venezuelan projects investable, without waiting for the whole country to be up and running. And honestly, it would be absurd to ignore that advantage.

The real question is: how do you capture that opportunity without committing all the gas that might be needed tomorrow to rebuild Venezuela's own capacity?

The core issue is that a policy of “let's reserve a percentage for Venezuela” isn't enough on its own. You can reserve gas in a contract and still have no plant available to consume it. You can build a plant and still have no pipeline to get the molecule there. You can have both, and still have no buyer that can pay reliably.

In infrastructure, all of those things are part of the same system.

Perla is the warning

Venezuela already has a pretty uncomfortable precedent for what happens when one part works and the other doesn't.

The Perla project produces offshore gas for the domestic market. Eni and Repsol operate it, and PDVSA buys part of that output. The gas is used primarily for power generation. In principle, it sounds exactly like the model Venezuela needs.

But in that project, the payment side broke down. By the end of 2025, PDVSA owed around $3.3 billion to Eni, including approximately one billion in accrued interest. Financial and sanctions restrictions disrupted, for significant stretches, the mechanism through which Eni could receive crude as payment for the gas. Now in 2026, that payment-in-kind arrangement is operating again under the new framework provided by the United States.

For me, Perla is not an argument against using gas for electricity in Venezuela. It's the opposite. It's a warning about how not to do it. Saying the molecule has more social value inside the country isn't enough. The producer ultimately needs to get paid.

Contracts have to survive political changes. The payment mechanism has to work. Volumes have to be auditable. Every obligation has to be verifiable.

And if the arrangement depends on U.S. authorizations, that legal rail has to be treated as part of the project's infrastructure, not as a footnote. OFAC today authorizes certain oil and gas operations for companies like BP, Shell, Eni and Repsol, but under specific conditions around contracts, payments and transactions with the interim government and PDVSA.

Two bankable destinations for the same resource

That changes the conversation. The question isn't just: do we export the gas or use it in Venezuela? The real question is: how do we build two bankable destinations for the same new resource base?

One toward Trinidad, LNG and international markets. Another toward generation, industry and strategic assets inside Venezuela. And make both of them able to pay.

Because if Venezuela waits until Loran, Cocuina-Manakin, Dragon and other projects are producing to then decide how much gas it needs domestically, it will probably be too late.

The moment to create Venezuelan pull is before that. That can mean reserving domestic volumes inside the original commercial design. But it also means building the physical destination for those volumes. A power plant. A petrochemical complex. An industrial corridor. A power system built around a port. An oil cluster that can operate partially isolated from the national grid.

And alongside that asset, there needs to be a credible gas contract with an auditable payment mechanism.

What will probably happen is the opposite of the concern: Trinidad may actually be one of the reasons part of Venezuela's eastern gas finally gets developed at all. That's an advantage. But it also creates a new responsibility. Venezuela can't assume that because it has enormous gas resources, that gas will be available whenever the country decides it needs it. Geology is not the same as availability. And production doesn't mean it's accessible either.

A molecule can exist beneath Venezuelan waters and, commercially, already belong to a chain that ends in Point Fortin years before it ever reaches the surface. That's why the Cocuina-Manakin case matters so much to me. Not because of the specific 70/30 split. But because it shows where that decision actually happens.

If Venezuela is going to rebuild from the nodes outward, those nodes need more than turbines and pipelines. They need to compete for energy within the commercial architecture that's being built right now. And that may be one of the defining issues of the next several years. In the end, it comes down to who builds first a physical, contractual and financial reason for the molecule to go their way.