Why BP’s Loran Phase 2 Licence Is Not a Bankable Project Yet

The BP-led consortium was awarded an exploration and production licence for Loran Phase 2 in the Plataforma Deltana area in mid-August 2026. It is a legitimate milestone: a named operator, defined working interests, and formal Venezuelan government approval for one of the Caribbean’s largest undeveloped offshore gas resources.

It is also, on its own, not much more than that. A licence is a legal instrument. It is not a final investment decision (FID), not a signed offtake contract, and not a molecule of gas reaching a buyer. The distance between the two is where most Venezuelan offshore gas projects have stalled, and where the real analytical work begins.

What separates a well-informed assessment of this project from a headline-driven one is understanding the four conditions that must be met, in sequence, before Loran Phase 2 becomes bankable. Here is the framework for evaluating each of them, what the evidence actually supports, and where the binding constraints sit today.

Why a licence is only the beginning for Venezuelan offshore gas

The licence awarded in August 2026 confirms international oil company (IOC) participation in the Loran resource. The consortium structure is straightforward:

• BP as operator
• XRG (ADNOC’s international energy investment vehicle) holding an equal working interest
• UCC Oil and Gas Holding LLC holding an equal working interest

That lineup signals that capable, well-capitalised parties are willing to engage with Venezuelan offshore gas, at least on paper. The question is what happens after the paper is signed.

The Dragon precedent

The most instructive comparison is the Dragon field, a Venezuelan offshore gas project designed to pipe gas to Trinidad and Tobago to supply the Atlantic LNG facility. Dragon operates under a bespoke authorisation from the U.S. Office of Foreign Assets Control (OFAC), a tailored legal structure that allows Shell to develop the field within the constraints of U.S. sanctions on Venezuela. Despite that defined legal path, active IOC involvement, and a clear monetisation route, Dragon had still not reached FID by mid-2026.

Shell’s offshore gas negotiations for additional Venezuelan acreage in 2026 provide a parallel data point on how IOCs are calibrating their engagement with Venezuela: active enough to preserve optionality, cautious enough that none have accelerated to FID even where a bespoke OFAC authorisation already exists.

That timeline is the baseline any investor should apply to Loran Phase 2, which sits further back in the development sequence than Dragon. Venezuela’s incremental gas trade moves in early 2026, including its first dedicated LPG export agreement in January and a first U.S.-bound cargo in February, signal some opening of commercial channels. But LPG exports and LNG development operate at entirely different scales of complexity and capital.

Sanctions are the gating variable, and each project needs its own key

U.S. sanctions on Venezuela do not function as a single on-off switch. They create a compliance environment in which every participant in a project’s commercial chain, the sponsoring IOC, financing banks, engineering procurement and construction (EPC) contractors, and technology providers, must independently satisfy their own regulatory obligations. A licence held by the sponsor does not automatically clear the path for every counterparty downstream.

OFAC sanctions adjustments in 2026 have shifted the broad regulatory backdrop for Venezuelan hydrocarbon projects, but project-specific licensing remains a separate legal requirement; what applies to oil sector participants does not automatically extend to offshore gas development consortia seeking to engage banks and EPC contractors.

The Dragon field illustrates how this works in practice. Shell’s ability to develop Dragon rests on a bespoke OFAC authorisation, a project-specific licence that applies to that field, that operator, and that commercial structure. Loran Phase 2 cannot inherit Dragon’s approval. It would need its own equivalent, negotiated and granted through its own process.

That leaves two structural pathways to sanctions clearance:

1. A broad easing or restructuring of Venezuela-related sanctions that removes or substantially relaxes the compliance burden across all projects and participants.
2. A project-specific licensing structure, similar to Dragon’s OFAC authorisation, that satisfies every commercial counterparty in the Loran Phase 2 chain individually.

Neither pathway has a guaranteed timeline. Neither is visible on today’s evidence.

Without one of those two pathways, the licence risks remaining a paper asset: a legal right to develop gas that cannot be converted into funded engineering, procurement, and construction.

For investors in BP, XRG, or any downstream counterparty, this means a positive political signal from Washington is necessary but not sufficient. The project still requires tailored legal architecture that every commercial participant can stand behind, and that architecture does not yet exist.

Getting the gas to market: Atlantic LNG’s real capacity versus its headline number

Atlantic LNG, located in Trinidad and Tobago, is Latin America’s largest LNG export facility and the most obvious monetisation route for Loran Phase 2 gas. It is proximate, operational, and already positioned as the anchor for the Dragon field’s commercial strategy. On paper, it looks like a straightforward plug-in.

The reality is more complicated. Atlantic LNG’s nameplate capacity is approximately 14.8-15 million tonnes per annum (mtpa) across four trains. But Train 1 has been permanently decommissioned, removing roughly 3 mtpa from that figure and leaving effective operational capacity at approximately 11.8 mtpa. In early 2026, utilisation was running at approximately 65% of that effective capacity. Train 4, the facility’s largest single unit at approximately 5.2 mtpa, has been subject to major maintenance periods that further constrain what is actually available to new feedgas suppliers.

That 65% utilisation figure sounds like available headroom. It is not, at least not in a commercially accessible sense. Existing commercial arrangements and maintenance schedules govern who can access that capacity and when. Loran’s path through Atlantic LNG would require three specific things:

• New cross-border pipeline infrastructure connecting Venezuelan waters to Trinidad, conceptually similar to the Dragon field pipeline
• A bilateral agreement between Venezuela and Trinidad and Tobago governing volumes, tariffs, and sovereignty questions
• A tolling deal negotiated with Atlantic LNG’s existing shareholders, balancing economics for current participants and the new gas supplier

Each of those carries its own negotiating complexity. Dragon’s experience has already demonstrated how protracted bilateral gas agreements between the two countries can be.

Caribbean gas development timelines are consistently longer than initial projections suggest, and the bilateral negotiating dynamics between Venezuela and Trinidad and Tobago over volumes, tariffs, and sovereignty questions have proven capable of stalling projects at the commercial agreement stage even when the upstream resource and technical pathway are well-defined.

The alternative is building dedicated Venezuelan LNG capacity, a route that offers greater commercial control but at substantially higher cost. Venezuela currently has no LNG liquefaction terminal and has never exported LNG at commercial scale. A greenfield facility would typically require $3-6 billion in capital expenditure and 5-8 years of construction before first LNG, assuming efficient execution. Floating LNG (FLNG) reduces some onshore complexity but carries its own financing challenges in a sanctions-constrained environment.

Choosing the wrong monetisation assumption inflates project economics and shortens the perceived timeline to first LNG. Neither route is simple, and neither is guaranteed.

The LNG market Loran Phase 2 would enter is not the market that made the project attractive

Even if sanctions clear and a monetisation route is locked in, Loran Phase 2 faces a commercial environment that has shifted materially since Venezuelan offshore gas re-entered the conversation during the tight LNG markets of 2022-2023.

The International Energy Agency (IEA) characterised 2026 as a period of significant LNG supply growth globally, driven by new projects across multiple producing nations.

The scale of that growth is substantial. Global operational liquefaction capacity stood at approximately 524.5-525 mtpa at the end of 2025, according to the IGU World LNG Report. The Oxford Institute for Energy Studies (OIES) estimates that available LNG export capacity will grow by approximately 53 billion cubic metres (bcm) year-on-year in 2026 alone, and by roughly 113 bcm across 2025-2027. U.S. LNG capacity illustrates the concentration of this expansion: operating export capacity at the end of 2025 was approximately 18 billion cubic feet per day (Bcf/d), or roughly 136.5 mtpa, with another 15 Bcf/d (approximately 112 mtpa) under construction and scheduled for commissioning between mid-2026 and 2031.

This connects directly to the pre-FID commercial problem. Lenders require long-term sales and purchase agreements (SPAs), typically with tenors of 15-20 years, signed with creditworthy buyers before committing capital. Those buyers now have multiple alternative supply options already under construction, from projects that carry no sanctions exposure, no cross-border sovereignty questions, and clear regulatory frameworks.

The 113 bcm of capacity additions across 2025-2027 means buyers hold negotiating leverage they did not have during the LNG tightness of 2022-2023, which is precisely when Venezuelan offshore gas became commercially attractive again. That leverage directly weakens Loran Phase 2’s ability to command the long-term offtake pricing it needs to satisfy project financiers. Speed to FID is simultaneously more valuable and more difficult.

The LNG supply-demand imbalance building across 2025-2026 is not a temporary dislocation; structural additions from U.S., Qatar, and East African projects are extending the buyer’s market well into the decade, compressing the long-term contract pricing that project financiers for late-mover developments like Loran Phase 2 would require to commit capital.

What has to go right, in sequence, before Loran Phase 2 becomes a bankable project

The conditions for FID are not a checklist that gets ticked off in any order. They form a sequential dependency, where failure at any one point stops the chain:

1. Sanctions clarity and licensing: A regulatory framework, either broad sanctions easing or a project-specific OFAC licence, must be in place that gives IOCs, banks, and service firms confidence in long-term participation. This is the first gate, and it has not been cleared.
2. A defined monetisation route: The project must select and lock in a primary route (Atlantic LNG tolling or dedicated LNG) along with the required cross-border agreements, infrastructure, and commercial structures.
3. Bankable offtake: Pre-FID SPAs with creditworthy buyers must be secured, despite competition from a large slate of better-de-risked new LNG supply.
4. Resource and technical de-risking: Proven and probable reserves must be certified at a level sufficient to support long-term plateau production, and the subsea and surface engineering must be demonstrated as technically and financially executable.
5. Domestic governance and execution capacity: Venezuela must demonstrate consistent policy toward foreign operators and gas exports, including stable fiscal terms and a reliable framework for repatriation of capital and profits.

The Dragon project’s slow progress even under a specific OFAC authorisation is the most relevant real-world data point for how long this sequence can take. Loran Phase 2 has not yet cleared the first gate.

The sequential structure matters because investors cannot treat partial progress on one condition as proportional progress toward FID. The chain breaks at the weakest link, and right now, that link is sanctions clarity.

Loran Phase 2 is best understood as a leveraged call on future political and market normalisation in Venezuela and the wider LNG market, potentially rewarding if conditions align but not yet bankable on today’s evidence.

Loran Phase 2 as an option, not a forecast

The four risk layers, sanctions, monetisation pathway, market competition, and execution sequencing, converge on a single characterisation: Loran Phase 2 has a real resource, a real consortium, and real constraints, with no visible near-term resolution of the binding factors.

The consortium of BP, XRG/ADNOC, and UCC Oil and Gas Holding LLC confirms that capable parties are engaged. That is necessary but not sufficient. Capable parties have been engaged with Venezuelan offshore gas before, and the conversion rate from engagement to producing field remains low.

The specific signals that would constitute genuine progress are identifiable:

• A project-specific OFAC licence for Loran Phase 2, or a broad restructuring of Venezuela-related sanctions
• A signed bilateral gas agreement between Venezuela and Trinidad and Tobago
• Pre-FID offtake commitments from creditworthy LNG buyers
• FID on the Dragon project, which would serve as proof-of-concept for the Venezuelan-to-Trinidad gas route

Until those signals materialise, the project sits in the option-value category. That is not dismissive of the upside; it is an accurate reading of where the evidence places it. Monitoring those four variables is what separates an investor tracking this project intelligently from one reacting to announcements.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. These statements are speculative and subject to change based on market developments and company performance.