Who is XRG and what it came to Venezuela for

On August 13, bp announced that the Government of Venezuela had awarded it the exploration and production license for Phase 2 of the Loran field, in the Plataforma Deltana. bp Exploration Caribbean will operate the development with two partners that hold the same stake, 33.3% each: XRG, ADNOC's international energy investment company, and UCC Oil and Gas Holding, a subsidiary of Qatar's UCC Holding. XRG receives its share through an assignment from PDVSA Gas, subject to regulatory approvals and compliance with applicable international sanctions.

It is worth pausing on what the phases mean, because they are not chronological stages of a single development. Loran contains seven reservoirs, six of them cross-border with Trinidad and Tobago. The division into phases splits that complex between two distinct operating groups. Shell received the Phase 1 license in June; bp has led Phase 2 since August, with up to 4 trillion cubic feet of recoverable gas within a field whose total resource is estimated at 7.3 Tcf. Both phases would advance in parallel. The arrangement divides execution between two operators with long experience in the basin and adds, in the second phase, two partners that contribute capital and construction capacity.

The field was discovered in 1983, with the Loran 1X well drilled by Lagoven. In February 2003, the then Ministry of Energy and Mines granted the license for Block 2 of the Plataforma Deltana to PDVSA Gas and Chevron, which drilled Loran 2X, 3X and 4X between 2004 and 2005. Between 2007 and 2017, the Framework Treaty on Field Unification, the Declaration of Commerciality, the Unification Agreement and the Conceptual Development Plan for the Loran-Manatee Unit were signed. After that, 23 years without development. Chevron ceded its position this year in an asset swap that strengthened its presence in the Orinoco Belt, and that opened the door that Shell, bp, XRG and UCC have just walked through.

Loran is the Venezuelan portion of the Loran-Manatí field, which crosses the maritime boundary with Trinidad and Tobago. Independent estimates attribute about 7.3 Tcf to the Venezuelan side and 2.7 Tcf to the Trinidadian side, roughly 10 Tcf combined. The Plataforma Deltana lies 120 kilometers southwest of Trinidad and 90 kilometers northeast of Delta Amacuro, closer to other parties' infrastructure than to its own. That geography explains almost everything that follows. ADNOC created XRG in November 2024 with an enterprise value above $80 billion and a mandate to more than double its asset value within ten years. The Emirati state oil company owns all of the capital, but the company has its own board and mandate, which allows it to move as an investor rather than as a state producer. The name abbreviates "exergy," the maximum useful work that can be extracted from a system. It is organized into three platforms: international gas, global chemicals and energy solutions. Some third-party estimates place it today above $150 billion, a figure that ADNOC has not confirmed in its statements.

Its gas portfolio explains the interest in Loran. XRG holds positions in Rio Grande LNG in the United States, the Argentina LNG project, Arcius Energy in Egypt, the Absheron field in Azerbaijan, the Southern Gas Corridor, Block 1 offshore Turkmenistan and Area 4 in Mozambique, the concession where Coral Sul FLNG operates. It is assembling an integrated gas and LNG platform spanning supply, liquefaction and marketing. With Rio Grande, Argentina LNG and now Loran, it is accumulating positions across the Atlantic Basin, which is what a marketer needs to run a trading book and not merely a set of assets.

Loran matters because of what exists in Point Fortin. Atlantic LNG, Latin America's largest liquefaction plant, cut its nominal capacity from 15.5 to about 12 million tonnes per year and loaded fewer than 9 million in 2025, according to LSEG data. Its Train 1 has been placed into decommissioning for lack of gas. There is built and paid-for capacity there working far below its design, a few miles from an undeveloped reservoir. The scheme described for Loran-Manatí involves drilling subsea wells on the Venezuelan side and connecting them by tie-back to Shell's Hibiscus platform in Trinidad. The pipeline capacity has been raised to 1 billion cubic feet per day. For whoever structures the financing, that removes from the budget the most expensive component of an LNG project, the liquefaction train, and shortens the time between disbursement and first cash flow. In project finance, that timeline usually weighs on returns more than the size of the reservoir. The other reason is regulatory, and it is the one a Venezuelan reader should examine most carefully. The reform of the Organic Law on Hydrocarbons was published in Official Gazette No. 6,978 Extraordinary on January 29, 2026, and was regulated in July through Decree No. 5,381. During the year, OFAC issued and amended a sequence of general licenses covering oil, gas, petrochemicals, mining and telecommunications. The US Treasury did not lift the sanctions regime; it adjusted it in stages, with narrowly interpreted permits and renewable validity. LEĜA Abogados described the result as a managed opening, sustained by contingent contracts and high compliance standards. That is the ground on which Loran Phase 2 was signed, and XRG itself made its participation conditional on it.

It is therefore worth asking what Venezuela gains, because the answer is not in bp's statement but in the text of that law. The state is entitled to a stake of up to 30% as royalty on volumes extracted and not reinjected. Added to this are the Integrated Hydrocarbons Tax, at a rate of up to 15% of gross revenue, and income tax. The same law exempts the Tax on Large Fortunes, contributions to LOCTI, sports, anti-drug efforts and pension protection, along with state and municipal taxes, and excludes the sector from the Public Procurement Law.

There is a benefit that does not appear in the fiscal ledger and that may weigh more for the real economy. The official plan calls for allocating gas first to domestic demand and only later opening production to Caribbean markets, which would address the gas shortage that has burdened national industry. The development also requires subsea EPC contracts, seabed inspection campaigns and offshore mechanical integrity programs. It is an offshore oilfield services market that does not exist in Venezuela at this scale today, and it would be built around a project with tier-one operators auditing quality. And all of this happens without the country having to finance its own liquefaction plant, the outlay that has historically sunk Venezuelan gas projects at the paper stage.

That benefit should be measured carefully. The law empowers the Executive to set and modify the royalty rate project by project, taking into account the nature of the investment, economic viability and international competitiveness, and it includes an economic-financial equilibrium clause that obliges compensation to the operator if the legal or fiscal framework changes. The 30% is a ceiling, not a rate. In the case of Dragón, it was reported that Caracas would retain at least 45% of revenue, a figure that offers a reference but not a contractual precedent. And as an analysis published in Derecho y Sociedad warned, it is still not known with certainty how the integrated tax will affect project viability. Venezuela is introducing a fiscal regime at the same time that it negotiates under it.

The corporate structure of Phase 2 says something about risk. Three partners with exact thirds means none controls the outcome. bp brings deepwater operations and a long presence in the basin, XRG brings sovereign-balance-sheet capital with a long horizon, and UCC brings construction capacity. The arrangement also spreads political exposure across three home jurisdictions: the United Kingdom, the United Arab Emirates and Qatar. No shareholder stands alone in the face of a change of course in Washington.

A great deal remains open, and a license is not yet a project. No final investment decision has been announced, no capex has been published, and the commercial terms for the cross-border gas flow have not been disclosed. The framework that enables the operation is renewed in administrative stages. Three things are worth watching in the coming months. The final investment decision, which Shell has hinted could come before the end of 2026 if the fiscal frameworks are consolidated. The commercial agreement that will govern the flow to Trinidad. And the validity of the OFAC licenses. If all three move forward, Venezuela will have monetized offshore gas without building its own liquefaction plant. If not, it will have a signed contract and the gas will remain where it has been since 1983.