Rio Grande LNG plans train 6 FID in 2027: CEO

Spanish Market: Natural gas
28/01/26

US LNG developer NextDecade has plans to finance a sixth 6mn t/yr train at its 30.2mn t/yr Rio Grande LNG export plant in 2027, driven by customer interest for new LNG supply beyond 2030, chief executive Matt Schatzman told Argus today on the sidelines at the Baker Hughes annual meeting in Florence, Italy.

NextDecade took two final investment decisions in 2025 to add trains 4 and 5 to its Rio Grande LNG export terminal in Brownsville, Texas, where the company is already building the first three trains. The decisions were part of a banner year for US LNG, which included project developers greenlighting construction for more than 65mn t/yr of new liquefaction capacity and customers signing up for 31.5mn t/yr of offtake.

Energy Transfer's decision to scrap its proposed 16.5mn t/yr Lake Charles LNG export terminal in December put a damper on enthusiasm in the industry's investment cycle. But the cancellation should not be viewed as "a barometer for the incremental investment" that will take place in the US LNG industry, Schatzman said, adding that NextDecade had more demand for offtake from train 5 than it had supply to offer.

"The timing of train 6 fits well with a lot of people's supply plans," Schatzman said of the potential expansion, which would be operational by 2032. "We don't see a lot of folks looking for more LNG in 2029 or 2030, but [they are] definitely looking at the next decade."

The 18.1mn t/yr first phase of Rio Grande LNG is expected to commission its three trains in 2027, 2028 and 2029. Trains 4 and 5 are slated to come on line in 2030 and 2031.

Contractor Bechtel is ahead of schedule in building train 1, which could move its timeline earlier, Schatzman said.

By Jon Mainwaring and Tray Swanson

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28/01/26

Feedgas flows to US Gulf LNG terminals recover

Houston, 28 January (Argus) — Flows of natural gas to LNG export facilities on the US Gulf coast continued to recover today with milder weather and lower regional gas prices, but flows to the two terminals on the Atlantic coast were still reduced, interstate pipeline data show. Overall feedgas nominations climbed to 15.8bn ft³ on 28 January, up from a one-year low of 10.9bn ft³ on 25 January. The preliminary flows are 2.1bn ft³ below the 30-day average through 23 January, when the storm began affecting export nominations. Flows remain subdued to Cheniere's 33mn t/yr Sabine Pass terminal in Louisiana and the 4mn t/yr Elba Island and 5.75mn t/yr Cove Point terminals on the Atlantic coast, though nominations can fluctuate later in the day. The return to normal ranges coincides with falling day-ahead gas prices at key regional hubs that tie into the Gulf coast export facilities. Those spot prices had risen above the value of LNG delivered to northwest Europe in the second half of February, which incentivized customers from LNG facilities with the flexibility to do so to send their feedgas toward the domestic market. Feedgas costs to Cove Point and Elba Island have declined from record highs but stood at $31.70/mn Btu and $33.15/mn Btu, respectively, on 27 January. Both were well above delivered LNG prices in Europe in the second half of February, which were $12.88/mn Btu on the same day. A forecast for colder-than-normal weather on the US Atlantic coast through 1 February may continue to offer price support. Both Cove Point and Elba Island are utilizing their regasification capacity to import LNG. BP's 174,000m³ BW Enn Snow Lotus LNG carrier delivered a cargo from Trinidad and Tobago to Cove Point on 26 January, and Shell's same-sized Paris Knutsen is set to deliver a shipment to Elba Island on 28 January, Kpler data show. By Tray Swanson Feedgas flows to US LNG terminals bn ft³/d Weighted US LNG feedgas costs vs. European LNG $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Japanese firms add flexibility with US gas footprint

28/01/26

Japanese firms add flexibility with US gas footprint

The unique structure of US LNG projects may attract more upstream investment from Japanese firms, write Tray Swanson and Motoko Hasegawa London, 28 January (Argus) — Japanese trading house Mitsubishi has this month made its first foray into the US shale gas market, buying upstream assets in the Haynesville basin from US firm Aethon. The purchase marks the fourth and largest Japanese acquisition in US gas since March, after deals by compatriots Tokyo Gas, Jera and Japex, and brings Japanese firms' total investment in US shale gas to $10bn since the start of 2025. The spending comes after pressure from President Donald Trump to invest in the US. The two countries signed a trade deal in July , lowering the reciprocal tariff rate on Japan to 15pc from 25pc in exchange for $550bn of potential Japanese investment in the US. But more than the direction of US political winds, the primary motivation for each company appears to be their own long-term interests. The upstream investments reflect the firms' individual assessments of business viability, think-tank the Institute of Energy Economics Japan's executive analyst, Takafumi Yanagisawa, tells Argus. Such decisions are part of a long-term outlook, considering both short-term factors and long-term concerns such as durability through policy changes, he says. While such investments may be seen as a matter of short-term convenience under the lens of US-Japanese relations, allowing the Japanese government to claim compliance under the trade deal, they also chime with Japanese firms' long-held business strategies. For some of these firms, the investments mark a sizeable expansion rather than an incursion into the US gas value chain. Tokyo Gas subsidiary TG Natural Resources began gathering Haynesville acreage in 2017, and acquired Rockcliff Energy in 2023, raising its Haynesville production to 1.3bn ft³/d (13.4bn m³/yr) at the time. And Tokyo Gas, Jera and Mitsubishi have processing agreements with US LNG export facilities, for which they must procure their own feedgas. The upstream investments promise stable supply, protecting the firms from the cross-hub basis risk that comes with sourcing gas connected to the US' Henry Hub for shipment to international delivered markets in Asia-Pacific and Europe. The excess gas not destined for liquefaction can be marketed domestically for use in heavy industry and power generation, which holds a particular upside given the US' artificial intelligence-driven data centre buildout. In Mitsubishi's case, its new Haynesville production complements a comprehensive US gas and power strategy. This includes subsidiaries such as gas marketer Cima, which already handles 5bn ft³/d of midstream supply, as well as power producer Diamond Generation and electricity trading firm BETM. Upstream hedging Japan's largest LNG importer, Jera, previously had similar exposure to US power markets but sold its interest in three gas-fired plants in September. Jera bought its first US upstream stake in the Haynesville basin a month later, strengthening its LNG value chain with 500mn ft³/d of production, equivalent to 3.5mn t/yr of LNG. Jera holds a combined 6.5mn t/yr of LNG offtake from US projects due on line by the end of the decade, and plans to double its output to 1bn ft³/d by 2030. Additional Japanese investments in US shale gas are likely to continue, especially given the unique structure of US LNG projects, Yanagisawa says. In the US, LNG projects are often separated from upstream operations, with different entities involved in supplying gas to each facility. This creates an incentive for companies exposed to US LNG to also invest upstream as a physical hedge for their Henry Hub-indexed LNG supplies. The project structure in other countries requires much larger financial commitments because non-US LNG projects tend to encompass both upstream and midstream value chains, presenting fewer investment opportunities, Yanagisawa says. US shale acquisitions $bn Buyer Asset location, output Value incl. debt Date Mitsubishi Haynesville, 2.1bn ft³/d 7 Jan-26 Japex Colorado/Wyoming, 35,000 boe/d 1.3 Dec-25 Jera Haynesville, 500mn ft³/d 1.5 Oct-25 Tokyo Gas Haynesville, 1.4bn ft³/d from 2030 1 Mar-25 Mitsui Haynesville (46,500 acres), na Undisclosed Jun-24 Tokyo Gas Haynesville, 1.3bn ft³/d 2.7 Dec-23 — company press releases Japan's US LNG offtake deals mn t/yr Company Terminal Capacity Start date Tokyo Gas Cove Point 1 2018 Jera Freeport LNG 2 2019 Mitsubishi Cameron 4 2019 Mitsui Cameron 4 2019 Jera CP2 1 2029 Jera Sabine Pass/Corpus Christi 1 2029 Mitsui Calcasieu Pass/Plaquemines/CP2 1 2029 Jera Commonwealth 1 2030 Jera Port Arthur 2 2030 Tokyo Gas Calcasieu Pass/Plaquemines/CP2 1 2030 Jera Rio Grande 2 2031 Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Brazil groups seek fossil fuel phase-out: Update

28/01/26

Brazil groups seek fossil fuel phase-out: Update

Updates with finance ministry's comments on when it will deliver the roadmap draft. Sao Paulo, 28 January (Argus) — Brazil's path to phase out fossil fuels needs to focus on the power and industrial sectors and include ambitious goals that can reduce risks, preserve energy security, ensure tariff fairness and maintain economic competitiveness, climate umbrella group Observatorio do Clima said. Brazilian president Luiz Inacio Lula da Silva on 8 December asked the energy, environment and finance ministries to draft a resolution by 3 February mapping out the phase-out of fossil fuels. He previously called for the creation of an international plan to move away from fossil fuels during a leaders' summit only a few days before November UN Cop 30 climate summit in northern Brazil. But the call did not make it to the summit's final decision despite backing from more than 80 countries . Instead, the Cop 30 presidency pledged to create a roadmap on the issue outside of official negotiations. An initial draft could be ready by April , when Colombia is set to host a global summit on the topic , according to Cop 30 president Andre Correa do Lago. Brazil's finance ministry told Argus that it is working on the roadmap draft alongside the environment and energy ministries, as well as Lula's chief of staff, and that it will deliver it on 9 February. The Observatorio do Clima's proposal includes 46 recommendations laid out in three sections: energy policy and transition guidelines; financing and economic fundamentals; and governance guidelines. The recommendations include: Replacing thermoelectric power plants with renewable-powered sources whenever possible, as well as avoiding contracting new fossil-fueled facilities; Fully banning hydraulic fracturing; Gradually reducing natural gas and oil usage in industry by replacing them with alternative fuel sources such as green hydrogen, biomass and electricity; Discontinuing investments in carbon capture and storage projects; A plan to end crude block auctions; Adding fuels such as biomethane, biodiesel, ethanol and hydrogen to Brazil's transport sector; Eliminating fossil fuel subsidies; Increasing state-controlled Petrobras' spending on renewables; Establishing a national fund to finance the energy transition. The plan was published and officially forwarded to the government on Wednesday, Observatorio do Clima's public policy coordinator Suely Araujo said. The group has held informal talks with government officials, she added. It will serve as both a guideline to the Brazilian government as well as to the Cop 30 presidency and the Colombia conference, WWF Brazil's energy transition lead Ricardo Fujii said. The group also plans to bring the roadmap to the meeting of Brazil's energy transition forum, which will be held this week. But phasing out fossil fuels could seem to run counter to Brazil's plans to keep increasing crude production. It produces around 4mn b/d of crude , making it one of the 10 largest producers globally, according to its hydrocarbon regulator ANP. Further, Brazil plans to expand crude output to 5.3mn b/d by 2030, according to energy research bureau Epe, hinging on new exploratory frontiers such as the southern Pelotas basin and the environmentally sensitive equatorial margin. By Lucas Parolin Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Trinidad eyes late 2027 start for Venezuelan gas field

28/01/26

Trinidad eyes late 2027 start for Venezuelan gas field

Goa, 28 January (Argus) — Trinidad and Tobago expects gas production at Venezuela's offshore Dragon field to start in the final quarter of 2027, energy minister Roodal Moonilal said today, adding that there is no indication that recent developments in Venezuela have impacted the project's prospects. "We have received no signal from the Venezuelan government that any of the agreements have been cancelled or are to be cancelled," Moonilal told reporters on the sidelines of India Energy week in Goa, adding that talks with partners including Shell and BP on project planning and execution were continuing. Delays affecting some ongoing projects were linked to licensing processes in Washington rather than agreements with Caracas, he said. The US Treasury Department's Office of Foreign Assets Control (OFAC) issued a license in October 2025 allowing Shell and Trinidad's state-owned natural gas company NGC to resume developing the field after earlier authorisations were revoked because of Washington's Venezuela policy aimed at increasing pressure on President Nicolás Maduro's government Moonilal said Shell currently holds the license allowing it to conduct transactions and negotiations related to the project, but an additional authorisation would be required to proceed with full-scale development and production. "The initial licence is for transactions and negotiations, not production and development," he said, adding that a second application would be needed and that progress continues to be monitored following discussions late last year. Dragon, which is in Venezuelan waters close to the maritime border with Trinidad, is expected to produce around 350mn ft³/d, and holds an estimated 3.5 trillion ft³ of reserves, Moonilal said. Trinidad is also seeking OFAC licences to advance the development of smaller Venezuelan offshore gas fields, including the Loran and Manakin-Cocuina fields, which could supply additional gas volumes to Trinidad for LNG exports and domestic use. Once developed, gas from Venezuelan fields would be piped to Trinidad, liquefied for export and used to support petrochemical production, with some volumes potentially supplying global LNG markets, including Europe, Moonilal said. By Rithika Krishna Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Shell takes LNG near Bahamas as US storm shifts flows

27/01/26

Shell takes LNG near Bahamas as US storm shifts flows

Houston, 27 January (Argus) — A Shell-operated LNG carrier that diverted from the Netherlands last week is delivering part of its cargo to a bunker vessel in Shell's fleet near the Bahamas, Kpler ship-tracking data show, likely an effect from the winter storm that recently swept the US. Shell controls the liquefaction capacity at the 4mn t/yr Elba Island export terminal in Georgia, which is also authorized to supply LNG for bunkering operations. The company has flexibility with the feedgas, allowing it to redirect gas into the domestic market, where the recent arctic blast raised nearby spot prices to record highs. The terminal has taken no feedgas since 24 January and has instead injected at least 550mn ft³/d into the gas grid, pipeline data show. But with Elba Island not producing LNG, Shell may need to redirect cargoes from elsewhere to meet bunkering obligations in the Bahamas. Shell's 174,000m³ Nantes Knutsen loaded at the 11.8mn t/yr Atlantic LNG terminal in Trinidad and Tobago on 16 January and initially signaled arrival at the Netherlands' 12.4mn t/yr Gate terminal. The vessel diverted toward the Bahamas' Freeport anchorage last week and on 27 January began a ship-to-ship transfer (STS) with the Shell-operated 18,000m³ New Frontier 2 , a bunker vessel operating in the Jamaica and Bahamas small-scale market, Kpler data show. The Nantes Knutsen will still have a partial cargo remaining after the STS. It could follow another LNG carrier in Shell's fleet, the 174,000m³ Paris Knutsen , which is signaling for arrival at Elba Island on 28 January with a cargo from Trinidad. If completed, that would be the first LNG delivery to Elba Island since 2020, according to Kpler data. Record high prices in Transco zone 5, a bellwether for prices in the US mid-Atlantic region, likely are incentivizing Shell to deliver into the US market. The day-ahead price at Transco zone 5 was $133.85/mn Btu on 26 January, the highest since Argus began collecting data in February 2009, before declining to $40.78/mn Btu on 27 January. The price remains at a significant premium to delivered LNG prices for cargoes arriving in northwest Europe in the second half of February, which were $12.16/mn Btu the same day. BP delivered another Trinidad-loaded cargo to the 5.75mn t/yr Cove Point LNG terminal in Maryland on 26 January. Cove Point also ties into Transco zone 5. Farther north, Total's 174,000m³ LNG Endeavour arrived at the 7.4mn t/yr Saint John import terminal in New Brunswick, Canada, on 27 January with a cargo from Egypt. LNG delivered to Saint John can be regasified and sent by pipeline to the US northeast, where day-ahead prices at Algonquin Citygates were $126.62/mn Btu on 26 January, the highest since Argus began collecting data in September 2008. That price also declined on 27 January to $64.74/mn Btu, but a colder-than-normal forecast could offer price support for the pipeline-constrained region through 1 February. By Tray Swanson Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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Rio Grande LNG plans train 6 FID in 2027: CEO

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