Viewpoint: UK offshore faces deeper consolidation

Spanish Market: Crude oil, Natural gas
15/12/25

UK offshore oil and gas operators are bracing for more consolidation next year after the government confirmed the Energy Profits Levy (EPL) will remain in place until March 2030.

The EPL, introduced in 2022, raised the headline tax rate on upstream profits to 78pc from 40pc, reshaping project economics and company strategies. Executives argue the current price environment is "far from windfall" and describe the fiscal regime as punitive. Faced with higher taxes and tighter margins, operators are seeking scale and cost savings through mergers and joint ventures.

Shell and Norway's state-controlled Equinor formally launched their new UK offshore joint venture, Adura, earlier this month after agreeing the deal in 2024. Also this month, TotalEnergies agreed to form a UK-focused joint venture with Neo Next, an independent owned by Spain's Repsol and Norwegian private equity firm HitecVision.

The new business, Neo Next+, will hold more than 50pc of the Elgin-Franklin gas complex, where TotalEnergies is already operator, and interests in several other fields. The deal will leave BP as the only European major still directly operating a UK portfolio itself.

Other examples of operators restructuring to manage UK exposure include Italian firm Eni exchanging its UK upstream assets for a stake in North Sea producer Ithaca Energy, and UK independent Harbour Energy merging with Germany's Wintershall Dea in an $11.2bn transaction that added assets offshore Norway and in other regions. Both those deals closed in 2024.

Although Harbour has since cut hundreds of North Sea offshore jobs, it is not giving up on the UK. It agreed a deal this month to increase its interest in the UK's Catcher field to 90pc, from 50pc, via a takeover of junior independent Waldorf Production. The deal, which will also give Harbour a stake in the Kraken field, will add 20,000 b/d of oil equivalent (boe/d) to the firm's UK production.

Harbour is the UK's largest independent producer for now, with output of 156,000 b/d of oil equivalent (boe/d) from the UK continental shelf in January-September this year. But analysts who track the sector estimate Adura will eventually produce more than 200,000 boe/d. And TotalEnergies expects Neo Next+ to reach 250,000 boe/d in 2026.

While operators consolidate to help manage fiscal pressure, the outlook for fresh projects is limited by government policy. Greenfield oil and gas developments in the UK will be scarce in the 2026 and beyond. The government's ban on new licences remains in force. Its North Sea Future Plan, released on budget day, allows limited additional production near existing producing fields. Operators are expected to direct capital spending to near-field tiebacks and other work to lift output from existing developments.

Two greenfield projects that could see first oil or gas towards late 2026 are Rosebank and Jackdaw. Equinor and Ithaca continue to work on Rosebank. Shell continues to work on Jackdaw. But the government must still decide whether the resubmitted environmental plans meet the required standard.

As for Ithaca Energy's Cambo development, west of Shetlands, which has yet to reach a final investment decision, analysts are increasingly sceptical that it will proceed at all. After the budget, investment bank Stifel issued a "sell" note on Ithaca's shares. Its valuation now assumes Ithaca's 100pc-owned Cambo project will not go ahead.

By Jon Mainwaring

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15/12/25

Aramco Jafurah project still in commissioning: Resend

Clarifies distinction between raw gas and sales gas. Story originally published on 11 December Dubai, 15 December (Argus) — Saudi state-controlled Aramco has begun to commission the first phase of its giant Jafurah natural gas project, but is yet to begin full commercial operations, according to the company's executive vice president of gas Abdulkarim Al-Ghamdi. "Jafurah… we started the commissioning last week," Al-Ghamdi told the Middle East Gas Conference in Dubai on Wednesday. "And that will be commissioned fully now, for production, before year-end." The phase is "on schedule" and "in advanced commissioning", he said. Al-Ghamdi's comments are the first from Aramco since the Saudi finance ministry said production at Jafurah had begun. In its 2026 budget released last week the ministry listed "completion of the first phase of the Jafurah gas plant construction and commencement of production with a capacity of 450mn ft³/d," as one of the country's achievements for 2025. It did not specify a date for the start. Aramco has not made its own start-up announcement. A source close to the project said a formal Aramco announcement regarding Jafurah is likely "soon" ꟷ probably before the end of the year when commissioning is complete, as per Al-Ghamdi's comments. With in-place reserves of 229 trillion ft³ (6.87 trillion m³) of raw gas and 75bn bl of condensate, Jafurah is the largest unconventional gas field in the Mideast Gulf, and constitutes a major pillar of Aramco's ambitious gas expansion plans. The 450mn ft³/d capacity referenced by the ministry reflects the project's initial maximum raw gas processing, which aligns with Aramco's long-held plans for output to begin at 200mn ft³/d as sales gas, rising to 650mn ft³/d of sales gas by the end of 2026. A second phase, which is scheduled to come on stream in 2027, would then gradually lift sales gas production to 2bn ft³/d by the end of the decade. It constitutes part of an ambitious Aramco programme to expand gas production by more than 80pc by the end of the decade, relative to a 2021 baseline of 9.2bn ft³/d. This implies output of at least 16.6bn ft³/d by 2030, with Jafurah delivering just over one-quarter of the increase. Jafurah will also produce about 420mn ft³/d of ethane, and 630,000 b/d of NGLs and condensate as by-products by 2030. Traders told Argus last week that Aramco has offered spot Jafurah condensate for loading in February. Market sources say Jafurah condensate has an API gravity of 49.75° and sulphur content of 0.16pc. The ethane and NGLs will be sent to the Riyas fractionation plant, which is being built as part of the phase two development. The condensate will be sent to the Juaymah terminal, where Aramco is expanding its storage and export facilities. By Nader Itayim Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: Saudi condensate to lead supply rise in 2026

15/12/25

Viewpoint: Saudi condensate to lead supply rise in 2026

Singapore, 15 December (Argus) — The Asian condensate market is bracing for the introduction of a new grade from Saudi Arabia in 2026, which may cause significant pricing disruptions if demand cannot keep pace with the rise in supplies. Condensate loadings from state-controlled Saudi Aramco's new Jafurah natural gas project should start in the first quarter of 2026 , in cargo sizes of 500,000 bl, traders said. Some expect 3-4 spot cargoes a month to be made available. Jafurah condensate, with an API gravity of 49.75° and sulphur content of 0.16pc, appears to be similar in quality to Australian Ichthys and Qatari condensates, which are rich in naphtha and middle distillates. It may also compete with lighter crudes like US light sweet WTL. Jafurah's ramp-up speed will be a critical factor for 2026, and some traders think condensate prices will have to be gradually adjusted lower when the new supply comes. Buyers may initially be hesitant to commit to Jafurah condensate given its quality is untested, so its impact on similar-quality grades may not be immediate. The bulk of condensate produced in Asia-Pacific and the Mideast Gulf goes to the UAE, South Korea, Singapore and China, mostly to splitters. Any potential price decline next year resulting from more supply may be capped by expectations of condensate offers from Qatar's North Field East (NFE) expansion project emerging only towards the end of 2026, with its effects not anticipated to be felt until 2027. This is perhaps a strategic move aimed at preventing a flood of supply in 2026 that would drive down prices even more, a Singapore trader said. The project is supposed to start up in mid-2026 . State-owned QatarEnergy (QE) has, in the meantime, struck several long-term supply deals with the UAE's Enoc , Japan's Mitsui and a Singapore unit of Shell . "[They have] covered some of their [supply] lengths already, but [there is] still a lot more," a trader said. QE typically sells its Qatari Low Sulphur Condensate (LSC) and Deodorized Field Condensate (DFC) — also produced at the North Field — via regular tenders, and traders expect condensate from the expansion project to be of similar quality to these. Qatar is the world's third-largest condensate producer, behind Russia and the US, according to IEA figures, and QE's LSC and DFC account for a quarter of the world's internationally traded condensate. These volumes were nearly 850,000 b/d last year, data from oil analytics firm Vortexa show. Australia is also a major condensate supplier, shipping about 180,000 b/d last year, mainly to Asian buyers. Demand outlets One potential source of demand for these new condensates is China, given its need for naphtha as a feedstock for its expanded petrochemical capacities, while middle distillates produced from splitting the condensates can be sold off, traders said. Recent US sanctions on Russia — a major global exporter of naphtha — have made buyers, including China, reluctant to take Russian naphtha . China imported around 77,000 b/d of condensate last year, Vortexa data show. Iranian sour South Pars condensate accounted for close to 50pc of that, which was probably discounted because of Iranian sanctions, so any replacement supplies would have to be priced competitively for China to consider switching. Singapore's 70,000 b/d Bukom splitter could be another source of condensate demand once it is properly up and running , traders said, adding to the 237,000 b/d Bukom refinery's purchases of grades like Qatari condensate. Refiners often view heavy condensates as an alternative to ultra-light crude feedstock and could turn to such supplies if they are priced at a level that makes sense for them economically compared to regular crude grades. In the past, firm prices for light sour crudes like Abu Dhabi Murban had prompted some refiners to turn to Qatari condensates. Otherwise, Aramco especially may be banking on replacement demand from buyers in South Korea, the UAE and Singapore, hoping to switch some of their purchases away from Qatari and Ichthys condensates, as well as lighter crudes, traders said. If there is insufficient demand for the additional supplies, some condensates can even be blended with crude to create lighter grades of crude, a Singapore trader said, optimistic that the market will somehow find a way to absorb these extra supplies over the next few years. By Reena Nathan Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Seized oil tanker likely heading to Houston

12/12/25

Seized oil tanker likely heading to Houston

New York, 12 December (Argus) — The US-seized oil tanker Skipper, carrying Venezuelan oil, is en route to Houston, Texas, according to data from oil analytics firm Vortexa. If Houston is the very-large crude carrier's final destination, it will likely discharge the 1.9mn bls of Merey crude it is carrying via lightering offshore since Houston-area ports are too shallow to allow such a large ship dock to offload at an onshore terminal. The US seized the falsely-flagged Skipper on 10 December for its alleged involvement in smuggling Iranian oil to support Lebanon-based Hezbollah and Iran's Islamic Revolutionary Guard. But the seizure is widely seen as an extension of ongoing efforts by the US to pressure the Venezuelan government over the flow of drugs from the country. The US said it intends to seize other tankers on existing sanctions lists that are carrying Venezuelan crude. The US has stationed a large naval force in the waters near Venezuela since September as part of an effort ostensibly aimed at stopping waterborne drug shipments. The seizure of the Skipper has not had any clear effect on freight or crude markets so far, but more seizures and Caracas' response could change that. The US tried to pressure Iran through ship seizures from 2019-24, seizing a total of nine tankers, including four vessels in 2020 that were due to deliver Iranian gasoline cargoes to Venezuela. The US discontinued the practice because Tehran retaliated by seizing tankers passing through or near the strait of Hormuz at the entrance to the Mideast Gulf. Venezuelan president Nicolas Maduro's government calls the seizure of the Skipper "an act of international piracy", but Caracas may not have the same capability to retaliate as Tehran. It could block loadings by Chevron, which is importing oil to the US under a sanctions waiver that the US reissued in August. Exports to the US, shipped under Chevron's waiver, stood at about 130,000 b/d in November, down from 150,000 b/d in October. By Charlotte Bawol and Haik Gugarats Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Japan’s energy demand falls on economic slowdown

12/12/25

Japan’s energy demand falls on economic slowdown

Osaka, 12 December (Argus) — Japan's energy consumption in the April 2024-March 2025 fiscal year fell again from a year earlier, pressured by slower industry activity. The country's 2024-25 final energy use totalled 292mn kiloliters, or 1.84bn bl of oil equivalent (boe), down by 1.7pc from a year earlier, according to preliminary data released on 12 December by the trade and industry ministry Meti. This marks the third consecutive annual decline. Coal use in final energy consumption fell by 3.7pc from a year earlier to 172mn boe in 2024-25, while oil demand declined by 3.7pc to 841mn boe. This came as energy consumption in the manufacturing and transportation sectors declined by 3.2pc to 766mn boe, and by 1.5pc to 445mn boe respectively. But demand for natural gas and city gas rose by 1.5pc from a year earlier to 167mn boe. Power demand also edged up by 1pc to 517mn boe. Coal-fired power generation edged up by 0.9pc to 283.4TWh during the period, while oil- and gas-fired power dropped by 2.7pc to 71TWh and by 2.4pc to 315.7TWh. Zero-emission power supplies, including renewables and nuclear power, rose by 3.9pc to 322.1TWh. Japan's energy-derived CO2 emissions fell by 1.4pc from a year earlier to 908mn t in 2024-25, supported by the increased use of renewable and nuclear power supplies. The 2024-25 emissions represented a 26pc fall compared with the country's 2013-14 baseline, or the lowest level since 1990-91. The lower energy consumption, as well as increased use of domestic renewable and nuclear energy, helped lift Japan's energy self-sufficiency rate to 16.4pc in 2024-25, up by 1.1 percentage points from a year earlier, based on International Energy Agency methodology. By Motoko Hasegawa Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

TotalEnergies ends Papua LNG rebid phase: Correction

12/12/25

TotalEnergies ends Papua LNG rebid phase: Correction

Corrects headline and 'FID' to 'development forum' in last paragraph Sydney, 12 December (Argus) — New engineering, procurement and construction (EPC) contract offers have been received for the proposed 5.6mn t/yr Papua LNG project in Papua New Guinea (PNG), operator TotalEnergies said, following extensive design revisions for the delayed development. The firm is concluding the rebid phase after receiving new offers at reasonable costs, managing director of TotalEnergies EP PNG Arnaud Berthet told the PNG Resources and Energy Investment Conference in Sydney on 10 December. TotalEnergies relaunched EPC tendering late last year after previously estimated costs were considered too high for the project to proceed. The company expanded the contractor pool to include Chinese firms and reduced the gas pipeline diameter to 30 inches from 40 inches. This change increased the number of vessels able to perform pipelay, Berthet said, increasing competition, while it also routed the condensate pipeline west to a new floating storage and offloading vessel, reducing pipeline length. A development forum is planned for January-March next year, a legal requirement ahead of a final investment decision, which JV partner Australian independent Santos has previously signalled is likely in early 2026 . LNG sales and purchase agreements are under negotiation, and seven export credit agencies along with more than 30 commercial banks are interested in financing the project, Berthet said. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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