India defers upstream hopes into 2026

Spanish Market: Crude oil, Natural gas
02/01/26

India wants to open up access to more of its upstream but it is struggling to attract foreign operators, writes Rituparna Ghosh

The global oil and gas industry is seeing something of an exploration revival, but India's efforts to attract foreign investment to its upstream sector have faced repeated setbacks as New Delhi has struggled to offer the right incentives.

India fulfils close to 90pc of its crude needs with overseas supplies, with imports expected to have hit a record high of 4.9mn b/d last year, from 4.7mn b/d in 2024. Crude imports could climb further in 2026 on the back of rising demand. Alongside this, India's currency is still depreciating against the US dollar, making imports more expensive. Long-standing efforts to boost energy security by reviving Indian oil production saw New Delhi in February launch India's 10th bidding roundunder its Hydrocarbon Exploration and Licensing Policy's Open Acreage Licensing Programme (OALP), with 25 upstream oil and gas blocks on offer.

Around 192,000km² was up for grabs, compared with the 379,000km² in the first nine rounds, making it the largest ever OALP bidding round in terms of acreage. It was initially due to close at the end of July 2025 but, after four deferrals, bidding has most recently been extended until 18 February. The government has not given a reason for the latest deferral, but it is likely because investors were still being put off by India's upstream regulations and tax policies, sources say.

Discussions are ongoing over new drilling regulations, a government official told reporters at the 28th Energy Technology Meet in Hyderabad in October. The new rules aim to expand on India's amended legislation to offer foreign investors greater policy certainty and fiscal stability — something that has deterred most international oil companies from investing in India's upstream sector.

This has left domestic state-run and private-sector oil companies dominating India's licensing rounds, but the sector saw some signs of improved foreign interest last year. Brazilian state-controlled Petrobras signed letters of intent with Indian state-owned producers ONGC and Oil India in February, to collaborate on exploration and production projects. Petrobras is also considering opportunities in Indian deepwater and ultra-deepwater crude blocks, chief executive Magda Chambriard says. And majors ExxonMobil, Chevron, TotalEnergies and BP have all signed initial agreements to partner with ONGC and Oil India over the past two years.

Under the ninth bidding round, 28 upstream oil and gas blocks were offered in January 2024, of which ONGC won 15. But one of ONGC's 15 wins was a first-time partnership between BP, private-sector refiner RIL and ONGC, which won a shallow-water block in the Saurashtra basin. ONGC has a 40pc stake in the consortium, and RIL and BP hold 30pc each. Separately, ONGC in January 2025 awarded a contract to BP to operate and enhance crude and gas production from its Mumbai High fields, as part of India's efforts to attract foreign investment upstream.

Taxing times

But a recent hike in taxes complicates matters for foreign majors looking to invest in India's upstream, because it raises input costs. New Delhi increased its goods and services tax (GST) on exploration, development and production of oil and gas to 18pc from 12pc, effective from 22 September. The government currently takes 60-70pc of oil producers' revenue in the form of royalties and other taxes, a senior industry official says. Indian upstream firms sell their output based on international prices. Retail sales of oil products and natural gas do not fall under the GST regime, resulting in limited pricing freedom for domestic oil and gas producers.

Tax concerns and bidding round deferrals add to uncertainty over whether New Delhi can crack the formula for attracting more foreign investment to its upstream. Another setback will be a blow for the government's ambition to increase its acreage under oil and gas exploration to 1mn km² by 2030.

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02/01/26

UK offshore faces deeper consolidation

High taxes, tighter margins and a ban on new exploration will continue to drive rationalisation in the sector, writes Jon Mainwaring London, 2 January (Argus) — UK offshore oil and gas operators are bracing for more consolidation in 2026, after the government confirmed its 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 Norwegian state-controlled Equinor last month formally launched their new UK offshore joint venture, Adura, after agreeing the deal in 2024. And 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, as well as 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 of those deals closed in 2024. Harbour has continued to diversify its portfolio away from the UK North Sea, last month agreeing to acquire privately held US firm LLOG for $3.2bn, marking its entry into the deepwater US Gulf of Mexico. And on the Mexican side of the maritime border, the company has just become operator of the deepwater Zama field, in which it already held a 32.2pc stake. Harbour has cut hundreds of North Sea offshore jobs since 2024, but it is not giving up on the UK. It agreed a deal last month to increase its interest in the UK's Catcher field to 90pc from 50pc, through a takeover of junior independent Waldorf Production . The deal will also give Harbour a stake in the Kraken field and will add 20,000 b/d of oil equivalent (boe/d) to the firm's UK production. Harbour is the UK's largest producer for now, with output of 156,000 boe/d from the UK offshore in January-September last year. But analysts estimate Adura will eventually produce over 200,000 boe/d, and TotalEnergies expects Neo Next+ to reach 250,000 boe/d in 2026. Policy constraints 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 2026 and beyond. The government's ban on new licences remains in force. Its North Sea Future Plan — released on the same day the budget was delivered to parliament in November — allows limited additional production near existing producing fields. Operators are expected to direct capital spending to near-field tie-backs and other work to lift output from existing developments. Two greenfield projects that could see first oil or gas towards the end of this year 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 its required standards. Analysts are increasingly sceptical that Ithaca's 100pc-owned Cambo development, west of Shetland, will proceed at all, with the project yet to reach a final investment decision . After the budget announcement, investment bank Stifel issued a "sell" note on Ithaca's shares. Its valuation now assumes Cambo will not go ahead. Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Viewpoint: Brazil’s biomethane at a crossroads

02/01/26

Viewpoint: Brazil’s biomethane at a crossroads

Sao Paulo, 2 January (Argus) — Brazil's biomethane sector is approaching a pivotal juncture in 2026, with the start of the biomethane mandate and the creation of the biomethane certificate of guarantee of origin (CGOB), which will establish renewable attribute pricing and shape the sector's future. The government's proposal to set the 2026 biomethane mandate at 0.25pc — equivalent to 238,500 m³/d of biomethane — has introduced new uncertainty into pricing expectations under the biomethane certificate of guarantee of origin (CGOB) rules. While some market participants anticipate CGOB values slipping below suppliers' R1/m³ (19¢) floor, key regulatory elements such as certificate rules, delivery models and contract requirements remain undefined. Producers argue that R1/m³ is the minimum price needed to support new projects, considering combined revenue from CGOB rules, decarbonization credits (Cbios) and gas sales, but the ministry's cautious target suggests limited initial demand. Suppliers stress that multi-year targets will be essential to give investors the confidence needed to expand supply in coming years. In contrast, buyers broadly welcomed the modest 0.25pc target as a soft launch that avoids sudden price shocks. The sector's trajectory relies on effectively distinguishing between the energy and renewable components of biomethane, a separation that is essential for Brazil to enhance its position as a provider of renewable attributes. The main challenge lies in establishing a system compatible with both voluntary and obligated buyers, aligned with international standards, and capable of delivering clear price signals to promote investment. Public hearings on CGOB rules and the proposed targets are scheduled for January, leaving final decisions to later in the year. Developing a transparent framework for recognizing and pricing renewable attributes remains central, and consensus on these matters has yet to be reached. The groundwork for these developments was laid during 2025 with rigorous regulatory discussions, increased investments, and a deeper engagement between producers and consumers. In addition, seven new biomethane facilities started operations in Brazil, which expanded national production capacity by 439,827 m³/d to 1.1mn m³/d. Recent debates surrounding regulatory mandates have played an instrumental role in informing market development, particularly with respect to the valuation of biomethane's renewable attribute. This focus accelerated market growth and strengthened alignment among stakeholders on pricing issues. Although differences in perspective persist, consensus has grown on the definition of the renewable premium, while several aspects of the mandate remain unresolved as the new year approaches. According to Argus , the Brazilian biomethane fob plant price is currently reported at R3.28/m³ as of 1 January 2026 . In early 2025, Petrobras initiated an open call for biomethane supply, a significant milestone as the Brazilian oil company will be the largest obligated entity under the new mandate, despite negotiations still ongoing. The open call resulted in 20 proposals advancing to the negotiation stage, according to Petrobras. The state-owned company accepted all proposals for biomethane and CGOB supply in 2026. The progress seen in 2025 has paved the way for possible changes in 2026, though important steps still lie ahead. Public hearings regarding the CGOB rules and the proposed targets still need to take place, and the final decisions on the mandate are likely to come in early 2026. The development of a clear, transparent framework for recognizing and pricing renewable attributes remains a central topic of discussion, and there is not yet a definitive consensus on these matters. By Rebecca Gompertz Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Viewpoint: Brazil seeks gas growth and price cuts

02/01/26

Viewpoint: Brazil seeks gas growth and price cuts

Sao Paulo, 2 January (Argus) — Brazil's natural gas market enters 2026 with supply source abundance and favorable global conditions, but structural challenges remain. Its ability to convert that supply into competitive pricing will depend on delivery infrastructure, regulations at the state and federal level and the integration of new dynamics such as LNG flexibility and carbon emissions compliance. Domestic gas production is set to rise beyond the record levels reached in late 2025, supported by pre-salt developments and new offshore processing. According to government-owned energy research firm EPE's recently published PDE 2035 Gas report, national output available for market consumption could climb toward 127mn m³/d by 2035 from around 65mn m³/d currently, with early gains already visible. Monthly data from hydrocarbons regulator ANP show gas production, including volumes re-injected for oil production, stabilizing near 190mn–195mn m³/d in the second half of 2025. However, beyond southeast Brazil where the pre-salt cluster faces setbacks, Petrobras has postponed investments in the Sergipe-Alagoas Basin offshore Brazil — originally expected to start in 2026 and deliver up to 18mn m³/d — until 2030, delaying regional supply expansion. LNG imports and flexibility The global LNG market is entering 2026 with its largest supply wave in history — with around 390bn m³/yr of new liquefaction capacity approved from 2019-2025. New projects in the US, Qatar and Africa, combined with slower Asian demand growth, could restrain spot prices. This offers Brazil an opportunity to secure competitive cargoes for its eight regasification terminals and the planned Suape facility. LNG will remain a critical balancing tool, especially during seasonal demand peaks and thermal dispatch spikes, complementing domestic production and potential Argentinian pipeline flows from the Vaca Muerta shale formation. But infrastructure bottlenecks, including limited interconnections and uneven pipeline access, fragment the market and create regional disparities. And regulatory harmonization between federal and state jurisdictions remains incomplete, slowing the development of a competitive free market. Decarbonization targets and biomethane incentives starting in 2026 will further reshape contract structures and cost dynamics, adding complexity to pricing. Gas demand growth in 2026 looks moderate, led by industrial sectors such as chemicals, fertilizers and ceramics. Thermal dispatch anchoring the system Power generation will remain volatile, with thermal dispatch depending on hydropower availability and electricity prices during the region's dry season in the second half of the year. By Betina Moura Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Venezuela's Maduro offers talks, oil deal with US

02/01/26

Venezuela's Maduro offers talks, oil deal with US

Caracas, 2 January (Argus) — Venezuela president Nicolas Maduro asked for dialogue with US president Donald Trump whenever and wherever after the US has continued to increase military pressure on his government. The call comes days after Trump said the US used drones to destroy a dock in Venezuela allegedly used in drug shipments and after it has fatally struck boats offshore of Venezuela and seized oil tankers. The US said it destroyed an additional five alleged narco-boats offshore of Venezuela in the last three days of December, after some 27 previous attacks. He pleaded for dialogue with Trump "whenever you want, wherever you want and in any form you want", this time offering to give Venezuelan oil to US companies "just like we are doing with Chevron", Maduro said during an hour-long interview with academic Ignacio Ramonet, released on Thursday. Chevron operates in Venezuela with state-owned PdV under a waiver from US sanctions. It imported about 120,000 b/d of crude from Venezuela to the US in December, based on data from Kpler ship tracking. That has fallen from the about 200,000 b/d Chevron was importing early in 2025 before its previous waiver expired in May, later replaced with a modified waiver. The US began to build up about 10pc of its naval force in the Caribbean offshore of Venezuela from early September, which Trump says is to fight illegal drugs. Maduro claims the US is trying to force him from office. The US accuses him of drug trafficking, money laundering and human rights violations. Maduro has alternated between defiance and pleading with Trump for talks. During the interview delivered while Maduro appears to drive a SUV around the capital of Caracas, a red baseball cap similar to those worn by Trump and his supporters was displayed on the back seat, inscribed with "No War, Yes Peace". On 28 December Maduro compared Trump to "King Herod" from the Bible, ahead of the most recent US attacks on boats. Maduro since 25 December has released close to 200 political prisoners, the government and non-governmental agencies have said. During the interview Maduro also said the Venezuelan economy grew by 9pc in 2025 and was going to grow by the same amount in 2026. The UN's economic commission for Latin America and the Caribbean, Cepal, has said that Venezuela's economy grew by 6.5pc in 2025 and projected last week that it will grow by about 3pc in 2026. By Carlos Camacho Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

Viewpoint: Rising Guyanese crude flows open new markets

02/01/26

Viewpoint: Rising Guyanese crude flows open new markets

Sao Paulo, 2 January (Argus) — Increasing Guyanese crude production in the second half of 2025 has contributed to wider discounts against North Sea Dated and an expansion of destinations for the South American grade, especially to Asia-Pacific markets. In 2024, no Guyanese cargoes headed to Asia, according to oil analytics firm Vortexa data, compared with 24 cargoes in 2025, of which 13 were in the second half of the year. Europe remains Guyana's main export destination, receiving about 60pc of all exports, followed by Central and North America with 25pc of exports combined. Medium sweet Liza, Unity Gold and Payara Gold prices dropped from an overall 98¢/bl premium to North Sea Dated in the first half of 2025 to a 33¢/bl discount against the benchmark in the second half of the year. In late November, those prices reached discounts of between $2.80-$3/bl to Dated, their widest discounts since Argus launched Guyanese assessments in February 2024. In August, Guyana started to produce its new medium sweet Golden Arrowhead grade at a time when the European market was already looking well supplied. Scheduled exports then jumped from 709,000 b/d in July to over 860,000 b/d in September and to an expected record-high 964,000 b/d for February 2026, according to loading programs seen by Argus . This has led sellers to lower prices in order to compete with other similar-quality alternatives available to European refiners, such as Norwegian medium sour Johan Sverdrup, Brazilian medium sweet Buzios, and a wide range of light and medium west African crudes. Falling Guyanese prices in the second half of 2025 opened the arbitrage to Asian markets, such as China and India, as Asian buyers tend to only look for Guyanese supplies when discounts are below $2.50/bl to Dated. Flows to Asia increase Chinese sellers have started to buy Guyanese crudes regularly since the end of September, securing one or two cargoes every month, usually closer to the end of the loading program when prices are generally lower. Indian buyers also opted for Guyanese grades in November, when the medium sweet grades were cheaper compared with their usual west African supplies and as US sanctions against Russia's Rosneft and Lukoil, announced in late October, limited the country's intake of Russian supply. With restriction for loading of very large crude carriers (VLCC) in the winter months lifted by Guyana since mid-2025, Asian buyers could also benefit from better freight economics with larger vessels. However, a hike in VLCC prices since the start of September, and especially since the start of November, have capped a possible increase in voyages to the region. The US market has also increased its intake of Guyanese crudes, especially at the Gulf coast this year. The US received about 20pc of all Guyanese exports in 2025, according to Vortexa data. Of that supply, 60pc headed to the US west coast, while 37pc went to the US Gulf coast, compared to 75pc and 21pc, respectively, in 2024. The increase came as Chevron completed its acquisition of US independent Hess, giving the major a stake in Guyana's crude exploration consortium. Regional supplies rise Guyanese output is set to rise further in 2026 as the Uaru project is expected to be commissioned, bringing 250,000 b/d more supply to the market. Guyana expects to produce 1.4mn b/d of crude by 2027 and around 1.7mn b/d by 2030 . Rising Guyanese production will join growing output from multiple South American countries. Brazil reached 4mn b/d of crude production in October , according to hydrocarbon regulator ANP, boosted by output from the prolific pre-salt fields, which now account for 81.4pc of the country's total crude and gas production. Brazil's most exported grades are medium sweet Tupi, Buzios and Mero, all of which compete directly with Guyanese grades in Europe. With sellers trying to reach new markets, Guyanese crudes could also compete with Brazilian grades in Asia-Pacific. Meanwhile, Argentina aims to increase its crude production to 1.5mn b/d in 2030 from 800,000 b/d currently, led by rising light sweet Medanito output. Despite its lighter quality, price trends suggest that Medanito may already compete with Guyanese grades in some markets, such as the US west coast. And Argentinian sellers also aim to increase their exports to Asia-Pacific markets over time. As a result, weakening Guyanese crude prices in the second half of 2025 may be a preview of price trends in the coming months, given the increase in production of light and medium Latin American grades. By João Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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