Viewpoint: RIN market awaits US policy clarity

Spanish Market: Biofuels, Natural gas, Oil products
02/01/26

US renewable fuel credits have traded in a narrow range for months but are likely to break out soon, when President Donald Trump's administration provides more clarity on incentives in the new year.

Under the Renewable Fuel Standard, US oil refiners and importers must annually blend different types of biofuels or buy Renewable Identification Number (RIN) credits from those that do. The RIN market is closely watched by producers and marketers of biofuels such as ethanol, biodiesel and renewable natural gas, since higher credit prices make blending economics more attractive.

Policy shifts supported RIN prices in 2025, including new tax credit rules that slashed subsidies for many fuels and encouraged the use of scarcer low-carbon feedstocks, as well as a plan Trump administration plan to require record-high blending during the next two years and to halve RIN credits for foreign fuels and feedstocks.

Following the release of that proposal in June, values for current-year ethanol D6 and biomass-based diesel D4 credits rose to their highest levels since September 2023. RIN traders anticipated more expensive input costs, as reflected in a widening soybean oil-heating oil spread, hurting credit generation at the same time as the Trump administration moved to mandate more blending — the perfect storm for rising prices in 2026.

But uncertainty over other policies has limited RIN credit growth more recently. Since October, current-year D4 and D6 credits have closed each session between 100¢/RIN and 110¢/RIN, rare for markets that are prone to frequent volatility.

The government's unclear approach to exemptions from the biofuel blend program — which eligible small refiners can request at any time for any year — is one wrinkle. During Trump's first term, officials granted small refinery exemptions en masse, injecting a burst of added supply into the RIN market that sank credit prices and made it easier for refiners to reach their targets. Last summer, the Trump administration granted dozens of full and partial exemptions, and more requests are pending, raising fears of a similar supply shock.

But the potential weakness comes with a parachute. The Trump administration has floated making oil companies without exemptions bring more biofuels to market over the next two years to offset recent waivers. The plan has divided the industry and kicked off a last-minute lobbying campaign, with oil majors hoping to avoid picking up the slack and biofuel advocacy groups warning of pain for farmers if biofuel demand lags.

So the market is at a standstill, with RIN traders guessing as to future policy. Strong mandates, penalties for foreign feedstocks and compensating for recent exemptions would support prices. But shifts in policy — coupled with guaranteed higher tax breaks for crop-based fuels in 2026 — threaten the opposite.

Even if administration officials stay quiet until regulations are finalized, the calendar could provide RIN traders with an important signal. The Trump administration last told a court that it expects to finalize updates to the biofuel blend program in first-quarter 2026, meaning the industry will start the year lacking clarity on how many biofuel gallons — and what type — they should bring to market. The delay is important because US regulators have been more cautious in the past when finalizing retroactive biofuel mandates to avoid legal scrutiny.

But the biggest price moves will ultimately depend on final policy clarity.

By Matthew Cope and Cole Martin

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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.

India defers upstream hopes into 2026

02/01/26

India defers upstream hopes into 2026

India wants to open up access to more of its upstream but it is struggling to attract foreign operators, writes Rituparna Ghosh Mumbai, 2 January (Argus) — 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 round under 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. 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.

Viewpoint: California asphalt supply in limbo

02/01/26

Viewpoint: California asphalt supply in limbo

Houston, 2 January (Argus) — The potential closure of US independent Valero's 145,000 b/d refinery in Benicia, California, this spring is expected to boost asphalt trade flows and prices as buyers seek supply from farther afield. Valero in April 2025 said it planned to close or repurpose Benecia by April 2026. The plant produces roughly 400,000 short tons/yr of asphalt, according to market participants, accounting for about 35pc of total asphalt production capacity in the state. Benecia is the only local source of supply for the northern California market. The next closest producer is near Bakersfield in central California, about 280 miles from the San Francisco market. Bay Area retail asphalt prices are expected to rise as buyers shift to delivered rail volumes from the Rocky Mountains or Canada to make up for the shortage. Other North American rail markets could also see upward price pressure, with more volume directed to the US west coast. Bay Area rack prices averaged roughly a $200/st premium to rail values in the Rockies during 2025 and this week have been in the $470-$510/st range. A supply disruption could push prices rapidly higher. The last major disruption out west was in March 2022, when a fire damaged the 58,000 b/d Billings, Montana, refinery, which at the time was owned by ExxonMobil. Wholesale rail values in the Rockies rose to a 14-year high of $612.50/st in July 2022, a 39pc increase from March of that year. Asphalt production capacity in California totals 25,950 b/d or about 4,600 st/d , 15pc below 2020 levels and nearly 50pc below 2015 levels, according to US Energy Information Administration data. US west coast receipts of Rockies asphalt rail shipments totaled about 1.97mn bl or 351,785st through September 2025, 33pc above flows during the same period in 2015. Canadian rail volumes destined for the US west coast have also been on the rise recently. About 61,000 bl or 10,892st of Canadian asphalt landed on the US west coast in September, 9pc above September 2022 flows and the highest level for the month since 2018. Asphalt goes west The pending loss of production has spurred several companies to enter the wholesale asphalt market to fill the supply gap. Construction firm Teichert is developing a new terminal in West Sacramento, California, after purchasing a former fertilizer facility with rail and waterborne access. The facility has access to a deepwater shipping channel, and market participants have noted the possibility of waterborne imports if the economics are favorable. The most recent US west coast waterborne import was in August 2024 when a ship carrying Venezuelan asphalt landed in Portland, Oregon, according to Kpler data. Some market participants said California has never received a waterborne asphalt import. Asphalt terminal operator Ergon and San Joaquin Refining in August announced they had started discussions for a potential strategic partnership, and other suppliers have been heard looking at building tanks in or near California to supply the market. Valero also operates an asphalt terminal with rail access, a truck rack and storage capacity of about 300,000 bl in Pittsburg, California, and some market participants have noted the potential expansion of the site could boost rail flows into the terminal as well. Further south, Marathon Petroleum plans to produce asphalt and construct a truck-loading rack at its 365,000 b/d Los Angeles refinery in Carson, California, according to a project overview released by the company. An increase in asphalt production would likely not be seen immediately, however. Market participants expect Marathon's project to take roughly two years to complete because of the lack of existing asphalt infrastructure at the refinery and California's strict regulatory environment, and that additional source of supply would still be nearly 400 miles from San Francisco. By Cobin Eggers Send comments and request more information at feedback@argusmedia.com Copyright © 2026. Argus Media group . All rights reserved.

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