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Brazil moves to sell more gas to domestic market

  • : Crude oil, Natural gas, Oil products
  • 23/04/06

Brazil took the first step to allow state-owned pre-salt oil marketing company (PPSA) to direct the federal government's share of oil and natural gas to the national market.

The national energy policy council (CNPE) published a resolution today asking the PPSA, with the support of the Energy Research Bureau (EPE), to study and present an analysis on "the technical and economic feasibility of mechanisms to prioritize the national supply of fuels derived from petroleum" within 180 days.

Brazil wants to direct natural gas owned by the government in production-sharing agreements and traded by PPSA to the domestic market — especially to the fertilizer industry — at lower prices, the CNPE has said.

PPSA owns gas from the pre-salt fields, where production could reach 3.2mn m³/d by 2029. The proposed ordinance would require PPSA to swap its crude for gas with producers, add it to the other gas it owns and sell it at a discount to industrial users and thermal power generators in Brazil. The mines and energy ministry estimates that 46,000 b/d of oil can be swapped for gas. The cost for this operation is still unclear.

By Flávia Pierry

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25/12/22

P66, Kinder expand proposed western US fuel pipeline

P66, Kinder expand proposed western US fuel pipeline

Houston, 22 December (Argus) — Independent refiner Phillips 66 and midstream giant Kinder Morgan are expanding a plan for a proposed refined products pipeline system from the midcontinent to western US markets. An initial open season for the project, which closed on 19 December, resulted in significant interest, including shipper commitments for the proposed Western Gateway pipeline, the companies said Monday. As a result, a second open season will launch in January for remaining capacity and will include new destinations west of Colton, California, through a joint tariff with Kinder Morgan's existing SFPP pipeline that will be reversed between Watson, California, and Colton, allowing access to Los Angeles markets. The companies did not disclose the length of the second open season. The Western Gateway project, announced in October, includes a new 200,000 b/d pipeline from Borger, Texas, to Phoenix, Arizona, combined with the reversal of SFPP from Colton, California, to Phoenix, Arizona. Philips 66 owns and operates a 149,000 b/d refinery in Borger. In addition, the Phillips 66-operated Gold pipeline, which currently flows from Borger to St Louis, Missouri, would be reversed to allow refined products from midcontinent refineries to flow south to Borger and supply the Western Gateway system. The companies expect the Western Gateway project to be completed in 2029. The proposed pipeline system comes as two large California refineries are planning to close, including Phillips 66's 139,000 b/d Los Angeles refining complex. Phillips 66 stopped processing crude at the Los Angeles facility in mid-October as part of a planned shutdown announced about a year earlier. It expects to idle remaining units by the end of this month. In addition, Valero is planning to shut down or repurpose its 145,000 b/d refinery in Benicia, California, by April 2026. The planned closures have triggered major concerns about California's tight and often volatile oil products market and the impact on neighboring states . Another large US midstream company, Oneok, is considering building a 200,000 b/d pipeline — the Sun Belt Connector — to carry gasoline, diesel and jet fuel from El Paso, Texas, to Phoenix, Arizona. In addition, US independent refiner HF Sinclair is considering several pipeline expansions that would move more refined products from the Rocky Mountains region to markets further west. By Eunice Bridges Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Viewpoint: US, European LNG spread may narrow in 2026

25/12/22
25/12/22

Viewpoint: US, European LNG spread may narrow in 2026

Houston, 22 December (Argus) — The spread between US and European LNG prices will likely narrow further in 2026, but forward prices indicate US LNG supply under long-term contracts will remain comfortably profitable in international spot markets until at least summer 2027 as a wave of new supply comes on line. A recent rally in the US natural gas market highlighted US LNG's tightening margins. The indicative long-term LNG contract price — 115pc of US benchmark Henry Hub plus a $3/mn Btu liquefaction fee — surpassed the Argus Gulf coast (AGC) spot fob price in early December for the first time in more than two years amid cold weather in the US, mild weather in Europe and high Atlantic basin freight rates. But the premium over the spot price was brief and caused no change to export schedules. The front-month Henry Hub contract quickly shed its gains on warmer weather, falling to $3.89/mn Btu on 16 December from a nearly three-year high of $5.29/mn Btu on 5 December. Prices hovered around $4/mn Btu through 19 December. The impact was solely on profit margins rather than fundamentals. Customers of US LNG facilities did not need to cancel cargoes under take-or-pay provisions because a profit incentive to maximize exports remained. Liquefaction costs are considered sunk, and the spread between Henry Hub and European LNG prices remained wide enough to more than cover shipping costs. Though rising exports may add to domestic pricing volatility during cold winter weather through the end of the decade, US and European gas futures today indicate long-term offtake from US LNG terminals will remain profitable until the summer of 2027, assuming freight rates of $80,000/d and a 50¢/mn Btu discount to the European benchmark TTF for northwest European deliveries. At that time, contracts with $3/mn Btu liquefaction fees could surpass delivered LNG prices in northwest Europe, though the arbitrage for US gas would remain open for contracts with lower fees (see chart) . Fees now range between $2.50-2.80/mn Btu for US supply coming on line toward the end of the decade. Contracts with fees on either end of that range remain below European LNG prices until summer 2029 and summer 2028, respectively, assuming freight rates of $80,000/d. But cargo cancellations are not always necessary when long-term US LNG contract prices surpass international prices. Terminal operators and their customers finalize annual delivery plans as well as upward and downward delivery tolerances before the start of each year, leaving less flexibility later in the year. If a customer wishes to cancel a cargo, they typically must notify the terminal up to two months in advance, which would likely only happen in an environment where the cost of 115pc of Henry Hub plus freight stabilizes above European LNG prices. The spread between Henry Hub and delivered European prices is wide enough to absorb freight costs through winter 2030-31. If an offtaker opts for a lower quantity in its delivery tolerance or cancels a cargo, the volume returns to the terminal operator, which could still market and sell the cargo on the spot market. This effectively shifts the seller of a cargo from the LNG customer to the LNG terminal operator. The likelihood of cancellations beyond 2027 may be higher in the spring and autumn shoulder seasons, when demand in Europe is typically lower. Depending on the previous winter, this may be more likely to occur in autumn, given the annual rebuild of Europe's underground gas inventories that begins in the spring. Additional liquefaction capacity has already helped tighten margins for US LNG since Europe's conflict-driven volatility in 2022 . The AGC fob's premium over the long-term indicative contract averaged $3.95/mn Btu through 19 December this year, down from $4.63/mn Btu, $5.37/mn Btu and $20.13/mn Btu in 2024, 2023 and 2022, respectively. But the anticipated convergence of US and European LNG is not guaranteed. Geopolitical conflict could disrupt existing trade patterns. And lower prices in Europe will be contingent on new LNG projects, led by the US and Qatar, maintaining their timelines, which are prone to delays from supply chain issues and workforce constraints. This would add upside risk to international prices and downside risk for Henry Hub if the delays are in the US. By Tray Swanson European LNG spot prices vs long-term US LNG $/mn Btu Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

US shale firms see subdued spending next year

25/12/22
25/12/22

US shale firms see subdued spending next year

New York, 22 December (Argus) — US president Donald Trump took to prime-time TV this week to reassure voters that 2026 will see a stronger economy, but US shale executives see little prospect of an imminent upturn in their business. US oil and gas firms plan to keep capital spending flat to slightly lower next year, according to a closely watched survey by the Federal Reserve Bank of Dallas, as the industry grapples with lower oil prices. Although activity edged lower in the fourth quarter, uncertainty grew and companies remained increasingly wary about future prospects in the poll of 131 executives from Texas, southern New Mexico and northern Louisiana that was carried out earlier this month. "Decreasing oil prices are making many of our firm's wells uneconomic," one exploration and production (E&P) executive said. "Capital efficiencies and returns drive our investment decisions," another respondent said. "If economic conditions worsen, drilling and completion activities will cease in 2026." The muted outlook for spending next year comes as producers have adopted a wait-and-see approach in recent months, given an increasingly uncertain macro backdrop, with crude prices trading near four-year lows this week on fears of global oversupply. A number of shale operators have posted higher-than-expected production this year. At the same time, spending has come in below expectations as drilling operations become more efficient, a trend UK bank Barclays says could be repeated in 2026. The executives who took part in the Dallas Fed survey gave varied responses when asked about their spending plans for next year depending on their size. Large producers — or those with output of 10,000 b/d or more — were more likely to say they expect capital expenditure to remain close to this year's levels. The most selected response among smaller firms — with production under 10,000 b/d — was for a slight increase. Although there are more small firms in the US, the larger companies account for more than 80pc of total US output. When asked about the oil price they were using for capital planning in 2026, the average response among executives was $59/bl for WTI. That was down from the $68/bl average price for the US benchmark that firms planned to use this year. The Dallas Fed said it was not necessarily a surprise that companies were not planning to trim spending further given weaker oil prices. Capital-intensive care "Oil and gas is a capital-intensive business," the bank's senior business economist, Kunal Patel, said. "It takes a lot of money to sustain the wells, even to keep production flat, and so that's why I don't think you're seeing as many people looking to significantly cut." Also, the prices that companies are using to plan next year's budgets are not too far from current breakeven levels. And producers may yet respond with deeper cuts to spending if prices tumble again. Oil and natural gas production was relatively unchanged in the fourth quarter, the survey showed, while costs rose at a slower pace than in the previous three months. "While oil prices have not been low enough this quarter to force a substantial cutback in activity, they were not high enough to support any growth either," Dallas Fed assistant vice-president Michael Plante said. In its annual E&P spending survey, Barclays expects upstream capital expenditure in North America to fall by 5pc in 2026, on lower US activity, reduced reinvestment ratios, and the impact of drilling and well completion efficiencies. That would mark its third consecutive annual decline. Barclays also revised down this year's upstream spending forecast to a decline of 5pc, from an initial estimate of a 3pc drop. The change was driven by further US rig count losses after Opec+ started to ramp up supplies, as well as the hit from Trump's tariff wars. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

Canada’s oil sands to demonstrate durability in 2026

25/12/22
25/12/22

Canada’s oil sands to demonstrate durability in 2026

Calgary, 22 December (Argus) — Canadian oil sands heavyweights will show durability in 2026 with modest production gains in a lower oil price environment, while tempting investors with bigger, longer-term plans at a time of renewed interest in pipeline projects. Canadian Natural Resources (CNRL), Cenovus, Suncor and Imperial Oil plan to pump out a combined 3.9mn b/d of oil equivalent (boe/d) in 2026, with 75pc of that focused on Alberta's oil sands region. Production gains among the Calgary-based firms will be 1-4pc, with CNRL and Cenovus leading the charge after sizeable acquisitions but also internal growth that has been years in the making. CNRL will push output to a record 1.6mn boe/d across 2026 after becoming sole owner in the 315,000 Albian oil sands mines in Alberta following an asset swap with Shell. The additional bitumen production also simplifies operations for the country's largest oil producer, which can now share trucks and personnel across its oil sands mines, which also includes its fully owned Horizon project. For its part, Horizon skipped a turnaround in 2025 to add 28,000 b/d of production, part of a growing theme of trimming downtime in the oil sands. Meanwhile, Cenovus seems poised to be the second Canadian operator to surpass 1mn boe/d with the upper end of its 2026 guidance just 15,000 boe/d shy of that mark. Boosted by two major acquisitions of cross-town rivals and sizeable organic growth, Cenovus will have doubled production since 2020 when output stood at 471,000 boe/d. It closed on its C$8.6bn ($6.1bn) purchase of MEG Energy in November to bring another 110,000 b/d into its fold, with plans to grow that to 150,000 b/d by 2028. Cenovus five years ago swallowed Husky Energy in a deal to increase its downstream and upstream exposure in Canada and abroad. And the company recently completed a three-year growth investment cycle and expects roughly 100,000 b/d of new production, also by 2028, at Sunrise, Lloydminster and West White Rose in Atlantic Canada combined. Capital spending for the four largest oil sands producers will climb to $14bn in 2026, up by 5pc from 2025, led by CNRL and Cenovus eyeing future growth. Endurance runners The production and spending plans come against a backdrop of global oversupply, highlighting oil sands operators' ability to not only weather, but grow, in a lower oil price environment with their suite of long-life, low-decline assets. Cenovus said its oil sands operating costs will be only $9/bl in 2026, while CNRL in another metric reports its corporate breakeven, including dividends, is just above $40/bl. In other words, oil sands producers would still have breathing space should WTI fall to the $51/bl predicted by the US Energy Information Administration in 2026 . But beyond 2026, an export pipeline capacity crunch is forecast to unfold from the third quarter of 2028 and that could put pressure on domestic prices, according to US bank TD Cowen. Trans Mountain and Enbridge plan for expansions to come on line in mid-to-late 2027, delaying the potential bottleneck by a year. Operators across the basin may be eyeing more growth but may not be ready to accelerate those plans until confidence grows on takeaway capacity. Acquisitions of producing assets may offer more assurance of that. "It's easier to grow by buying. If you grow organically, you pull that egress time forward," TD Cowen's managing director of institutional equity research, Menno Hulshof, said. CNRL has also outlined several projects it may pursue in the longer term, with front-end work due to start in 2026, potentially to unlock up to 260,000 b/d of new capacity between three oil sands projects. Significant output could come on line from 2030, and Alberta's recently proposed 1mn b/d pipeline to the Pacific will be key to an investment revival in the province. By Brett Holmes Oil sands capex guidance ($bn) 2026 2025 ±% 2026/25 CNRL 4.6 4.2 9 Cenovus 3.7 3.5 7 Suncor 4.1 4.2 -2 Imperial Oil 1.5 1.4 5 — company budgets Oil sands production guidance (boe/d) Oil sands Other Total ±% 2026/25 CNRL 867,500 752,500 1,620,000 3 Cenovus 767,500 197,500 965,000 4 Suncor 797,500 57,500 855,000 1 Imperial Oil 450,500 0 450,500 4 — company 2026 budgets Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

German fuel demand rises before 2026 price increase

25/12/22
25/12/22

German fuel demand rises before 2026 price increase

Hamburg, 22 December (Argus) — German consumers increased fuels orders in the last full working week of 2025 to fill their tanks ahead of a probable price increase at the start of the new year. Low prices also boosted heating oil demand. Fuel demand rose significantly in the week ending 21 December, after stockbuilding failed to materialise in the previous week. Diesel spot sales for truck loading submitted to Argus increased by almost 50pc on the week, and E5 gasoline sales by 35pc. Diesel sales on 17 December were the highest in four months, while gasoline sales were the highest since September 2023. Gasoline filling stations, freight forwarders and other large-scale consumers waited until the last minute to fill their tanks before higher costs from the CO2 tax and greenhouse gas (GHG) quota take effect in 2026. Sellers recently offered B7 diesel for loading in January with premiums of €10-13/100l, and gasoline prices rose by a similar amount. Gasoline filling stations built up stocks ahead of the holidays, because the few remaining working days until the end of the year restrict logistics. Low prices also drove heating oil demand, at least in the first half of the week. The national average heating oil price reached its lowest point for the year on 16 December. This motivated consumers to buy, although the premiums for the new year are much lower than for road fuels at around €3-4/100l because of the CO2 tax increase. But some can only be delivered in January because of logistical bottlenecks. Heating oil spot volumes in 2025 so far are around 10pc above the 2024 level, mainly because consumers stocked up when the front-month Ice gasoil futures contract reached its lowest level since the end of 2021 in early April. The heating oil price fell to its lowest level in more than three years. Prices were subdued by the prospect of a global economic slowdown as a result of the trade conflict between the US and China and the so-called reciprocal duties for some of the US' most important trading partners. Lower Ice gasoil futures also triggered additional purchases at the end of November. Diesel spot volumes in 2025 were around 5pc below the previous year, probably because of a weak manufacturing sector. The average production index in January-October was almost two percentage points below the same period in 2024 and about six points below 2023. The truck mileage index lagged behind previous years in most months, with a noticeable affect on industrial demand for diesel. By Gabriele Zindel and Johannes Guhlke Send comments and request more information at feedback@argusmedia.com Copyright © 2025. Argus Media group . All rights reserved.

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