TotalEnergies sees 'exceptional' refining result in 2Q

: Crude oil, Natural gas, Oil products
22/07/15

TotalEnergies expects its refining and chemicals division to deliver "exceptional" results in the second quarter, driven by "very high" margins for middle distillates and gasoline.

The company said on 15 July that the variable cost margin achieved by its European refining business averaged $145.70/t in April-June, more than three times the level of the previous three months and around 14 times higher than the second quarter of 2021. It marks the highest refining margin by some distance since the company began reporting a variable cost indicator in 2018.

Refinery output across the industry struggled to keep up with demand in the second quarter, while gains in oil product prices and crack spreads outpaced rises in crude values. Other integrated oil and gas companies — including Shell, ExxonMobil and Spain's Repsol — have also flagged up a pending windfall from soaring refining margins in recent trading updates.

Upstream profits are set to be strong as well, given the rise in oil and gas prices compared with the second quarter last year. But for TotalEnergies, the higher price environment will be partially offset by a drop in production. The firm expects its upstream output, excluding LNG, to be around 100,000 b/d of oil equivalent lower than the first quarter on the back of disruptions in Nigeria and Libya, as well as a higher volume of planned maintenance.

The company said it expects to report a strong performance from its integrated gas, renewables and power segment "but without replicating the exceptional contribution of the first quarter of 2022".

By James Keates

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24/12/30

Viewpoint: Permian waiting on new gas lines

Houston, 30 December (Argus) — Natural gas prices in the Permian basin of west Texas and southeast New Mexico fell to historic lows in 2024, with increased takeaway out of the region likely not picking up before 2026. Gas in the Permian basin is fundamentally tied to crude economics, with associated gas being a byproduct of crude-directed drilling. US benchmark WTI values continued to boost crude output in 2024, with month-ahead Nymex WTI futures for delivery in 2024 averaging $76.20/bl, down from $78/bl in 2023, but still much higher than in previous years since 2014. As of the week ended 20 December, the Permian basin rig count stood at 304 rigs, down by only five rigs from the same time a year prior , according to oilfield service provider Baker Hughes. The vast majority of those rigs were crude-directed. Strong associated gas output has frequently pushed spot prices at the Waha hub in west Texas into negative territory since 2019. Waha prices held positive through 2021, helped in part by increased takeaway capacity, before turning negative in four trading sessions in 2022 and seven sessions in 2023. Negative Waha prices were a much more regular feature in 2024, with sellers needing to pay buyers to take Permian gas for about 47pc of the trading sessions throughout January-November. The Waha index fell to -$7.085/mmBtu on 29 August, a historic low. But prices averaged above $2/mmBtu from the middle of November into the first half of December , buoyed by seasonally stronger demand and the end of planned and unplanned maintenance on several Permian pipelines. Spot prices at the Waha hub returned below $1/mmBtu in the final full week of December, as unseasonably mild weather crimped demand. The January-March block for Waha was $2.235/mmBtu as of 27 December, according to Argus forward curves. Spot prices often have been negative despite growing export demand from the LNG sector and for pipeline flows to Mexico. Even excluding potential flows through the most recently commissioned 1.7 Bcf/d (17.6bn m³/yr) ADCC pipeline in south Texas, aggregate feedgas flows to US liquefaction facilities edged higher to 12.9 Bcf/d in January-November from 12.75 Bcf/d a year earlier. Pipeline exports to Mexico rose to 6.06 Bcf/d in January-September from 5.7 Bcf/d a year earlier, US Energy Information Administration (EIA) data show. Pipelines out of the Permian have typically taken little time to reach capacity, as was the case when US firm Kinder Morgan's Gulf Coast Express and Permian Highway pipelines opened in 2019 and 2020, respectively, and more recently in 2021 with the Whistler pipeline. Similarly, flows on the 2.5 Bcf/d Matterhorn Express Pipeline quickly ramped up in October after the line began taking on gas in September. Takeaway capacity out of the Permian is not planned to rise much further before 2026. Several large new pipelines remain under construction or in the planning stage, including the 2 Bcf/d Apex and 2.5 Bcf/d Blackcomb pipelines, both due to enter service in 2026. Oneok's 2.8 Bcf/d Saguaro Connector pipeline is not expected before 2027. Targa's proposed Apex Pipeline, which would link the Permian to the Port Arthur LNG project, remains under consideration. Oversupply led to output cuts in more gas-directed fields in the US in 2024, but Permian gas production has been immune to the low price environment. Low or negative prices at Waha may eventually spur output cuts in the oil-oriented Permian, but that would require WTI prices falling closer to breakeven. Permian producers need WTI to be at a minimum of $62/bl to profitably drill a new well, while the breakeven price for an existing well was $38/bl, according to an April survey by consumer data platform Statista. Producers such as Chevron do plan to curb spending in the region by as much as 10pc in 2025. Chief executive Mike Wirth noted in the company's third quarter 2024 earnings call that Permian "growth will become less the driver and free cash flow will become more of the driver". Yet Permian gas, which accounts for roughly a fifth of US output, is still set to rise to 26.1 Bcf/d in 2025 from a projected 24.8 Bcf/d in 2024, according to the US EIA's December Short-Term Energy Outlook . By David Haydon Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Trump tariffs may shift crude flows to USWC

24/12/30

Viewpoint: Trump tariffs may shift crude flows to USWC

Houston, 30 December (Argus) — President-elect Donald Trump's proposed 25pc tariff on Canadian and Mexican imports could redirect key imported oil grades from the US west coast, opening avenues for displaced Latin American crudes to reappear. The tariffs, which Trump announced on 25 November, could displace about 9pc of the crude US west coast refiners import. Canadian crude flows from the newly expanded 890,000 b/d Trans Mountain pipeline system, which recently have drawn purchases in the US west coast, would force barrels to Asia-Pacific . Mexican crude sellers would divert crude to other outlets as well, like Europe or Asia-Pacific. Refiners on the US west coast increased purchases of Canadian grades after the May startup of the Trans Mountain Expansion (TMX). Cheaper prices and closer proximity to Vancouver, British Columbia, where TMX crude loads, allowed the heavy sour crudes to find favor along the US west coast. But the proposed tariffs could raise landed TMX prices, no longer making it the cheapest heavy sour option. US west coast buyers would pay a 25pc import tariff to US Customs and Border Protection on TMX crude once it has entered port. US west coast refiners received around 169,000 b/d of crude from the Vancouver area since the pipeline came on line in May, up from less than 40,000 b/d a year earlier, data analytics firm Vortexa shows. Around 60pc of Mexico's crude exports in 2024 went to the US, mostly to the US Gulf coast, according to Vortexa data. Tariffs could lead to a drop in prices to adjust to a tariffed American market or for Mexican crude going more often to other destinations such as Europe or Asia-Pacific. Spain, South Korea and India, were the second, third and fourth most common destinations for Mexican crude exports in 2024, respectively. Mexico's crude production and export infrastructure is concentrated on the country's east coast, making exports to Asia-Pacific difficult. Mexico would need to invest in building exporting infrastructure from the west coast to improve trade routes to Asia, market participants say. But Mexico's state-owned oil company Pemex plans to continue cost-cutting measures, led by recently elected President Claudia Sheinbaum, so infrastructure expansion is unlikely. Other Latin crudes could also experience a rise after being displaced by the commencement of TMX in May. Since then, heavier crudes from countries such as Colombia, Ecuador and Argentina have found more frequent routes to the US Gulf coast and Asia-Pacific. Market participants believe lighter Brazilian grades could find routes to the US west coast as TMX supply increases in China. China imported 683,000 b/d of Brazilian crudes in 2024, c ompared with 180,000 b/d of imports to the US west coast from Brazil, according to Vortexa. Sources say the tariffs are a bargaining chip by the incoming administration, and participants are skeptical they will be implemented by the Trump administration. Instead, the tariffs could exclude crude and other commodities. More than $3.3bn of goods and services cross the US-Canada border each day, according to Canada's Fall Economic Statement (FES), which notes Canada is the largest market for 36 US states. Market participants are vocally against the proposed tariffs. Tariffs on crude and refined products "will not help our industry compete, nor will they support US energy dominance and affordability for consumers," the American Fuel and Petrochemical Manufactures said on 27 November . Cenovus is also trying to explain to policy makers in the incoming Trump administration how tariffs on Canada could impact the energy system in North America. But the incoming administration shows no sign of backing off the tariffs for 2025. By Rachel McGuire and João Scheller Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: Chancay port may increase Peru bunker demand

24/12/30

Viewpoint: Chancay port may increase Peru bunker demand

New York, 30 December (Argus) — The opening of Peru's Chancay port next year likely will boost the country's bunkering demand and drive-up competition on the Latin American Pacific coast. Able to accommodate larger ships and vessels equipped with marine exhaust scrubbers, the unveiling of the new facility — likely in the first quarter — could spur demand for very low-sulphur fuel oil (VLSFO) and high-sulphur fuel oil (HSFO). Chancay, which is owned by Chinese state-owned port operating company Cosco Shipping and Peruvian mining company Volcan, has a 17.8-meter depth, compared with a depth of 16 meters in El Callao part, which is south of Chancay near Lima, Peru. Chancay's depth allows it to receive container ships with a capacity of up to 18,000 twenty-foot equivalent units The larger vessels will likely take on around 3,000-5,000 metric tonnes of marine fuel in one port call, according to one source familiar with the Peruvian bunker market. "The port is gradually beginning to receive container vessels, RoRo, and bulk carriers," said Augusto Ganoza, who heads Chilean bunker supplier Agunsa's operations in Peru. "I anticipate an increase in bunkering demand at Chancay, particularly if vessels call at Callao first and then proceed to Chancay, which I believe will be the case for most." But bunker buying appetite in Chancay also will depend on marine fuel prices in China. El Callao VLSFO was assessed at a $85/t premium to Zhoushan, China, in November. That differential tightened from its peak earlier this year at $143/t in April. That differential could temper the expected increase in bunkering demand in Peru. Other market contacts from outside Peru said that any increase in demand stemming from Chancay's opening is unlikely to drag down activity in competing ports such as Panama, largely because of higher prices in Peru and better quality of bunker fuel available in Panama. The VLSFO November monthly average in El Callao was $656/t, which was an $89/t premium to Panama VLSFO. By Luis Gronda Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US midcon E15 shift looms again

24/12/30

Viewpoint: US midcon E15 shift looms again

Houston, 30 December (Argus) — A potential reformulation of gasoline in eight midcontinent states to accommodate year-round 15pc ethanol gasoline (E15) could lead to shortages in midcontinent fuel supply and an increase in retail prices in 2025. Approaching the 2025 summer driving season, Illinois, Iowa, Minnesota, Nebraska, Ohio, South Dakota, Wisconsin and, now, Missouri once again await the US Environmental Protection Agency's (EPA) enforcement of compliance on their exclusion from the 1-psi rule. The one-pound waiver in the Clean Air Act allows for a 1 psi higher Reid Vapor Pressure (RVP), a more expensive specification for 9-10pc ethanol blend that allows gasoline during the summer to be 9 RVP. Opting out would lead to the production of two separate grades of gasoline, the standard summer 9 RVP CBOB and a new, non-waiver 7.80 RVP CBOB that could be blended into E15. Many of the refiners and pipelines in the region would serve states that have opted out of the waiver, and states that will remain within the waiver and the lack of uniformity in specifications across the midcontinent would likely cause difficulty in logistics for refiners and pipeline operators. This new 7.80 RVP gasoline formulation would be a boutique grade CBOB that would only be found in the midcontinent during the summer, adding to the difficulty of producing the grade. The differences between the waiver and the non-waiver grades of gasoline would be mostly contained to the summer driving season, according to participants in the US midcontinent gasoline market. American Fuel and Petrochemical Manufacturers (AFPM), a trade association for fuel makers, again petitioned the EPA to delay the midcontinent governors' request until 2026. AFPM cited a new study by US consultancy Baker and O'Brien that forecast a 131,000 b/d decrease in CBOB production if the midcontinent states were to opt out of the waiver. This would be the equivalent of a sustained refinery outage in the region and could lead to supply-cost increases of 9-12¢/USG, up from an estimated 8-12¢/USG a year earlier. Baker and O'Brien's study also indicated that supply costs could be between $700mn and $1.2bn, with the lower end using the 185 days of the summer driving season with no disruptions and the upper end of the range assuming at least a two-week regional supply shortage. The study also said that a delay until 2026 would allow for more time to implement the capital investments needed to fully accommodate the change to non-waiver gasoline in some of the states but noted that many of the improvements needed would take two years to complete. Many refiners and pipeline operators are hesitant to invest when a legislative solution could make the changes unnecessary. US Gulf coast supply lines The US midcontinent relies on the US Gulf coast to provide resupply in the event of a refinery outage in the region or to accommodate increasing demand. The Explorer Pipeline which connects from the US Gulf coast to the US midcontinent is one of the major pipelines to deliver product into the region. Transit time on the pipeline for delivery to the Chicago area is roughly two weeks. The US midcontinent in 2021-2024 averaged receipts of 1.16mn bl/month of finished gasoline during the May-September summer driving season, according to US Energy Information Administration data. The arbitrage for shipping CBOB into the US midcontinent from the US Gulf coast is already on average open across the summer. A change in formulations would likely increase the need for product. Southern US midcontinent CBOB averaged an 8.33¢/USG premium to US Gulf coast product during the summer, over the Explorer's 7.14¢/USG tariff for shipping product from Pasadena, Texas, to Tulsa, Oklahoma. Chicago's Buckeye Complex CBOB averaged a 10.10¢/USG premium to its Gulf coast counterpart, also over the 8.40¢/USG tariff for shipping. History of delays The governors of Iowa, Nebraska, Illinois, Minnesota, Wisconsin, Illinois, Kansas, South Dakota and North Dakota in 2022 requested an exclusion from the 1-pound waiver in the Clean Air Act by claiming the waiver was contributing to air pollution in those states, a request that would require blendstocks for E10 and E15 sold in those states to be reformulated. The EPA granted their request in February 2024, but delayed lifting the waiver for summer 2024, following a slew of petitions from trade associations, refiners and pipeline companies asking for delays. The measure is still pending. President Joe Biden's administration avoided a potential disruption to seasonal E15 sales by tapping emergency powers in April 2022 to allow for the sale of E15 during the approaching summer, citing supply disruptions in the wake of Russia's invasion of Ukraine. EPA issued similar emergency waivers ahead of summer in 2023 and 2024 to facilitate the sale of E15, using the waiver 9 RVP gasoline. The US Congress is considering legislation options to avoid requirements to reformulate gasoline. A stopgap government funding bill that would fund the government through March included language to extend the one-pound waiver to E15 year-round and make the shift by the eight midcontinent states and the attached reformulation unnecessary. But the E15 provision was pulled from the stopgap funding bill following criticisms from President-elect Donald Trump and Telsa chief executive Elon Musk . By Zach Appel Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Viewpoint: US fuel oil supply challenge to deepen

24/12/30

Viewpoint: US fuel oil supply challenge to deepen

Houston, 30 December (Argus) — US residual fuel oil supplies are dwindling and face multiple challenges in 2025 because of reduced global inventories and a persistent backwardation in the domestic market. Total US inventories of residual fuel oil fell to a historic 42-year-low multiple times during 2024, including nine instances in the fourth quarter alone, according to Energy Information Administration (EIA) data. Supplies hit rock bottom at just under 23mn bl in the week ending 29 November, down by 12pc year-on-year. Despite the shrinking supplies, the US market has shown little reaction. Throughout 2024, ICE Brent futures — the basis for US residual fuel oil — remained in backwardation between the front and second month, averaging $0.60/bl. This is nearly double the full year 2023 backwardation average of $0.39/bl. The persistent backwardation of the fuel oil curve means inventory figures lack the drive to encourage wholesalers and retailers to make purchases in anticipation of future demand, traders said. The diminishing future value results in potential losses for traders who are considering purchasing spot barrels for storage as forward prices are lower than current spot prices. Residual fuel oil is primarily used as a maritime fuel for large ships, a fuel for backup power generation and for various industrial purposes. In the US it is often refined further into other road fuels. The production of US residual fuel oil has been steadily increasing in recent years, beginning even before implementation of the International Maritime Organization's 2020 global rule imposing a 0.5pc sulphur cap on marine fuels. However, output averages over the past four years remain well below pre-2019 levels. Since the US imposed sanctions on Russian fuel exports in February 2023, weekly residual fuel oil imports into the US have averaged just over 100,000 b/d, nearly half of the previous two-year average at 196,000 b/d. Mexico has now become the largest fuel oil exporter to the US, accounting for nearly 33pc of all US fuel oil imports over the past two years, claiming the top spot from Russia. Planned expansion of Mexico's refinery infrastructure may crimp US supplies, however. Mexican state-owned Pemex's 400,000 b/d Dos Bocas refinery — which is still in the start-up process — would take a greater share of Mexico's Maya crude. Maya crude yields a significant portion of fuel oil when refined. This would leave less Maya bound for the US, which has taken nearly 60pc of Mexico's Maya over the past three-years, according to Vortexa data. Pemex is also adding two new coker units to its Tula and Salinas Cuz refineries as part efforts to become more self-reliant and add an additional 168,000 b/d of road fuel output. Coker units process fuel oil to turn it into higher value road fuels, which would curtail flows to the US. Refinery maintenance involving a few US crude distillation units is set to begin in January, which could further limit domestic fuel oil production. The National Weather Service's winter forecast for the east coast is expected to be warmer than usual, likely leading to reduced demand for both high-sulphur fuel oil used in power generation and low-sulphur blending components. By Craig Ross Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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