Phillips 66 to shut Los Angeles refinery late 2025

Market: Crude oil, Oil products
16/10/24

US independent refiner Phillips 66 will shut its 139,000 b/d Los Angeles, California, refinery in the fourth quarter of 2025, citing an uncertain future in the state.

The company said it is working with land and real estate development firms to evaluate the future use of the 650-acre site that houses linked facilities in Wilmington and Carson employing 600 staff and 300 operators.

Chief executive Mark Lashier said in a press release today that the long-term sustainability of the company's Los Angeles operations was "uncertain and affected by market dynamics" but that Phillips 66 is committed to meeting ongoing California demand.

Phillips 66 plans to supply California gasoline markets with fuels from its own refining network and from other suppliers while supplying renewable diesel (RD) and sustainable aviation fuel (SAF) from its Rodeo renewables refinery near San Francisco.

It is unclear what project Phillips 66 is eyeing for the Los Angeles site, but Lashier said it would "support the environment" and improve the regions "critical infrastructure".

Earlier this week, California governor Gavin Newsom (D) a bill authorizing the state's energy regulator to require refiners to maintain minimum gasoline inventories. It was the latest step in an ongoing regulatory effort by Newsom's office to mitigate against gasoline price spikes, but is viewed by the industry as a broader, hostile attack on its business.

Chevron, the US oil major that has long complained about a hostile regulatory environment in its home state of California, to relocate its headquarters to Houston.

By Nathan Risser

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16/10/24

US west coast retail asphalt prices weaken with TMX

Houston, 16 October (Argus) — California retail asphalt prices declined in October as the 590,000 b/d Trans Mountain Expansion (TMX) pipeline altered local crude dynamics. October prices for Bay Area, Los Angeles and Bakersfield racks dropped by $10/st to $40/st from September and ranged from about 8pc to 13pc below year-prior prices. October is typically a month with strong demand, and the National Weather Service reported below-normal precipitation levels over the past two weeks. Even so, asphalt prices were pressured lower by a weaker local crude index. The California state crude oil price index declined by roughly $32/st to $401.40/st for October, its lowest level since September 2021, as TMX becomes a valuable crude source for US west coast refiners. Retail asphalt prices in California typically follow changes in the state's index, which is linked to the cost of local crude in the Buena Vista and Midway Sunset fields. The monthly state crude index posting from January to April averaged a $95/st discount to WTI crude futures over the period. From May to October, following the commercial start of TMX, WTI's premium over the state index widened to about $104/st. The larger differential comes as refiners in California increased imports of Canadian crude even as TMX opened an outlet for oil sands producers to ship to Asia. Canadian crude imports to California refineries have more than quadrupled since the commercial start of the pipeline compared to the same time last year, according to Kpler data. Some market participants noted TMX crude produces high quality asphalt, but diluents added to improve flow on the pipeline has forced some refiners to limit runs. US west coast asphalt inventories averaged about 2.7mn bl from May to July 2024, according to the latest US EIA data. This is roughly 2pc below levels seen over the same period in 2023. By Cobin Eggers Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Japan’s Kansai to scrap Ako oil-fired units in 2025

16/10/24

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16/10/24

Japan’s Kansai to scrap Ako oil-fired units in 2025

Tokyo, 16 October (Argus) — Japanese power utility Kansai Electric Power is planning to decommission its 600MW No.1 and No.2 ageing oil-fired units at its Ako power complex at the end of July 2025. Kansai plans to close the ageing oil-fired power units in Hyogo prefecture on 31 July next year as it is hard to maintain those units, especially after overuse during the fiscal year of 2020-21 .The property will be used to set up a power plant which does not emit carbon emissions, Kansai said but did not reveal further details. Kansai previously planned to convert the 36- and 37-year-old power units to burn coal instead of oil, but was forced to scrap the plan because of emissions concerns. Kansai's remaining oil-fired power units will be only the 600MW No.1 and No.3 units at its Gobo power complex after the Ako's closures. The utility's oil consumption totalled 2,750 b/d in 2023-24, down by 84pc on the year, according to the company's latest financial result. By Reina Maeda Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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IEA sees steeper oil demand fall in long-term outlook

16/10/24

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16/10/24

IEA sees steeper oil demand fall in long-term outlook

London, 16 October (Argus) — Long term global oil demand is set to fall by more than previously anticipated, according to the baseline scenario in the IEA's latest World Energy Outlook (WEO). The Paris-based agency's stated policies scenario (Steps), which is based on prevailing policies worldwide, sees global oil demand — excluding biofuels — falling to 93.1mn b/d in 2050, compared with 97.4mn b/d in last year's WEO. This is mainly because of lower-than-previously expected oil use in transportation, particularly in shipping. The Steps scenario still sees global oil demand peaking before 2030 at less than 102mn b/d, after which it falls to 2023 levels of 99mn b/d by 2035. This is mostly because of a rapid uptake of electric vehicles (EVs), reducing oil demand for road transport. EVs have displaced around 1mn b/d of gasoline and diesel demand since 2015 and are set to avoid 12mn b/d of oil demand growth between 2023 and 2035 under Steps, the IEA said. The latest Steps scenario shows China's pre-eminence in global oil demand growth is fading, as the world's second largest oil consumer shifts towards electricity. Steps sees Chinese oil demand growing by just 1.2mn b/d to 17.4mn b/d by 2030, and then falling to 16.4mn b/d by 2035 and to 11.8mn b/d by 2050. India overtakes China as the world's main source of oil demand growth in Steps, adding almost 2mn b/d by 2035 and 2.4mn b/d by 2050. But its oil consumption in 2050 of 7.6mn b/d will still be lower than China's in the same year. The IEA's latest baseline oil demand scenario widens the gap with producer group Opec, which sees oil consumption continuing to rise to 2050 "with the potential for it to be higher." Opec's World Oil Outlook (WOO) — released in September — bumped up its long-term oil demand forecast to 2045 by around 3mn b/d compared with its previous release. It extended its forecast period to 2050, when it put oil demand at 120mn b/d. That equates to a 27mn b/d difference between the IEA and Opec baseline oil demand scenarios in 2050. Binding contraction The IEA said the slowdown in oil demand growth in its Steps scenario puts major resource owners, such as Opec+ countries, "in a bind" as they face a significant overhang of supply. Global spare oil production capacity of around 6mn b/d is set to rise to 8mn b/d by 2030 if announced projects go ahead, it said. The Steps scenario sees global oil production falling from 96.9mn b/d in 2023 to 90.3mn b/d in 2050, with Opec increasing its share of output from 34pc to 40pc in the period. Steps sees US oil supply growth continuing to 2030 and then contracting by around 250,000 b/d a year on average between 2030-50. Brazil, Argentina and Guyana are seen adding more than 2.5mn b/d to supply by 2035. The WEO explores two other scenarios — the announced pledges scenario (APS) assumes government targets on emissions are met in full and on time, while the net zero emissions by 2050 (NZE) scenario lays a path to limit global warming to 1.5°C. Oil demand in 2050 in APS and in NZE is lower compared with last year's WEO. In APS, oil demand falls to 92.8mn b/d by 2030, 82mn b/d in 2035 and 53.7mn b/d by 2050 — with around 135mn more EVs on the road by 2035 compared with Steps. In NZE, oil demand falls to 78.3mn b/d by 2030, 57.8mn b/d by 2035 and 23mn b/d by 2050 — with 1.14bn more EVs on the road by 2035 compared with Steps. By Aydin Calik Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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Tax credit delay risks growth of low-CO2 fuels

15/10/24

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15/10/24

Tax credit delay risks growth of low-CO2 fuels

New York, 15 October (Argus) — A new US tax credit for low-carbon fuels will likely begin next year without final guidance on how to qualify, leaving refiners, feedstock suppliers, and fuel buyers in a holding pattern. The US Treasury Department this month pledged to finalize guidance around some Inflation Reduction Act tax credits before President Joe Biden leaves office but conspicuously omitted the climate law's "45Z" incentive for clean fuels from its list of priorities. Kicking off in January and lasting through 2027, the credit requires road and aviation fuels to meet an initial carbon intensity threshold and then ups the subsidy as the fuel's emissions fall. The transition to 45Z was always expected to reshape biofuel markets, shifting benefits from blenders to producers and encouraging the use of lower-carbon waste feedstocks, like used cooking oil. And the biofuels industry is used to uncertainty, including lapsed tax credits and retroactive blend mandates. But some in the market say this time is unique, in part because of how different the 45Z credit will be from prior federal incentives. While the credit currently in effect offers $1/USG across the board for biomass-based diesel, for example, it is unclear how much of a credit a gallon of fuel would earn next year since factors like greenhouse gas emissions for various farm practices, feedstocks, and production pathways are now part of the administration's calculations. This delay in issuing guidance has ground to a halt talks around first quarter contracts, which are often hashed out months in advance. Renewable Biofuels chief executive Mike Reed told Argus that his company's Port Neches, Texas, facility — the largest biodiesel plant in the US with a capacity of 180mn USG/yr — has not signed any fuel offtake contracts past the end of the year or any feedstock contracts past November and will idle early next year absent supportive policy signals. Biodiesel traders elsewhere have reported similar challenges. Across the supply chain, the lack of clarity has made it hard to invest. While Biden officials have stressed that domestic agriculture has a role to play in addressing climate change, farmers and oilseed processors have little sense of what "climate-smart" farm practices Treasury will reward. Feedstock deals could slow as early as December, market participants say, because of the risk of shipments arriving late. Slowing alt fuel growth Recent growth in US alternative fuel production could lose momentum because of the delayed guidance. The Energy Information Administration last forecast that the US would produce 230,000 b/d of renewable diesel in 2025, up from 2024 but still 22pc below the agency's initial outlook in January. The agency also sees US biodiesel production falling next year to 103,000 b/d, its lowest level since 2016. The lack of guidance is "going to begin raising the price of fuel simply because it is resulting in fewer gallons of biofuel available," said David Fialkov, executive vice president of government affairs for the National Association of Truck Stop Operators. And if policy uncertainty is already hurting established fuels like biodiesel and renewable diesel, impacts on more speculative but lower-carbon pathways — such as synthetic SAF produced from clean hydrogen — are potentially substantial. An Argus database of SAF refineries sees 810mn USG/yr of announced US SAF production by 2030 from more advanced pathways like gas-to-liquids and power-to-liquids, though the viability of those plants will hinge on policy. The delay in getting guidance is "challenging because it's postponing investment decisions, and that ties up money and ultimately results in people perhaps looking elsewhere," said Jonathan Lewis, director of transportation decarbonization at the climate think-tank Clean Air Task Force. Tough process, ample delays Regulators have a difficult balancing act, needing to write rules that are simultaneously detailed, legally durable, and broadly acceptable to the diverse interests that back clean fuel incentives — an unsteady coalition of refiners, agribusinesses, fuel buyers like airlines, and some environmental groups. But Biden officials also have reason to act quickly, given the threat next year of Republicans repealing the Inflation Reduction Act or presidential nominee Donald Trump using the power of federal agencies to limit the law's reach. US agriculture secretary Tom Vilsack expressed confidence last month that his agency will release a regulation quantifying the climate benefits of certain agricultural practices before Biden leaves office , which would then inform Treasury's efforts. Treasury officials also said this month they are still "actively" working on issuing guidance around 45Z. If Treasury manages to issue guidance, even retroactively, that meets the many different goals, there could be more support for Congress to extend the credit. The fact that 45Z expires after 2027 is otherwise seen as a barrier to meeting US climate goals and scaling up clean fuel production . But rushing forward with half-formed policy guidance can itself create more problems later. "Moving quickly toward a policy that sends the wrong signals is going to ultimately be more damaging for the viability of this industry than getting something out the door that needs to be fixed," said the Clean Air Task Force's Lewis. By Cole Martin Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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PetroChina offloads TMX crude pipeline commitment

15/10/24

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15/10/24

PetroChina offloads TMX crude pipeline commitment

Calgary, 15 October (Argus) — PetroChina Canada is no longer a shipper on the 590,000 b/d Trans Mountain Expansion (TMX) crude pipeline, less than six months after Canada's newest pipeline went into service. The Chinese-owned refiner has parted with its commitment on the pipeline connecting Edmonton, Alberta, to Burnaby, British Columbia, according to a letter to the Canada Energy Regulator on 10 October. The project has helped Canadian crude producers reach new markets on the Pacific Rim, with China often singled out as a target. PetroChina Canada "has now assigned these agreements to another party and will not be a committed shipper going forward," the letter read, without disclosing the other company or reasoning. TMX roughly tripled the capacity of the Trans Mountain system to 890,000 b/d when it went into service on 1 May, but critics questioned how useful the expansion would be. Shippers were quick to dispel any concerns about the line's utilization by ramping up throughputs in the first few months of service. The latest official figures from Trans Mountain show 704,000 b/d was shipped in June , its first full month of operation. However, the expansion was riddled with construction delays and of concern is who will ultimately foot the bill for the C$35bn ($25bn) project's cost overruns — Trans Mountain or shippers through higher tolls. The original budget for the project was C$5.5bn when first conceived more than a decade ago with many of the shippers signing up for capacity around that time. The tolling dispute will continue into 2025 to determine what portion of the extra costs the shippers will be responsible for, with the regulator responsible for making the final decision. Interim tolls in place have the fixed costs for a heavy crude shipper with a 20-year term to move 75,000 b/d or more at about C$9.54/bl ($6.96/bl). "Shippers should not reasonably be expected to be subject to C$7.4bn (and counting) in cost growth without serious scrutiny of Trans Mountain's costs," lawyers in March this year told the CER on behalf of several shippers, including PetroChina. Trans Mountain says approximately 80pc of the TMX is backed by firm commitments with the balance saved for walk-up shippers. PetroChina Canada owns the MacKay River oil sands project in northeast Alberta which has produced about 10,000 b/d of bitumen from January to August this year, according to data from the Alberta Energy Regulator (AER). PetroChina Canada also owns the undeveloped Dover oil sands project, has a 50pc stake in the Grand Rapids oil sands pipeline, natural gas production in western Canada and a 15pc stake in the 14mn t/yr LNG Canada export facility. By Brett Holmes Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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