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US oil company filings put 'spotlight' on taxes

  • Market: Crude oil, Natural gas, Oil products
  • 14/10/24

Recently reported data showing some US-headquartered oil and gas companies regularly paid less in taxes to the US than to foreign governments could become a focus in an upcoming debate in the US Congress over federal tax policy.

ExxonMobil reported paying nearly $1.2bn in taxes to the US in 2023, a fraction of the $5.6bn in taxes it paid to the UAE the same year, according to a first-time "Form SD" report it filed with the US Securities and Exchange Commission (SEC) last month. In its own report, Chevron disclosed it paid nearly $1.2bn in taxes to the US last year, compared with $4bn to Australia. US independent Hess paid $190,000 in taxes to the US last year and $50mn in taxes to Malaysia.

Oil industry officials say the data on tax payments — disclosed ahead of a 30 September deadline the SEC set as part of a long-delayed provision from the 2010 Dodd-Frank Act — does not provide a comprehensive view of industry's tax obligations, which can vary among countries depending on the tax code and their operations. The payment disclosures also do not cover payroll taxes or state and local taxes, for example, and do not say if a company had carryover net operating losses or tax credits that reduced its overall tax bill in the US.

"It would be very inaccurate to reach a conclusion that only takes a little bit of information, and try to extrapolate from that the big picture," an oil industry official said.

But tax watchdogs say the disclosures should give Congress further cause to revisit the federal tax code, to understand why some profitable oil companies headquartered in the US are able to pay far less in taxes to the US than to foreign governments, or in some years pay no taxes to the US. US independent Apache parent APA reported paying no income taxes to the US in 2023 on a net income of $2.3bn, according to its filing. APA said "tax net operating losses" last year reduced its tax bill to zero.

"Having this information publicly available puts a spotlight on an industry that so far has escaped that attention," nonprofit group Financial Accountability and Corporate Transparency Coalition's policy director Zorka Milin said. "It does put them on a back foot. I think that's obvious, and they need to get used to that."

The tax disclosures, which only cover publicly listed companies, show some US oil companies with international operations paid nearly all of their government taxes to the US. US independent EOG Resources paid $1.1bn in taxes to the US last year and $9mn to Trinidad. US independent Devon Energy's $350mn in reported tax payments last year went entirely to the US, according to its filing. Devon has operations in Canada but no reported tax payments.

ExxonMobil, in a filing with the SEC alongside its disclosure report, said the data in Form SD had a narrow focus, whereas its "total expense for taxes and duties" in the US was more than $10bn, which includes tax obligations from its acquisition of Pioneer Natural Resources. Chevron, which reported US tax expenses of $1.8bn in the US last year in separate securities filings, said it complies with "all legal and contractual requirements" where it operates. Hess said that except for a subsidiary that paid the reported $190,000 in taxes, all other subsidies were in a taxable loss position last year.

The release of the tax data comes as Congress heads to a "tax cliff" from the expiration at the end of 2025 of an estimated $4 trillion in tax cuts that were made temporary, under former president Donald Trump's Tax Cuts and Jobs Act (TCJA) in 2017. To extend those tax cuts, Congress will be looking for revenue-raisers, such as increasing corporate taxes or cutting spending. Democratic presidential candidate Kamala Harris says the US will "have to raise corporate tax rates" to offset the costs of her policies. Republican presidential candidate Donald Trump has pledged to cut corporate tax rates to as low as 15pc, from 21pc currently, alongside various other tax cuts that are likely to cost trillions of dollars.

Consumer groups say the disparity in the "tax take" in the US compared with other countries is noteworthy, because it suggests that oil companies could remain profitable in the US even if taxes were higher. Oil industry officials, meanwhile, say they want Congress to cut tax further than the 21pc corporate tax rate enacted in 2017 through the TCJA.

"We supported TCJA because it lowered corporate tax rates," American Petroleum Institute president Mike Sommers said on 26 September during an event on Capitol Hill. "It's still in a competitive place, but it should be lowered even more."


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16/10/24

'No reason' for Cyprus gas monopoly: Cyfield

'No reason' for Cyprus gas monopoly: Cyfield

London, 16 October (Argus) — There is "no reason" for the gas market monopoly given to state-owned Cygas to continue given sufficient private-sector interest in investing, the chief executive of construction and energy conglomerate Cyfield, George Chrysochos, has told Argus . Cyprus gave Cygas the monopoly thinking that it was the only feasible way to cover the large cost of developing the Vasilikos LNG import terminal, but the government has since been "extremely slow and inefficient in completing the terminal", Chrysochos said. And since 2019, private investors — notably regional producer Energean — have shown increasing interest in Cyprus' gas market, "indicating that there is no reason for the monopoly to exist", he said, adding that a competitive liberalised market would reduce the price of gas imports and therefore also domestic electricity production. The Vasilikos project is currently under investigation by national and European authorities on suspicion of procurement fraud, misappropriation of EU funds and corruption. The project's shared liability between disparate companies made it "impossible for many parties to show interest", Chrysochos said. Completing the project is a priority for Cyprus and that can be done in one of two ways, he said. Either state-owned developer ETYFA could issue a new construction tender using EU and Cypriot funds, which could potentially be completed within a year, or ETYFA could "give the terminal as a concession" to a new operator that finances all remaining work, operates the facility and pays annual rights to Cygas, Chrysochos said. The "ideal scenario" for bringing gas to Cyprus would be to build a pipeline directly to existing Israeli offshore fields, and if funding for a pipeline to Israel's Karish field were available, that would "definitely bring cheaper gas to Cyprus", he said. "All redundancies are welcome," he added. But with Vasilikos already 80pc complete and its floating storage and regasification unit (FSRU) purchased, completing the terminal is the "most reasonable option", Chrysochos said. Cyprus has made several large gas discoveries in its exclusive economic zone, but has been unable to develop them commercially. "Cyprus is a small market and cannot serve as a starting point that will make this extraction feasible," Chrysochos said, meaning that "the viability of the project depends 100pc on the sale of these quantities abroad." Because of this, the only "feasible way" for Cyprus to utilise its discoveries is to pipe the gas to Egypt, where it can be liquefied and then exported back to Cyprus or elsewhere, he said. Alternatively, a pipe could be built to bring gas directly to Cyprus from the Aphrodite field. The consortium developing Aphrodite submitted plans to pipe processed gas to Egypt in September , with similar plans for production at Cronos . Cyfield subsidiary Power Energy Cyprus has been building a 260MW combined-cycle gas turbine (CCGT) plant, which had been intended to be fully operational by early 2025. The construction works are almost complete, but if delays to the Vasilikos terminal prove "significant", the firm might opt to modify the plant to run on diesel, which would require "significant" capital expenditure, Chrysochos said. In any case, Cyfield supports the government in completing Vasilikos and hopes that the CCGT will be operational with either gas or diesel in the next 12 months, he said. Considering the small size of the Cypriot market and that the Electricity Authority of Cyprus is building another power plant, Cyfield now plans to gradually shift its focus for the future to storage and renewables, he said. The proposed 1GW Great Sea electricity interconnector with Greece, approved by the Cypriot council of ministers last month , poses a "greater threat" to local generation than it offers in terms of opportunities, Chrysochos said. Because the scale of energy projects in Greece and Europe is much larger than in Cyprus, the levelised cost of energy is lower, so "it is almost impossible at this stage for Cyprus to export electricity to Europe", he said. The Great Sea line would probably make Cypriot generation redundant and would also be "extremely expensive for the Cypriot consumer, which means that any benefit from importing electricity from Greece will never outweigh the cost", he said. By Brendan A'Hearn 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
News
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
News
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
News
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
News
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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