Chinese oil demand to peak before 2030: CNPC

Spanish Market: Coal, Crude oil, Natural gas, Oil products, Petrochemicals
28/12/21

China's petrochemical needs will fuel oil demand growth while a slowdown in incremental oil demand in the transportation sector will contribute to a peak in overall oil consumption before 2030, according to the latest forecast by state-controlled CNPC's research arm the Economics and Technology Research Institute (ETRI).

Chinese oil demand is expected to peak at 18.2mn b/d (780mn t/yr) before 2030, with the petrochemicals sector driving oil demand through 2030. But oil demand is forecast to drop to 8.8mn b/d by 2050 and 5.4mn b/d by 2060.

This will exacerbate the oversupply in refining capacity after 2030, requiring refiners to increase production of higher-end products, rather than transportation fuels, as part of energy transition efforts, the ETRI said. Beijing has already outlined a crude distillation capacity limit of 20mn b/d for Chinese refining capacity in 2025.

Electrification, or the use of electric vehicles, will be especially rapid in the transportation sector between 2031-50. This will reduce gasoline and diesel demand, although petrochemicals demand is still expected to be relatively stable during this period.

Demand for oil products including gasoline, diesel and jet fuel could peak at 8.4mn b/d by 2025 and decline to 1.3mn b/d by 2060, driven by the rise of new energy vehicles (NEVs) and development of railways. Chinese apparent products demand, including gasoline, diesel and jet fuel, averaged 6.9mn b/d in January-November, data from the National Bureau of Statistics and Customs Bureau show.

China's auto fleet still has room to grow, the ETRI said. NEVs will account for 10pc of China's total auto fleet in 2028, and rise to 80pc in 2052. NEVs currently account for just 2.3pc of vehicles in China.

China's auto sales in 2022 are expected to rise by 5.4pc from a year earlier to 27.5mn, with NEVs leading the increase, according to the China Association of Automobile Manufacturers (CAAM).

Sales of NEVs are forecast to rise by 47pc to 5mn in 2022, the CAAM said.

The country's primary energy consumption could also peak during 2030-35, at around 6bn t of standard coal equivalent (tce), then decline to 5.7bn tce by 2060 as renewables production rises, according to the ETRI. China only just met its 2020 consumption target of 5bn t tce with demand of 4.98bn tce.

The ETRI has also forecast Chinese coal demand to peak by 2025, and gas demand by 2040.

The institute expects Chinese crude production to remain at around 4mn b/d before 2035 but for natural gas output to grow at a faster pace, reaching 250bn m³/yr by 2030 and 350bn m³/yr by 2060. Chinese crude output averaged 100,000 b/d or 3pc higher on the year at 3.94mn b/d in January-November. Gas output rose by 8.9pc on year to 186bn m³ in January-November.

For 2021, national crude output is expected at 3.98mn b/d and gas output at 206bn m³, the National Energy Administration said.

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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.

Brazil polymers, chem import tax hike begins

15/10/24

Brazil polymers, chem import tax hike begins

Sao Paulo, 15 October (Argus) — Brazil's import tax increase on a number of polymers and chemicals to 20pc from 12.6pc, including polyethylene (PE), polypropylene (PP) and polyvinyl chloride (PVC), has gone into effect. The new import tax rate was effective on 15 October and is valid for 12 months, according to Gecex, the Brazilian committee for commercial trade management. A PVC plastic converter with operations across Latin America told Argus that although the tax increase only started today, Brazilian polymers producers already raised prices by 5-6pc since the end of September. PVC import prices into Brazil, with the exception of those originating from the US, also followed suit last week, the source said. Higher prices are expected in Brazil despite stable PVC demand. Furthermore, maritime logistics difficulties at ports in southern Brazil continue and there is concern they will worsen as the end of the year approaches, putting more pressure on plastic resins prices. The major port of Navegantes is currently undergoing an expansion project that has created delays at that port and surrounding ports. US traders said that the increase in Brazilian import taxes is likely to lead to at least a short-term decline in US exports to Brazil. "I think short term, over one to two months, [the higher taxes] will deter imports," said one US trader. "[Brazilian polymers producer] Braskem will take advantage and increase the price… and then customers will buy anyway at the new price level." During that short period, there will be increased availability of US product for other regions, according to another US trader. "Big volumes will need to go elsewhere," said the trader. "Maybe elsewhere in South America, maybe other regions." Domestic manufacturers and chemical industry associations welcomed the decision when it was first announced on 18 September. Brazil's chemical industry association Abiquim has been asking the government to provide commercial protections for 62 products since May. But critics of the tax hikes say they will increase costs for consumers and manufacturers who rely on imported polymers and chemicals. Brazil's plastic industry association Abiplast said in September it was concerned that the higher import taxes will increase production costs for plastic products, which could result in higher prices for end consumers. The Brazilian chemical industry is responsible for around 11pc of Brazil's GDP, according to Abiquim. By Fred Fernandes and Michelle Klump Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Tax credit delay risks growth of low-CO2 fuels

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 Fialkoff, 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.

PetroChina offloads TMX crude pipeline commitment

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.

Lignite displaces gas in German power mix

15/10/24

Lignite displaces gas in German power mix

London, 15 October (Argus) — Rallying German gas prices have pushed a significant amount of gas-fired generation out of the country's power mix this month, opening space for lignite. Average daily gas-fired generation in Germany has slipped to 3.8GW so far this month from 4.2GW in September and August and 4.1GW in July. During that time, lignite-fired generation climbed to 9GW from 7.2GW in September and August and 7.4GW in July. Coal-fired generation has also edged down to 2.9GW so far this month from just over 3GW in September, but higher than the averages of 2.3GW in August and 1.4GW in July. Meanwhile, supporting demand for thermal-fired generation, German renewables output has fallen to 30.3GW so far in October from just under 32GW in September when wind generation stepped up, but slightly above the 29.5GW in August when wind output was lower. Remaining German power demand in recent weeks has been covered by imports, which have risen to a net 3.8GW so far this month from 3.4GW in September, but remained well below the 6.2GW in August. Electricity imports from neighbouring countries such as France are occasionally cheaper than domestic generation and can help fill in gaps between German power demand and supply. A combination of changing renewable output, higher gas prices, stable lignite prices and lower emissions prices have spurred changes in the German power mix. The German THE day-ahead has risen strongly since late July and prices have rallied in recent weeks against a backdrop of rising geopolitical tensions in the Middle East. Meanwhile, German lignite-fired plants typically source fuel from nearby mines, substantially insulating domestic lignite prices from external market forces. German regulator Bnetza assumed earlier this year that domestic lignite would cost about €3/MWh in 2024-25. At the same time, near-term prices in the EU emissions trading system (ETS) — a key driver of competitiveness for German lignite-fired generation — have fallen. Prompt ETS allowances closed at €65.36/t of CO2 equivalent (CO2e) on Monday, down from €72.14/t CO2e on 19 August, boosting the profitability of lignite-fired plants, which are the more CO2 intensive than coal and gas. Those recent price shifts have made output from lignite-fired plants with a typical efficiency of 36pc more profitable than normal 55pc-efficient gas-fired plants as well as coal-fired stations operating at 40pc efficiency, which have also become more profitable . By contrast, in the first eight months of this year, 36pc-efficient lignite-fired plants had competed tightly with 55pc-efficient gas-fired plants even as gas prices fell to the bottom of the coal-to-gas fuel-switching range ( see fuel-switching graph ). Buffer zone More competitive lignite-fired generation has also started acting as the domestic buffer to cover gaps between supply and demand left by renewable generation ( see power generation graph ). After Germany renewable generation dropped to 26.8GW on 2-9 October from a strong 45.5GW on 26-28 September, lignite-fired generation jumped to 10.1GW from 6.4GW — a 57pc gain — while gas-fired output only rose to 3.5GW from roughly 3GW and coal-fired generation increased to 2.9GW from 2.3GW. In December-July, when the gas and lignite fuel-switching range was tight, generation from both fuels reacted similarly to fluctuations in renewable output and both plant types buffered their generation based on demand ( see power generation graph ). And forward prices assessed by Argus suggest that lignite-fired generation could remain competitive against gas and coal-fired output in the German power mix next month. As of market close on Monday, November-dated fuel and emissions prices would place the operating costs of a 36pc-efficient lignite-fired plant during that time below those of a 55pc-efficient gas-fired plant and a 40pc-efficient coal-fired plant. That said, Germany's decreasing lignite and coal-fired generation capacity limits how much of the national power mix those plant types can provide. As of April, Germany had 82.4GW of gas-fired capacity, but just 15.1GW of lignite-fired capacity and 11.5GW of coal-fired plants, according to Bnetza. By Lucas Waelbroeck Boix Fuel switching range €/MWh Power generation by fuel, 7 day average GW Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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