Netherlands joins in to end fossil fuel funding abroad

Spanish Market: Coal, Crude oil, LPG, Natural gas, Oil products
08/11/21

The Netherlands today said it will join a group of 25 countries and institutions to end public financing of unabated coal, oil and gas projects overseas by the end of 2022.

The initial pledge, signed at the UN Cop 26 conference in Glasgow on 4 November, seeks to prioritise financing of green projects, but the details still need to be ironed out.

The US, Canada and the UK are among the countries committed to stop new direct support to fossil fuels by 2022, along with Denmark, Finland, Mali, Costa Rica and South Sudan. The European Investment Bank (EIB) is also party to the deal.

"Dutch development bank FMO had already signed up to the statement but not the Dutch government as a whole," campaign group Oil Change International said. "Today's announcement by the Netherlands means that the Dutch export credit agency — Atradius Dutch State Business, which is responsible for about €1.5mn ($1.74mn) in public support for fossil fuels overseas — will also need to end financing for oil, gas and coal projects by the end of 2022."

Public investments to be shifted from fossil fuels to cleaner energy could now amount to $19bn/yr if signatories follow through with their pledges.

By Caroline Varin

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04/11/24

Oil services upturn takes a pause for breath

New York, 4 November (Argus) — The boom in demand for oil field services is showing signs of wavering in the short term as international customers signal greater caution around spending and the outlook for US shale remains challenged. Upstream spending growth in the North American onshore market is expected to be flat in 2025, with low natural gas prices, drilling efficiencies and further consolidation among producers in the shale patch all exerting downward pressure. Given a mixed international outlook, one bright spot will be offshore markets, and deepwater in particular, according to investment management firm Evercore ISI. "The solid growth years of 2023 and 2024 are over as the cycle resets," senior managing director James West says. "We view 2025 as an aberration in a long-term, albeit slower, growth cycle." In the near term, the sector's attention will be focused on spending plans by top producers including state-run Saudi Aramco and Brazil's Petrobras, as well as any signs of a potential recovery in Chinese oil demand given the government's latest stimulus efforts to kick-start growth. The sector has had to contend with more than $200bn of shale mergers and acquisitions over the past year, which has shrunk the pool of available customers, and led to oil field services providers beginning their own round of consolidation. Moreover, with capital discipline remaining the rallying cry, significant productivity gains have enabled producers to do more with less. Its immediate challenges were put into stark contrast this week by oil's renewed plunge, this time on the back of Israel's decision to spare Iran's energy infrastructure from retaliatory strikes. SLB, the biggest oil field services contractor, has attributed recent price volatility to concerns over an oversupplied market owing to higher output from non-Opec producers, as well as questions over when the cartel will return barrels to the market and weak economic growth. That spurred some customers to adopt a "cautionary approach" when it came to activity and spending in the third quarter. Gas to the rescue But SLB remains upbeat over the long-term outlook, given the current emphasis on energy security, a key role for natural gas in the energy transition, and expectations that oil will remain a "large part" of the energy mix for decades to come. Gas investment remains robust in international markets, particularly in Asia, the Middle East and the North Sea. "While short-cycle oil investments have been more challenged, long-cycle deepwater projects globally and most capacity expansion projects in the Middle East remain economically and strategically favourable," SLB chief executive Olivier Le Peuch says. Exploration successes in frontier regions from Namibia to Suriname are also unlocking vast reserves that only serve to bolster confidence in the offshore market. Global offshore investment decisions will approach $100bn this year and in the next 2-3 years, adding up to more than $500bn for 2023-26, according to Le Peuch, representing a "growth engine for the industry going forward". Meanwhile, Baker Hughes expects to capitalise on a growing market for gas infrastructure equipment. The company forecasts natural gas demand will grow by almost 20pc by 2040, with global LNG demand increasing at a faster rate of 75pc. "This is the age of gas," chief executive Lorenzo Simonelli says. The top services firms see limited short-term growth prospects for North America, with the exception of the Gulf of Mexico. Hydraulic fracturing services provider Liberty Energy plans a temporary reduction in its fleet in response to slower customer activity and market pressures. And SLB says any potential pick-up in gas rigs could be offset by a further decline in oil rigs owing to efficiencies. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Asian demand might cap WTI availability for Europe

04/11/24

Asian demand might cap WTI availability for Europe

London, 4 November (Argus) — Asia-Pacific refiners have increased their intake of US light sweet WTI crude for November loading and could remain keen buyers in December, potentially limiting supply for Europe. Asian refiners have bought around 1.3mn b/d of WTI loading in November, traders say, up from roughly 800,000 b/d loading in October, and surpassing average flows of 1.15mn b/d to the region this year. Arbitrage economics from the US to Asia are better than those to Europe at present, traders say. And firmer refining margins for naphtha-rich crudes in Asia-Pacific could prompt refiners to maintain high purchases of WTI in December. Asian buyers tend to seek WTI around two weeks before European refiners owing to the longer shipping times, affecting availability of the grade in Europe. European interest in November-loading WTI has been limited by refinery maintenance, exacerbated by an abundance of cheap light sweet crude in the region following the sudden restart of Libyan crude exports in October. The rebound in Libyan supply after a period of disruption pressured differentials for competing light sweet grades from the North Sea and Mediterranean regions. North Sea Forties and Ekofisk and Algerian Saharan Blend fell to their lowest in at least two months against North Sea Dated in mid-October. At the same time, delivered WTI has been supported by high freight rates. Shipping costs to take an Aframax from the US Gulf coast to Europe were 62pc higher on average in October than in September, narrowing WTI's discount to North Sea light sweet crudes. Abundant and affordable WTI has tended to act as a cap on light sweet crude prices in the region. But the higher freight costs have meant that WTI has been one of the more expensive crudes in the North Sea Dated basket. WTI was at parity to light sweet Oseberg in early October, up from a discount of around $1/bl a month earlier. WTI has set the benchmark as the lowest-priced crude only six times in the past two months, compared with 26 occasions over the same period last year. But European demand for crude is expected to rebound in December, as regional refineries ramp up following autumn maintenance. Ekofisk has already added around 60¢/bl relative to WTI since mid-October, briefly moving from a discount to a premium to the US grade over 25-29 October. Any WTI supply tightness in the final weeks of the year, and continued firm demand in Asia, could limit WTI flows to Europe and support light sweet crude prices. Arbitrage effects For some Asia-Pacific refiners, a workable WTI arbitrage has helped pressure the price of alternative supplies. Indian refiner IOC opted to buy two cargoes of WTI in a tender which closed on 17 October instead of the west African crude it typically favours. The refiner bought a cargo of WTI each from US-based Occidental Petroleum and Japanese trading company Mitsui for delivery in December and January to the western port of Vadinar and eastern port of Paradip, market participants say. Lacklustre interest from Indian and European buyers, and plentiful light sweet crude supply, have since combined to pressure some Nigerian crude differentials, pushing them down by 20¢-$1.15/bl against North Sea Dated in October. This has helped reinvigorate demand and clear more November shipments on the eve of the December-loading cycle. IOC subsequently bought a shipment each of Nigerian Agbami from Chevron and Angolan Nemba from an undisclosed seller in a tender which closed on 24 October. But up to a dozen November-loading Nigerian cargoes remained unsold as of 29 October, according to traders. By Lina Bulyk Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Opec+ delays supply return for one month

03/11/24

Opec+ delays supply return for one month

London, 3 November (Argus) — Eight Opec+ members that were due to begin raising crude output from December have opted to delay the restart by one month, the Opec secretariat said today, 3 November. The eight ꟷ Saudi Arabia, Russia, Iraq, the UAE, Kuwait, Kazakhstan, Algeria and Oman ꟷ had already postponed, by two months, a plan to start returning supply, over concerns about worsening economic indicators, and in turn, weakening oil prices. With these concerns still very much live, the group has decided again to delay the start of a move that would have added 180,000 b/d to global supply in December. The eight "have agreed to extend the November 2023 voluntary production adjustments of 2.2mn b/d for one month until the end of December 2024," the Opec secretariat said. As was the case with the postponement in September, the secretariat did not give any explicit rationale for the move. This one month deferral means a decision about whether to start returning supply in January, or to delay again, will coincide with Opec and Opec+ group meetings that are scheduled to take place in early December. Delegate sources told Argus after the first postponement that its decision was also to allow some of the group's serial overproducers, namely Iraq, Russia and Kazakhstan, time to improve compliance with their pledged output targets. The secretariat today again made a point of underlining the wider group's "collective commitment to achieve full conformity," with a focus on those three countries. Benchmark North Sea Dated crude was assessed by Argus at $73.48/bl on Friday, 1 November, around $20/bl below where it was before Opec+ announced its initial output cut in October 2022. The alliance has reduced output by 4mn b/d since then, Argus estimates. Much of the oil price weakness is down to an increasingly gloomy demand outlook, primarily driven by worse-than-expected consumption growth in China. Global oil supply is also higher than Opec+ would prefer — including from its own overproducers — and is due to rise further, with the US, Guyana and Canada driving gains. The IEA forecasts a supply surplus of more than 1mn b/d in 2025, even in the absence of any increase from Opec+. By Nader Itayim and Bachar Halabi Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

TMX exports reach new record in October

01/11/24

TMX exports reach new record in October

Houston, 1 November (Argus) — Crude exported via the 590,000 b/d Trans Mountain Expansion (TMX) pipeline reached a new high in October at 413,000 b/d. TMX loadings out of Vancouver were up by 103,100 b/d from September and surpassed the previous record of 368,800 b/d in August by 12pc, according to data by analytics firm Vortexa. The exports loaded onto 24 Aframax tankers, up from an average 20 per month, according to Teekay Tankers in an earnings call. Of those 24 Aframaxes, nine went directly to Asia-Pacific ports while at least four went to the Pacific Area Lightering zone (PAL), where the vessels discharged onto very large crude carriers (VLCCs) for Asia-Pacific. The rest traveled to ports along the US west coast. China overtook the US west coast as the largest importer of TMX crude in October, increasing its loadings from 139,900 b/d in September to 208,300 b/d, or over 50pc of the total volume. A record amount of TMX crude still departed for the US west coast in October at 204,700 b/d, up 20pc from the prior month. Future imports into the region might be stifled in the short-term, with US independent refiner PBF planning to run less TMX crude during the fourth quarter amid higher prices and ongoing maintenance on equipment used to remove impurities from heavy sour crude, like the grades exported from TMX. Long-term, TMX transportation rates could become more economical for California refineries, PBF said in its third quarter earnings call. Canadian high-TAN crude fob Vancouver averaged a roughly $11.35/bl discount to December Ice Brent in August, when October cargoes were trading, while heavy sour Cold Lake averaged a roughly $10.60/bl discount. By Rachel McGuire Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

Mexican hydrogen regulatory efforts gain ground

01/11/24

Mexican hydrogen regulatory efforts gain ground

Mexico City, 1 November (Argus) — The Mexican hydrogen association (AMH2) has made significant strides in recent discussions with regulators and officials, unveiling a comprehensive roadmap for industrial hydrogen adoption. The group's report estimates there will be demand for about 392,189 tonnes (t) of hydrogen per year across seven major industries during Mexico's pilot hydrogen development phase. This includes sector-specific hydrogen demands of 148,350 t/yr from oil refining through 10 potential applications; 107,325 t/yr for mining; 55,877 t/yr for hydrogen blending in natural gas; 23,932 t/yr in the metals industry; 35,040 t/yr tied to ammonia production; 15,265 t/yr for public transport; and 6,400 t/yr for methanol production. AMH2's strategy urges the administration of President Claudia Sheinbaum to designate a lead ministry for hydrogen development, prioritize green hydrogen production and introduce incentives for project financing, technology development and energy transition initiatives. Additionally, it calls for regulatory adaptations to facilitate hydrogen's integration into Mexico's natural gas infrastructure, including quality, transportation, distribution and safety standards, especially for industrial equipment. Legal reforms to support hydrogen development will also be needed, according to the report, targeting laws governing mining, water, hydrocarbons, nuclear energy, energy transition, environmental protection, electric power, bioenergy and geothermal power. For green hydrogen — generated with renewable energy — the focus would be on the latter five areas. These efforts align with Mexico's long-term energy plan (Prodesen 2023-2037), which envisions converting 12 combined cycle power plants, totaling 1.024GW, to operate on a 70pc natural gas and 30pc hydrogen blend between 2033 and 2036. AMH2 president Israel Hurtado said although Mexico's pipeline infrastructure could handle up to a 15pc green hydrogen blend, achieving a 30pc blend would require further technological advances expected over the next decade. Prodesen also identifies regions for hydrogen injection into pipeline networks, including Sonora, Sinaloa, Tamaulipas, Oaxaca, Veracruz, Baja California and the Yucatan peninsula. Yet new regulations will be crucial to establish a robust framework for hydrogen blending in existing infrastructure. The Sheinbaum's administration has committed to reducing carbon emissions and promoting clean energy, Hurtado said, with a $13.5bn investment pledge in renewables over six years and a target for 45pc of national power from renewables by 2030. AMH2 has built early connections with Sheinbaum's team, including Jorge Islas, her energy and climate advisor during the campaign, who now heads the energy ministry's (Sener) energy transition unit and supports green hydrogen initiatives. AMH2 leaders also recently met with energy regulator (CRE) president Leopoldo Melchi and commissioner Walter Jimenez, who expressed strong interest in hydrogen regulation. The association and CRE agreed to form a technical workgroup to develop clean hydrogen regulations collaboratively. Looking ahead, AMH2 plans to meet with energy minister Luz Elena Gonzalez and Mexico's economy ministry to further discuss the hydrogen strategy. But CRE's workgroup is on hold pending potential legislative reforms that could reorganize Mexico's energy regulators under Sener's supervision. Projects in development AMH2 has identified 16 hydrogen projects in Mexico, with eight in various development stages and eight announced. Primarily focused on green hydrogen, these projects represent an estimated $19bn investment. The largest, Helax, is a $10bn green hydrogen production facility in Oaxaca, connected to the Interoceanic Trans-Isthmus Corridor. AMH2 anticipates production to start within two years following initial permitting. The roadmap suggests that, even if only six projects are operational by 2030, the sector could generate 3.351GW and attract $1.8bn in investments. These projects are projected to bring in $2.5bn in revenue over six years and yield $1.9bn in tax contributions. By James Young Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.

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