RdK to resell stored Venezuelan crude, blendstock
Curacao's state-owned RdK plans to resell close to 865,000 bl of locally stored Venezuelan crude, products and blendstock that it acquired at an 11 June auction.
RdK was the sole bidder at the auction, which was conducted by Curacao's state-owned CRU, a utility company that serviced the 335,000 b/d Isla refinery formerly operated by Venezuela's state-owned PdV.
The bulk price at which RdK acquired the oil was not disclosed. Some of the revenue will be used to cover Isla's legacy debts to CRU.
The purchase includes crude, fuel oil, naphtha, slops, aviation gasoline, butane and isopentane, among others. The slops are left over from Isla's former production of Group I and naphthenic base oils.
RdK told Argus the crude and oil products will be processed or blended before they are marketed at an unspecified date.
Curacao's Dutch-controlled government is currently in the final stages of negotiating an operating contract for the long-idle refinery, together with the terminal and CRU, with consortium Corc.
Corc's lead partner is Dick and Doof, a Dutch contractor that formerly serviced Shell's Caribbean and Latin American downstream assets. The refinery was built by Shell over a century ago.
The auction closes one of the final chapters in the island's legacy commercial relationship with PdV, which neglected maintenance and lacked feedstock to keep the refinery operating in the final years of its long-term lease.
Trading company Mercuria is currently using storage tanks at Bullen Bay under a short-term lease signed in December 2020.
Curacao was a key part of PdV's Dutch Caribbean logistical network that also included Aruba. The once-thriving Venezuelan company, which has been subject to US sanctions since January 2019, is struggling to keep its domestic operations afloat.
PdV still controls the 10mn bl Bopec storage terminal on the island of Bonaire, but Dutch authorities have determined that the tanks and jetties are too deteriorated to carry out a safe auction of the fuel oil stored there.
Bonaire is part of the Netherlands, unlike Curacao, which is an autonomous member of the Dutch kingdom.
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Pemex fuel output surges, imports down in March
Pemex fuel output surges, imports down in March
Mexico City, 29 April (Argus) — Mexico's state-owned Pemex increased its gasoline and diesel output by 32pc in March from a year earlier, cutting its road fuels imports by 25pc year over year. Pemex's gasoline and diesel output at its six domestic refineries amounted to 562,300 b/d in March, up from 427,100 b/d in the same month of 2023, according to the company's monthly data published on 26 April. Gasoline production rose by 27pc to 350,400 b/d in March year over year. Gasoline output increased by 13pc from February. Pemex's gasoline imports fell by 16pc in March from a year prior, driven by increased domestic production. On a monthly basis, gasoline imports fell by 18pc from February. The company's diesel output surged by 40pc to 211,900 b/d in March year over year, driving imports down by 43pc to 112,500 b/d (see table) . Diesel production was 26pc higher in March compared with February. Road fuels output increased as Pemex's refining system processed 23pc more crude — 1.06mn b/d — in March from the prior year, as result of billion-dollar investments since 2019 to rehabilitate Pemex's refineries and a decline in crude exports . Pemex's regular 87-octane gasoline domestic sales remain almost steady at 527,400 b/d in March from a year earlier. In contrast, 92-octane premium gasoline sales rose by 11pc to 132,800 b/d year over year, as demand for premium gasoline in Mexico has increased this year. The company's diesel sales ticked up by 1pc in March from a year earlier and were 3pc above February sales. Pemex's domestic sales of refined products accounted for 75.6pc of the company's total revenue in the first quarter, Pemex said during its earnings call on 26 April. This compares to a 70.8pc share in full-year 2023, the company said. By Antonio Gozain Pemex fuel production, imports and sales '000 b/d Product Mar 24 Feb 24 Mar 23 YOY ±% Monthly ±% Production Gasoline 350 310 275.5 27.2 12.9 Diesel 212 168 152 39.8 26.0 LPG 110.0 104.0 100.3 9.7 5.8 Jet fuel 38 38 46 -17.1 1.6 Imports Gasoline 307 376 366.0 -16.1 -18.4 Diesel 112 119 196 -42.5 -5.1 LPG 69 100 101 -31.8 -31.1 Internal sales Regular gasoline 527 520 527 0.1 1.5 Premium gasoline 133 134 120 10.9 -0.7 Diesel 261.0 254.0 258 1.2 2.8 ULSD 30.0 28 32 -4.8 8.3 Jet fuel 95 97 94 1.0 -2.3 LPG 167 194 164 2.0 -13.8 Jet fuel and premium gasoline imports and ULSD imports and production are not broken out Pemex Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Norway's marine bio mandate ineffective: Marine market
Norway's marine bio mandate ineffective: Marine market
London, 29 April (Argus) — Norway's 6pc advanced biodiesel mandate for marine, which came into effect in October, has done little to incentivise the uptake of physical marine biodiesel blends at Norwegian ports, market participants told Argus . As of October 2023, bunker fuel suppliers in Norway must ensure that a minimum of 6pc, on a volume per volume basis, of the total amount of liquid fuels sold per year consists of advanced biofuel in the form of fatty acid methyl ester (Fame) or hydrotreated vegetable oil (HVO). The mandate is only applicable to bunker fuels sold in the domestic market, impacting vessels operating between Norwegian ports as well as local tugboats, offshore supply barges, and fishing vessels. Market participants confirmed that the mandate operates on a mass-balance system at the moment, such that the mandate could also be met by supplying the equivalent amount of biofuels into the inland road sector. Consequently, participants said that very few buyers end up purchasing the physical marine biofuel blends, and instead marine fuel suppliers have had to utilise the mass-balance system to meet their mandated targets. This has resulted in a premium added onto conventional bunker fuels in Norwegian ports of about $56-60/t on average. A market participant described the current system as "like a CO2 tax", with most marine fuel buyers paying the premium rather than purchasing a marine biodiesel blend directly. Participants told Argus that HVO is popular and frequently used in road transport because of its superior specifications compared with biodiesel and its generally low freezing point. Norway's HVO imports typically originate from the US — Kpler data shows that about 68.4pc of HVO flows into Norway have originated from there this year. This is mainly because Norway does not apply the same anti-dumping measures as EU nations, which typically put a substantial premium on US-origin biodiesel imports. Norwegian shipowners going internationally are exempt from being liable to the additional premium imposed by the mandate. But participants told Argus that they usually have to pay the premium and then claim it back from the Norwegian Environment Agency (NEA). The system may change very soon. Market participants told Argus that the NEA is considering some changes to the mandate requirement. A gradual move away from the mass balance system is being discussed, in favour of a physical product mandate that would require biofuel blends to be sold to bunker fuel buyers. Further, a switch from an annual reporting system to a monthly one could also be on the cards. NEA is also reportedly looking at mandating the availability of marine biodiesel at all Norwegian ports and biodiesel fuel reconciliation at the tank rather than terminal. By Hussein Al-Khalisy Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Service firms talk up long-term gas prospects
Service firms talk up long-term gas prospects
New York, 29 April (Argus) — Leading oil field service firms are bullish on the outlook for natural gas demand in coming years even though the fuel remains stuck in the doldrums for now, with US prices near pandemic lows amid oversupply after a mild winter. "This is the age of gas," Baker Hughes chief executive Lorenzo Simonelli says, adding that global demand for the power plant and heating fuel is due to climb by almost 20pc through 2040. "Gas is abundant, lower emission, low cost, and the speed to scale is unrivalled," he says. Halliburton also sees natural gas as the "next big leg of growth" in North America, driven by demand for LNG expansion projects, although its current plans do not envisage any comeback this year. Given a shrinking fracking fleet and lack of new equipment being built, the stage is set for an "incredibly tight market" in future, chief executive Jeff Miller says. A recovery in natural gas activity in the US may not happen until the end of this year or even 2025, Liberty Energy chief executive Chris Wright says. "Customers need to see that prices have firmed, that export volume demand actually is pulling upward at a meaningful rate," he says. On recent first-quarter earnings calls, service firms were upbeat about international growth prospects in the face of escalating geopolitical tensions in the Middle East. The backdrop remains one of growing demand for oil and gas and an "even deeper focus" on energy security, according to Olivier Le Peuch, chief executive of SLB, the world's biggest oil field service company. SLB, formerly known as Schlumberger, expects overseas growth momentum to make up for a slowdown in North America this year. "The relevance of oil and gas in the energy mix continues to support further investments in capacity expansion, particularly in the Middle East and in long-cycle projects across global offshore markets," Le Peuch says. But results in North America will be depressed by the combination of low gas prices, capital discipline and producer consolidation. International rescue Halliburton expects international revenue growth in the "low double-digits" for the full year, with some margin expansion given the tight market for equipment and labour. Steady activity levels are seen in North America after land completion activity bottomed out in the fourth quarter of 2023 and rebounded in the first quarter. "The world requires more energy, not less, and I'm more convinced than ever that oil and gas will fill a critical role in the global energy mix for decades to come," Miller says. The positive outlook is reinforced by customers' multi-year activity plans across markets and assets. Baker Hughes forecasts "high single-digit growth" when it comes to the outlook for international drilling and completion spending this year. But customer spending in North America is expected to fall in a "low to mid-single-digit range" when compared with 2023. "We continue to anticipate declining activity in the US gas basins, partially offsetting modest improvement in oil activity during the second half of the year," Simonelli says. Beyond 2024, upstream spending is seen growing further across international markets, albeit at a "more moderate" pace than seen in recent years, according to Baker Hughes. SLB paced a decline among oil service stocks at the end of January when state-controlled Saudi Aramco scrapped plans to increase crude output capacity to 13mn b/d from 12mn b/d. But Saudi Arabia has stepped up its plans to boost gas output, by 60pc by 2030. This new energy mix was not anticipated six months ago, but it will "not have a natural impact on our ambition for growth" in Saudi Arabia, Le Peuch says. And Saudi gas plans will require substantial investment in gas infrastructure, which is a "long-term net positive" for Baker Hughes, Simonelli says. By Stephen Cunningham Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Production, patience driving Canada’s oil sands profits
Production, patience driving Canada’s oil sands profits
Calgary, 29 April (Argus) — Canadian oil sands operators enjoying firm profits on strong production are getting ready for a major boost when a new export pipeline to the Pacific coast goes into commercial service this week. The federally owned 590,000 b/d Trans Mountain Expansion (TMX) remains on track to start operations on 1 May, and the line has already started to bear fruit. More than 4mn bl of Canadian crude is being pushed into the C$34bn ($25bn) expansion for linefill, helping to work down inventory levels in Alberta while lifting local prices relative to international benchmarks, as intended. The largest four oil sands companies — Canadian Natural Resources (CNRL), Cenovus, Suncor, and Imperial Oil — are all shippers on the expansion. They closed 2023 with a new production record of 3.6mn b/d of oil equivalent (boe/d) combined in the fourth quarter, and are targeting further increases as they plan to fill the new pipeline. About 80pc of their output comes from their core oil sands businesses, with the balance from natural gas and offshore projects. The higher output compensated for a slight dip in prices, helping to push profits higher. First-quarter 2024 results are likely to be a similar story, but it is the second quarter when producers look ready to shine as prices climb to multi-month highs. A combined profit of C$26bn in 2023 was a stellar result for the big four oil sands operators, despite a 25pc decline from the record C$34bn set the previous year. Their massive projects are agnostic to daily price swings, instead focused on uptime, long-term fundamentals and capitalising on key step-changes such as the one TMX presents. Patience in the oil sands is key. TMX will cater largely to heavy crude producers, which saw diluted bitumen prices in Alberta rise only slightly quarter on quarter to $58/bl in the first quarter. But climbing global benchmarks in April and a shrinking heavy sour discount with the help of TMX linefill now has the outright price for the crude approaching $70/bl. This is above guidance given in 2024 corporate budgets, and far above oil sands operating costs that for some are as low as $12/bl. The TMX factor TMX will nearly triple the existing 300,000 b/d Trans Mountain system that connects oil-rich Alberta to the docks in Burnaby, British Columbia. The expansion was first conceived more than a decade ago with the intention of being operational by late-2017, but cost overruns and repeated delays put the project in jeopardy. Canadian producers that sought growth during that period of frustration are poised to take advantage of this new era of excess export capacity. CNRL, Cenovus and Suncor have been significant buyers in the oil sands in recent years, doubling down on the world's third-largest deposit of oil while many international companies fled amid regulatory uncertainty. The government itself enabled a foreign operator to leave Canada, buying the Trans Mountain system from Kinder Morgan in 2018. But as Prime Minister Justin Trudeau's Liberal party sees TMX to completion, and then the line's planned sale, it is also readying legislation towards something more on-brand for climate-concerned Ottawa: carbon capture. A carbon capture and storage (CCS) project spearheaded by Pathways Alliance — a consortium of the six largest oil sands producers — is awaiting federal and provincial help to push their proposal forward. Federal incentives are soon to become law, the Trudeau government said this month, with the expectation that tax credits will advance the massive C$16.5bn project and start to offset oil sands greenhouse gas emissions to meet net zero pledges for all parties involved. TMX represents a new era for Canadian crude producers, but so too does CCS, as it could attract even more investment into Alberta's oil sands region. 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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