Malaysia’s Petronas achieves first gas at Kasawari
Malaysian state-owned Petronas has started first gas production at the Kasawari field at an initial flow rate of 200mn ft³/d (5.6mn m³/d), the firm announced today.
The field is located in Block SK316, approximately 200km off the coast of Sarawak. It contains an estimated 10 trillion ft³ of natural gas resources, with a gas sales rate of 545mn ft/d, according to Petronas.
Petronas Carigali, a subsidiary of Petronas, holds a 90pc stake in the Kasawari field and is the operator. Exploration and Production Malaysia Venture (EPMV) holds the remaining 10pc stake.
The Kasawari gas field development includes a central processing platform, a flare platform and a wellhead platform, which are all interconnected. Gas from the field is exported to a new riser platform at the E11 production hub through an 81km carbon steel pipeline for further gas delivery to customers in Bintulu, Petronas said.
The Kasawari gas field is a crucial feed source for the Petronas LNG complex in Bintulu and in addressing the increasing domestic demand for gas, said Petronas.
Carbon capture and storage
Petronas is also still looking to develop its carbon capture and storage (CCS) capabilities, including at the Kasawari field, even as it looks to maximise fossil fuel production.
The firm on 20 August announced it signed a joint study and development agreement with Abu Dhabi's state-controlled Adnoc and UK decarbonisation firm Storegga, to evaluate the CO2 emission storage capabilities of saline aquifers and construction of CCS facilities in the Penyu basin, offshore peninsular Malaysia.
The agreement targets at least 5mn t/yr of CO2 capture and storage capacity by 2030. The scope of the agreement includes a CO2 shipping and logistics study, geophysical and geomechanical modelling, reservoir simulation and containment research while exploring the application of advanced technologies, including artificial intelligence, to enhance storage capacity, Petronas said.
Malaysia has a target of net zero emissions by 2050. Petronas is a member of Malaysia's National Energy Transition Roadmap committee, which has identified CCS as one of six energy transition levers to enable the country to be sustainable, low-carbon and resilient.
In line with this, Petronas has signed multiple deals with foreign firms to jointly develop CCS projects with Malaysia, including Japanese firms Jera, Mitsui, and Japex. Petronas is also involved in cross-border projects with South Korean firms.
Malaysia has a geological abundance of deep saline aquifer reservoirs, which should allow for the development of large-scale, permanent CO2 storage solutions. This latest agreement will significantly accelerate regional deployment of CCS and if successful, will lay the foundations for a regional CCS hub that serves both domestic and international emitters, Petronas added.
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Papua LNG FID set for late 2025: Australia’s Santos
Papua LNG FID set for late 2025: Australia’s Santos
London, 22 August (Argus) — A final investment decision (FID) on the 5.6mn t/yr Papua LNG project in Papua New Guinea is likely to be taken in late 2025, Australian independent Santos' chief executive Kevin Gallagher told an investor call marking the firm's half-year results to 30 June. The joint-venture partners are working to reset the initial engineering phase of the project, Gallagher said, with design optimisations under way to reduce capital expenditure on Papua LNG. Santos' "best estimate" is that the project partners would reach an FID towards the end of 2025, Gallagher said. The preferred development concept continues to include processing up to 2mn t/yr of Papua LNG's raw gas through the 6.9mn t/yr ExxonMobil-operated PNG LNG plant . The $10bn project to build Papua New Guinea's second LNG export terminal was initially expected to reach an FID by early 2024 ahead of first production in early 2028, but this was postponed in April by the need for more commercially viable engineering, procurement and construction contracts, operator TotalEnergies said . TotalEnergies holds a 37.55pc stake in Papua LNG, with ExxonMobil controlling 37.04pc, Santos 22.83pc and Japanese upstream company JX Nippon 2.58pc. By Tom Major Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Oil producers sell US gas at lowest prices in years
Oil producers sell US gas at lowest prices in years
New York, 21 August (Argus) — Large crude oil producers in the second quarter sold their US natural gas output at the lowest prices in years as gas pipelines out of the Permian basin ran full and the US gas market remained oversupplied. The historically discounted gas — mostly associated gas production — did little to dent the crude producers' profits, however, as crude sales represent a much larger share of their revenue and crude prices have remained strong. Nevertheless, crude-driven associated gas production comprises a significant share of total US gas output. Chevron, which reported 2.6 Bcf/d (74mn m³/d) of US gas output in the second quarter, posted average realized sales at 73¢/mmBtu, the lowest for the oil major since the first quarter of 2020, according to company filings. This was down from its year-earlier sales realized at $1.18/mmBtu and its full-year 2022 sales realized at $5.35/mmBtu. A little more than half of Chevron's second-quarter US production, on an oil equivalent basis, came out of the Permian basin of west Texas and eastern New Mexico, while a quarter came out of Colorado. ExxonMobil fared little better, with average sales realized at $1/mmBtu for its 2.9 Bcf/d of US gas in the second quarter, down from $1.40/mmBtu a year earlier and the lowest since at least 2002, as far back as Internet-accessible company filings reach. If it realized a more middling price of $3/mmBtu on its US gas output, its second-quarter revenue would have been $548mn higher than its actual revenue of $51.2bn. EOG Resources in the second quarter averaged realized sales at $1.51/mmBtu for its 1.7 Bcf/d of US gas output, while ConocoPhillips realized 31¢/mmBtu for its 1.6 Bcf/d of lower-48 US gas output. Diamondback Energy posted such a low average price realization for its 564mn cf/d of US gas in the second quarter — 10¢/mmBtu — that earlier this month it said it had curtailed some oil production just to bring down the amount of gas that was coming up the well alongside the oil. State and federal regulations hinder indiscriminate so-called "economic" flaring, forcing producers to sometimes pay buyers to take gas off their hands in the absence of available pipeline takeaway capacity. "Obviously, we need to start making more money on our gas in the Permian," Diamondback chief financial officer Kaes Van't Hof said. Fly in the oil well Still, large crude producers are not exactly hurting. Exxon reported a $9.2bn profit, up from $7.9bn a year earlier, while Chevron reported a $4.4bn profit, down from $6bn a year earlier. Diamondback's second-quarter profit of $837mn was also up from its year-earlier profit of $556mn. Those profits, on the back of solid crude prices in the latest quarter, were also partly thanks to booming oil production in the Permian basin, which as a side effect has flooded the region with associated gas. The pace of that gas growth has outpaced developers' efforts to expand local gas pipeline takeaway capacity, plunging spot prices there into negative territory . The Waha spot index in the second quarter averaged -58¢/mmBtu. This upside-down market is not likely to last, however, as the 2.5 Bcf/d Matterhorn Express pipeline comes on line later this year to relieve takeaway constraints in the Permian. Argus forward curves show the September price of -48¢/mmBtu at Waha rising to 49¢/mmBtu in October, with the 2025-calendar strip there averaging $2.07/mmBtu — not so far below Tuesday's 2025 strip settlement at the US benchmark Henry Hub of $3.29/mmBtu. By Julian Hast Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
Sweden, Zambia Article 6 agreement eyes renewables
Sweden, Zambia Article 6 agreement eyes renewables
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Indonesia may tighten POME oil export rules: Ministry
Indonesia may tighten POME oil export rules: Ministry
Singapore, 21 August (Argus) — Indonesian exports of palm oil wastes and residues including palm oil mill effluent (Pome) oil may soon be subjected to stricter export regulations, according to a draft document from its trade ministry. The ministry released the draft after a meeting with biofuel feedstock exporters on 20 August. The timeline for a decision on finalising the regulation is still unclear, although some market participants said it could be made by this month. Exports of Pome oil, high acid palm oil residue (Hapor) and empty fruit bunches (EFB) oil under the HS code 2306.60.90 are expected to require export permits, a change from the previous requirement of only export rights. While more details were not disclosed, meeting domestic market obligations (DMO) is usually a prerequisite to get export permits, suppliers said. This means that companies will need to sell a certain amount of cooking oil within Indonesia — or buy export quotas or credits from palm oil refineries around $15-$20/t — before they are able to export these products. This has led to expectations of potentially tightened feedstock exports. Refineries who sell cooking oil volumes to remote areas of Indonesia will also receive higher export quotas. As of January 2023, only crude palm oil (CPO), refined, bleached and deodorised (RBD) palm oil, RBD palm olein and used cooking oil (UCO) were subject to the DMO requirements. The previously-set domestic Highest Retail Price (Harga Eceran Tertinggi or HET) for cooking oil sold to consumers at 14,000 rupiah/l is now Rp15,700/l. This is likely because of higher CPO prices and packaging costs, a Indonesia-based supplier said. But market participants said they were also anticipating this increase previously. The higher HET implies that companies' cost of acquiring export permits in the medium to long term could fall, having sold cooking oil at higher prices domestically, market participants said. DMO for cooking oil Indonesia's Ministry of Trade also issued a regulation on 16 August stating that the DMO scheme for cooking oil will move fully from bulk to packaged palm olein – in 500ml, 1 litre (l), 2l and 5l volumes. This is likely to help maintain stable cooking oil prices and control inflation, as packaged olein is easier to monitor than bulk, a supplier said. The deadline for moving from bulk to packaged volumes is 12 November. Refineries under the DMO must also supply cooking oil volumes domestically of around 250,000 t/month, compared with approximately 300,000 t/month previously. But actual volumes will also depend on factors like how much palm oil wastes and residues exporters want to ship in a particular month too, a supplier said. The draft document did not include updates to long-awaited changes to export duties and levies to POME oil, UCO and other products, market participants said. They were expecting these changes in September or October when the new government is sworn in, although the actual timeline is difficult to determine. Current combined export duties and levies on POME for August is only $10/t, considering a CPO reference price of $820.11/t. UCO is not subject to duties, but have levies of $35/t. By Sarah Giam Send comments and request more information at feedback@argusmedia.com Copyright © 2024. Argus Media group . All rights reserved.
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